SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark one)
(x) Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2001
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or
( ) Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ____________ to ____________
Commission file number 1-8246
Southwestern Energy Company
(Exact name of Registrant as specified in its charter)
Arkansas 71-0205415
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2350 N. Sam Houston Parkway East, Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (281) 618-4700
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock - Par Value $.10 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes x No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. x
---
The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $278,979,412 based on the New York Stock Exchange --
Composite Transactions closing price on March 7, 2002, of $11.19.
The number of shares outstanding as of March 7, 2002, of the Registrant's
Common Stock, par value $.10, was 25,502,070.
DOCUMENTS INCORPORATED BY REFERENCE
Document incorporated by reference and the Part of the Form 10-K into which
the document is incorporated: Definitive Proxy Statement to holders of the
Registrant's Common Stock in connection with the solicitation of proxies to be
used in voting at the Annual Meeting of Shareholders on May 15, 2002 - PART III.
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TABLE OF CONTENTS
Part I pg
Item 1 Business 3
Business strategy 3
Exploration and production 3
Natural gas distribution 9
Marketing and transportation 12
Other items 13
Item 2 Properties 13
Item 3 Legal proceedings 15
Item 4 Submission of matters to a vote of security holders 15
Executive officers of the registrant 15
Part II
Item 5 Market for registrant's common equity and related
stockholder matters 17
Item 6 Selected financial data 18
Item 7 Management's discussion and analysis of financial
condition and results of operations 20
Item 7A Quantitative and qualitative disclosure about
market risks 29
Item 8 Financial statements and supplementary data 31
Item 9 Changes in and disagreements with accountants on
accounting and financial disclosure 50
Part III
Item 10 Directors and executive officers of the registrant 51
Item 11 Executive compensation 51
Item 12 Security ownership of certain beneficial owners
and management 51
Item 13 Certain relationships and related transactions 51
Part IV
Item 14 Exhibits, financial statement schedules, and reports
on Form 8-K 51
2
Part I
ITEM 1. BUSINESS
Southwestern Energy Company (the "Company" or "Southwestern") is an energy
company primarily focused on natural gas. The Company was incorporated in
Arkansas in 1929 as a local gas distribution company. Today, Southwestern is an
exempt holding company under the Public Utility Holding Company Act of 1935 and
derives the vast majority of its operating income and cash flow from its oil and
gas exploration and production business. In February 2001, the Company relocated
its corporate headquarters from Fayetteville, Arkansas to Houston, Texas. The
Company is involved in the following business segments:
1.Exploration and Production - Engaged in natural gas and oil
exploration, development and production, with operations principally
located in Arkansas, Oklahoma, Texas, New Mexico, and Louisiana.
This represents the Company's primary business.
2.Natural Gas Distribution - Engaged in the gathering, distribution
and transmission of natural gas to approximately 136,000 customers
in Arkansas.
3.Marketing and Transportation - Provides marketing and
transportation services in the Company's core areas of operation and
owns a 25% interest in the NOARK Pipeline System, Limited
Partnership (NOARK).
This Report on Form 10-K includes certain statements that may be deemed to
be "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Part II, Item 7 of this Report for a discussion of factors that
could cause actual results to differ materially from any such forward-looking
statements.
Business Strategy
The Company's business strategy is to provide long-term growth through
focused exploration and production of oil and natural gas. The Company seeks to
maximize cash flow and earnings and provide consistent growth in oil and gas
production and reserves through the discovery, production and marketing of high
margin reserves from a balanced portfolio of drilling opportunities. This
balanced portfolio includes low-risk development drilling in the Arkoma Basin
and East Texas, moderate-risk exploration and exploitation in the Permian Basin,
and high-potential exploration opportunities in the onshore Gulf Coast region.
The Company further enhances shareholder value by creating and capturing
additional value beyond the wellhead through its natural gas distribution,
marketing and transportation activities.
EXPLORATION AND PRODUCTION
In 1943, the Company commenced a program of exploration for and development
of natural gas reserves in Arkansas for supply to its utility customers. In
1971, the Company initiated an exploration and development program outside
Arkansas, unrelated to the utility's requirements. Since that time,
Southwestern's exploration and development activities outside Arkansas have
expanded substantially.
[map showing the states of Arkansas, Louisiana, Texas, Oklahoma and
New Mexico with the following areas identified: Arkoma Basin with the
Company's Gas distribution system and Ozark Pipeline, Anadarko Basin,
Permian Basin, East Texas Overton Field and Gulf Coast]
In 1998, Southwestern brought in new senior management for its exploration
and production business and has since replaced over 70% of its professional
technical staff to refocus its exploration and production effort. Additionally
in 1998, the Company closed its Oklahoma City office and moved these operations
to Houston in an effort to increase future profitability. The segment was also
reorganized into asset management teams to provide an area-specific focus in
exploration and
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development projects and a new incentive compensation system was put in place to
more closely align its employees' efforts with the interests of its
shareholders. As a result of these changes, the operating results of this
business segment have improved substantially over the last few years and, in
2001, the segment set new records for oil and gas production, reserve additions,
operating income and cash flow generated from operations.
At December 31, 2001, the Company had proved oil and gas reserves of 402.0
billion cubic feet (Bcf) equivalent, including proved natural gas reserves of
355.8 Bcf and proved oil reserves of 7,704 thousand barrels (MBbls). The
Company's reserve life index approximated 10.1 years at year-end 2001, with 80%
of total reserves classified as proved, developed. All of the Company's reserves
are located entirely within the United States. Revenues of the exploration and
production subsidiaries are predominately generated from production of natural
gas. Sales of gas production accounted for 89% of total operating revenues for
this segment in 2001, 82% in 2000, and 87% in 1999.
Areas of Operation
Southwestern engages in oil and gas exploration and production through its
wholly-owned subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production
Company (SEPCO) and Diamond "M" Production Company (Diamond M). SEECO operates
exclusively in the state of Arkansas and holds a large base of both developed
and undeveloped gas reserves and conducts an ongoing drilling program in the
historically productive Arkansas part of the Arkoma Basin. SEPCO conducts
development drilling and exploration programs in the Oklahoma portion of the
Arkoma Basin, the Permian Basin of Texas and New Mexico, the Anadarko Basin of
Oklahoma, and in Louisiana and Texas. Diamond M operates properties in the
Permian Basin of Texas. A wholly-owned subsidiary of SEPCO, Overton Partners,
L.L.C., owns an interest in Overton Partners, L.P., a limited partnership formed
in 2001 to drill and complete the first 14 development wells in SEPCO's Overton
Field in East Texas.
Southwestern replaced 224% of its production in 2001 by adding an estimated
89.3 Bcf equivalent (Bcfe) of proved oil and gas reserves at a finding and
development cost of $1.11 per thousand cubic feet equivalent (Mcfe), excluding
reserve revisions. The Company's finding cost including the effect of downward
reserve revisions due to lower year-end commodity prices was $1.60 per Mcfe in
2001. Southwestern's three-year average finding and development cost was $1.22
per Mcfe, including reserve revisions. The following table provides information
as of December 31, 2001 related to proved reserves, well count, and gross and
net acreage, and 2001 annual information as to production, reserve additions and
capital expenditures for each of the Company's core operating areas.
Texas/
Arkoma Mid-Continent New Mexico Louisiana Total
-------------------------------------------------------
Proved reserves:
Gas (Bcf) 186.0 28.1 106.9 34.8 355.8
Oil (MBbls) - 1,426 5,017 1,261 7,704
Total reserves (Bcfe) 186.0 36.6 137.0 42.4 402.0
Production (Bcfe) 22.3 2.8 9.9 4.8 39.8
Reserve additions (Bcfe) 23.2 8.6 43.2 14.3 89.3
Capital expenditures (in millions) $ 28.6 $ 0.9 $ 44.9 $ 24.6 $ 99.0
Total gross wells 806 551 445 32 1,834
Percent operated 44% 29% 39% 66% 39%
Gross acreage 348,143 62,168 377,863 150,992 939,166
Net acreage 237,511 6,629 114,740 87,526 446,406
Arkoma Basin. The Arkoma Basin provides a solid foundation for the
Company's exploration and production program and represents the primary source
of production and reserves for the Company. At December 31, 2001, the Company
had approximately 186.0 Bcf of natural gas reserves in the Arkoma Basin,
representing 52% of the Company's natural gas reserves and 46% of total reserves
on a Bcf equivalent basis. The Company participated in 52 wells during 2001 with
an 81% success ratio. Southwestern's Arkoma program added 23.2 Bcf of gas
reserves at a finding and development cost of $1.23 per thousand cubic feet
(Mcf) in 2001. The Company's natural gas production in the basin was 22.3 Bcf, a
12% increase over production levels in 2000. Until 2001, Southwestern had
experienced declining production in the Arkoma over the past eight years.
Average net daily production in 2001 was 61.1 million cubic feet (MMcf/d).
Southwestern's Arkoma Basin operations continue to generate a significant
amount of the Company's cash flow. With average three-year finding and
development costs of $1.05 per Mcf and three-year average production, or
lifting, costs of $.26 per Mcf (including production taxes), the Company's cash
margins per well in the Arkoma remain very attractive.
4
Lifting costs continued to be low during 2001 at $.32 per Mcf (including
production taxes). After direct general and administrative expenses of $.14 per
Mcf, Southwestern's netback per Mcf after cash expenses was 89% of the average
price it realized for its Arkoma production in 2001, including the impact of
commodity hedges.
Southwestern's traditional operating area over the years has been in the
"fairway" portion of the basin in Arkansas, which is primarily within the
boundaries of the Company's utility gathering system. The Company's strategy in
this core producing area is to delineate new geologic plays and extend
previously identified trends using Southwestern's extensive databank of regional
structural and stratigraphic maps. Southwestern completed 14 wells out of 18
drilled in the fairway in 2001 that added 8.3 Bcf of new reserves. Southwestern
plans to drill up to 15 wells in the fairway portion of the basin in 2002.
In recent years, Southwestern has extended its development program outside
of the traditional fairway area to continue its growth. During 2001, the Company
continued the development of its Haileyville prospect in Pittsburg County,
Oklahoma, with excellent results. Since initial drilling in the area in 1999,
Southwestern has successfully completed 13 out of 20 wells drilled. In 2001,
Southwestern encountered high-deliverability gas sands in the prospect which
resulted in two wells, the Agnes #1-18 and the Cope #3A, separately producing at
gross rates of over 20 MMcf/d. Total production at Haileyville was 3.0 Bcf net
to Southwestern in 2001 and the prospect added a net of approximately 5.0 Bcf of
new gas reserves from six wells. Southwestern's average working interest in the
prospect is approximately 35%.
In 2001, the Company also continued the development of its Ranger Anticline
prospect area, located at the southern edge of the Arkansas portion of the
basin. To date, the Company has successfully drilled 10 out of 14 wells in this
prospect, adding 12.4 Bcf of reserves net to Southwestern's interest at a
finding cost of $.69 per Mcf. In 2001, the Company drilled the Catlett #1-13
well which was placed on production at 2.2 MMcf/d with an 80% working interest,
resulting in new reserves of 2.7 Bcf. The Catlett #1-13 well is an example of
the continued successful development of this complex overthrust play. The
Company also plans to begin testing new exploration prospect areas on the
southern edge of the basin similar to its Ranger Anticline play.
Additionally, during 2001 the Company initiated an extensive workover
program in the Arkoma, which included fracture stimulations, artificial lift,
recompletion and wellbore repair projects that provided meaningful production
increases. The Company performed 55 of these workover projects in 2001 resulting
in production increases totaling 4.4 MMcf/d, at a total cost of $1.4 million.
The Company's strategy for the Arkoma is to continue its exploitation
drilling and workover programs at a level to maintain its production and reserve
base. In 2002, Southwestern plans to invest approximately $18.5 million in the
basin to drill approximately 40 wells and perform approximately 50 workovers.
Mid-Continent. Southwestern's activities in this region are primarily
focused on the Anadarko Basin of Oklahoma. At December 31, 2001, the Company had
approximately 28.1 Bcf of natural gas reserves and 1,426 MBbls of oil reserves
in the region, representing 8% and 19%, respectively, of the Company's total gas
and oil reserves. Average net daily production in 2001 for this region was 7.7
MMcf equivalent (MMcfe). Southwestern does not expect its Mid-Continent
operations to be a primary area of future growth due to its efforts to
concentrate on those areas where it has a competitive advantage. The Company
intends to produce these properties to depletion, sell them or trade them for
properties in the Company's core areas of operation. During 2000, the Company
sold at auction a portion of its properties in the Mid-Continent area with
proved reserves of 13.8 Bcfe for approximately $13.1 million.
Texas/New Mexico. Southwestern has key operations in the states of Texas
and New Mexico, and is primarily focused on its Overton Field in East Texas, and
the Permian Basin in West Texas and Southeast New Mexico. At December 31, 2001,
Southwestern had proved reserves of 106.9 Bcf of gas and 5,017 MBbls of oil in
the region, representing 30% and 65%, respectively, of the Company's total gas
and oil reserves.
Overton Field. In April 2000, the Company purchased the Overton Field in
Smith County, Texas, from Total Fina Elf for $6.1 million. Estimated initial
reserves associated with the purchase were 7.5 Bcfe, for a purchase price of
$.81 per Mcfe. The purchase included 16 active gas wells in 13 spacing units,
8,800 contiguous acres in established units and 2,000 additional undeveloped
acres outside the units. Overton provides the Company with a low-risk multi-year
drilling program and significant production and reserve growth potential. This
is due to the level of infill drilling that is possible in the field over the
next several years. When purchased by Southwestern in April of 2000, the field
was primarily drilled on 640-acre spacing, or one well per square mile.
Analogous Cotton Valley fields in the area have been drilled to 80-acre spacing.
By downspacing the field to 80-acre spacing, Southwestern could have an
additional 90 drilling locations.
During 2001, Southwestern's subsidiary, SEPCO, formed a limited
partnership, Overton Partners, L.P., with an investor to drill and complete the
first 14 development wells at Overton. This partnership was created to
accelerate the development of the field. SEPCO is the partnership's General
Partner and contributed 50% of the capital required to drill the first 14 wells.
5
In return, SEPCO receives 65% of the partnership's available cash distributions
prior to payout of the investor's initial investment and 85% of the
partnership's available cash distributions after payout. Production and reserve
statistics for Overton include 100% of the partnership's activity, and all
operating and financial results are incorporated into the Company's consolidated
financial statements.
Southwestern drilled a total of 15 wells at its Overton Field during 2001,
including 14 development wells in the Overton limited partnership. The wells
targeted the Cotton Valley Taylor sand formation at approximately 12,000 feet
and all 15 wells were successful. Daily production at Overton increased from 2
MMcfe in March of 2001 to approximately 16 MMcfe at year-end, resulting in
production of 2.3 Bcfe net to Southwestern during 2001. The Company's average
production cost at Overton was $.53 per Mcfe in 2001. Southwestern's proved
reserves at Overton increased to 57.6 Bcfe at year-end 2001, up from 22.0 Bcfe
at the end of 2000. The Company invested approximately $30.9 million in its
drilling program at Overton during 2001, including $13.5 million funded by the
owner of the minority interest in the Overton partnership. The capital
investments resulted in reserve additions of 37.8 Bcfe, for a finding and
development cost of $.82 per Mcfe. Southwestern's average working interest in
the field is 97% and average net revenue interest is 80%. Southwestern expanded
its position in the Overton area during 2001 through a farm-in of approximately
5,800 adjacent acres. The acreage contains nine 640-acre units, most of which
have only been drilled to 640-acre spacing. The Company has contracted to drill
a minimum of two wells on this acreage in 2002. In total, Southwestern plans to
invest approximately $12 million to drill 5 to 10 wells in the Overton Field
area during 2002.
Permian Basin. Since 1997, Southwestern has established a growing presence
in the Permian Basin. At December 31, 2001, Southwestern had proved reserves of
33.5 Bcf of gas and 4,251 MBbls of oil in the basin, or 59.0 Bcfe. The Company
successfully completed 19 out of 26 wells drilled in the Permian in 2001,
resulting in a success rate of 73%. Southwestern's average working interest in
these wells was approximately 43%. Average net daily equivalent production in
the basin was 17.0 MMcfe and production costs, including production taxes,
averaged $.67 per Mcfe during 2001. In 2001, the Company invested $13.6 million
in the Permian, resulting in reserve additions of 5.4 Bcfe for a finding and
development cost of $2.52 per Mcfe. Southwestern's three-year average finding
and development cost in the Permian is $1.33 per Mcfe and three-year average
reserve replacement ratio is 197%.
Southwestern had a meaningful discovery during 2001 at its Roepke prospect
in Crane County, Texas. The discovery well, the Cowden Ranch 48 #7, encountered
approximately 87 feet of oil-bearing pay in the Upper and Lower Devonian
formations. This well, along with two other successful wells on the prospect,
added net reserves of 3.3 Bcfe in 2001, and has set up additional development
wells planned for 2002.
In late 1999, the Company entered into a joint exploration agreement with
Phillips Petroleum to explore for deeper formations under acreage that is
held-by-production in Southeast New Mexico. This initial joint venture agreement
spawned the development of two more joint exploration agreements that were
consummated in late 2000, one with Energen Resources and a second agreement with
Phillips. In total, these agreements provide the Company access to an additional
98,700 gross acres to pursue drilling opportunities. Under the agreements,
Phillips and Energen have a deferred election at casing point, allowing them to
retain a pre-specified working interest share. These agreements have terms
ranging from 12 to 21 months, with continuous drilling options thereafter. To
date, the Company has successfully drilled 18 out of 21 wells under these joint
ventures and four wells are scheduled to be drilled under the agreements in
2002.
The Company plans to continue to pursue its strategy of medium-risk
exploration and exploitation in the Permian Basin, albeit at a slower pace.
Southwestern plans to invest approximately $8.0 million in the Permian in 2002,
which includes drilling up to 14 wells.
Louisiana. South Louisiana continues to be the main focus area of the
Company's exploration activities. At December 31, 2001, Southwestern had proved
reserves of 34.8 Bcf of gas and 1,261 MBbls of oil in the state, representing
11% of the Company's total reserves on a gas equivalent basis. Average net daily
production in this area was 13.2 MMcfe and production costs (including
production taxes) averaged $.58 per Mcfe during 2001. The Company invested $24.6
million in the area in 2001 and added 14.3 Bcfe of proved reserves for a finding
and development cost of $1.72 per Mcfe. Southwestern's three-year average
finding and development cost in Louisiana is $1.65 per Mcfe and its three-year
reserve replacement ratio is 484%.
Southwestern's exploration success continued in 2001 with three meaningful
discoveries in South Louisiana. Since the first exploration discovery at the
Company's Gloria prospect in December 1999, Southwestern has posted an
impressive track record in the area with six successful wells out of the last
nine drilled in South Louisiana.
In January 2001, Southwestern announced a discovery at its Malone prospect,
located five miles south of the Company's Gloria discovery in Assumption Parish.
The discovery well SL 16626 #1 encountered approximately 260 feet of gas pay in
five separate productive sands within the Miocene formation. After drilling the
initial discovery well, Southwestern immediately drilled an offset development
well on the prospect that reached total depth in February 2001. Both wells are
producing at a combined gross rate of 27.0 MMcf/d and 525 barrels of oil per day
(Bopd). Southwestern is the operator of the wells and holds a 33% working
interest and a 24.3% net revenue interest in the prospect.
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After drilling dry holes at its Whitehorse and Mahone prospects, the
Company made another gas discovery in its Eden 3-D project area. The Mire #1
well on the Company's Horeb prospect in Acadia Parish penetrated 50 feet of pay
in the Nonion Struma sand at approximately 12,100 feet. This well was placed on
production in November 2001 and is currently producing 12.6 MMcf/d and 160 Bopd.
Southwestern operates the Mire well with a 21.5% working interest and a 16.4%
net revenue interest.
In December 2001, the Company announced a discovery at its Crowne Prospect
located in Cameron Parish, Louisiana. The Miami Corporation #27-1 well
encountered 75 feet of pay in the targeted Planulina objective. The well was
placed on production in February 2002 at 10.0 MMcf/d and 35 Bopd. Southwestern
has spud a second well, the Miami Corporation #34-2, to further delineate and
develop the reservoir. Southwestern is the operator of these wells with a 40%
working interest and a 28.8% net revenue interest.
In February 2002, the Company announced that it had reached total depth on
the Raymond Egle #1, a development well on its North Grosbec discovery. After
overcoming significant mechanical problems during the drilling of this well, it
was placed on production at 20.0 MMcf/d and 800 Bopd. The discovery well, the
Brownell-Kidd #1, continues to deliver at high rates since being placed on
production in May 2000 and is currently producing at 15.0 MMcf/d and 550 Bopd.
These wells are operated by Petro-Hunt, L.L.C., and Southwestern holds a 25%
working interest and a 17.4% net revenue interest in the prospect.
The Company has an extensive inventory of 3-D seismic data covering over
1,470-square miles in Louisiana. From this extensive 3-D database, Southwestern
has internally generated an inventory of exploration prospects. The Company also
continues to gain exposure to additional 3-D seismic data for future drilling
opportunities, including a new 3-D shoot currently underway covering
approximately 140-square miles in a highly prospective region in St. Martin and
St. Mary Parishes. Southwestern is the operator of the new project with a 40%
working interest. The seismic data is expected to be delivered in the third
quarter of 2002. In 2002, the Company plans to invest approximately $22.7
million in the Gulf Coast region and drill up to eight exploration wells.
Acquisitions
In 2001, Southwestern purchased proved reserves of 4.5 Bcfe for $6.5
million, or $1.46 per Mcfe. Included were overriding royalty interests in the
Arkoma Basin of 2.2 Bcfe, and 1.9 Bcfe of additional working interest in the
Company's Overton Field.
In April 2000, the Company purchased the Overton Field in Smith County,
Texas, from Total Fina Elf for $6.1 million. Proved developed producing reserves
associated with the purchase were 7.5 Bcfe, for a purchase price of $.81 per
Mcfe. The purchase included 16 active gas wells in 13 spacing units, 8,800
contiguous acres in established units and 2,000 additional undeveloped acres
outside the units. As discussed previously, Southwestern believes the Overton
Field contains significant development potential.
In 1999, the Company purchased producing properties in the Permian Basin
with estimated proved reserves of 9.4 Bcf of gas and 576 MBbls of oil, or 12.9
Bcfe. The properties were purchased from Petro-Quest Exploration, a privately
held company headquartered in Midland, Texas, for $9.4 million. The Company did
not make any producing property acquisitions in 1998 or 1997. In 1996, the
Company acquired approximately 32.7 Bcf of gas and 6,350 MBbls of oil located in
Texas and Oklahoma for $45.8 million. The Company's current strategy is to
pursue selective acquisitions where it sees further potential and that
complement its existing operations.
Capital Spending
Southwestern invested a total of $99.0 million in its exploration and
production program during 2001, including $13.5 million funded by the owner of
the minority interest in the Overton partnership. Southwestern participated in
drilling 101 wells during 2001, of which 80 were successful, 19 were dry and two
were still in progress at year-end. The Company's investments were balanced
between its core areas of operations, with approximately $28.6 million invested
in the Arkoma Basin, $30.9 million at Overton Field in East Texas, $13.6 million
in the Permian Basin, and $24.6 million in South Louisiana. Approximately $20.6
million was invested in exploratory tests, $57.2 million in development drilling
and workovers, $4.2 million for the acquisition of leasehold and seismic data,
$6.5 million for producing property acquisitions and $10.5 million in
capitalized interest and expenses and other technology-related expenditures.
In 2002, the Company's planned capital budget for exploration and
production is $61.3 million, and a large percentage of this capital,
approximately 67%, is allocated to drilling. As in 2001, the Company's
investments will again be balanced between its core areas of operations, with
approximately 50% of the Company's capital allocated to lower-risk development
drilling activities in the Arkoma Basin ($18.5 million) and East Texas ($12.1
million). The remainder of Southwestern's capital will be allocated to
medium-risk exploration and exploitation in the Permian Basin ($8.0 million) and
to high-potential exploration in the Gulf Coast ($22.7 million). Of the $61.3
million capital budget, approximately $11.4 million is allocated to exploration
wells, $29.9 million to development drilling, $4.3 million for land and
leasehold acquisition, $3.9 million for
7
seismic expenditures, and $11.8 million in capitalized interest and expenses and
technology-related items. Although no capital was budgeted for acquisitions in
2002, the Company will continue to seek producing property transactions in its
core producing areas that would complement its overall strategy. The Company
expects to maintain its capital investments within the limits of internally
generated cash flow, and will adjust its capital program accordingly.
Sales and Major Customers
Daily natural gas equivalent production averaged 109.0 MMcfe in 2001,
compared to 97.7 MMcfe in 2000 and 90.2 MMcfe in 1999. The Company's gas
production was 35.5 Bcf in 2001, compared to 31.6 Bcf in 2000 and 29.4 Bcf in
1999. The Company also produced 719,000 barrels of oil in 2001, compared to
676,000 barrels of oil in 2000 and 578,000 barrels in 1999. Southwestern is
targeting its production in 2002 to be approximately 42 Bcfe.
The Company realized an average wellhead price of $3.85 per Mcf for its
natural gas production in 2001, compared to $2.88 per Mcf in 2000 and $2.21 per
Mcf in 1999. The Company's average oil price realized was $23.55 per barrel in
2001, compared to $22.99 per barrel in 2000 and $17.11 per barrel in 1999.
Southwestern's gas sales to unaffiliated purchasers were 30.4 Bcf in 2001,
compared to 23.8 Bcf in 2000 and 21.2 Bcf in 1999. All of the Company's oil
production is sold to unaffiliated purchasers. This gas and oil production is
sold under contracts which reflect current short-term prices and which are
subject to seasonal price swings. These combined gas and oil sales accounted for
83% of total exploration and production revenues in 2001, 76% in 2000 and 69% in
1999.
Southwestern's largest single customer for sales of its gas production is
the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas
Western). These sales are made by SEECO, Inc. (SEECO) primarily under contracts
obtained under a competitive bidding process. See "Natural Gas Distribution -
Gas Purchases and Supply" below for further discussion of these contracts. Sales
to Arkansas Western accounted for approximately 17% of total exploration and
production revenues in 2001, 24% in 2000 and 31% in 1999. SEECO's sales to
Arkansas Western were 5.1 Bcf in 2001, compared to 7.8 Bcf in 2000 and 8.2 Bcf
in 1999. The decrease in sales in 2001 was primarily caused by Arkansas
Western's reduced supply requirements due to warmer weather and the sale of the
utility's Missouri gas distribution properties in May 2000. Weather in 2001, as
measured in degree days, was 9% warmer than both normal and the prior year for
Arkansas Western's service territory. Weather was normal in 2000 and 21% colder
than 1999; however, sales to Arkansas Western decreased in 2000 due to the sale
of the utility's Missouri properties. SEECO's gas production provided
approximately 33% of the utility's requirements in 2001, 42% in 2000 and 41% in
1999. SEECO also owns an unregulated natural gas storage facility that has
historically been utilized to help meet its peak seasonal sales commitments. The
storage facility is connected to Arkansas Western's distribution system.
Future sales to Arkansas Western's gas distribution systems will be
dependent upon the Company's success in obtaining gas supply contracts with the
utility systems. In the future, the Company's subsidiaries will continue to bid
to obtain these gas supply contracts, although there is no assurance that it
will be successful. If successful, the Company cannot predict the amount of
premium that would be associated with the new contracts. Southwestern expects
future increases in its gas production to come primarily from sales to
unaffiliated purchasers. The Company is unable to predict changes in the market
demand and price for natural gas, including changes which may be induced by the
effects of weather on demand of both affiliated and unaffiliated customers for
the Company's production. Additionally, the Company holds a large amount of
undeveloped leasehold acreage and producing acreage, and has an inventory of
drilling leads, prospects and seismic data that will continue to be evaluated
and developed in the future. The Company's exploration programs have been
directed primarily toward natural gas in recent years.
The Company periodically enters into hedging activities with respect to a
portion of its projected crude oil and natural gas production through a variety
of financial arrangements intended to support oil and gas prices at targeted
levels and to minimize the impact of price fluctuations. The Company's policies
prohibit speculation with derivatives and limit swap agreements to
counterparties with appropriate credit standings. At December 31, 2001, the
Company had hedges in place on 32.3 Bcf of future gas production. Subsequent to
December 31, 2001 and prior to March 13, 2002, the Company hedged 4.0 Bcf of
2002 gas production under costless collars with floor prices ranging from $2.25
to $2.50 per Mcf and ceiling prices ranging from $3.00 to $3.75 per Mcf, and
entered into a collar on 4.0 Bcf of 2003 gas production with a $3.00 per Mcf
floor and a $4.75 per Mcf ceiling. Fixed price swaps on 2.5 Bcf of 2002 gas
production have a weighted average fixed price receipt of $2.61 per Mcf. The
Company also hedged 277,500 barrels of 2002 oil production at a fixed West Texas
Intermediate crude price of $20.07 per barrel. The Company currently has hedges
in place on approximately 65% of its targeted 2002 gas production and
approximately 40% of its 2002 targeted oil production. See Item 7A of this Form
10-K, "Quantitative and Qualitative Disclosures About Market Risk," for further
information regarding the Company's hedge position at December 31, 2001.
Disregarding the impact of hedges, the Company expects the average price it
receives for its gas production to be approximately $.05 to $.10 per Mcf lower
than average spot market prices, as market differentials that reduce the average
prices received are partially offset by demand charges it receives under the
contracts covering its intersegment sales
8
to Arkansas Western. Disregarding the impact of hedges, the Company expects the
average price it receives for its oil production to be approximately $1.00 per
barrel lower than average spot market prices, as market differentials reduce the
average prices received.
Competition
All phases of the gas and oil industry are highly competitive. Southwestern
competes in the acquisition of properties, the search for and development of
reserves, the production and sale of gas and oil and the securing of the labor
and equipment required to conduct operations. Southwestern's competitors include
major gas and oil companies, other independent gas and oil concerns and
individual producers and operators. Many of these competitors have financial and
other resources that substantially exceed those available to Southwestern. Gas
and oil producers also compete with other industries that supply energy and
fuel.
Competition in the state of Arkansas has increased in recent years, due
largely to the development of improved access to interstate pipelines. Due to
the Company's significant leasehold acreage position in Arkansas and its
long-time presence and reputation in this area, the Company believes it will
continue to be successful in acquiring new leases in Arkansas. While improved
intrastate and interstate pipeline transportation in Arkansas should increase
the Company's access to markets for its gas production, these markets will
generally be served by a number of other suppliers. Thus, the Company will
encounter competition that may affect both the price it receives and contract
terms it must offer. Outside Arkansas, the Company is less established and faces
competition from a larger number of other producers. The Company has in recent
years been successful in building its inventory of undeveloped leases and
obtaining participating interests in drilling prospects in Oklahoma, Texas, New
Mexico and Louisiana.
NATURAL GAS DISTRIBUTION
The Company's subsidiary, Arkansas Western Gas Company, operates integrated
natural gas distribution systems concentrated primarily in North Arkansas. The
Arkansas Public Service Commission (APSC) regulates the Company's utility rates
and operations. Arkansas Western serves approximately 136,000 customers and
obtains a substantial portion of the gas they consume through its Arkoma Basin
gathering facilities.
[map showing the state of Arkansas detailing the utility service areas
concentrated in the Northern portion of the state and the location of
the Ozark Gas Transmission system]
On May 31, 2000, the Company completed the sale of its Missouri gas
distribution assets for $32.0 million. The sale resulted in a pretax gain of
approximately $3.2 million and proceeds from the sale were used to pay down
debt. The gas distribution statistics discussed below include the results from
the Company's Missouri utility operations through May 2000.
In June 2000, Southwestern announced it would pursue the sale of its
utility operations in Arkansas to fund a $109.3 million judgment against the
Company (Hales judgment). The Company hired Morgan Stanley Dean Witter as its
investment advisor to manage the sale process and the Company received several
serious expressions of interest from bona fide parties. However, the Company did
not receive an offer that it believed reflected the true value of the utility
system. Southwestern plans to operate the Arkansas utility properties as a
continuing part of its business.
Gas Purchases and Supply
Arkansas Western purchases its system gas supply through a competitive
bidding process implemented in October 1998, and directly at the wellhead under
long-term contracts with flexible pricing provisions. Bid requests under the
bidding process included replacement of the gas supply and no-notice service
previously provided by a long-term gas supply contract between Arkansas Western
and SEECO. In the initial 1998 bid, SEECO, along with the Company's marketing
subsidiary, successfully bid on five of seven gas supply packages with prices
based on the Reliant East Index plus a demand
9
charge. Based on normal weather patterns, the volumes of gas projected to be
supplied under these contracts were approximately equal to the historical annual
volumes purchased under the expired long-term contract. However, under the new
contracts, SEECO supplied most of Arkansas Western's no-notice service and less
of its routine base requirements than it had under the previous contract. As a
result, during periods of warmer weather, lower total gas volumes would be
purchased by Arkansas Western than compared to periods of normal or colder
weather. All of the bid packages originally secured by the Company's
subsidiaries in 1998 have now expired. During the third quarter of 2001, SEECO
successfully bid on gas supply packages representing approximately half of the
requirements for Arkansas Western for 2002. SEECO was unsuccessful in bidding on
a no-notice gas supply package that it previously held that generated a
significant portion of the demand charges it received on affiliated sales.
Arkansas Western also purchases gas for its system supply from unaffiliated
suppliers accessed by interstate pipelines. These purchases are under firm
contracts with terms between one and two years. The rates charged by most
suppliers include demand components to ensure availability of gas supply and a
commodity component which is based on monthly indexed market prices. The
pipeline transportation rates include demand charges to reserve pipeline
capacity and commodity charges based on volumes transported. A portion of the
utility's gas purchases are under take-or-pay contracts. Currently, Arkansas
Western believes that it does not have a significant exposure to take-or-pay
liabilities resulting from these contracts and expects to be able to continue to
satisfactorily manage these contracts.
Arkansas Western has a regulated natural gas storage facility connected to
its distribution system in Northwest Arkansas that it utilizes to help meet its
peak seasonal demands. The utility also owns a liquefied natural gas facility
and contracts with an interstate pipeline for additional storage capacity to
serve its system in the northeastern part of the state. 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.
Arkansas Western has no restriction on adding new residential or commercial
customers and will supply new industrial customers that are compatible with the
scale of its facilities. Arkansas Western has never denied service to new
customers within its service area or experienced curtailments because of supply
constraints. Curtailment of large industrial customers occurs only infrequently
when extremely cold weather requires that system capacity be dedicated
exclusively to human needs customers.
The utility's rate schedules include purchased gas adjustment clauses
whereby the actual cost of purchased gas above or below the level included in
the base rates is permitted to be billed or is required to be credited to
customers. Each month, the difference between actual costs of purchased gas and
gas costs recovered from customers is deferred. The deferred differences are
billed or credited, as appropriate, to customers in subsequent months.
Markets and Customers
Arkansas Western continues to capitalize on the healthy economies and
sustained customer growth found in its Northwest Arkansas service territory. In
April 2001, the U.S. Census Bureau named Northwest Arkansas as the 6th fastest
growing community in the United States. The area population grew 47.5%, or 4.0%
annually, over the past ten years. As home to the largest public corporation in
the world, Wal-Mart Stores, Inc., the region has enjoyed significant growth due
to its presence in the area. Other corporations such as Tyson Foods and J.B.
Hunt Transportation have also contributed to the impressive development of this
region of the state. Approximately 85% of Arkansas Western's customers are
located in this growing region.
Arkansas Western provides natural gas to approximately 120,000 residential,
16,000 commercial, and 200 industrial customers, while also providing gas
transportation services to approximately 60 end-use and off-system customers.
Total gas throughput in 2001 was 27.1 Bcf, compared to 33.5 Bcf in 2000 and 36.4
Bcf in 1999. The decrease in 2001 resulted from the loss of throughput
associated with the sale of the utility's Missouri assets in May 2000 and warmer
weather. In 2000, the loss of throughput associated with the sale of the
Missouri assets was partially offset by colder weather. Off-system
transportation volumes were 3.1 Bcf in both 2001 and 2000 and 4.8 Bcf in 1999.
Residential and Commercial. Approximately 85% of the utility's revenues are
from residential and commercial markets. Residential and commercial customers
combined accounted for 54% of total gas throughput for the gas distribution
segment in 2001, compared to 55% in 2000 and 51% in 1999. Gas volumes sold to
residential customers were 8.4 Bcf in 2001, compared to 10.9 Bcf in 2000 and
10.8 Bcf in 1999. Gas sold to commercial customers totaled 6.1 in 2001 and 7.6
Bcf in 2000 and 1999. The decreases in gas volumes sold in 2001 were due to the
sale of the Company's Missouri utility properties and warmer weather. Weather
during 2001 was 9% warmer than both normal and the prior year as measured by
degree days.
The gas heating load is one of the most significant uses of natural gas and
is sensitive to outside temperatures. Sales, therefore, vary throughout the
year. Profits, however, have become less sensitive to fluctuations in
temperature recently as tariffs implemented in Arkansas contain a weather
normalization clause to lessen the impact of revenue increases and decreases
which might result from weather variations during the winter heating season.
10
Industrial and End-use Transportation. Deliveries to Arkansas Western's
industrial and transportation customers were 9.5 Bcf in 2001, 11.8 Bcf in 2000
and 13.1 Bcf in 1999. The decrease in deliveries in both 2001 and 2000 were
primarily due to the sale of the utility's Missouri properties. No industrial
customer accounts for more than 9% of Arkansas Western's total throughput.
Arkansas Western offers a transportation service that allows larger business
customers to obtain their own gas supplies directly from other suppliers. A
total of 54 customers are currently using the transportation service.
Competition
Arkansas Western has experienced a general trend in recent years toward
lower rates of usage among its customers, largely as a result of conservation
efforts that the Company encourages. Competition is increasingly being
experienced from alternative fuels, primarily electricity, fuel oil, and
propane. Arkansas Western has historically maintained a substantial price
advantage over these fuels for most applications. This has enabled the utility
to achieve excellent market penetration levels. However, the high gas prices
experienced in the 2000 - 2001 heating season temporarily eroded the price
advantage in some markets. Arkansas Western has now regained its price advantage
in substantially all markets as gas prices have declined. Arkansas Western also
has the ability through its approved tariffs to lower its rates to large
customers to be competitive with available alternative fuels or if the threat of
bypass exists.
Regulation
Arkansas Western's utility rates and operations are regulated by the APSC.
The Company operates through municipal franchises that are perpetual by state
law. These franchises, however, are not exclusive within a geographic area. As
the regulatory focus of the natural gas industry has shifted from the federal
level to the state level, some utilities across the nation have unbundled
residential sales services from transportation services in an effort to promote
greater competition. Although no such legislation or regulatory directives
related to natural gas are presently pending in Arkansas, Arkansas Western is
aggressively controlling costs and constantly reviewing issues such as system
capacity and reliability, obligation to serve, rate design and stranded or
transition costs.
In Arkansas, the state legislature enacted Act 1556 for the deregulation of
the retail sale of electricity by 2002. Act 1556 was modified by Act 324 of 2001
delaying the implementation of electric deregulation to not earlier than October
2003 and no later than October 2005. In December 2001, the APSC submitted its
annual report to legislature on the development of electric deregulation and
recommended that the legislature consider suspending deregulation to the year
2010 or 2012, or repeal Act 1556 (as modified by Act 324). It is unknown what
final legislation will be adopted or, if it is adopted, what its final form will
be. If electric deregulation occurs in Arkansas, legislative or regulatory
precedents may be set that would also affect natural gas utilities in the
future. These issues may include further unbundling of services and the
regulatory treatment of stranded costs.
Arkansas Western's most recent rate increase was approved in December 1996
for the utility's Northwest region and in December 1997 for its Northeast
region. The APSC approved annual rate increases of $5.1 million and $1.2
million, respectively. The December 1996 rate increase order issued by the APSC
also provided that Arkansas Western cause to be filed with the APSC an
independent study of its procedures for allocating costs between regulated and
non-regulated operations, its staffing levels and executive compensation. The
independent study was ordered by the APSC to address issues raised by the Office
of the Attorney General of the State of Arkansas. The study was conducted in
1999 with a final report issued in December 1999. The report found the Company's
costs to be reasonable in all categories.
In May 1999, the Staff of the APSC initiated a proceeding in which it
sought an annual reduction of approximately $2.3 million in the rates Arkansas
Western charges its customers in Northwest Arkansas. Staff's position was based
on various adjustments to the utility's rate base, operating expenses, capital
structure and rate of return. A large portion of the proposed reduction was
based on a downward adjustment to the utility's current return on equity
authorized by the APSC in 1996. During the third quarter of 1999, Arkansas
Western reached agreement with the Staff and the APSC to resolve this issue and
to close several other open dockets. In the settlement agreement, Arkansas
Western agreed to reduce its rates collected from customers on a prospective
basis in the amount of $1.4 million annually, effective December 1, 1999. The
agreement also includes the resolution of a proceeding initiated in December
1998 by the Staff of the APSC where the Staff had recommended the disallowance
of approximately $3.1 million of gas supply costs. As a part of the settlement,
this docket was closed with no negative adjustment to the Company.
In February 2001, the APSC approved a 90-day temporary tariff to collect
additional gas costs not yet billed to customers through the normal purchased
gas adjustment clause in the utility's approved tariffs. Arkansas Western had
under-recovered purchased gas costs of $12.9 million in its current assets at
December 31, 2000. The amount of under-recovered purchased gas costs increased
significantly during January 2001 as a result of rapidly increasing gas costs.
The temporary tariff allowed
11
the utility accelerated recovery of the gas costs it had incurred during the
2000 - 2001 winter heating season. At December 31, 2001, Arkansas Western had
over-recovered purchased gas costs of $8.2 million, which will be refunded to
its customers during 2002.
Gas distribution revenues in future years will be impacted by customer
growth and rate increases allowed by the APSC. In recent years, Arkansas Western
has experienced customer growth of approximately 2% to 3% annually in its
Northwest Arkansas service territory, while it has experienced little or no
growth in its service territory in Northeast Arkansas. Based on current economic
conditions in its service territories, the Company expects this trend in
customer growth to continue.
MARKETING AND TRANSPORTATION
Gas Marketing
Southwestern's gas marketing subsidiary, Southwestern Energy Services
Company, was formed in 1996 to better enable the Company to capture downstream
opportunities which arise through marketing and transportation activity. Through
utilization of Southwestern's existing asset base, its focus is to create and
capture value beyond the wellhead.
The Company's marketing operations include the marketing of Southwestern's
own gas production and third-party natural gas. Operating income for this
segment was $2.7 million in 2001, compared to $2.5 million in 2000 and $2.1
million in 1999. The segment marketed 49.6 Bcf of natural gas in 2001, compared
to 59.6 Bcf in 2000 and 63.1 Bcf in 1999. In late 2000, this segment began
marketing less third-party natural gas in an effort to reduce its potential
credit risk and concentrated more of its efforts on Southwestern's affiliated
production. Of the total volumes marketed, purchases from the Company's
exploration and production subsidiaries accounted for 66% in 2001, 33% in 2000
and 31% in 1999.
NOARK Partnership
At December 31, 2001, the Company held a 25% general partnership interest
in NOARK. The NOARK Pipeline was a 258-mile intrastate natural gas transmission
system that extended across northern Arkansas interconnecting with Arkansas
Western's gas distribution systems. NOARK Pipeline was completed and placed in
service in 1992 and has been operating below capacity and generating losses
since it was placed in service.
In January 1998, the Company entered into an agreement with Enogex Inc.
(Enogex), a subsidiary of OGE Energy Corp., to expand NOARK Pipeline and provide
access to Oklahoma gas supplies through an integration of NOARK Pipeline with
the Ozark Gas Transmission System (Ozark). Ozark was a 437-mile interstate
pipeline system that began in eastern Oklahoma and terminated in eastern
Arkansas. Enogex acquired Ozark and contributed the pipeline system to the NOARK
partnership. Enogex also acquired the NOARK partnership interests not held by
Southwestern. On July 1, 1998, the Federal Energy Regulatory Commission (FERC)
authorized the operation and integration of Ozark and NOARK Pipeline as a
single, integrated pipeline. Enogex funded the acquisition of Ozark and the
expansion and integration with NOARK Pipeline which resulted in Southwestern's
interest in the partnership decreasing from 48% to 25% with Enogex owning a 75%
interest. There are also provisions in the agreement with Enogex which allow for
future revenue allocations to the Company above its 25% partnership interest if
certain minimum throughput and revenue assumptions are not met.
The new integrated system, known as Ozark Pipeline, became operational
November 1, 1998, and includes 749 miles of pipeline with a total throughput
capacity of 330 MMcf/d. Deliveries are currently being made by the pipeline to
portions of Arkansas Western's distribution systems and to the interstate
pipelines with which it interconnects. The average daily throughput for the
pipeline was 134.1 MMcf/d in 2001, compared to 188.2 MMcf/d in 2000 and 167.5
MMcf/d in 1999. At December 31, 2001, Arkansas Western had transportation
contracts with Ozark Pipeline for 66.9 MMcf/d of firm capacity. These contracts
expire in 2002 and 2003 and are renewable annually thereafter until terminated
with 180 days' notice. The merged pipeline system now has greater access to
major gas producing fields in Oklahoma. With access to greater regional
production, Southwestern expects the pipeline's additional throughput to create
new marketing and transportation opportunities and reduce the losses as
experienced on the project in the past. The merged pipeline also provides the
Company's utility systems with additional access to gas supply. The Company's
share of the pretax loss from operations related to its NOARK investment was
$1.5 million in 2001, $1.8 million in 2000 and $2.0 million in 1999.
Competition
The Company's gas marketing activities are in competition with numerous
other companies offering the same services, many of which possess larger
financial and other resources than those of Southwestern. Some of these
competitors are affiliates of companies with extensive pipeline systems that are
used for transportation from producers to end-users. Other factors affecting
competition are cost and availability of alternative fuels, level of consumer
demand, and cost of and proximity to pipelines and other transportation
facilities. The Company believes that its ability to effectively compete within
the marketing segment in the future depends upon establishing and maintaining
strong relationships with producers and end-users.
12
NOARK Pipeline previously competed with two interstate pipelines, one of
which was the Ozark system, to obtain gas supplies for transportation to other
markets. Because of the available transportation capacity in the Arkansas
portion of the Arkoma Basin, competition had been strong and had resulted in
NOARK Pipeline transporting gas for third parties at rates below the maximum
tariffs presently allowed. The integration with Ozark provides increased
supplies to transport to both local markets and markets served by the three
major interstate pipelines that Ozark Pipeline connects with in eastern
Arkansas. The Company believes that Ozark Pipeline will provide the additional
supplies necessary to compete more effectively for the transportation of natural
gas to end-users and markets served by the interstate pipelines.
Regulation
Prior to the integration with Ozark, the operations of NOARK Pipeline were
regulated by the APSC. The APSC had established a maximum transportation rate of
approximately $.285 per dekatherm. The integration of NOARK Pipeline with Ozark
resulted in an interstate pipeline system subject to FERC regulations and FERC
approved tariffs. The FERC has set the maximum transportation rate of Ozark
Pipeline at $.2867 per dekatherm.
OTHER ITEMS
Environmental Matters
The Company's operations are subject to extensive federal, state and local
laws and regulations, including the Comprehensive Environmental Response,
Compensation and Liability Act, the Clean Water Act, the Clean Air Act and
similar state statutes. These laws and regulations require permits for drilling
wells and the maintenance of bonding requirements in order to drill or operate
wells and also regulate the spacing and location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandoning of wells, the prevention
and cleanup of pollutants and other matters.
Southwestern maintains insurance against costs of clean-up operations, but
is not fully insured against all such risks. Compliance with environmental laws
and regulations has had no material effect on Southwestern's capital
expenditures, earnings, or competitive position. Although future environmental
obligations are not expected to have a material impact on the results of
operations or financial condition of the Company, there can be no assurance that
future developments, such as increasingly stringent environmental laws or
enforcement thereof, will not cause the Company to incur material environmental
liabilities or costs.
Real Estate Development
Southwestern's wholly owned subsidiary, A. W. Realty Company (AWR), owns an
interest in approximately 150 acres of real estate, most of which is
undeveloped. AWR's real estate development activities are concentrated on a
130-acre tract of land located near the Company's offices 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 that would minimize the Company's
initial capital expenditures, but still enable it to retain an interest in any
appreciation in value. This activity, however, does not represent a significant
portion of the Company's business.
Employees
At December 31, 2001, Southwestern had 525 total employees, 31 of whom are
represented under a collective bargaining agreement. The Company believes that
its relations with its employees are good.
ITEM 2. PROPERTIES
For additional information about the Company's gas and oil operations,
refer to Notes 5 and 6 to the financial statements in Item 8 ("Financial
Statements and Supplementary Data"). For information concerning capital
expenditures, refer to page 41 ("Capital Expenditures" section of Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations"). Also refer to Item 6 ("Selected Financial Data") for information
concerning gas and oil produced.
13
The following table provides information concerning miles of pipe of the
Company's gas distribution systems. For a further description of Arkansas
Western's properties, see the discussion under Item 1 ("Business").
Total
------
Gathering 387
Transmission 984
Distribution 3,756
--------------------------------------------------------------------------------
5,127
================================================================================
The following information is provided to supplement that presented in Item
8. For a further description of Southwestern's oil and gas properties, see the
discussion under Item 1 ("Business").
Leasehold acreage
Undeveloped Developed
Gross Net Gross Net
---------------------------------------------------
Arkoma 126,453 76,051 221,690 161,460
Mid-Continent 6,038 2,884 56,130 3,745
Texas/New Mexico 205,948 78,166 171,915 36,574
Louisiana 107,642 78,161 43,350 9,365
--------------------------------------------------------------------------------
446,081 235,262 493,085 211,144
================================================================================
Producing wells
Gas Oil Total
Gross Net Gross Net Gross Net
--------------------------------------------------
Arkoma 806 402.0 - - 806 402.0
Mid-Continent 163 111.4 388 78.0 551 189.4
Texas/New Mexico 220 68.8 225 113.4 445 182.2
Louisiana 17 7.8 15 10.6 32 18.4
--------------------------------------------------------------------------------
1,206 590.0 628 202.0 1,834 792.0
================================================================================
Wells drilled during the year
Exploratory
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
---- -----------------------------------------------------
2001 13.0 6.5 8.0 3.8 21.0 10.3
2000 13.0 4.0 12.0 4.8 25.0 8.8
1999 4.0 1.5 4.0 1.6 8.0 3.1
Development
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
---- -----------------------------------------------------
2001 67.0 29.5 11.0 2.9 78.0 32.4
2000 65.0 21.9 14.0 6.3 79.0 28.2
1999 47.0 18.3 15.0 6.1 62.0 24.4
Wells in progress as of December 31, 2001
Gross Net
---------------
Exploratory - -
Development 2.0 0.9
--------------------------------------------------------------------------------
Total 2.0 0.9
================================================================================
In December 2001, the Company announced that the Miami Corporation #27-1
well at its Crowne prospect in Cameron Parish, Louisiana, encountered
approximately 75 feet of net pay in the targeted Planulina objective. In
February, the well was placed on production at a rate of 10.0 MMcf/d and 35
Bopd. Southwestern is currently drilling a second well in the prospect to
further delineate and develop the reservoir. Southwestern is the operator of
these wells with a 40% working interest.
14
During 2001, Southwestern was required to file Form 23, "Annual Survey of
Domestic Oil and Gas Reserves," with the Department of Energy. The basis for
reporting reserves on Form 23 is not comparable to the reserve data included in
Note 6 to the financial statements in the 2001 Annual Report to Shareholders.
The primary differences are that Form 23 reports gross reserves, including the
royalty owners' share, and includes reserves for only those properties where the
Company is the operator.
ITEM 3. LEGAL PROCEEDINGS
The Company recently settled litigation, subject to court approval, in a
case filed against the Company and two of its subsidiaries in a state court in
Sebastian County, Arkansas related to the Company's Stockton Gas Storage
Facility in Franklin County, Arkansas (the "Stockton Storage Facility"). As
previously disclosed, this class action suit was filed on August 25, 2000 on
behalf of a class of plaintiffs comprised of all surface owners, mineral owners,
royalty owners and overriding royalty owners in the Stockton Storage Facility.
The plaintiffs alleged various wrongful, intentional and fraudulent acts
relating to the operation of the storage pool beginning in 1968 and continuing
to the present and claimed ownership rights in the gas that the Company has
stored in the storage pool in an amount in excess of $5 million in actual
damages, interest, attorney's fees and punitive damages. Under the terms of the
settlement, the Company has agreed to pay the plaintiffs a cash settlement
amount and enter into new gas storage agreements at rental rates commensurate
with current market rates. The settlement of this litigation did not have a
material impact on the Company's results of operations for 2001.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a non-capital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial position or reported results of operations of
the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 2001, to a vote of security holders, through the solicitation
of proxies or otherwise.
Executive Officers of the Registrant
Years Served
Name Officer Position Age as Officer
--------------------------------------------------------------------------------
Harold M. Korell President and Chief Executive Officer 57 5
and Director
Greg D. Kerley Executive Vice President and 46 12
Chief Financial Officer
Richard F. Lane Executive Vice President, 44 3
Southwestern Energy Production Company
and SEECO, Inc.
Mark K. Boling Senior Vice President, General Counsel 44 -
and Secretary
Charles V. Stevens Senior Vice President, 52 13
Arkansas Western Gas Company
Mr. Korell has served as President since October 1998 and assumed the
position of Chief Executive Officer on January 1, 1999. He joined the Company in
1997 as Executive Vice President and Chief Operating Officer. From 1992 to 1997,
he was employed by American Exploration Company where he was most recently
Senior Vice President - Operations. From 1990 to 1992, he was Executive Vice
President of McCormick Resources and from 1973 to 1989, he held various
positions with Tenneco Oil Company, including Vice President, Production.
15
Mr. Kerley was appointed to his present position in December 1999.
Previously, he served as Senior Vice President and Chief Financial Officer from
1998 to 1999, Senior Vice President - Treasurer and Secretary from 1997 to 1998,
Vice President - Treasurer and Secretary from 1992 to 1997, and Controller from
1990 to 1992. Mr. Kerley also served as the Chief Accounting Officer from 1990
to 1998.
Mr. Lane was appointed to his present position in December 2001.
Previously, he served as Senior Vice President from February 2001 and Vice
President - Exploration from February 1999. Mr. Lane joined the Company in
February 1998 as Manager - Exploration. From 1993 to 1998, he was employed by
American Exploration Company where he was most recently Offshore Exploration
Manager. Previously, he held various managerial and geological positions at
FINA, Inc. and Tenneco Oil Company.
Mr. Boling joined the Company in his present position in January 2002.
Prior to joining the Company, Mr. Boling had a private law practice in Houston
specializing in the oil and gas industry since 1993. Previously, Mr. Boling was
a partner with Fulbright and Jaworski L.L.P. where he was employed from 1982 to
1993.
Mr. Stevens has served the Company in his present position since December
1997. Previously, he served as Vice President of Arkansas Western Gas Company
from 1988 to 1997.
All officers are elected at the Annual Meeting of the Board of Directors
for one-year terms or until their successors are duly elected. There are no
arrangements between any officer and any other person pursuant to which he was
selected as an officer. There is no family relationship between any of the named
executive officers or between any of them and the Company's directors.
16
Part II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is traded on the New York Stock Exchange under
the symbol "SWN." At December 31, 2001, the Company had 2,124 shareholders of
record. The following prices represent closing market transactions on the New
York Stock Exchange.
Range of Market Prices Cash Dividends Paid
Quarter Ended 2001 2000 2001 2000
-------------------------------------------------
March 31 $11.20 $ 8.76 $ 7.44 $5.44 - $.06
June 30 $16.35 $ 8.77 $10.38 $6.06 - $.06
September 30 $13.50 $10.45 $10.00 $6.13 - -
December 31 $13.05 $ 9.51 $10.44 $7.25 - -
On June 22, 2000, the Arkansas Supreme Court affirmed a $109.3 million
judgment against the Company from a class action lawsuit brought by royalty
owners. As a result of the judgment, the Company suspended its quarterly
dividend. Dividends totaling $3.0 million were paid during 2000.
17
ITEM 6. SELECTED FINANCIAL DATA
2001 2000 1999 1998 1997 1996
------------------------------------------------------------------------------------------------------------------
Financial Review (in thousands)
Operating revenues
Exploration and production $ 153,937 $ 110,920 $ 75,039 $ 86,232 $ 100,129 $ 86,978
Gas distribution 147,282 151,234 132,420 134,711 154,155 142,730
Gas marketing and other 190,773 208,196 137,942 97,795 83,511 30,636
Intersegment revenues (147,065) (106,467) (65,005) (52,433) (61,606) (57,004)
-------------------------------------------------------------------------------------------------------------------
344,927 363,883 280,396 266,305 276,189 203,340
-------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 68,161 58,669 45,370 39,863 46,806 42,851
Gas purchases - marketing 68,010 133,221 92,851 73,235 63,054 14,114
Operating and general 64,108 59,790 57,957 61,915 59,167 50,509
Unusual items - 111,288 - - - -
Depreciation, depletion and amortization 52,899 45,869 41,603 46,917 48,208 42,394
Write-down of oil and gas properties - - - 66,383 - -
Taxes, other than income taxes 9,080 8,515 6,557 6,943 7,018 5,476
-------------------------------------------------------------------------------------------------------------------
262,258 417,352 244,338 295,256 224,253 155,344
-------------------------------------------------------------------------------------------------------------------
Operating income (loss) 82,669 (53,469) 36,058 (28,951) 51,936 47,996
Interest expense, net (23,699) (23,230) (17,351) (17,186) (16,414) (13,044)
Other income (expense) (799) 1,997 (2,331) (3,956) (5,017) (4,015)
Minority interest in partnership (930) - - - - -
-------------------------------------------------------------------------------------------------------------------
Income (loss) before income taxes and
extraordinary item 57,241 (74,702) 16,376 (50,093) 30,505 30,937
-------------------------------------------------------------------------------------------------------------------
Income taxes
Current - - 537 (6,029) (732) (5,569)
Deferred 21,917 (28,905) 5,912 (13,467) 12,522 17,320
-------------------------------------------------------------------------------------------------------------------
21,917 (28,905) 6,449 (19,496) 11,790 11,751
-------------------------------------------------------------------------------------------------------------------
Income (loss) before extraordinary item 35,324 (45,797) 9,927 (30,597) 18,715 19,186
Extraordinary item - (890) - - - -
-------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 35,324 $ (46,687) $ 9,927 $ (30,597) $ 18,715 $ 19,186
-------------------------------------------------------------------------------------------------------------------
Cash flow from operations, net of working
capital changes (in thousands) $ 144,583 $ (53,203)(1)$ 58,131 $ 93,708 $ 79,483 $ 71,830
Return on equity 19.3% n/a 5.21% n/a 8.45% 9.23%
-------------------------------------------------------------------------------------------------------------------
Common Stock Statistics
Basic earnings (loss) per share $ 1.40 $ (1.86) $ .40 $ (1.23) $ .76 $ .78
Diluted earnings (loss) per share $ 1.38 $ (1.86) $ .40 $ (1.23) $ .76 $ .78
Cash dividends declared and paid per share - $ .12 $ .24 $ .24 $ .24 $ .24
Book value per share $ 7.19 $ 5.61 $ 7.60 $ 7.45 $ 8.92 $ 8.41
Market price at year-end $ 10.40 $ 10.38 $ 6.56 $ 7.50 -$ 12.88 $ 15.13
Number of shareholders of record at year-end 2,124 2,192 2,268 2,333 - 2,379 2,572
Average diluted shares outstanding 25,601,110 25,043,586 24,947,021 24,882,170 24,777,906 24,788,587
-------------------------------------------------------------------------------------------------------------------
(1) Cash flow from operations, net of working capital changes, for 2000 would
have been $58.1 million excluding the effects of unusual and extraordinary
items.
18
2001 2000 1999 1998 1997 1996
----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands)
Total debt, including current portion $ 350,000 $ 396,000 $ 302,200 $ 283,436 $ 299,543 $ 278,285
Common shareholders' equity 183,086 141,291 190,356 185,856 221,565 207,941
----------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 533,086 $ 537,291 $ 492,556 $ 469,292 $ 521,108 $ 486,226
----------------------------------------------------------------------------------------------------------------------------
Total assets $ 743,123 $ 705,378 $ 671,446 $ 647,620 $ 710,866 $ 660,190
----------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt 65.7% 73.70% 61.35% 60.27% 57.23% 56.96%
Equity 34.3% 26.30% 38.65% 39.73% 42.77% 43.04%
----------------------------------------------------------------------------------------------------------------------------
Capital Expenditures (in millions)
Exploration and production $ 99.0 $ 69.2 $ 59.0 $ 52.4 $ 73.5 $ 110.3
Gas distribution 5.3 6.0 7.1 10.1 12.6 12.8
Other 1.8 .5 .9 1.9 2.7 1.8
----------------------------------------------------------------------------------------------------------------------------
$ 106.1 $ 75.7 $ 67.0 $ 64.4 $ 88.8 $ 124.9
----------------------------------------------------------------------------------------------------------------------------
Exploration and Production
Natural gas:
Production, Bcf 35.5 31.6 29.4 32.7 33.4 34.8
Average price per Mcf $ 3.85 $ 2.88 $ 2.21 $ 2.34 $ 2.57 $ 2.26
Oil:
Production, MBbls 719 676 578 703 749 391
Average price per barrel $ 23.55 $ 22.99 $ 17.11 $ 13.60 $ 19.02 $ 21.21
Total gas and oil production, Bcfe 39.8 35.7 32.9 36.9 37.9 37.1
Average production (lifting) cost per Mcf equivalent $ .62 $ .55 $ .44 $ .43 $ .45 $ .29
Proved reserves at year-end:
Natural gas, Bcf 355.8 331.8 307.5 303.7 291.4 297.5
Oil, MBbls 7,704 8,130 7,859 6,850 7,852 8,238
Total reserves, Bcfe 402.0 380.6 354.7 344.8 338.5 346.9
----------------------------------------------------------------------------------------------------------------------------
Gas Distribution(1)
Sales and transportation volumes, Bcf:
Residential 8.4 10.9 10.8 11.1 12.6 13.4
Commercial 6.1 7.6 7.6 7.6 8.4 8.8
Industrial 2.5 3.5 3.5 4.2 6.6 7.7
End-use transportation 7.0 8.3 9.6 8.8 6.6 5.5
----------------------------------------------------------------------------------------------------------------------------
24.0 30.3 31.5 31.7 34.2 35.4
Off-system transportation 3.1 3.1 4.8 1.1 2.8 3.6
----------------------------------------------------------------------------------------------------------------------------
27.1 33.4 36.3 32.8 37.0 39.0
----------------------------------------------------------------------------------------------------------------------------
Customers at year-end:
Residential 119,856 119,024 158,606 156,384 154,864 151,880
Commercial 16,177 16,282 21,929 22,229 21,431 20,845
Industrial 209 228 290 303 311 326
----------------------------------------------------------------------------------------------------------------------------
136,242 135,534 180,825 178,916 176,606 173,051
----------------------------------------------------------------------------------------------------------------------------
Degree days 3,654 3,994 3,179 3,472 4,131 4,341
Percent of normal 91% 100% 79% 87% 103% 108%
----------------------------------------------------------------------------------------------------------------------------
(1) Gas distribution statistics include the operations of the Company's Missouri
properties through the sale date of May 31, 2000.
19
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the financial statements and the notes thereto included
in Item 8 of this report and with the discussion below on "Forward-Looking
Information."
RESULTS OF OPERATIONS
Southwestern reported record net income of $35.3 million in 2001, or $1.38
per share on a fully diluted basis, compared to a net loss of $46.7 million in
2000, or $1.86 per share, and net income of $9.9 million in 1999, or $.40 per
share. The loss for 2000 includes one-time charges for unusual items, including
a $109.3 million judgment in the Hales lawsuit and $2.0 million for other
litigation, an extraordinary loss on the early retirement of debt, and a $3.2
million gain from the sale of the Company's Missouri utility properties.
Exclusive of these one-time charges and the gain on sale, net income for 2000
would have been $20.5 million, or $.82 per share.
Results for both 2001 and 2000 (excluding unusual items) reflect growth in
oil and gas production volumes and higher oil and gas prices realized. Results
for 1999 were negatively impacted by lower wellhead prices for the Company's oil
and gas production and by unseasonably warm weather.
Exploration and Production
The Company's exploration and production segment's revenue, profitability
and future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, which are dependent upon numerous factors beyond its
control, such as economic, political and regulatory developments and competition
from other sources of energy. The energy markets have historically been very
volatile, and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future.
2001 2000 1999
-----------------------------------
Revenues (in thousands) $ 153,937 $ 110,920 $ 75,039
Operating income (loss) (in thousands) $ 69,340 $ (70,584)(1) $ 16,451
Gas production (Bcf) 35.5 31.6 29.4
Oil production (MBbls) 719 676 578
Total production (Bcfe) 39.8 35.7 32.9
Average gas price per Mcf $ 3.85 $ 2.88 $ 2.21
Average oil price per Bbl $ 23.55 $ 22.99 $ 17.11
Operating expenses per Mcfe
Production expenses $ 0.45 $ 0.40 $ 0.35
Production taxes $ 0.17 $ 0.15 $ 0.09
General & administrative expenses $ 0.34 $ 0.32 $ 0.30
Full cost pool amortization $ 1.14 $ 1.06 $ 1.00
(1) Includes a charge of $109.3 million for the Hales judgment and a charge of
$2.0 million related to other litigation. Excluding these unusual items,
operating income for the exploration and production segment would have been
$40.7 million for 2000.
Revenues and Operating Income
The Company's exploration and production revenues increased 39% in 2001 and
48% in 2000. The increases were due to increases in production and higher
average prices received.
Operating income of the exploration and production segment was $69.3
million in 2001 compared to $40.7 million in 2000, excluding the impact of the
Hales judgment and the other unusual items, and $16.5 million in 1999. The
increase in 2001 was due to an 11% increase in equivalent oil and gas production
and higher oil and gas prices realized, partially offset by increased operating
costs and expenses. The increase in 2000 was due to an 8% increase in equivalent
oil and gas production and higher oil and gas prices realized, partially offset
by increased operating costs and expenses.
Production and Sales
Gas and oil production totaled 39.8 billion cubic feet equivalent (Bcfe) in
2001, 35.7 Bcfe in 2000 and 32.9 Bcfe in 1999. The increase in 2001 production
volumes resulted from the Company's continued exploration and development of its
South Louisiana properties, the development of its Overton Field in East Texas
and increased production in the Arkoma Basin.
20
The increase in 2000 production volumes resulted from new wells added in
2000 and 1999 in the Company's Permian Basin and South Louisiana operating
areas, partially offset by the loss of production from certain wells in the
Company's Mid-Continent operating area that were sold at auction during 2000.
Gas sales to unaffiliated purchasers were 30.4 Bcf in 2001, up from 23.8
Bcf in 2000 and 21.2 Bcf in 1999. Sales to unaffiliated purchasers are primarily
made under contracts which reflect current short-term prices and which are
subject to seasonal price swings. Intersegment sales to the Company's utility
subsidiary, Arkansas Western Gas Company (Arkansas Western) were 5.1 Bcf in
2001, 7.8 Bcf in 2000 and 8.2 Bcf in 1999. See "Gas Distribution - Operating
Costs and Expenses" below for further discussion of the utility's gas purchases.
The decrease in sales in 2001 was caused by Arkansas Western's reduced supply
requirements due to warmer weather and the sale of the utility's Missouri gas
distribution properties in May 2000. Weather in 2001, as measured in degree
days, was 9% warmer than both normal and the prior year in Arkansas Western's
service territory. Weather was normal in 2000 and 21% colder than 1999; however,
sales to Arkansas Western decreased in 2000 due to the sale of the utility's
Missouri properties. The Company's gas production provided approximately 33% of
the utility's requirements in 2001, 42% in 2000 and 41% in 1999.
Future sales to Arkansas Western's gas distribution systems will be
dependent upon the Company's success in obtaining gas supply contracts with the
utility systems. In the future, the Company will continue to bid to obtain these
gas supply contracts, although there is no assurance that it will be successful.
If successful, the Company cannot predict the amount of premium that would be
associated with the new contracts. The Company expects future increases in its
gas production to come primarily from sales to unaffiliated purchasers. The
Company is unable to predict changes in the market demand and price for natural
gas, including changes which may be induced by the effects of weather on demand
of both affiliated and unaffiliated customers for the Company's production.
Additionally, the Company holds a large amount of undeveloped leasehold acreage
and producing acreage, and has an inventory of drilling leads, prospects and
seismic data that will continue to be evaluated and developed in the future. The
Company's exploration programs have been directed primarily toward natural gas
in recent years.
Commodity Prices
The average price realized for the Company's gas production was $3.85 per
Mcf in 2001, $2.88 per Mcf in 2000, and $2.21 per Mcf in 1999. The changes in
the average price realized primarily reflects changes in average annual spot
market prices and the effects of the Company's price hedging activities. The
Company's hedging activities lowered the average gas price $.31 per Mcf in 2001,
$1.04 per Mcf in 2000, and $.06 per Mcf in 1999. Additionally, the Company has
historically received monthly demand charges related to sales made to its
utility segment which has increased the Company's average gas price realized.
The Company periodically enters into hedging activities with respect to a
portion of its projected crude oil and natural gas production through a variety
of financial arrangements intended to support oil and gas prices at targeted
levels and to minimize the impact of price fluctuations (see Item 7A of this
Form 10-K and Note 8 of the financial statements for additional discussion). The
Company's policies prohibit speculation with derivatives and limit swap
agreements to counterparties with appropriate credit standings. At December 31,
2001, the Company had hedges in place on 33.0 Bcf of gas. Subsequent to December
31, 2001 and prior to March 13, 2002, the Company hedged an additional 10.5 Bcf
of future gas production. There were no hedges in place at December 31, 2001 on
the Company's future oil production. Subsequent to December 31, 2001 and prior
to March 13, 2002, the Company hedged 277,500 barrels of its 2002 oil
production. The Company currently has hedged approximately 65% of its 2002
anticipated gas production level and 40% of its anticipated oil production
level.
Disregarding the impact of hedges, the Company expects the average price it
receives for its gas production to be approximately $.05 to $.10 per Mcf lower
than average spot market prices, as market differentials that reduce the average
prices received are partially offset by demand charges it receives under the
contracts covering its intersegment sales to the Company's utility systems.
Future changes in revenues from sales of the Company's gas production will be
dependent upon changes in the market price for gas, access to new markets,
maintenance of existing markets, and additions of new gas reserves.
The Company realized an average price of $23.55 per barrel for its oil
production for the year ended December 31, 2001, up from $22.99 per barrel for
2000 and $17.11 per barrel for 1999. The Company's hedging activities lowered
the average oil price $.03 per barrel in 2001 and $6.39 per barrel in 2000.
Hedges had no impact on the average realized oil price in 1999. Disregarding the
impact of hedges, the Company expects the average price it receives for its oil
production to be approximately $1.00 per barrel lower than average spot market
prices, as market differentials reduce the average prices received.
Operating Costs and Expenses
Production expenses per Mcfe for this business segment were $.45 in 2001,
compared to $.40 in 2000 and $.35 in 1999. Production taxes per Mcfe were $.17
in 2001, compared to $.15 in 2000 and $.09 in 1999. The increase in unit
production
21
expenses in 2001 was due to increased workover expenses and an industry-wide
increase in costs related to normal production activities. The increase in unit
production expenses in 2000 was due primarily to an increase in workover
expenses. The increases in 2001 and 2000 production taxes per Mcfe were due to
increased severance and ad valorem taxes that resulted from higher commodity
prices. General and administrative expenses per Mcfe were $.34 in 2001, compared
to $.32 in 2000 and $.30 in 1999. The increase in general and administrative
costs per Mcfe in 2001 was due primarily to increased legal costs related to the
resolution of litigation. The increase in general and administrative costs in
2000 as compared to 1999 resulted primarily from increases in incentive
compensation pay that is dependent upon the operating results for this segment.
The Company's full cost pool amortization rate averaged $1.14 per Mcfe for
2001, compared to $1.06 in 2000 and $1.00 in 1999. The rate increased in 2001 as
compared to 2000 due primarily to negative revisions of proved reserves that
resulted from a decline in average gas prices and to a $6.6 million decline in
the balance of unevaluated costs excluded from amortization in the full cost
pool. The average rate increased in 2000 due primarily to a $9.9 million decline
in the balance of unevaluated costs excluded from amortization.
The Company utilizes the full cost method of accounting for costs related
to its oil and natural gas properties. Under this method, all such costs
(productive and nonproductive) are capitalized and amortized on an aggregate
basis over the estimated lives of the properties using the units-of-production
method. These capitalized costs are subject to a ceiling test, however, which
limits such pooled costs to the aggregate of the present value of future net
revenues attributable to proved gas and oil reserves discounted at 10 percent
(standardized measure) plus the lower of cost or market value of unproved
properties. Any costs in excess of this ceiling are written off as a non-cash
expense. The expense may not be reversed in future periods, even though higher
oil and gas prices may subsequently increase the ceiling. Full cost companies
must use the prices in effect at the end of each accounting quarter to calculate
the ceiling value of its reserves. At December 31, 2001, 2000 and 1999, the
Company's unamortized costs of oil and gas properties did not exceed this
ceiling amount. At December 31, 2001, the Company's standardized measure was
calculated based upon quoted market prices of $2.65 per Mcf for gas and $19.84
per barrel for oil, adjusted for market differentials. A decline in oil and gas
prices from year-end 2001 levels or other factors, without other mitigating
circumstances, could cause a future write-down of capitalized costs and a
non-cash charge against future earnings.
In 2001, the Company's subsidiary, Southwestern Energy Production Company
(SEPCO), formed a limited partnership with an investor to drill and complete the
first 14 development wells in SEPCO's Overton Field located in Smith County,
Texas. This partnership was created to provide capital necessary to accelerate
the field's development. The Overton properties were acquired by SEPCO in April
2000 and have multiple development locations through the downspacing of the
existing producing units. Because SEPCO is the sole general partner and owns a
majority interest in the partnership, operating and financial results for the
partnership are consolidated with the other operations of the Company and the
investor's share of the partnership activity is reported as a minority interest
item in the financial statements. During 2001, the minority interest owner in
the partnership contributed $13.5 million in capital to the limited partnership
and received distributions of $1.5 million. The investor's share of 2001
revenues, less operating costs and expenses, was $.9 million.
Inflation impacts the Company by generally increasing its operating costs
and the costs of its capital additions. The effects of inflation on the
Company's operations prior to 2000 have been minimal due to low inflation rates.
However, during both 2001 and 2000, the impact of inflation intensified in
certain areas of the Company's exploration and production segment as shortages
in drilling rigs, third-party services and qualified labor developed due to an
overall increase in the activity level of the domestic oil and gas industry. The
Company anticipates that this impact is now decreasing along with the current
level of commodity prices.
Gas Distribution
The operating results of the Company's gas distribution segment are highly
seasonal. The extent and duration of heating weather also impacts the
profitability of this segment, although the Company has a weather normalization
clause that lessens the impact of revenue increases and decreases which might
result from weather variations during the winter heating season. The gas
distribution segment's profitability is also dependent upon the timing and
amount of regulatory rate increases that are filed with and approved by the
Arkansas Public Service Commission (APSC). For periods subsequent to allowed
rate increases, the Company's profitability is impacted by its ability to manage
and control this segment's operating costs and expenses.
On May 31, 2000, the Company completed the sale of its Missouri gas
distribution assets for $32.0 million. The sale resulted in a pretax gain of
approximately $3.2 million and proceeds from the sale were used to pay down
debt. As a result of the adverse Hales judgment, the Company's Board of
Directors authorized management to pursue the sale of the Company's remaining
gas distribution operations. The sale process did not result in an acceptable
bid and the Company currently plans to operate these assets as a continuing part
of its business.
22
2001 2000 1999
-----------------------------------------
($ in thousands except for Mcf amounts)
Revenues $ 147,282 $ 151,234 $ 132,420
Gas purchases $ 96,058 $ 93,992 $ 68,876
Operating costs and expenses $ 40,878 $ 42,587 $ 46,357
Operating income $ 10,346 $ 14,655 $ 17,187
Deliveries (Bcf)
Sales and end-use transportation 24.0 30.4 31.6
Off-system transportation 3.1 3.1 4.8
Average number of customers 134,041 152,773 177,328
Average sales rate per Mcf $ 8.26 $ 6.55 $ 5.67
Heating weather - degree days 3,654 3,994 3,179
Percent of normal 91% 100% 79%
Note: Data for 2000 and 1999 includes the operations of the Company's Missouri
properties through the sale date of May 31, 2000. Excluding the Missouri
operations, operating income would have been $12.6 million in 2000 and $14.6
million in 1999.
Revenues and Operating Income
Gas distribution revenues fluctuate due to the pass-through of gas supply
cost changes and the effects of weather. Because of the corresponding changes in
purchased gas costs, the revenue effect of the pass-through of gas cost changes
has not materially affected net income.
Gas distribution revenues decreased 3% in 2001 and increased 14% in 2000.
The decrease in 2001 was due to the loss of revenues resulting from the sale of
the utility's Missouri assets and the effects of warmer weather, partially
offset by a higher unit sales rate caused by high gas prices. The increase in
2000 was due to a higher sales rate and increased sales volumes caused by colder
weather, partially offset by the loss of revenues resulting from the sale of the
utility's Missouri assets in May 2000. Weather during 2001 in the utility's
service territory was 9% warmer than both normal and the prior year. Weather in
2000 was normal and 21% colder than the prior year.
Operating income for Southwestern's utility systems decreased 29% in 2001
and 15% in 2000. The decrease in 2001 resulted from the full-year impact of the
sale of the utility's Missouri assets, the effects of warmer weather that were
not fully offset by the Company's weather normalization clause in its tariffs
and increased bad debt expense caused by record high natural gas prices
experienced in the first part of 2001. The decrease in 2000 resulted from the
sale of the Missouri assets and a $1.4 million annual rate reduction that was
implemented in December 1999.
Deliveries and Rates
In 2001, Arkansas Western sold 17.0 Bcf to its customers at an average rate
of $8.26 per Mcf, compared to 22.1 Bcf at $6.55 per Mcf in 2000 and 21.9 Bcf at
$5.67 per Mcf in 1999. Additionally, Arkansas Western transported 7.0 Bcf in
2001, 8.3 Bcf in 2000 and 9.6 Bcf in 1999 for its end-use customers. The
decrease in volumes sold and transported in 2001 resulted from the sale of the
utility's Missouri properties and warmer weather. The decrease in the combined
volumes sold and transported in 2000 resulted from the sale of the Missouri
properties, partially offset by increased deliveries due to colder weather. The
fluctuations in the average sales rates reflect changes in the average cost of
gas purchased for delivery to the Company's customers, which are passed through
to customers under automatic adjustment clauses.
Total deliveries to industrial customers of the utility segment, including
transportation volumes, were 9.5 Bcf in 2001, 11.8 Bcf in 2000 and 13.1 Bcf in
1999. The decline in deliveries in 2001 resulted from warmer heating weather and
the sale of the utility's Missouri assets. In 2000, the decline resulted from
the sale of the Missouri assets. Arkansas Western also transported 3.1 Bcf of
gas through its gathering system in both 2001 and 2000 for off-system
deliveries, all to the Ozark Gas Transmission System, compared to 4.8 Bcf in
1999. The level of off-system deliveries each year generally reflects the
changes of on-system demands of the Company's gas distribution systems for the
Company's gas production. The average off-system transportation rate was
approximately $.13 per Mcf, exclusive of fuel, in 2001 and $.10 per Mcf in 2000
and 1999.
Gas distribution revenues in future years will be impacted by the utility's
gas purchase costs, customer growth and rate increases allowed by the APSC. In
recent years, Arkansas Western has experienced customer growth of approximately
2% to 3% annually in its Northwest Arkansas service territory, while it has
experienced little or no customer growth in its service
23
territory in Northeast Arkansas. Based on current economic conditions in the
Company's service territories, the Company expects this trend in customer growth
to continue.
Tariffs implemented in Arkansas as a result of rate increases in both 1996
and 1997 contain a weather normalization clause to lessen the impact of revenue
increases and decreases which might result from weather variations during the
winter heating season. Rate increase requests, which may be filed in the future,
will depend on customer growth, increases in operating expenses, and additional
investment in property, plant and equipment. See "Regulatory Matters" below for
additional discussion.
Operating Costs and Expenses
The changes in purchased gas costs for the gas distribution segment reflect
volumes purchased, prices paid for supplies, the mix of purchases from
intercompany versus third-party sources and the sale of Missouri assets as
discussed above. Other operating costs and expenses of the gas distribution
segment decreased in both 2001 and 2000 due primarily to the sale of the
utility's Missouri assets. Operating costs in 2001 included increased bad debt
expense caused by high natural gas prices.
In October 1998, Arkansas Western instituted a competitive bidding process
for its gas supply. These bid requests included replacement of the gas supply
and no-notice service previously provided by a long-term gas supply contract
between Arkansas Western and one of the Company's exploration and production
subsidiaries, SEECO, Inc. (SEECO). In the initial 1998 bid, SEECO, along with
the Company's marketing subsidiary, successfully bid on five of seven gas supply
packages with prices based on the Reliant East Index plus a demand charge. Based
on normal weather patterns, the volumes of gas projected to be supplied under
these contracts were approximately equal to the historical annual volumes sold
under the expired long-term contract. However, under the new contracts, SEECO
supplied most of Arkansas Western's no-notice service and less of its routine
base requirements than it had under the previous contract. As a result, during
periods of warmer weather, lower total gas volumes would be purchased by
Arkansas Western than compared to periods of normal or colder weather. All of
the bid packages originally secured by the Company's subsidiaries in 1998 have
now expired. During the third quarter of 2001, SEECO successfully bid on gas
supply packages representing approximately half of the requirements for Arkansas
Western for 2002. SEECO was unsuccessful in bidding on a no-notice gas supply
package that it previously held that generated a significant portion of the
demand charges it received on affiliated sales. Other purchases by Arkansas
Western are made under long-term contracts with flexible pricing provisions.
Inflation impacts the Company's gas distribution segment by generally
increasing its operating costs and the costs of its capital additions. The
effects of inflation on the utility's operations in recent years have been
minimal due to low inflation rates. Additionally, delays inherent in the
rate-making process prevent the Company from obtaining immediate recovery of
increased operating costs of its gas distribution segment.
Regulatory Matters
Arkansas Western's rates and operations are regulated by the APSC. It
operates through municipal franchises that are perpetual by state law, but are
not exclusive within a geographic area. Although its rates for gas delivered to
its retail customers are not regulated by the Federal Energy Regulatory
Commission (FERC), its transmission and gathering pipeline systems are subject
to the FERC's regulations concerning open access transportation. As the
regulatory focus of the natural gas industry has shifted from the federal level
to the state level, some utilities across the nation have unbundled residential
sales services from transportation services in an effort to promote greater
competition. No such legislation or regulatory directives related to natural gas
are presently pending in Arkansas.
In Arkansas, the state legislature enacted Act 1556 for the deregulation of
the retail sale of electricity by 2002. Act 1556 was modified by Act 324 of 2001
delaying the implementation of electric deregulation to not earlier than October
2003 and no later than October 2005. In December 2001, the APSC submitted its
annual report to the Arkansas legislature on the development of electric
deregulation and recommended that the legislature consider suspending
deregulation to the year 2010 or 2012, or repeal Act 1556 (as modified by Act
324). It is unknown what final legislation will be adopted or, if it is adopted,
what its final form will be. If electric deregulation occurs in Arkansas,
legislative or regulatory precedents may be set that would also affect natural
gas utilities in the future. These issues may include further unbundling of
services and the regulatory treatment of stranded costs.
Arkansas Western has historically maintained a substantial price advantage
over electricity for most applications. This has enabled the utility to achieve
excellent market penetration levels. However, during 2001 the high gas prices
experienced in the 2000 - 2001 heating season temporarily eroded the price
advantage. Arkansas Western has now regained its price advantage in
substantially all markets as gas prices have declined.
Arkansas Western's most recent rate increase was approved in December 1996
for the utility's Northwest region and in December 1997 for the Northeast
region. The APSC approved increases of $5.1 million and $1.2 million,
respectively. During 1999, the APSC initiated a proceeding in which it sought a
$2.3 million reduction in the rates for the Northwest region.
24
In late 1999, the APSC and Arkansas Western reached a settlement in which
the Northwest region's rates were reduced by $1.4 million. The reduction was
primarily due to a downward adjustment to the return on equity that the APSC had
established in the 1996 rate case. While Arkansas Western continues to
experience customer growth and has aggressively controlled its costs, its return
on investment has declined in recent years. The Company anticipates that it will
seek rate relief to improve Arkansas Western's profitability by filing a rate
increase application with the APSC during 2002.
In February 2001, the APSC approved a 90-day temporary tariff to collect
additional gas costs not yet billed to customers through the utility's normal
purchased gas adjustment clause in its approved tariffs. The Company had
under-recovered purchased gas costs of $12.9 million in current assets at
December 31, 2000. The level of under-recovered costs had increased
significantly during January 2001 as a result of rapidly increasing gas costs.
The temporary tariff allowed the utility accelerated recovery of the gas costs
it had incurred during the 2000 - 2001 winter heating season.
In June 2001, the APSC established a set of policy principles for gas
procurement for utilities. The APSC intends for these policy principles to guide
utilities in their gas purchasing decisions. Utilities are required to take all
reasonable and prudent steps necessary to develop a diversified gas supply
portfolio. The portfolio should consist of an appropriate combination of
different types of gas purchase contracts and/or financial hedging instruments
that are designed to yield the optimum balance of reliability, reduced
volatility and reasonable price. Utilities will be required to submit on an
annual basis their gas supply plan, along with their contracting and/or hedging
objectives, to the APSC's General Staff for review and determination as to
whether it is consistent with these policy principles. If the plan includes a
hedging strategy and it is determined to be consistent with the objectives of
the policy principles, utilities will be allowed to flow any hedging gain or
loss to customers through the purchased gas adjustment clause. During 2001,
Arkansas Western submitted to the General Staff its annual gas supply plan for
the 2001 - 2002 heating season and a revision to its purchased gas adjustment
clause for the recovery of hedging gains and losses. Arkansas Western's gas
supply plan and the revision to its purchased gas adjustment clause were both
approved by the APSC.
Arkansas Western also purchases gas from unaffiliated producers under
take-or-pay contracts. The Company believes that it does not have a significant
exposure to liabilities resulting from these contracts and expects to be able to
continue to satisfactorily manage its exposure to take-or-pay liabilities.
In connection with the sale of its Missouri utility operations in 2000, the
Company retained responsibility for five unresolved cases pertaining to the
Missouri Public Service Commission's (MPSC) annual review of Arkansas Western's
gas cost purchasing practices and gas cost recovery. In November 2001, the MPSC
approved a stipulation and agreement that settled all five cases. The settlement
did not have a material effect on the Company's results of operations.
Marketing and Other
Marketing
2001 2000 1999
-------------------------------
Revenues (in millions) $ 190.3 $ 207.7 $ 137.5
Operating income (in millions) $2.7 $2.5 $2.1
Gas volumes marketed (Bcf) 49.6 59.6 63.1
Operating income for the marketing segment was $2.7 million on revenues of
$190.3 million in 2001, compared to $2.5 million on revenues of $207.7 million
in 2000, and $2.1 million on revenues of $137.5 million in 1999. The Company
marketed 49.6 Bcf in 2001, compared to 59.6 Bcf in 2000 and 63.1 Bcf in 1999.
The decline in total volumes marketed in 2001 reflects the Company's increased
focus on marketing its own production and limiting the marketing of third-party
volumes in an effort to reduce its credit risk. Of the total volumes marketed,
purchases from the Company's exploration and production subsidiaries accounted
for 66% in 2001, 33% in 2000 and 31% in 1999. The Company enters into hedging
activities with respect to its gas marketing activities to provide margin
protection (see Item 7A of this Form 10-K and Note 8 of the financial statements
for additional discussion).
NOARK Partnership
The marketing segment also manages the Company's 25% interest in the NOARK
Pipeline System, Limited Partnership (NOARK). The NOARK Pipeline was a 258-mile
intrastate gas transmission system that extended across northern Arkansas
interconnecting with the Company's distribution systems. The NOARK Pipeline had
been operating below capacity and generating losses since it was placed in
service in September 1992.
In January 1998, the Company entered into an agreement with Enogex Inc.
(Enogex), a subsidiary of OGE Energy Corp., to expand the NOARK system and
provide access to Oklahoma gas supplies through an integration of NOARK with the
Ozark Gas Transmission System (Ozark). Ozark was a 437-mile interstate pipeline
system which began in eastern Oklahoma
25
and terminated in eastern Arkansas. Effective August 1, 1998, Enogex acquired
Ozark and contributed the pipeline system to the NOARK partnership. Enogex also
acquired the NOARK partnership interests not held by Southwestern. Enogex funded
the acquisition of Ozark and the expansion and integration with NOARK, which
resulted in Southwestern's interest in the partnership decreasing to 25% (from
48%) with Enogex owning a 75% interest. There are also provisions in the
agreement with Enogex which allow for future revenue allocations to the Company
above its 25% partnership interest if certain minimum throughput and revenue
assumptions are not met.
Ozark Pipeline, the new integrated system, became operational November 1,
1998, and includes 749 miles of pipeline with a total throughput capacity of 330
million cubic feet of gas per day (MMcf/d). Deliveries are currently being made
by the integrated pipeline to portions of Arkansas Western's distribution
systems, and to the interstate pipelines with which it interconnects. Ozark
Pipeline had an average daily throughput of 134.1 MMcf/d in 2001, 188.2 MMcf/d
in 2000 and 167.5 MMcf/d in 1999. In 1998, NOARK had an average daily throughput
of 27.3 MMcf/d before the integration with Ozark. As a result of a rate case
filed in 2000, Ozark Pipeline's maximum transportation rate increased from
$.2455 per dekatherm to $.2867 per dekatherm effective November 1, 2000. At
December 31, 2001, the Company's gas distribution subsidiary has transportation
contracts with Ozark Pipeline for 66.9 MMcf/d of firm capacity. These contracts
expire in 2002 and 2003 and are renewable annually thereafter until terminated
with 180 days' notice.
The Company's share of the pretax loss from operations included in other
income related to its NOARK investment was $1.5 million in 2001, $1.8 million in
2000, and $2.0 million in 1999. The improvements since 1999 result primarily
from the ability to collect higher transportation rates on interruptible
volumes. The Company believes that it will be able to continue to reduce the
losses it has experienced on the NOARK project and expects its investment in
NOARK to be realized over the life of the system (see Note 7 of the financial
statements for additional discussion).
As further explained in Note 11 of the financial statements, the Company
has severally guaranteed the debt service on a portion of NOARK's outstanding
debt. The outstanding balance was $73.0 million at December 31, 2001, and the
Company's share of the guarantee relates to $43.8 million of that amount. This
debt financed a portion of the original cost to construct the NOARK Pipeline.
Other Income, Costs and Expenses
Interest costs, net of capitalization, were up 2% in 2001 and 34% in 2000,
both as compared to prior years. A decrease in interest costs in 2001 that
resulted from lower average borrowings and a lower average interest rate was
slightly more than offset by a lower level of capitalized interest related to
the Company's oil and gas properties. The increase in 2000 was caused primarily
by higher average borrowings that resulted from payment of the Hales judgment
and a lower level of capitalized interest. Interest capitalized decreased 35% in
2001 and 26% in 2000. The reductions in capitalized interest are primarily due
to decreases in the level of costs excluded from amortization in the Company's
exploration and production segment.
Other income (expense) in 2001 resulted from the Company's share of NOARK's
operating loss, as discussed above, offset by interest income in the gas
distribution segment related to under-recovered gas purchase costs. The increase
in other income in 2000 resulted from the $3.2 million gain on the sale of the
Company's Missouri gas distribution assets and gains from the sale of other
miscellaneous assets. Other income (expense) in 1999 related primarily to the
Company's share of NOARK's operating loss and certain costs incurred related to
a judgment bond that the Company was required to post after receiving the
initial adverse verdict in the Hales case.
The Hales judgment was the primary cause for the Company's deferred tax
benefit of $28.9 million in 2000. Excluding the impact of this change in
deferred income taxes, the changes in the provisions for current and deferred
income taxes recorded each year result primarily from the level of taxable
income, the collection of under-recovered purchased gas costs, abandoned
property costs, and the deduction of intangible drilling costs in the year
incurred for tax purposes, netted against the turnaround of intangible drilling
costs deducted for tax purposes in prior years. Intangible drilling costs are
capitalized and amortized over future years for financial reporting purposes
under the full cost method of accounting.
LIQUIDITY AND CAPITAL RESOURCES
The Company depends on internally-generated funds and its revolving line of
credit discussed under Financing Requirements as its major sources of liquidity.
Net cash provided by operating activities was $144.6 million in 2001, compared
to cash used in operating activities of $53.2 million in 2000 and cash provided
by operating activities of $58.1 million in 1999. The net cash used in operating
activities in 2000 was a result of the Hales judgment and the impact of high
year-end gas prices on working capital. The primary components of cash generated
from operations are net income, depreciation, depletion and amortization, the
provision for deferred income taxes and changes in current assets and current
liabilities. Net cash from operating activities provided over 100% of the
Company's capital requirements for routine capital expenditures, cash dividends,
and scheduled debt retirements in 2001 and 89% in 1999.
26
The Company's cash flow from operating activities is highly dependent upon
market prices that the Company receives for its gas and oil production. The
price that the Company receives for its production is also influenced by the
Company's commodity hedging activities, as more fully discussed in Item 7A of
this Form 10-K and Note 8 to the financial statements. Natural gas and oil
prices are subject to wide fluctuations and have declined significantly in the
first quarter of 2002 as compared to prices received during 2001. The Company
expects 2002 cash flow from operating activities to decline from the 2001 level
although it is unable to predict with any degree of accuracy the impact of the
decline.
Capital Expenditures
Capital expenditures totaled $106.1 million in 2001, $75.7 million in 2000,
and $67.0 million in 1999. The Company's exploration and production segment
expenditures included acquisitions of interests in oil and gas producing
properties totaling $5.8 million in 2001, $6.7 million in 2000 and $9.4 million
in 1999. The Company's reported capital investments in 2001 include the gross
expenditures in the Overton Field partnership discussed previously. The owner of
the minority interest in the Overton partnership funded $13.5 million of the
Company's exploration and development expenditures during 2001.
2001 2000 1999
-------------------------------
(in thousands)
Exploration and production $ 98,964 $ 69,211 $ 59,004
Gas distribution 5,347 5,994 7,124
Other 1,749 512 839
--------------------------------------------------------------------------------
$ 106,060 $ 75,717 $ 66,967
--------------------------------------------------------------------------------
Capital investments planned for 2002 total approximately $68.0 million,
consisting of $61.3 million for exploration and production, $5.7 million for gas
distribution system improvements and $1.0 million for general purposes. The
Company expects that its level of capital investments will be adequate to allow
the Company to maintain its present markets, explore and develop its existing
gas and oil properties as well as generate new drilling prospects, and finance
improvements necessary due to normal customer growth in its gas distribution
segment. The Company may adjust its level of future capital investments
dependent upon the level of cash flow generated from operations.
Financing Requirements
Southwestern's total debt outstanding was $350.0 million at December 31,
2001. This compares to total debt of $396.0 million at December 31, 2000,
including $171.0 million under a short-term credit facility. In 2001, the
Company's strong cash flow from operations allowed it to fund its capital
program and pay down $46 million of debt. In July 2001, the Company arranged a
new unsecured revolving credit facility with a group of banks to replace its
existing short-term credit facility that was put in place in July 2000. The new
revolving credit facility has a current capacity of $155 million and expires in
July 2004. The capacity of the revolving credit facility decreases to $140
million in June 2002 and to $125 million in June 2003. The interest rate on the
new facility is calculated based upon the debt rating of the Company. The
Company is currently paying 137.5 basis points over the London Interbank Offered
Rate (LIBOR). The new credit facility contains covenants which impose certain
restrictions on the Company. Under the credit agreement, the Company may not
issue total debt in excess of 70% of its total capital, must maintain a certain
level of shareholders' equity, and must maintain a ratio of earnings before
interest, taxes, depreciation and amortization (EBITDA) to interest expense at
or above a stated ratio. The ratio of EBITDA to interest expense in effect
through December 31, 2002 is 3.75. These covenants change over the term of the
credit facility and generally become more restrictive. The Company was in
compliance with its debt agreements at December 31, 2001. The Company has also
entered into interest rate swaps for calendar year 2002 that allow the Company
to pay a fixed average interest rate of 4.8% (based upon current rates under the
revolving credit facility) on $100 million of its outstanding revolving debt.
In July 2000, the Company replaced its then existing revolving credit
facilities that had previously provided the Company access to $80.0 million of
variable rate capital with a new credit facility that had a capacity of $180.0
million. This facility was used to fund the Hales judgment of $109.3 million,
pay off the existing revolver balance and retire $22.0 million of private
placement debt. The credit facility was also used to fund normal working capital
needs. The interest rate on the facility was 112.5 basis points over the LIBOR
rate and was 7.85% at December 31, 2000. The credit facility had a term of 364
days and expired in July 2001.
In August 2000, the Company retired $22.0 million of 9.36% private
placement notes. Certain costs of the redemption were expensed and are
classified as an extraordinary loss, net of related income tax effects.
27
In 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes due
2027 and $40.0 million of 7.21% Medium-Term Notes due 2017. These notes were
issued under a supplement to the Company's $250.0 million shelf registration
statement filed with the Securities and Exchange Commission in February 1997,
for the issuance of up to $125.0 million of Medium-Term Notes. The Company has
$25.0 million of capacity remaining under the shelf registration statement. The
Company also has $125.0 million of 6.7% Notes due in 2005 that were issued under
the shelf registration. The Company's public notes are rated BBB by Standard and
Poor's and Baa3 by Moody's.
If the Company were unable to comply with any of the covenants of its
various debt agreements, a waiver would have to be requested to avoid a default
under the agreements. Further, the Company's public debt could be downgraded by
the rating agencies which could increase the cost of funds under its revolving
credit facility.
In June 1998, the NOARK partnership issued $80.0 million of 7.15% Notes due
2018. The notes require semi-annual principal payments of $1.0 million that
began in December 1998. The Company accounts for its investment in NOARK under
the equity method of accounting and does not consolidate the results of NOARK.
The Company and the other general partner of NOARK have severally guaranteed the
principal and interest payments on the NOARK debt. The Company's share of the
several guarantee is 60% and amounted to $43.8 million at December 31, 2001. The
Company advanced $1.4 million to NOARK to fund its share of debt service
payments in 2001 and advanced $3.3 million in 2000. If NOARK is unable to
generate sufficient cash in the future to service its debt and the Company is
required to continue contributing cash to fund its debt service guarantee, the
Company could be required to record its share of the NOARK debt commitment under
current accounting rules.
At the end of 2001, the Company's capital structure consisted of 65.7% debt
(excluding the Company's several guarantee of NOARK's obligations) and 34.3%
equity, with a ratio of EBITDA to interest expense of 5.69. As part of its
strategy to insure cash flow to fund its operations and meet the restrictive
covenant tests under its debt agreements, the Company has hedged approximately
65% of its expected 2002 gas production and 40% of its expected 2002 oil
production. The Company does not expect to reduce its long-term debt materially
in 2002, assuming commodity prices remain at or near current levels and the
Company's capital investment plans do not change from current expectations.
Working Capital
The Company maintains access to funds that may be needed to meet seasonal
requirements through its credit facility explained above. The Company had
positive working capital of $21.7 million at the end of 2001, compared to net
negative working capital of $127.0 million at the end of 2000 caused by the
short-term revolving credit facility balance of $171.0 million. Current assets
decreased by 17% in 2001, while current liabilities (without consideration of
short-term debt) increased 4%. The decrease in current assets and the slight
increase in current liabilities at December 31, 2001, was due primarily to
decreases in accounts receivable, accounts payable and under-recovered purchased
gas costs that resulted from extremely high market prices for natural gas at
year-end 2000, offset by increases in gas stored underground, over-recovered
purchased gas costs, and current assets and liabilities recorded for derivatives
at December 31, 2001. At December 31, 2001, Southwestern had over-recovered
purchased gas costs of $8.2 million, which will be refunded to its customers
during 2002.
FORWARD-LOOKING INFORMATION
All statements, other than historical financial information, may be deemed
to be forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Although the Company believes the expectations
expressed in such forward-looking statements are based on reasonable
assumptions, such statements are not guarantees of future performance and actual
results or developments may differ materially from those in the forward-looking
statements. Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include, but are
not limited to, the timing and extent of changes in commodity prices for gas and
oil, the timing and extent of the Company's success in discovering, developing,
producing, and estimating reserves, property acquisition or divestiture
activities that may occur, the effects of weather and regulation on the
Company's gas distribution segment, increased competition, legal and economic
factors, governmental regulation, the financial impact of accounting regulations
for derivative instruments, changing market conditions, the comparative cost of
alternative fuels, conditions in capital markets and changes in interest rates,
availability of oil field services, drilling rigs and other equipment, as well
as various other factors beyond the Company's control.
28
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Market risks relating to the Company's operations result primarily from the
volatility in commodity prices, basis differentials and interest rates, as well
as credit risk concentrations. The Company uses natural gas and crude oil swap
agreements and options and interest rate swaps to reduce the volatility of
earnings and cash flow due to fluctuations in the prices of natural gas and oil
and in interest rates. The Board of Directors has approved risk management
policies and procedures to utilize financial products for the reduction of
defined commodity price and interest rate risks. These policies prohibit
speculation with derivatives and limit swap agreements to counterparties with
appropriate credit standings.
Credit Risks
The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of trade receivables and derivative contracts
associated with commodities trading. Concentrations of credit risk with respect
to receivables are limited due to the large number of customers and their
dispersion across geographic areas. No single customer accounts for greater than
3% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
Interest Rate Risk
The following table provides information on the Company's financial
instruments that are sensitive to changes in interest rates. The table presents
the Company's debt obligations, principal cash flows and related
weighted-average interest rates by expected maturity dates. Variable average
interest rates reflect the rates in effect at December 31, 2001 for borrowings
under the Company's credit facility. The Company's policy is to manage interest
rates through use of a combination of fixed and floating rate debt. Interest
rate swaps may be used to adjust interest rate exposures when appropriate. The
Company has entered into interest rate swaps for the calendar year 2002 that
allow the Company to pay a fixed average interest rate of 4.8% (based upon
current rates under the revolving credit facility) on $100 million of its
outstanding revolving debt.
Expected Maturity Date Fair Value
-------------------------------------------------------------------------------
2002 2003 2004 2005 2006 Thereafter Total 12/31/01
-------------------------------------------------------------------------------
($ in millions)
Fixed Rate - - - $ 125.0 - $ 100.0 $ 225.0 $ 231.2
Average Interest Rate - - - 6.70% - 7.46% 7.04%
Variable Rate - - $ 125.0 - - - $ 125.0 $ 125.0
Average Interest Rate - - 5.47% - - - 5.47%
Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production, to hedge activity in its
marketing segment, and to hedge the purchase of gas in its utility segment
against the inherent price risks of adverse price fluctuations or locational
pricing differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps and options include (1) transactions in
which one party will pay a fixed price (or variable price) for a notional
quantity in exchange for receiving a variable price (or fixed price) based on a
published index (referred to as price swaps), (2) transactions in which parties
agree to pay a price based on two different indices (referred to as basis
swaps), and (3) the purchase and sale of index-related puts and calls (collars)
that provide a "floor" price below which the counterparty pays (production
hedge) or receives (gas purchase hedge) funds equal to the amount by which the
price of the commodity is below the contracted floor, and a "ceiling" price
above which the Company pays to (production hedge) or receives from (gas
purchase hedge) the counterparty the amount by which the price of the commodity
is above the contracted ceiling.
The primary market risks related to the Company's derivative contracts are
the volatility in market prices and basis differentials for natural gas and
crude oil. However, the market price risk is offset by the gain or loss
recognized upon the related sale or purchase of the natural gas or sale of the
oil that is hedged. Credit risk relates to the risk of loss as a result of
non-performance by the Company's counterparties. The counterparties are
primarily major investment and commercial banks which management believes
present minimal credit risks. The credit quality of each counterparty and the
level of financial exposure the Company has to each counterparty are
periodically reviewed to ensure limited credit risk exposure.
The following table provides information about the Company's financial
instruments that are sensitive to changes in commodity prices. The table
presents the notional amount in Bcf (billion cubic feet) and MBbls (thousand
barrels), the weighted average contract prices, and the total dollar contract
amount by expected maturity dates. The "Carrying Amount"
29
for the contract amounts is calculated as the contractual payments for the
quantity of gas or oil to be exchanged under futures contracts and does not
represent amounts recorded in the Company's financial statements. The "Fair
Value" represents values for the same contracts using comparable market prices
at December 31, 2001. At December 31, 2001, the "Fair Value" exceeded the
"Carrying Amount" of these financial instruments by $4.2 million.
Expected Maturity Date
2002 2003
--------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------------------------------------
PRODUCTION AND MARKETING
Natural Gas
Swaps with a fixed-price receipt
Contract volume (Bcf) 13.4 9.2
Weighted average price per Mcf $ 2.88 $ 3.18
Contract amount (in millions) $ 38.6 $ 40.2 $ 29.3 $ 29.3
Swaps with a fixed-price payment
Contract volume (Bcf) .3 -
Weighted average price per Mcf $ 2.96 -
Contract amount (in millions) $ .7 $ .6 - -
Price collars
Contract volume (Bcf) 6.0 4.1
Weighted average floor price per Mcf $ 4.00 $ 3.00
Contract amount of floor (in millions) $ 24.0 $ 32.2 $ 12.3 $ 14.2
Weighted average ceiling price per Mcf $ 4.72 $ 4.65
Contract amount of ceiling (in millions) $ 28.3 $ 27.8 $ 19.0 $ 17.9
NATURAL GAS PURCHASES
Swaps with a fixed-price payment
Contract volume (Bcf) 3.3 -
Weighted average price per Mcf $ 4.20 -
Contract amount (in millions) $ 13.9 $ 8.1 - -
At December 31, 2001, the Company had a single financial instrument that is
sensitive to changes in interest rates. This $50 million notional interest rate
swap has a fixed rate of 4.33%. Its carrying amount of $2.2 million is
calculated as the contractual payments for interest on the notional amount to be
exchanged under futures contracts and does not represent amounts recorded in the
Company's financial statements. The fair value of $1.2 million represents the
value for the same contract using comparable market prices at December 31, 2001.
At December 31, 2001, the "Carrying Amount" exceeded the "Fair Value" of this
interest rate swap by $1.0 million. Subsequent to December 31, 2001, the Company
entered into additional interest rate swaps totaling $50 million that have an
average fixed rate of 2.58%.
Subsequent to December 31, 2001 and prior to March 13, 2002, the Company
entered into additional derivative contracts to hedge gas and oil production
sales and utility gas purchases. Price collar hedges on 4.0 Bcf of 2002 gas
production sales have floor prices ranging from $2.25 to $2.50 per Mcf and
ceiling prices ranging from $3.00 to $3.75 per Mcf and a collar on 4.0 Bcf of
2003 gas production has a $3.00 per Mcf floor and a $4.75 per Mcf ceiling. Fixed
price swaps on gas production sales of 2.5 Bcf in the second quarter of 2002
will yield a weighted average price of $2.61 per Mcf. Natural gas swaps on
notional gas purchase volumes of .3 Bcf in 2002 and .7 Bcf in 2003 were executed
under which the Company will pay a fixed price of $2.91 per Mcf. Under a crude
oil swap the Company will receive a fixed price of $20.07 per barrel on a
notional volume of 277,500 barrels.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
pg.
Reports of Management and Independent Public Accountants 32
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999 33
Consolidated Balance Sheets as of December 31, 2001 and 2000 34
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 35
Consolidated Statements of Retained Earnings for the years ended
December 31, 2001, 2000 and 1999 36
Consolidated Statements of Comprehensive Income (Loss) for the
years ended December 31, 2001, 2000 and 1999 36
Notes to Consolidated Financial Statements, December 31, 2001,
2000 and 1999 37
31
Report of Management
Management is responsible for the preparation and integrity of the
Company's financial statements. The financial statements have been prepared in
accordance with accounting principles generally accepted in the United States
consistently applied, and necessarily include some amounts that are based on
management's best estimates and judgment.
The Company maintains a system of internal accounting and administrative
controls and an ongoing program of internal audits that management believes
provide reasonable assurance that assets are safeguarded and that transactions
are properly recorded and executed in accordance with management's
authorization. The Company's financial statements have been audited by its
independent public accountants, Arthur Andersen LLP. In accordance with auditing
standards generally accepted in the United States, the independent auditors
obtained a sufficient understanding of the Company's internal controls to plan
their audit and determine the nature, timing, and extent of other tests to be
performed.
The Audit Committee of the Board of Directors, composed solely of outside
directors, meets with management, internal auditors, and Arthur Andersen LLP to
review planned audit scopes and results and to discuss other matters affecting
internal accounting controls and financial reporting. The independent auditors
have direct access to the Audit Committee and periodically meet with it without
management representatives present.
Report of Independent Public Accountants
To the Board of Directors and Shareholders of Southwestern Energy Company:
We have audited the consolidated balance sheets of SOUTHWESTERN ENERGY
COMPANY (an Arkansas corporation) AND SUBSIDIARIES as of December 31, 2001 and
2000, and the related consolidated statements of operations, retained earnings,
cash flows and comprehensive income (loss) for each of the three years in the
period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwestern Energy Company
and Subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 8 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivatives to
adopt the requirements of Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities."
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 4, 2002
32
Statements of Operations
Southwestern Energy Company and Subsidiaries
For the years ended December 31, 2001 2000 1999
-------------------------------------------------------------------------------------------------
(in thousands, except share/
per share amounts)
Operating revenues
Gas sales $ 248,952 $ 200,269 $ 165,898
Gas marketing 71,839 137,234 96,570
Oil sales 16,932 15,537 9,891
Gas transportation and other 7,204 10,843 8,037
--------------------------------------------------------------------------------------------------
344,927 363,883 280,396
--------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 68,161 58,669 45,370
Gas purchases - marketing 68,010 133,221 92,851
Operating expenses 39,035 34,808 33,783
General and administrative expenses 25,073 24,982 24,174
Unusual items - 111,288 -
Depreciation, depletion and amortization 52,899 45,869 41,603
Taxes, other than income taxes 9,080 8,515 6,557
--------------------------------------------------------------------------------------------------
262,258 417,352 244,338
--------------------------------------------------------------------------------------------------
Operating income (loss) 82,669 (53,469) 36,058
--------------------------------------------------------------------------------------------------
Interest expense
Interest on long-term debt 23,920 24,089 19,735
Other interest charges 1,374 1,588 923
Interest capitalized (1,595) (2,447) (3,307)
--------------------------------------------------------------------------------------------------
23,699 23,230 17,351
--------------------------------------------------------------------------------------------------
Other income (expense) (799) 1,997 (2,331)
--------------------------------------------------------------------------------------------------
Income (loss) before income taxes and minority interest 58,171 (74,702) 16,376
Minority interest in partnership (930) - -
--------------------------------------------------------------------------------------------------
Income (loss) before income taxes 57,241 (74,702) 16,376
--------------------------------------------------------------------------------------------------
Provision (benefit) for income taxes
Current - - 537
Deferred 21,917 (28,905) 5,912
--------------------------------------------------------------------------------------------------
21,917 (28,905) 6,449
--------------------------------------------------------------------------------------------------
Income (loss) before extraordinary item 35,324 (45,797) 9,927
Extraordinary loss due to early retirement
of debt (net of $569,000 tax benefit) - (890) -
--------------------------------------------------------------------------------------------------
Net income (loss) $ 35,324 $ (46,687) $ 9,927
--------------------------------------------------------------------------------------------------
Basic earnings per share
Income (loss) before extraordinary item $ 1.40 $ (1.82) $ .40
Extraordinary loss due to early retirement
of debt (net of $569,000 tax benefit) - (.04) -
Net income (loss) $ 1.40 $ (1.86) $ .40
--------------------------------------------------------------------------------------------------
Basic weighted average common shares outstanding 25,198,105 25,043,586 24,941,550
--------------------------------------------------------------------------------------------------
Diluted earnings per share
Income (loss) before extraordinary item $ 1.38 $ (1.82) $ .40
Extraordinary loss due to early retirement
of debt (net of $569,000 tax benefit) - (.04) -
--------------------------------------------------------------------------------------------------
Net income (loss) $ 1.38 $ (1.86) $ .40
--------------------------------------------------------------------------------------------------
Diluted weighted average common shares outstanding 25,601,110 25,043,586 24,947,021
--------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
33
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 2001 2000
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
ASSETS
Current assets
Cash $ 3,641 $ 2,386
Accounts receivable 42,763 77,041
Inventories, at average cost 26,606 17,000
Under-recovered purchased gas costs - 12,942
Hedging asset - SFAS No. 133 9,381 -
Regulatory asset - hedges 5,817 -
Other 4,996 3,486
---------------------------------------------------------------------------------------------------------------------------------
Total current assets 93,204 112,855
---------------------------------------------------------------------------------------------------------------------------------
Investments 15,538 15,574
Property, plant and equipment, at cost
Gas and oil properties, using the full cost method, including $21,102,000
in 2001 and $27,692,000 in 2000 excluded from amortization 970,680 872,023
Gas distribution systems 192,784 190,893
Gas in underground storage 32,046 27,867
Other 30,110 27,940
---------------------------------------------------------------------------------------------------------------------------------
1,225,620 1,118,723
Less: Accumulated depreciation, depletion and amortization 605,790 554,616
---------------------------------------------------------------------------------------------------------------------------------
619,830 564,107
---------------------------------------------------------------------------------------------------------------------------------
Other assets 14,551 12,842
---------------------------------------------------------------------------------------------------------------------------------
$ 743,123 $ 705,378
---------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ - $ 171,000
Accounts payable 41,644 54,304
Taxes payable 4,400 4,346
Interest payable 2,653 2,806
Customer deposits 4,845 4,799
Hedging liability - SFAS No. 133 6,990 -
Over-recovered purchased gas costs 8,184 -
Other 2,752 2,629
---------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 71,468 239,884
---------------------------------------------------------------------------------------------------------------------------------
Long-term debt 350,000 225,000
---------------------------------------------------------------------------------------------------------------------------------
Other liabilities
Deferred income taxes 122,381 97,431
Other 3,187 1,772
---------------------------------------------------------------------------------------------------------------------------------
125,568 99,203
---------------------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
---------------------------------------------------------------------------------------------------------------------------------
Minority interest in partnership 13,001 -
---------------------------------------------------------------------------------------------------------------------------------
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 19,764 20,220
Retained earnings, per accompanying statements 183,677 148,353
Accumulated other comprehensive income 5,763 -
---------------------------------------------------------------------------------------------------------------------------------
211,978 171,347
Less: Common stock in treasury, at cost, 2,261,766 shares in 2001 and 2,556,908 shares in 2000 25,196 28,485
Unamortized cost of restricted shares issued under stock incentive
plan, 416,537 shares in 2001 and 241,452 shares in 2000 3,696 1,571
---------------------------------------------------------------------------------------------------------------------------------
183,086 141,291
---------------------------------------------------------------------------------------------------------------------------------
$ 743,123 $ 705,378
---------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
34
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the years ended December 31, 2001 2000 1999
---------------------------------------------------------------------------------------------------------
(in thousands)
Cash flows from operating activities
Net income (loss) $ 35,324 $ (46,687) $ 9,927
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization 54,505 47,227 42,971
Deferred income taxes 21,917 (28,905) 5,912
Equity in loss of NOARK partnership 1,484 1,767 2,008
Gain on sale of Missouri utility assets - (3,209) -
Extraordinary loss due to early retirement of debt (net of tax) - 890 -
Minority interest in partnership (533) - -
Change in assets and liabilities:
Accounts receivable 34,278 (36,693) (2,684)
Income taxes receivable - 85 1,658
Under/over-recovered purchased gas costs 21,126 (14,104) (273)
Inventories (9,606) 2,290 1,292
Accounts payable (12,660) 22,156 (4,711)
Other current assets and liabilities (1,252) 1,980 2,031
---------------------------------------------------------------------------------------------------------
Net cash provided by (used in) operating activities 144,583 (53,203) 58,131
---------------------------------------------------------------------------------------------------------
Cash flows from investing activities
Capital expenditures (106,060) (75,717) (66,967)
Sale of Missouri utility assets - 32,000 -
Sale of oil and gas properties - 13,651 -
Investment in NOARK partnership (1,449) (3,250) (2,273)
(Increase) decrease in gas stored underground (4,179) 845 (4,433)
Other items 826 (1,066) 2,380
---------------------------------------------------------------------------------------------------------
Net cash used in investing activities (110,862) (33,537) (71,293)
---------------------------------------------------------------------------------------------------------
Cash flows from financing activities
Net increase (decrease) in revolving debt and short-term note (46,000) 115,800 20,300
Retirement of notes and payments on long-term debt - (24,910) (1,535)
Contribution from minority interest owner in partnership 13,534 - -
Dividends paid - (3,004) (5,985)
---------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities (32,466) 87,886 12,780
---------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 1,255 1,146 (382)
Cash at beginning of year 2,386 1,240 1,622
---------------------------------------------------------------------------------------------------------
Cash at end of year $ 3,641 $ 2,386 $ 1,240
The accompanying notes are an integral part of the financial statements.
35
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the years ended December 31, 2001 2000 1999
---------------------------------------------------------------------------------------------------------
(in thousands)
Retained earnings, beginning of year $ 148,353 $ 198,044 $ 194,102
Net income (loss) 35,324 (46,687) 9,927
Cash dividends declared ($.12 per share in 2000, $.24 per share in 1999) - (3,004) (5,985)
Retained earnings, end of year $ 183,677 $ 148,353 $ 198,044
Statements of Comprehensive Income (Loss)
Southwestern Energy Company and Subsidiaries
For the years ended December 31, 2001 2000 1999
---------------------------------------------------------------------------------------------------------
(in thousands)
Net income (loss) $ 35,324 $ (46,687) $ 9,927
Other comprehensive income:
Transition adjustment from adoption of SFAS No. 133 (36,963) - -
Unrealized gain on derivative instruments 19,852 - -
---------------------------------------------------------------------------------------------------------
Comprehensive income (loss) $ 18,213 $ (46,687) $ 9,927
---------------------------------------------------------------------------------------------------------
Reconciliation of accumulated other
comprehensive income (loss):
Balance, beginning of year $ - $ - $ -
Transition adjustment from adoption of SFAS No. 133 (36,963) - -
Current period reclassification to earnings 22,874 - -
Current period change in derivative instruments 19,852 - -
---------------------------------------------------------------------------------------------------------
Balance, end of year $ 5,763 $ - $ -
---------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of the financial statements.
36
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 2001, 2000 and 1999
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Consolidation
Southwestern Energy Company (Southwestern or the Company) is an integrated
energy company primarily focused on natural gas. Through its wholly-owned
subsidiaries, the Company is engaged in oil and gas exploration and production,
natural gas gathering, transmission and marketing, and natural gas distribution.
Southwestern's exploration and production activities are concentrated in
Arkansas, Louisiana, Texas, New Mexico and Oklahoma. The gas distribution
segment operates in northern Arkansas and, depending upon weather conditions and
current supply contracts, can obtain approximately 50% of its gas supply from
one of the Company's exploration and production subsidiaries. The customers of
the gas distribution segment consist of residential, commercial and industrial
users of natural gas. Southwestern's marketing and transportation business is
concentrated in its core areas of operations.
On May 31, 2000, the Company completed the sale of its Missouri gas
distribution assets for $32.0 million resulting in a pretax gain of
approximately $3.2 million. Proceeds from the sale of the Missouri assets were
used to reduce the Company's outstanding debt. As a result of the adverse Hales
judgment in June 2000, the Company's Board of Directors authorized management to
pursue the sale of the Company's remaining gas distribution assets. The sale
process did not result in an acceptable bid. The Company currently plans to
operate these assets as a continuing part of its business.
The consolidated financial statements include the accounts of Southwestern
Energy Company and its wholly-owned subsidiaries, Southwestern Energy Production
Company (SEPCO), SEECO, Inc., Arkansas Western Gas Company, Southwestern Energy
Services Company, Diamond "M" Production Company, Southwestern Energy Pipeline
Company, and A.W. Realty Company. The consolidated financial statements also
include the results for a limited partnership, Overton Partners, L.P., in which
SEPCO is the sole general partner. 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.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Minority Interest in Partnership
In 2001, SEPCO formed a limited partnership, Overton Partners, L.P., with
an investor to drill and complete the first 14 development wells in SEPCO's
Overton Field located in Smith County, Texas. Because SEPCO is the sole general
partner and owns a majority interest in the partnership, the operating and
financial results are consolidated with the Company's exploration and production
results and the investor's share of the partnership activity is reported as a
minority interest item in the financial statements. SEPCO contributed 50% of the
capital required to drill the first 14 wells. Revenues and expenses are
allocated 65% to SEPCO prior to payout of the investor's initial investment and
85% thereafter.
Unusual Items
In June 2000, the Company reported that the Arkansas Supreme Court ruled to
affirm the 1998 decision of the Sebastian County Circuit Court awarding $109.3
million in a class action to royalty owners of SEECO, Inc. (Hales judgment). The
Company fully satisfied the judgment and the Circuit Court in Sebastian County
issued an order in complete satisfaction of the judgment effective July 18,
2000. Additionally, the Company incurred an unusual charge of $2.0 million
during 2000 related to other litigation.
37
Property, Depreciation, Depletion and Amortization
Gas and Oil Properties. The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive)
including salaries, benefits, and other internal costs directly attributable to
these activities are capitalized and amortized on an aggregate basis over the
estimated lives of the properties using the units-of-production method. The
Company excludes all costs of unevaluated properties from immediate
amortization. The Company's unamortized costs of oil and gas properties are
limited to the sum of the future net revenues attributable to proved oil and gas
reserves discounted at 10 percent plus the lower of cost or market value of any
unproved properties. If the Company's unamortized costs in oil and gas
properties exceed this ceiling amount, a provision for additional depreciation,
depletion and amortization is required. At December 31, 2001, the Company's net
book value of oil and gas properties did not exceed the ceiling amount.
Decreases in market prices from December 31, 2001 levels, as well as changes in
production rates, levels of reserves, and the evaluation of costs excluded from
amortization, could result in future ceiling test impairments.
Gas Distribution Systems. Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of the
gas distribution system is provided using the straight-line method with average
annual rates for plant functions ranging from 1.5% to 5.8%. 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 cost of unevaluated
gas and oil properties excluded from amortization. In accordance with
established utility regulatory practice, an allowance for funds used during
construction of major projects is capitalized and amortized over the estimated
lives of the related facilities.
Gas Distribution Revenues and Receivables
Customer receivables arise from the sale or transportation of gas by the
Company's gas distribution subsidiary. The Company's 136,000 gas distribution
customers are located in northern Arkansas and represent a diversified base of
residential, commercial, and industrial users. The Company records gas
distribution revenues on an accrual basis, as gas volumes are used, to provide a
proper matching of revenues with expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual cost of purchased gas above or below the
level included in the base rates is permitted to be billed or is required to be
credited to customers. Each month, the difference between actual costs of
purchased gas and gas costs recovered from customers is deferred. The deferred
differences are billed or credited, as appropriate, to customers in subsequent
months. Rate schedules include a weather normalization clause to lessen the
impact of revenue increases and decreases which might result from weather
variations during the winter heating season. The pass-through of gas costs to
customers is not affected by this normalization clause.
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,
2001 and 2000 was not significant.
Income Taxes
Deferred income taxes are provided to recognize the income tax effect of
reporting certain transactions in different years for income tax and financial
reporting purposes.
38
Risk Management
The Company uses derivative financial instruments to manage defined
commodity price risks and interest rate risks and does not use them for trading
purposes. The Company uses commodity swap agreements and options to hedge sales
and purchases of natural gas and sales of crude oil. Gains and losses resulting
from hedging activities have been recognized in the statements of operations
when the related physical transactions of commodities were recognized. Gains or
losses from commodity swap agreements and options that do not qualify for
accounting treatment as hedges would be recognized currently as other income or
expense. See Note 8 for a discussion of the Company's hedging activities and the
effects of SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities."
Earnings Per Share and Shareholders' Equity
Basic earnings per common share is computed by dividing net income by the
weighted average number of common shares outstanding during each year. The
diluted earnings per share calculation adds to the weighted average number of
common shares outstanding the incremental shares that would have been
outstanding assuming the exercise of dilutive stock options. The Company had
options for 2,602,800 shares with an average exercise price of $9.79 outstanding
at December 31, 2000 that, due to the Company's net loss for 2000, would have
had an anti-dilutive effect and were, therefore, not considered. The Company had
options for 1,006,234 shares of common stock with a weighted average exercise
price of $13.83 per share at December 31, 2001, and options for 1,275,899 shares
of common stock with a weighted average exercise price of $12.97 per share at
December 31, 1999, that were not included in the calculation of diluted shares
because they would have had an anti-dilutive effect. The remaining 1,665,952
options at December 31, 2001 with a weighted average exercise price of $7.43,
and 785,300 options at December 31, 1999 with a weighted average exercise price
of $6.46 were included in the calculation of diluted shares.
During 2001 and 2000, the Company issued 299,850 and 154,438 treasury
shares, respectively, under a compensatory plan and for stock awards and
returned to treasury 18,184 and 10,955 shares, respectively, canceled from
earlier issues under the compensatory plan. The net effect of these transactions
was a reduction in treasury stock of $3.3 million and $1.6 million in 2001 and
2000, respectively.
Dividend on Common Stock
As a result of the adverse Hales judgment in June 2000, the Company has
indefinitely suspended payment of quarterly dividends on its common stock.
(2) DEBT
Debt balances as of December 31, 2001 and 2000 consisted of the following:
2001 2000
------------------------
(in thousands)
Senior notes
6.70% Series due 2005 $ 125,000 $ 125,000
7.625% Series due 2027, putable at the holders' option in 2009 60,000 60,000
7.21% Series due 2017 40,000 40,000
-------------------------------------------------------------------------------------------------------------
225,000 225,000
Other
Variable rate (3.44% at December 31, 2001) unsecured revolving credit arrangements 125,000 -
-------------------------------------------------------------------------------------------------------------
Total long-term debt $ 350,000 $ 225,000
-------------------------------------------------------------------------------------------------------------
Short-term debt
Variable rate unsecured revolving credit arrangements $ - $ 171,000
-------------------------------------------------------------------------------------------------------------
In July 2001, the Company arranged a new unsecured revolving credit
facility with a group of banks to replace its existing short-term credit
facility that was put in place in July 2000. The new revolving credit facility
has a current capacity of $155 million and a three-year term. The capacity of
the revolving credit facility decreases to $140 million in June 2002 and to $125
million in June 2003. The interest rate on the new facility is 137.5 basis
points over the current London Interbank
39
Offered Rate (LIBOR). The new credit facility contains covenants which impose
certain restrictions on the Company. Under the credit agreement, the Company may
not issue total debt in excess of 70% of its total capital, must maintain a
certain level of shareholders' equity, and must maintain a ratio of earnings
before interest, taxes, depreciation and amortization (EBITDA) to interest
expense of at least 3.75 or higher through December 31, 2002. These covenants
change over the term of the credit facility and generally become more
restrictive. The Company was in compliance with its debt agreements at December
31, 2001. The Company has entered into interest rate swaps for calendar year
2002 that allow the Company to pay an average fixed interest rate of 4.8% (based
upon current rates under the revolving credit facility) on $100 million of its
outstanding revolving debt.
There are no aggregate maturities of long-term debt for each of the years
ending December 31, 2002, 2003 and 2006. For each of the years ended December
31, 2004 and 2005, the aggregate maturity is $125.0 million. Total interest
payments were $24.4 million in 2001, $23.6 million in 2000, and $19.6 million in
1999.
(3) INCOME TAXES
The provision (benefit) for income taxes included the following components:
2001 2000 1999
--------------------------------------
(in thousands)
Federal:
Current $ - $ - $ -
Deferred 19,461 (23,723) 5,236
State:
Current - - 537
Deferred 2,575 (5,063) 795
Investment tax credit amortization (119) (119) (119)
------------------------------------------------------------------------------------------------------
Provision (benefit) for income taxes $ 21,917 $ (28,905) $ 6,449
------------------------------------------------------------------------------------------------------
The provision (benefit) for income taxes was an effective rate of 38.3% in
2001, 38.7% in 2000, and 39.4% in 1999. The following reconciles the provision
(benefit) for income taxes included in the consolidated statements of operations
with the provision (benefit) which would result from application of the
statutory federal tax rate to pretax financial income:
2001 2000 1999
--------------------------------------
(in thousands)
Expected provision (benefit) at federal statutory rate of 35% $ 20,034 $ (26,145) $ 5,732
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect 1,674 (3,291) 866
Other 209 531 (149)
------------------------------------------------------------------------------------------------------
Provision (benefit) for income taxes $ 21,917 $ (28,905) $ 6,449
------------------------------------------------------------------------------------------------------
The components of the Company's net deferred tax liability as of December
31, 2001 and 2000 were as follows:
2001 2000
-------------------------
(in thousands
Deferred tax liabilities:
Differences between book and tax basis of property $ 148,330 $ 129,702
Stored gas 8,037 8,883
Deferred purchased gas costs - 11,313
Prepaid pension costs 1,908 1,884
Book over tax basis in partnerships 11,148 11,755
Other 6,694 1,072
------------------------------------------------------------------------------------------------------
176,117 164,609
------------------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 721 884
Alternative minimum tax credit carryforward 3,766 3,046
Net operating loss carryforward 48,595 63,449
Other 1,849 1,671
------------------------------------------------------------------------------------------------------
54,931 69,050
------------------------------------------------------------------------------------------------------
Net deferred tax liability $ 121,186 $ 95,559
------------------------------------------------------------------------------------------------------
40
There were no income tax payments in 2001. Total income tax payments of $.5
million and $.6 million were made in 2000 and 1999, respectively.
(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
The Company applies SFAS No. 132, "Employers' Disclosures about Pensions
and Other Postretirement Benefits." Substantially all employees are covered by
the Company's defined benefit pension and postretirement benefit plans. The
following provides a reconciliation of the changes in the plans' benefit
obligations, fair value of assets, and funded status as of December 31, 2001 and
2000:
Other Postretirement
Pension Benefits Benefits
-------------------------------------------------
2001 2000 2001 2000
-------------------------------------------------
(in thousands)
Change in benefit obligations:
Benefit obligation at January 1 $ 56,571 $ 61,515 $ 2,011 $ 3,759
Service cost 1,318 1,682 71 85
Interest cost 4,133 4,509 138 268
Actuarial loss (gain) 3,338 1,438 10 (226)
Benefits paid (4,435) (7,256) (131) (138)
Amount transferred - (5,317) - -
Effect of settlement - - - (1,737)
--------------------------------------------------------------------------------------------------------
Benefit obligation at December 31 $ 60,925 $ 56,571 $ 2,099 $ 2,011
--------------------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets at January 1 $ 66,283 $ 70,478 $ 573 $ 615
Actual return on plan assets (2,478) 8,716 2 4
Employer contributions 18 13 228 308
Benefit payments (4,435) (7,256) (131) (138)
Amount transferred (378) (5,668) - -
Effect of settlement - - - (216)
--------------------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $ 59,010 $ 66,283 $ 672 $ 573
--------------------------------------------------------------------------------------------------------
Funded status:
Funded status at December 31 $ (1,916) $ 9,712 $ (1,427) $ (1,438)
Unrecognized net actuarial (gain) loss 2,288 (9,832) 322 299
Unrecognized prior service cost 4,514 4,965 - -
Unrecognized transition obligation - (37) 946 1,032
--------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 4,886 $ 4,808 $ (159) $ (107)
--------------------------------------------------------------------------------------------------------
The Company's supplemental retirement plan has an accumulated benefit
obligation in excess of plan assets. The plan's accumulated benefit obligation
was $326,000 and $286,000 at December 31, 2001 and 2000, respectively. There are
no plan assets in the supplemental retirement plan due to the nature of the
plan.
Net periodic pension and other postretirement benefit costs include the
following components for 2001, 2000 and 1999:
Other Postretirement
Pension Benefits Benefits
----------------------------------------------------------
2001 2000 1999 2001 2000 1999
----------------------------------------------------------
(in thousands)
Service cost $ 1,318 $ 1,682 $ 1,881 $ 71 $ 85 $ 99
Interest cost 4,133 4,509 4,130 138 268 261
Expected return on plan assets (5,829) (6,190) (6,259) (34) (39) (28)
Amortization of transition obligation (36) (183) (183) 86 103 103
Recognized net actuarial (gain) loss (97) (142) (142) 19 63 111
Amortization of prior service cost 451 451 451 - - -
--------------------------------------------------------------------------------------------------------
$ (60) $ 127 $ (122) $ 280 $ 480 $ 546
--------------------------------------------------------------------------------------------------------
41
The Company's pension plans provide for benefits on a "cash balance" basis.
A cash balance plan provides benefits based upon a fixed percentage of an
employee's annual compensation. The Company's funding policy is to contribute
amounts which are actuarially determined to provide the plans with sufficient
assets to meet future benefit payment requirements and which are tax deductible.
The postretirement benefit plans provide contributory health care and life
insurance benefits. Employees become eligible for these benefits if they meet
age and service requirements. Generally, the benefits paid are a stated
percentage of medical expenses reduced by deductibles and other coverages. The
Company has established trusts to partially fund its postretirement benefit
obligations.
The weighted average assumptions used in the measurement of the Company's
benefit obligations for 2001 and 2000 are as follows:
Other Postretirement
Pension Benefits Benefits
--------------------------------------------------
2001 2000 2001 2000
--------------------------------------------------
Discount rate 7.00% 7.25% 7.00% 7.25%
Expected return on plan assets 9.00% 9.00% 5.00% 5.00%
Rate of compensation increase 4.50% 4.50% n/a n/a
---------------------------------------------------------------------------------------------
For measurement purposes an 8% annual rate of increase in the per capita
cost of covered medical benefits and a 7.5% annual rate of increase in the per
capita cost of dental benefits was assumed for 2002. These rates were assumed to
gradually decrease to 6% for medical benefits and 5% for dental benefits for
2011 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one percentage point change in
assumed health care cost trend rates would have the following effects:
1% 1%
Increase Decrease
-------------------------
(in thousands)
Effect on the total service and interest cost components $ 29 $ (25)
Effect on postretirement benefit obligation $ 265 $(230)
---------------------------------------------------------------------------------------------
(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:
2001 2000 1999
------------------------------------
(in thousands)
Sales $ 153,937 $ 110,920 $ 75,039
Production (lifting) costs (23,604) (19,804) (14,039)
Depreciation, depletion and amortization (46,530) (39,048) (34,230)
---------------------------------------------------------------------------------------------
83,803 52,068 26,770
Income tax expense (31,819) (20,023) (10,528)
---------------------------------------------------------------------------------------------
Results of operations $ 51,984 $ 32,045 $ 16,242
---------------------------------------------------------------------------------------------
The results of operations shown above exclude unusual items in 2000 and
overhead and interest costs in all years. Income tax expense is calculated by
applying the statutory tax rates to the revenues less costs, including
depreciation, depletion and amortization, and after giving effect to permanent
differences and tax credits.
The table below sets forth capitalized costs incurred in gas and oil
property acquisition, exploration and development activities during 2001, 2000
and 1999:
2001 2000 1999
------------------------------------
(in thousands
Proved property acquisition costs $ 7,323 $ 7,428 $ 10,456
Unproved property acquisition costs 4,482 5,941 9,389
Exploration costs 23,490 27,853 19,519
Development costs 63,103 27,519 19,059
---------------------------------------------------------------------------------------------
Capitalized costs incurred $ 98,398 $ 68,741 $ 58,423
---------------------------------------------------------------------------------------------
Amortization per Mcf equivalent $1.14 $1.06 $1.00
---------------------------------------------------------------------------------------------
42
Capitalized interest is included as part of the cost of oil and gas
properties. The Company capitalized $1.6 million, $2.4 million and $3.3 million
during 2001, 2000 and 1999, respectively, based on the Company's weighted
average cost of borrowings used to finance the expenditures.
In addition to capitalized interest, the Company also capitalized internal
costs of $8.3 million, $7.3 million and $7.4 million during 2001, 2000 and 1999,
respectively. These internal costs were directly related to acquisition,
exploration and development activities and are included as part of the cost of
oil and gas properties.
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 2001 and 2000:
2001 2000
-------------------------
(in thousands)
Proved properties $ 944,502 $ 841,875
Unproved properties 26,178 30,148
----------------------------------------------------------------------------------------------------------------------------
Total capitalized costs 970,680 872,023
Less: Accumulated depreciation, depletion and amortization 502,882 457,551
----------------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 467,798 $ 414,472
----------------------------------------------------------------------------------------------------------------------------
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 2001. Of the total, approximately
$11.5 million is invested in Louisiana. The majority of Louisiana costs are
related to seismic projects that will be evaluated over several years as the
seismic data is interpreted and the acreage is explored. The remaining costs
excluded from amortization are related to properties which are not individually
significant and on which the evaluation process has not been completed. The
Company is, therefore, unable to estimate when these costs will be included in
the amortization computation.
2001 2000 1999 Prior Total
-----------------------------------------------------------
(in thousands)
Property acquisition costs $ 4,385 $ 1,880 $ 913 $ 2,432 $ 9,610
Exploration costs 725 1,891 3,434 2,155 8,205
Capitalized interest 225 566 782 1,714 3,287
----------------------------------------------------------------------------------------------------------------------------
$ 5,335 $ 4,337 $ 5,129 $ 6,301 $ 21,102
----------------------------------------------------------------------------------------------------------------------------
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 2001, 2000 and 1999:
2001 2000 1999
---------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
---------------------------------------------------------------------
Proved reserves, beginning of year 331,754 8,130 307,523 7,859 303,667 6,850
Revisions of previous estimates (21,598) (979) 5,357 (22) (7,464) 1,155
Extensions, discoveries, and other additions 77,187 1,272 53,389 1,347 34,730 225
Production (35,477) (719) (31,602) (676) (29,444) (578)
Acquisition of reserves in place 4,325 21 8,100 82 9,762 576
Disposition of reserves in place (378) (21) (11,013) (460) (3,728) (369)
Proved reserves, end of year 355,813 7,704 331,754 8,130 307,523 7,859
Proved, developed reserves:
Beginning of year 270,830 7,100 250,290 7,154 258,092 6,370
End of year 281,461 6,429 270,830 7,100 250,290 7,154
The "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves" (standardized measure) is a disclosure required by
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." The
standardized measure does not purport to present the fair market value of a
company's proved gas and oil reserves. In addition, there are uncertainties
inherent in estimating quantities of proved reserves. Substantially all
quantities of gas and oil reserves owned by the Company were estimated or
audited by the independent petroleum engineering firm of K & A Energy
Consultants, Inc.
43
Following is the standardized measure relating to proved gas and oil
reserves at December 31, 2001, 2000 and 1999:
2001 2000 1999
----------------------------------------
(in thousands)
Future cash inflows $ 1,095,843 $ 3,366,304 $ 989,997
Future production costs (313,357) (461,808) (195,131)
Future development costs (57,136) (44,609) (32,230)
Future income tax expense (182,103) (974,273) (247,408)
------------------------------------------------------------------------------------------------------------------
Future net cash flows 543,247 1,885,614 515,228
10% annual discount for estimated timing of cash flows (235,087) (990,472) (253,153)
------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 308,160 $ 895,142 $ 262,075
------------------------------------------------------------------------------------------------------------------
Under the standardized measure, future cash inflows were estimated by
applying year-end prices, adjusted for known contractual changes, to the
estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pretax cash inflows. Future income taxes were
computed by applying the year-end statutory rate, after consideration of
permanent differences, to the excess of pretax cash inflows over the Company's
tax basis in the associated proved gas and oil properties. Future net cash
inflows after income taxes were discounted using a 10% annual discount rate to
arrive at the standardized measure.
Following is an analysis of changes in the standardized measure during
2001, 2000 and 1999:
2001 2000 1999
----------------------------------------
(in thousands)
Standardized measure, beginning of year $ 895,142 $ 262,075 $ 222,793
Sales and transfers of gas and oil produced, net of production costs (130,333) (91,116) (61,000)
Net changes in prices and production costs (979,522) 837,691 48,506
Extensions, discoveries, and other additions, net of future production
and development costs 102,832 259,212 48,279
Acquisition of reserves in place 5,406 33,032 14,765
Revisions of previous quantity estimates (24,966) 20,178 (612)
Accretion of discount 133,136 38,076 32,447
Net change in income taxes 349,862 (317,527) (17,015)
Changes in production rates (timing) and other (43,397) (146,479) (26,088)
------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $ 308,160 $ 895,142 $ 262,075
------------------------------------------------------------------------------------------------------------------
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company holds a 25% general partnership interest in NOARK. NOARK
Pipeline was formerly a 258-mile intrastate gas transmission system which
extended across northern Arkansas. In January 1998, the Company entered into an
agreement with Enogex Inc. (Enogex) that resulted in the expansion of the NOARK
Pipeline and provided the pipeline with access to Oklahoma gas supplies through
an integration of NOARK with the Ozark Gas Transmission System (Ozark). Enogex
is a subsidiary of OGE Energy Corp. Ozark was a 437-mile interstate pipeline
system which began in eastern Oklahoma and terminated in eastern Arkansas.
Enogex acquired the Ozark system and contributed it to NOARK. Enogex also
acquired the NOARK partnership interests not owned by Southwestern. The
acquisition of Ozark and its integration with NOARK Pipeline was approved by the
Federal Energy Regulatory Commission in late 1998 at which time NOARK Pipeline
was converted to an interstate pipeline and operated in combination with Ozark.
Enogex funded the acquisition of Ozark and the expansion and integration with
NOARK Pipeline which resulted in the Company's ownership interest in the
partnership decreasing to 25% from 48%.
The Company's investment in NOARK totaled $15.5 million at December 31,
2001 and 2000, including advances of $1.4 million made during 2001, $3.3 million
made during 2000 and $2.3 million made during 1999. Advances are made primarily
to service NOARK's long-term debt. See Note 11 for further discussion of NOARK's
funding requirements and the Company's investment in NOARK.
44
NOARK's financial position at December 31, 2001 and 2000 is summarized
below:
2001 2000
--------------------------
(in thousands)
Current assets $ 8,363 $ 9,532
Noncurrent assets 175,299 179,136
--------------------------------------------------------------------------------
$ 183,662 $ 188,668
--------------------------------------------------------------------------------
Current liabilities $ 7,403 $ 11,803
Long-term debt 71,000 73,000
Partners' capital 105,259 103,865
--------------------------------------------------------------------------------
$ 183,662 $ 188,668
--------------------------------------------------------------------------------
The Company's share of NOARK's pretax loss was $1.5 million, $1.8 million
and $2.0 million for 2001, 2000 and 1999, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
operations.
NOARK's results of operations for 2001, 2000 and 1999 are summarized below:
2001 2000 1999
-------------------------------------
(in thousands)
Operating revenues $ 81,662 $ 73,633 $ 40,358
Pretax net loss $ (1,047) $ (1,391) $ (3,564)
--------------------------------------------------------------------------------
(8) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
the value:
Cash, Customer Deposits, and Short-Term Debt: The carrying amount is a
reasonable estimate of fair value.
Long-Term Debt: The fair value of the Company's long-term debt is estimated
based on the expected current rates which would be offered to the Company for
debt of the same maturities.
Commodity and Interest Hedges: The fair value of all hedging financial
instruments is the amount at which they could be settled, based on quoted market
prices or estimates obtained from dealers. The carrying amounts and estimated
fair values of the Company's financial instruments as of December 31, 2001 and
2000 were as follows:
2001 2000
-----------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-----------------------------------------------
(in thousands)
Cash $ 3,641 $ 3,641 $ 2,386 $ 2,386
Customer deposits $ 4,845 $ 4,845 $ 4,799 $ 4,799
Short-term debt - - $ 171,000 $ 171,000
Long-term debt $ 350,000 $ 356,179 $ 225,000 $ 226,309
Commodity and interest hedges $ 3,246 $ 3,246 $ (160) $ (60,596)
--------------------------------------------------------------------------------
Derivatives and Risk Management
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS No. 137 and SFAS No. 138, was adopted by the
Company on January 1, 2001. SFAS No. 133 requires that all derivatives be
recognized in the balance sheet as either an asset or liability measured at its
fair value. Special accounting for qualifying hedges allows a derivative's gains
and losses to offset related results on the hedged item in the income statement.
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded a
transition obligation of $60.6 million related to cash flow hedges in place that
are intended to reduce the volatility in commodity prices for the Company's
forecasted oil and gas production. At December 31, 2001, the Company recorded
hedging assets of $10.3 million, hedging liabilities of $7.1 million, a
regulatory asset of $5.8 million related to its utility gas purchase hedges, and
a net of tax gain to other comprehensive income (equity section of the balance
sheet) of $5.8 million. The amount recorded in other comprehensive income will
be relieved over time and taken to the income statement as the physical
transactions being hedged occur. There was no significant ineffectiveness during
2001 related to the Company's cash flow hedges and there were no discontinued
hedges. Additional volatility in earnings and other comprehensive income may
occur in the future as a result of the adoption of SFAS No. 133.
45
The Company uses natural gas and crude oil swap agreements and options and
interest rate swaps to reduce the volatility of earnings and cash flow due to
fluctuations in the prices of natural gas and oil and in interest rates. The
Board of Directors has approved risk management policies and procedures to
utilize financial products for the reduction of defined commodity price and
interest rate risks. These policies prohibit speculation with derivatives and
limit swap agreements to counterparties with appropriate credit standings.
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production, to hedge activity in its
marketing segment, and to hedge the purchase of gas in its utility segment
against the inherent price risks of adverse price fluctuations or locational
pricing differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps and options include (1) transactions in
which one party will pay a fixed price (or variable price) for a notional
quantity in exchange for receiving a variable price (or fixed price) based on a
published index (referred to as price swaps), (2) transactions in which parties
agree to pay a price based on two different indices (referred to as basis
swaps), and (3) the purchase and sale of index-related puts and calls (collars)
that provide a "floor" price below which the counterparty pays (production
hedge) or receives (gas purchase hedge) funds equal to the amount by which the
price of the commodity is below the contracted floor, and a "ceiling" price
above which the Company pays to (production hedge) or receives from (gas
purchase hedge) the counterparty the amount by which the price of the commodity
is above the contracted ceiling.
At December 31, 2001, the Company had outstanding natural gas price swaps
on total notional volumes of 13.4 Bcf in 2002 and 9.2 Bcf in 2003 for which the
Company will receive fixed prices ranging from $2.57 to $3.20 per MMBtu. Under
contracts on .3 Bcf in 2002, the Company will make average fixed price payments
of $2.96 per MMBtu and receive variable prices based on the NYMEX futures
market. At December 31, 2001, the Company also had outstanding natural gas price
swaps on total notional gas purchase volumes of 3.3 Bcf in 2002 for which the
Company will pay an average fixed price of $4.20 per Mcf.
At December 31, 2001, the Company had collars in place on 6.0 Bcf in 2002
and 4.1 Bcf in 2003 of future gas production. The 6.0 Bcf in 2002 had a floor
and ceiling of $4.00 and $4.72, respectively. The 4.1 Bcf in 2003 had a floor
and ceiling of $3.00 and $4.65, respectively. The Company's price risk
management activities reduced revenues $10.3 million in 2001, $39.3 million in
2000, and $1.1 million in 1999.
The Company has outstanding interest rate swaps on a notional amount of
$100 million. Under these contracts the Company will make average fixed interest
payments at 3.4% and receive variable prices based on the one-month LIBOR rate.
The Company currently pays an additional 1.4% above LIBOR on its revolving
credit facility.
The primary market risks related to the Company's derivative contracts are
the volatility in commodity prices, basis differentials and interest rates.
However these market risks are offset by the gain or loss recognized upon the
related sale or purchase of the natural gas or sale of oil that is hedged, and
payment of variable rate interest. Credit risk relates to the risk of loss as a
result of non-performance by the Company's counterparties. The counterparties
are primarily major investment and commercial banks which management believes
present minimal credit risks. The credit quality of each counterparty and the
level of financial exposure the Company has to each counterparty are
periodically reviewed to ensure limited credit risk exposure.
(9) STOCK OPTIONS
The Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan) was
adopted in February 2000 and provides for the compensation of officers, key
employees and eligible non-employee directors of the Company and its
subsidiaries. The 2000 Plan replaces the Southwestern Energy Company 1993 Stock
Incentive Plan (1993 Plan) and the Southwestern Energy Company 1993 Stock
Incentive Plan for Outside Directors (1993 Director Plan). The 2000 Plan
provides for grants of options, stock appreciation rights, shares of phantom
stock, and shares of restricted stock that in the aggregate do not exceed
1,250,000 shares. The types of incentives which may be awarded are comprehensive
and are intended to enable the Board of Directors to structure the most
appropriate incentives and to address changes in income tax laws which may be
enacted over the term of the 2000 Plan.
The 1993 Plan provided for the compensation of officers and key employees
of the Company and its subsidiaries through grants of options, shares of
restricted stock, and stock bonuses that in the aggregate did not exceed
1,700,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock and cash awards, the shares
46
related to which in the aggregate did not exceed 1,700,000 shares, and the grant
of limited and tandem SARs (all terms as defined in the 1993 Plan). The Company
has also awarded stock option grants outside the 2000 Plan and the 1993 Plan to
certain non-officer employees and to certain officers at the time of their hire.
The 2000 Plan awards each non-employee director who is eligible to
participate in the plan an annual Director's Option with respect to 8,000 shares
of common stock. Previously, the 1993 Director Plan provided for annual stock
option grants of 12,000 shares (with 12,000 limited SARs) to each non-employee
director. Options under the 1993 Director Plan were limited to no more than
240,000 shares.
The Company's 1985 Nonqualified Stock Option Plan expired in 1992, except
with respect to awards then outstanding. The following tables summarize stock
option activity for the years 2001, 2000 and 1999 and provide information for
options outstanding at December 31, 2001:
2001 2000 1999
------------------------------------------------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Exercise of Exercise of Exercise
Shares Price Shares Price Shares Price
-------------------------------------------------------------------
Options outstanding at January 1 2,602,800 $ 9.79 2,061,199 $ 10.49 1,634,901 $ 12.15
Granted 170,200 $ 10.13 666,100 $ 7.58 562,250 $ 6.18
Exercised 11,252 $ 7.00 - - 1,333 $ 7.31
Canceled 89,562 $ 9.22 124,499 $ 9.55 134,619 $ 12.68
------------------------------------------------------------------------------------------------------------
Options outstanding at December 31 2,672,186 $ 9.84 2,602,800 $ 9.79 2,061,199 $ 10.49
------------------------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
-------------------------------------------------------------------
Weighted
Weighted Average Weighted Weighted
Options Average Remaining Options Average
Range of Outstanding Exercise Contractual Exercisable Exercise
Exercise Prices at Year End Price Life (Years) at Year End Price
-------------------- -------------------------------------------------------------------
$6.00 - $7.00 558,018 $6.15 7.8 368,226 $6.15
$7.06 - $8.75 834,934 $7.41 8.2 441,229 $7.39
$9.06 - $13.38 740,300 $11.65 6.4 536,267 $12.26
$14.00 - $17.50 538,934 $14.95 3.3 480,372 $14.99
-------------------- -------------------------------------------------------------------
2,672,186 $9.84 1,826,094 $10.57
------------------------------------------------------------------------------------------------------------
All options are issued at fair market value at the date of grant and expire
ten years from the date of grant. Options generally vest to employees and
directors over a three to four year period from the date of grant. Of the total
options outstanding, 325,000 performance accelerated options were granted in
1994 at an option price of $14.63. These options vest over a four-year period
beginning in 2000.
The Company applies the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." Accordingly, no compensation cost has
been recognized for the stock option plans. Had compensation cost for the
Company's stock option plans been determined consistent with the provisions of
SFAS No. 123, the Company's net income (loss) and earnings (loss) per share
would have been reduced to the pro forma amounts indicated below:
2001 2000 1999
-------------------------------
Net income (loss), in thousands
As reported $ 35,324 $(46,687) $ 9,927
Pro forma $ 34,373 $(47,444) $ 9,241
Basic earnings (loss) per share
As reported $1.40 $(1.86) $.40
Pro forma $1.36 $(1.90) $.37
Diluted earnings (loss) per share
As reported $1.38 $(1.86) $.40
Pro forma $1.34 $(1.90) $.37
------------------------------------------------------------------------------------------------------------
47
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions: no dividend yield; expected volatility of 46.4%; risk-free interest
rate of 4.8%; and expected lives of 6 years.
The Company has granted 752,995 shares of restricted stock to employees
through 2001. Of this total, 421,895 shares vest over a three-year period,
288,550 shares vest over a four-year period, and the remaining shares vest over
a five-year period. The related compensation expense is being amortized over the
vesting periods. As of December 31, 2001, 295,146 shares have vested to
employees and 41,480 shares have been canceled and returned to treasury shares.
(10) COMMON STOCK PURCHASE RIGHTS
In 1999, the Company's Common Share Purchase Rights Plan was amended and
extended for an additional ten years. Per the terms of the amended plan, one
common share purchase right is attached to each outstanding share of the
Company's common stock. Each right entitles the holder to purchase one share of
common stock at an exercise price of $40.00, subject to adjustment. These rights
will become exercisable in the event that a person or group acquires or
commences a tender or exchange offer for 15% or more of the Company's
outstanding shares or the Board determines that a holder of 10% or more of the
Company's outstanding shares presents a threat to the best interests of the
Company. At no time will these rights have any voting power.
If any person or entity actually acquires 15% of the common stock (10% or
more if the Board determines such acquiror is adverse), rightholders (other than
the 15% or 10% stockholder) will be entitled to buy, at the right's then current
exercise price, the Company's common stock with a market value of twice the
exercise price. Similarly, if the Company is acquired in a merger or other
business combination, each right will entitle its holder to purchase, at the
right's then current exercise price, a number of the surviving company's common
shares having a market value at that time of twice the right's exercise price.
The rights may be redeemed by the Board for $.01 per right or exchanged for
common shares on a one-for-one basis prior to the time that they become
exercisable. In the event, however, that redemption of the rights is considered
in connection with a proposed acquisition of the Company, the Board may redeem
the rights only on the recommendation of its independent directors
(nonmanagement directors who are not affiliated with the proposed acquiror).
These rights expire in 2009.
(11) CONTINGENCIES AND COMMITMENTS
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018.
The Company's share of the several guarantee is 60%. At December 31, 2001 and
2000, the principal outstanding for these Notes was $73.0 million and $75.0
million, respectively. The Notes were issued in June 1998 and require
semi-annual principal payments of $1.0 million. Under the several guarantee, the
Company is required to fund its share of NOARK's debt service which is not
funded by operations of the pipeline. As a result of the integration of NOARK
Pipeline with the Ozark Gas Transmission System, as discussed further in Note 7,
management of the Company believes that it will realize its investment in NOARK
over the life of the system. Therefore, no provision for any loss has been made
in the accompanying financial statements. Additionally, the Company's gas
distribution subsidiary has transportation contracts for firm capacity of 66.9
MMcfd on NOARK's integrated pipeline system. These contracts expire in 2002 and
2003, and are renewable year-to-year thereafter until terminated by 180 days'
notice.
The Company recently settled litigation, subject to court approval, in a
case filed against the Company and two of its subsidiaries in a state court in
Sebastian County, Arkansas related to the Company's Stockton Gas Storage
Facility in Franklin County, Arkansas (the "Stockton Storage Facility"). As
previously disclosed, this class action suit was filed on August 25, 2000 on
behalf of a class of plaintiffs comprised of all surface owners, mineral owners,
royalty owners and overriding royalty owners in the Stockton Storage Facility.
Plaintiffs alleged various wrongful, intentional and fraudulent acts relating to
the operation of the storage pool beginning in 1968 and continuing to the
present, and claimed ownership rights in the gas that the Company has stored in
the storage pool in an amount in excess of $5 million in actual damages,
interest, attorney's fees and punitive damages. Under the terms of the
settlement, the Company has agreed to pay the plaintiffs a cash settlement
amount and enter into new gas storage agreements at rental rates commensurate
with current market prices. The settlement of this litigation did not have a
material impact on the Company's result of operations for 2001.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a non-capital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial position or reported results of operations of
the Company.
48
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
(12) SEGMENT INFORMATION
The Company applies SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information." The Company's reportable business segments
have been identified based on the differences in products or services provided.
Revenues for the exploration and production segment are derived from the
production and sale of natural gas and crude oil. Revenues for the gas
distribution segment arise from the transportation and sale of natural gas at
retail. The marketing segment generates revenue through the marketing of both
Company and third party produced gas volumes.
Summarized financial information for the Company's reportable segments is
shown in the following table. The "Other" column includes items related to
non-reportable segments (real estate and pipeline operations) and corporate
items.
Exploration
and Gas
Production Distribution Marketing Other Total
---------------------------------------------------------------------
2001 (in thousands)
Revenues from external customers $ 126,006 $ 147,082 $ 71,839 $ - $ 344,927
Intersegment revenues 27,931 200 118,486 448 147,065
Operating income 69,340 10,346 2,703 280 82,669
Depreciation, depletion and amortization expense 46,530 6,163 111 95 52,899
Interest expense (1) 18,238 4,413 34 1,014 23,699
Provision (benefit) for income taxes (1) 19,164 2,505 996 (748) 21,917
Assets 526,346 169,931 8,026 38,820(2) 743,123
Capital expenditures 98,964(3) 5,347 - 1,749 106,060
---------------------------------------------------------------------------------------------------------------------------------
2000
Revenues from external customers $ 75,597 $ 151,052 $ 137,234 $ - $ 363,883
Intersegment revenues 35,323 182 70,514 448 106,467
Unusual items (4) 111,288 - - - 111,288
Operating income (loss) (70,584) 14,655 2,460 - (53,469)
Depreciation, depletion and amortization expense 39,048 6,625 109 87 45,869
Interest expense (1) 17,472 4,608 16 1,134 23,230
Provision (benefit) for income taxes (1) (34,153) 4,869 912 (533) (28,905)
Assets 460,296 188,811 20,929 35,342(2) 705,378
Capital expenditures 69,211 5,994 24 488 75,717
---------------------------------------------------------------------------------------------------------------------------------
1999
Revenues from external customers $ 51,533 $ 132,293 $ 96,570 $ - $ 280,396
Intersegment revenues 23,506 127 40,956 416 65,005
Operating income 16,451 17,187 2,142 278 36,058
Depreciation, depletion and amortization expense 34,230 7,186 92 95 41,603
Interest expense (1) 11,345 5,027 - 979 17,351
Provision (benefit) for income taxes (1) 1,806 4,569 859 (785) 6,449
Assets 435,022 190,731 11,212 34,481(2) 671,446
Capital expenditures 59,004 7,124 9 830 66,967
---------------------------------------------------------------------------------------------------------------------------------
(1) Interest expense and the provision (benefit) for income taxes by segment
are an allocation of corporate amounts as debt and income tax expense
(benefit) are incurred at the corporate level.
(2) Other assets include the Company's equity investment in the operations of
NOARK (see Note 7), corporate assets not allocated to segments, and assets
for non-reportable segments.
(3) Includes $13.5 million funded by the owner of the minority interest in
Overton partnership.
(4) Includes $109.3 million for the Hales judgment and $2.0 million for other
litigation.
Intersegment sales by the exploration and production segment and marketing
segment to the gas distribution segment are priced in accordance with terms of
existing contracts and current market conditions. Parent company assets include
furniture and fixtures, prepaid debt costs, and prepaid pension costs. Parent
company general and administrative costs, depreciation expense and taxes other
than income are allocated to segments. All of the Company's operations are
located within the United States.
49
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the
years ended December 31, 2001 and 2000:
---------------------------------------------------------
March 31 June 30 September 30 December 31
---------------------------------------------------------
(in thousands, except per share amounts)
2001
---------------------------------------------------------
Operating revenues $ 137,129 $ 76,023 $ 59,396 $ 72,379
Operating income $ 32,599 $ 18,015 $ 14,263 $ 17,792
Net income $ 16,013 $ 6,869 $ 5,018 $ 7,424
Basic earnings per share $.64 $.27 $.20 $.29
Diluted earnings per share $.63 $.27 $.20 $.29
2000
---------------------------------------------------------
Operating revenues $ 96,913 $ 78,483 $ 75,342 $ 113,145
Operating income (loss) $ 21,056 $(101,849) $ 5,884 $ 21,440
Net income (loss) $ 9,186 $ (64,199) $ (754) $ 9,080
Basic and diluted earnings (loss) per share $.37 $(2.57) $(.03) $.36
----------------------------------------------------------------------------------------------------------
(14) NEW ACCOUNTING STANDARDS
In July 2001, the FASB issued Statement of Financial Accounting Standards
No. 141, "Business Combinations" (SFAS No. 141), Statement of Financial
Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No.
142), and Statement of Financial Accounting Standards No. 143, "Accounting for
Asset Retirement Obligations" (SFAS No. 143). In October, 2001, the FASB issued
Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144).
SFAS No. 141 requires that the purchase method of accounting be used for
all business combinations initiated after June 30, 2001. SFAS No. 142 requires
that goodwill and intangible assets with indefinite useful lives no longer be
amortized, but instead be tested for impairment at least annually in accordance
with the provisions of SFAS No. 142. The Company was required to adopt the
provisions of SFAS No. 141 immediately, and SFAS No. 142 effective January 1,
2002. Adoption of SFAS No. 141 and SFAS No. 142 had no impact on the Company's
results of operations or financial condition.
SFAS No. 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs and amends FASB Statement No. 19, "Financial Accounting
and Reporting by Oil and Gas Producing Companies." SFAS No. 143 requires that
the fair value of a liability for an asset retirement obligation be recognized
in the period in which it is incurred if a reasonable estimate of fair value can
be made, and that the associated asset retirement costs be capitalized as part
of the carrying amount of the long-lived asset. SFAS No. 143 is effective for
financial statements issued for fiscal years beginning after June 15, 2002. The
effect of this standard on the Company's results of operations and financial
condition is being evaluated.
SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of" and amends
Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations
- Reporting the Effects of Disposal of a Segment of a Business and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions." SFAS
No. 144 retains the basic framework of SFAS No. 121, resolves certain
implementation issues of SFAS No. 121, extends applicability to discontinued
operations, and broadens the presentation of discontinued operations to include
a component of an entity. SFAS No. 144 is effective for financial statements
issued for fiscal years beginning after December 15, 2001. Adoption of SFAS No.
144 had no impact on the Company's results of operations or financial position.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no changes in or disagreements with the Company's
independent public accountants on accounting and financial disclosure.
50
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 15, 2002 (the 2002 Proxy Statement), is hereby
incorporated by reference for the purpose of providing information about the
identification of directors. Refer to the sections "Election of Directors" and
"Share Ownership of Management and Directors" for information concerning the
directors.
Information concerning executive officers is presented in Part I, Item 4 of
this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The 2002 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 2002 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about security ownership of certain beneficial
owners and management. Refer to the sections "Security Ownership of Certain
Beneficial Owners" and "Share Ownership of Management and Directors" for
information about security ownership of certain beneficial owners and
management.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The 2002 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about related transactions. Refer to the
section "Share Ownership of Management and Directors" for information about
transactions with members of the Company's Board of Directors.
Part IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) The consolidated financial statements of the Company and its
subsidiaries and the report of independent public accountants are
included in Item 8 of this Report.
(2) The consolidated financial statement schedules have been omitted
because they are not required under the related instructions, or are
not applicable.
(3) The exhibits listed on the accompanying Exhibit Index (pages 53 and 54)
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 October 18, 2001, referencing a
conference call conducted on October 17, 2001, announcing the results of the
Company's third quarter 2001 activity.
51
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 29, 2002 BY: /s/ Greg D. Kerley
--------------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 29, 2002.
/s/ Harold M. Korell President, Chief Executive Officer
------------------------------------ and Director
Harold M. Korell
/s/ Greg D. Kerley Executive Vice President
------------------------------------ and Chief Financial Officer
Greg D. Kerley
/s/ Stanley T. Wilson Controller and Chief Accounting Officer
------------------------------------
Stanley T. Wilson
/s/ Charles E. Scharlau Director and Chairman
------------------------------------
Charles E. Scharlau
/s/ Lewis E. Epley, Jr. Director
------------------------------------
Lewis E. Epley, Jr.
/s/ John Paul Hammerschmidt Director
------------------------------------
John Paul Hammerschmidt
/s/ Robert L. Howard Director
------------------------------------
Robert L. Howard
/s/ Kenneth R. Mourton Director
------------------------------------
Kenneth R. Mourton
Supplemental Information to be Furnished With Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered Securities
Pursuant of Section 12 of the Act.
Not Applicable
52
EXHIBIT INDEX
Exhibit
No. Description
------- -----------
3. Articles of Incorporation and Bylaws of the Company (amended and
restated Articles of Incorporation incorporated by reference to
Exhibit 3 to Annual Report on Form 10-K for the year ended December
31, 1993); Bylaws of the Company (amended Bylaws of the Company
incorporated by reference to Exhibit 3 to Annual Report on Form 10-K
for the year ended December 31, 1994).
4.1 Amended and Restated Rights Agreement dated April 12, 1999
(incorporated by reference to Exhibit 4.1 to Annual Report on Form
10-K for the year ended December 31, 1999), as amended by Amendment
No. 1 to the Amended and Restated Rights Agreement dated March 15,
2002 (filed herewith).
4.2 Prospectus, Registration Statement, and Indenture on 6.70% Senior
Notes due December 1, 2005 and issued December 5, 1995 (incorporated
by reference to the Company's Forms S-3 and S-3/A filed on November 1,
1995, and November 17, 1995, respectively, and also to the Company's
filings of a Prospectus and Prospectus Supplement on November 22,
1995, and December 4, 1995, respectively).
4.3 Prospectus Supplement and Form of Distribution Agreement on
$125,000,000 of Medium-Term Notes dated February 21, 1997 (Prospectus
Supplement incorporated by reference to the Company's filing of a
Prospectus Supplement on February 21, 1997, Form of Distribution
Agreement incorporated by reference to Exhibit 10 filed with the
Company's Form 8-K dated February 21, 1997).
4.4 Short-Term Credit Agreement dated July 17, 2000 between Southwestern
Energy Company and Bank One, N.A., as administrative agent, and Bank
of America, N.A., as syndication agent (incorporated by reference to
Exhibit 4.4 to Annual Report on Form 10-K for the year ended December
31, 2000).
4.5 Credit Agreement dated July 12, 2001 between Southwestern Energy
Company and The Lenders; Bank One, N.A., as administrative agent, and
Royal Bank of Canada, as syndication agent (filed herewith).
10.1 Compensation Plans:
(a) Southwestern Energy Company Incentive Compensation Plan,
effective January 1, 1993, and Amended and Restated as of January
1, 1999 (incorporated by reference to Exhibit 10.2(b) to Annual
Report on Form 10-K for the year ended December 31, 1998).
(b) Nonqualified Stock Option Plan, effective February 22, 1985, as
amended July 10, 1989 (replaced by Southwestern Energy Company
1993 Stock Incentive Plan, dated April 7, 1993, which was
replaced by the Southwestern Energy Company 2000 Stock Incentive
Plan dated February 18, 2000) (original plan incorporated by
reference to Exhibit 10 to Annual Report on Form 10-K for the
year ended December 31, 1985; amended plan incorporated by
reference to Exhibit 10 to Annual Report on Form 10-K for the
year ended December 31, 1989).
(c) Southwestern Energy Company 1993 Stock Incentive Plan, dated
April 7, 1993 and Amended and Restated as of February 18, 1998
(replaced by the Southwestern Energy Company 2000 Stock Incentive
Plan dated February 18, 2000) (incorporated by reference to
Exhibit 10.2(d) to Annual Report on Form 10-K for the year ended
December 31, 1998).
(d) Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors, dated April 7, 1993 (replaced by the Southwestern
Energy Company 2000 Stock Incentive Plan dated February 18, 2000)
(incorporated by reference to the appendix filed with the
Company's definitive Proxy Statement to holders of the
Registrant's Common Stock in connection with the solicitation of
proxies to be used in voting at the Annual Meeting of
Shareholders on May 26, 1993).
(e) Southwestern Energy Company 2000 Stock Incentive Plan dated
February 18, 2000 (incorporated by reference to the appendix
filed with the Company's definitive Proxy Statement to holders of
the Registrant's Common Stock in connection with the solicitation
of proxies to be used in voting at the Annual Meeting of
Shareholders on May 24, 2000).
53
Exhibit
No. Description
------- -----------
10.2 Southwestern Energy Company Supplemental Retirement Plan, adopted May
31, 1989, and Amended and Restated as of December 15, 1993, and as
further amended February 1, 1996 (amended and restated plan
incorporated by reference to Exhibit 10.5 to Annual Report on Form
10-K for the year ended December 31, 1993; amendment dated February 1,
1996, incorporated by reference to Exhibit 10.5 to Annual Report on
Form 10-K for the year ended December 31, 1995).
10.3 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).
10.4 Southwestern Energy Company Nonqualified Retirement Plan, effective
October 4, 1995 (incorporated by reference to Exhibit 10.7 to Annual
Report on Form 10-K for the year ended December 31, 1995).
10.5 Employment and Consulting Agreement for Charles E. Scharlau, dated May
21, 1998 (incorporated by reference to Exhibit 10.9 to Annual Report
on Form 10-K for the year ended December 31, 1998).
10.6 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).
10.7 Form of Executive Severance Agreement for the Executive Officers of
the Company, effective February 17, 1999 (incorporated by reference to
Exhibit 10.12 to Annual Report on Form 10-K for the year ended
December 31, 1998).
10.8 Amended and Restated Limited Partnership Agreement of NOARK Pipeline
System, Limited Partnership dated January 12, 1998 and amended June
18, 1998 (amended and restated agreement incorporated by reference to
Exhibit 10.18 to Annual Report on Form 10-K for the year ended
December 31, 1997; first amendment thereto incorporated by reference
to Exhibit 10.14 to Annual Report on Form 10-K for the year ended
December 31, 1998).
21. Subsidiaries of the Registrant (filed herewith).
23. Consent of Arthur Andersen LLP (filed herewith).
99.1 Letter to Commission pursuant to Temporary Note 3T dated March 29,
2002 (filed herewith).
54
SOUTHWESTERN ENERGY COMPANY
AND
EQUISERVE TRUST COMPANY, N.A.
Rights Agent
-------------------------
Amendment No. 1 to the Amended and Restated Rights Agreement
Dated as of March 15, 2002
AMENDMENT NO. 1
TO THE AMENDED AND RESTATED RIGHTS AGREEMENT
This Amendment No. 1 to the Amended and Restated Rights Agreement (this
"Amendment"), dated as of March 15, 2002, between Southwestern Energy Company,
an Arkansas corporation (the "Company"), and Equiserve Trust Company, N.A.,
successor to The First National Bank of Chicago (the "Rights Agent"). All
capitalized terms used in this Amendment and not otherwise defined shall have
the respective meanings set forth in the Amended and Restated Rights Agreement
(as defined below).
W I T N E S S E T H:
- - - - - - - - - -
WHEREAS, on May 5, 1989 (the "Declaration Date"), the Board of Directors of
the Company authorized and declared a dividend of one right representing the
right to purchase one share of Common Stock upon the terms and subject to the
conditions set forth in a Rights Agreement, dated May 5, 1989, between the
Company and the Rights Agent (the "1989 Rights Agreement") for each outstanding
share of common stock, $2.50 par value, of the Company outstanding at the close
of business on May 19, 1989 (the "Record Date"), and authorized the issuance of
one Right with respect to each share of Common Stock that shall become
outstanding between the Record Date and the earlier of the Distribution Date and
the Expiration Date, each Right initially representing the right to purchase one
share of Common Stock upon the terms and subject to the conditions hereinafter
set forth;
WHEREAS, the Company declared a three-for-one stock split in 1993 and, in
connection with such split, the number of Rights was adjusted pursuant to
Section 11 of the 1989 Rights Agreement such that each certificate for Common
Stock outstanding as of the date of this Amended and Restated Rights Agreement
also represents one Right under the 1989 Rights Agreement representing the right
to purchase one share of Common Stock upon the terms and subject to the
conditions set forth in the 1989 Rights Agreement;
WHEREAS, on April 12, 1999, in compliance with the terms of Section 27 of
the 1989 Rights Agreement, the Company and the Rights Agent entered into an
Amended and Restated Rights Agreement (the "Amended and Restated Rights
Agreement") which amended and restated the 1989 Rights Agreement in its entirety
in order to extend the Expiration Date until April 12, 2009 and to make other
changes and provisions that they determined were necessary or desirable and did
not adversely affect the interests of the holders of the Rights;
WHEREAS, the Company wishes to amend the Amended and Restated Rights
Agreement in order to eliminate the requirement of all required approvals of
Independent Directors;
WHEREAS, in compliance with the terms of Section 27 of the Amended and
Restated Rights Agreement, the Company has (i) delivered to the Rights Agent a
certificate from an appropriate officer of the Company which states that this
Amendment has been approved by the Company's Board of Directors and is in
compliance with the terms of Section 27 of the
1
Amended and Restated Rights Agreement and (ii) instructed the Rights Agent to
execute this Amendment;
NOW, THEREFORE, in consideration of the premises and the mutual agreements
herein set forth, the parties hereby agree as follows:
Section l. Definitions.
(a) The definition of "Approved Offer" contained in subparagraph (d) of
Section 1 of the Amended and Restated Rights Agreement is hereby amended in its
entirety to read as follows:
""Approved Offer" shall mean a tender or exchange offer for all outstanding
shares of Common Stock that is at a price and on terms approved, prior to the
acceptance for payment of shares under such tender or exchange offer, by the
Board of Directors of the Company based upon the prior recommendation of a
majority of the board of directors."
(b) The references to the defined terms "Independent Directors" and
"Proposed Acquiror" contained in subparagraph (m) of Section 1 are hereby
deleted.
Section 2. Redemption. Subparagraph (a) of Section 23 of the Amended and
Restated Rights Agreement is amended in its entirety to read as follows:
"(a) The Company may, by resolution of its Board of Directors, at its
option, at any time prior to the earlier of (x) the Stock Acquisition Date or
(y) the close of business on the Final Expiration Date, redeem all but not less
than all of the then outstanding Rights at a redemption price of $0.01 per
Right, as such amount may be appropriately adjusted to reflect any stock split,
stock dividend or similar transaction occurring after the date of this Amended
and Restated Rights Agreement (such redemption price being hereinafter referred
to as the "Redemption Price"). The Company may , at its option, pay the
Redemption Price in cash, shares of Common Stock (based on the "current market
price", as defined in Section 11(d)(i) hereof, of the Common Stock at the time
of such Board resolution) or any other form of consideration deemed appropriate
by the Board of Directors."
Section 3. Exchange. Subparagraph (a) of Section 24 of the Amended and
Restated Rights Agreement is amended in its entirety to read as follows:
"(a) The Board of Directors of the Company may, at its option, at any time
after the Stock Acquisition Date exchange all or part of the then-outstanding
and exercisable Rights (which shall not include Rights that have become void
pursuant to the provisions of Section 11(a)(iii) hereof) for Common Stock (or
Common Stock Equivalents) at an exchange ratio of one share of Common Stock per
Right, appropriately adjusted to reflect any stock split, stock dividend or
similar transaction occurring after the date of this Amended and Restated Rights
Agreement (such exchange ratio being hereinafter referred to as the "Exchange
Ratio"). Notwithstanding the foregoing, the Board of Directors of the Company
shall not be empowered to effect such exchange at any time after any Person
(other than a Company Entity), together with all Affiliates and Associates of
such Person, becomes the Beneficial Owner of 50% or more of the Common Stock
then outstanding."
2
Section 4. Supplements and Amendments. Section 27 of the Amended and
Restated Rights Agreement is amended in its entirety to read as follows:
"The Company and the Rights Agent shall, if the Company so directs, from
time to time supplement or amend this Agreement without the approval of any
holders of Rights in order (i) to cure any ambiguity, (ii) to correct or
supplement any provision contained herein which may be defective or inconsistent
with any other provisions herein (provided that any amendment made pursuant to
clause (i) or (ii) hereof after a Stock Acquisition Date, shall not materially
adversely affect the interests of the holders of Right Certificates (other than
an Acquiring Person or any Affiliate or Associate thereof)), (iii) prior to the
Stock Acquisition Date, to effect any other change or modification which the
Company may deem necessary or desirable, or (iv) after the Stock Acquisition
Date, to make any other provisions in regard to matters or questions arising
hereunder which the Company may deem necessary or desirable and which shall not
adversely affect the interests of the holders of Right Certificates (other than
an Acquiring Person or any Affiliate or Associate thereof). Notwithstanding
anything contained in this Agreement to the contrary, this Agreement may not be
amended or supplemented (x) to reinstate a right of redemption if the Rights are
not then redeemable or (y) to decrease the Redemption Price. Upon the delivery
of a certificate from an appropriate officer of the Company which states that
the proposed supplement or amendment has been approved by the Company's Board of
Directors and is in compliance with the terms of this Section 27, the Rights
Agent shall execute such supplement or amendment; provided, however, that the
Rights Agent may, but shall not be obligated to, enter into any such supplement
or amendment that adversely affects its rights, duties or immunities under this
Agreement. Prior to the Distribution Date, the interests of the holders of
Rights shall be deemed to coincide with the interests of holders of shares of
Common Stock (other than an Acquiring Person, an Adverse Person or any Affiliate
or Associate thereof)."
Section 5. Determinations and Actions by the Board of Directors, etc.
Section 31 of the Amended and Restated Rights Agreement is amended in its
entirety to read as follows:
"The Board of Directors of the Company shall have the exclusive power and
authority to administer this Agreement and to exercise all rights and powers
specifically granted to the Board of Directors or to the Company, or as may be
necessary or advisable in the administration of this Agreement, including,
without limitation, the right and power to (i) interpret the provisions of this
Agreement, and (ii) make all determinations deemed necessary or advisable for
the administration of this Agreement (including, without limitation, a
determination to redeem or not to redeem the Rights pursuant to Section 23
hereof or to supplement or amend the Agreement and whether any proposed
supplement or amendment adversely affects the interests of the holders of Right
Certificates and comports with the requirements of Section 27 hereof or to find
or to announce publicly that any Person has become an Acquiring Person or an
Adverse Person). For all purposes of this Agreement, any calculation of the
number of shares of Common Stock or other securities outstanding at any
particular time, including for purposes of determining the particular percentage
of such outstanding shares of Common Stock or any other securities of which any
Person is the Beneficial Owner, shall be made in accordance with the last
sentence of Rule 13d-3(d)(1)(i) of the General Rules and Regulations under the
Exchange Act as in effect on the date of this Agreement. All such actions,
calculations, interpretations and determinations (including for purpose of
clause (y) below, all omissions with respect to the
3
foregoing) which are done or made by the Board of Directors of the Company in
good faith, shall (x) be final, conclusive and binding on the Company, the
Rights Agent, the holders of the Rights and all other parties, and (y) no
subject the Board of Directors or any director to any liability to the holders
of the Rights."
Section 6. Governing Law. This Amendment shall be deemed to be a contract
made under the laws of the State of Arkansas and for all purposes shall be
governed by and construed in accordance with the laws of such state applicable
to contracts to be made and performed entirely within such state.
Section 7. Counterparts. This Amendment may be executed in any number of
counterparts and each of such counterparts shall for all purposes be deemed to
be an original, and all such counterparts shall together constitute but one and
the same instrument.
Section 8. Descriptive Headings. Descriptive headings of the several
Sections of this Agreement are inserted for convenience only and shall not
control or affect the meaning or construction of any of the provisions hereof.
Section 9. Ratification of the Amended and Restated Rights Agreement.
Except as expressly amended hereby, the Amended and Restated Rights Agreement is
in all respects ratified and confirmed and all the terms, conditions and
provisions thereof shall remain in full force and effect.
IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
duly executed and their respective corporate seals to be hereunto affixed and
attested, all as of the date and the year first above written.
Attest: SOUTHWESTERN ENERGY COMPANY
By: /S/ MARK K. BOLING By: /S/ GREG D. KERLEY
---------------------------- --------------------------------
Mark K. Boling, Secretary Gregory D. Kerley,
Executive Vice President and
Chief Financial Officer
Attest: EQUISERVE TRUST COMPANY, N.A.
By: By:
-------------------------- --------------------------------
Title: Title:
4
================================================================================
CREDIT AGREEMENT
DATED AS OF JULY 12, 2001
AMONG
SOUTHWESTERN ENERGY COMPANY,
THE LENDERS,
BANK ONE, NA,
AS ADMINISTRATIVE AGENT,
AND
ROYAL BANK OF CANADA,
AS SYNDICATION AGENT
BANC ONE CAPITAL MARKETS, INC.
AS LEAD ARRANGER AND BOOK RUNNER
================================================================================
CREDIT AGREEMENT
This Agreement, dated as of July 12, 2001, is among Southwestern Energy
Company, the Lenders, Bank One, NA, a national banking association having its
principal office in Chicago, Illinois, as Administrative Agent, and Royal Bank
of Canada, as Syndication Agent. The parties hereto agree as follows:
ARTICLE I
DEFINITIONS
As used in this Agreement:
"Administrative Agent" means Bank One in its capacity as administrative
agent for the Lenders pursuant to Article X, and not in its individual capacity
as a Lender, and any successor Administrative Agent appointed pursuant to
Article X.
"Advance" means a group of Loans (i) made by the Lenders on the same
Borrowing Date or (ii) converted or continued by the Lenders on the same date of
conversion or continuation and, in either case, consisting of Ratable Loans of
the same Type and, in the case of Eurodollar Loans, for the same Interest
Period.
"Affected Lender" is defined in Section 2.20.
"Affiliate" of any Person means any other Person directly or indirectly
controlling, controlled by or under common control with such Person. A Person
shall be deemed to control another Person if the controlling Person owns 10% or
more of any class of voting securities (or other ownership interests) of the
controlled Person or possesses, directly or indirectly, the power to direct or
cause the direction of the management or policies of the controlled Person,
whether through ownership of stock, by contract or otherwise.
"Aggregate Commitment" means the aggregate of the Commitments of all the
Lenders, as reduced from time to time pursuant to the terms hereof.
"Agreement" means this credit agreement, as it may be amended or modified
and in effect from time to time.
"Agreement Accounting Principles" means generally accepted accounting
principles as in effect from time to time; provided that if the Borrower
notifies the Administrative Agent that the Borrower does not want to give effect
to any change in
generally accepted accounting principles (or if the Administrative Agent
notifies the Borrower that the Required Lenders do not want to give effect to
any such change), then Agreement Accounting Principles shall mean generally
accepted accounting principles as in effect immediately before the relevant
change in generally accepted accounting principles became effective, until
either such notice is withdrawn or this Agreement is amended in a manner
satisfactory to the Borrower and the Required Lenders.
"Alternate Base Rate" means, for any day, a rate of interest per annum
equal to the higher of (i) the Prime Rate for such day and (ii) the sum of the
Federal Funds Effective Rate for such day plus 0.5% per annum.
"Applicable Margin" means the "Applicable Margin" as determined in
accordance with Schedule 1B.
"Arranger" means Banc One Capital Markets, Inc.
"Article" means an article of this Agreement unless another document is
specifically referenced.
"Asset Sale" means any sale, lease, assignment for value or other
disposition by the Borrower or any Subsidiary, excluding (a) sales and other
dispositions in the ordinary course of business and (b) any sale or other
disposition of any asset listed on Schedule 2.8(a).
"Authorized Officer" means any of the following officers of the Borrower,
acting singly: the Chief Executive Officer, the President, the Chief Financial
Officer, the Treasurer or any Executive Vice President, Senior Vice President or
Vice President.
"Bank One" means Bank One, NA, a national banking association having its
principal office in Chicago, Illinois, in its individual capacity, and its
successors.
"Borrower" means Southwestern Energy Company, an Arkansas corporation, and
its successors and assigns.
"Borrowing Date" means a date on which an Advance or a Swing Line Loan is
made hereunder.
"Borrowing Notice" is defined in Section 2.4.
"Business Day" means (i) with respect to any borrowing, payment or rate
selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on
which banks generally are open in Chicago, Dallas and New York for the conduct
of substantially all of their commercial lending activities, interbank wire
transfers can be made on the Fedwire system and dealings in United States
dollars are carried on in the London interbank market and (ii) for all other
purposes, a day (other than a Saturday or Sunday) on which banks generally are
open in Chicago and Dallas for the conduct of substantially all of their
commercial lending activities and interbank wire transfers can be made on the
Fedwire system.
-2-
"Capitalized Lease" of a Person means any lease of Property, except oil and
gas leases, by such Person as lessee which would be capitalized on a balance
sheet of such Person prepared in accordance with Agreement Accounting
Principles.
"Capitalized Lease Obligations" of a Person means the amount of the
obligations of such Person under Capitalized Leases which would be shown as a
liability on a balance sheet of such Person prepared in accordance with
Agreement Accounting Principles.
"Cash Equivalent Investments" means, at any time, (a) any evidence of Debt,
maturing not more than one year after such time, issued or guaranteed by the
United States Government or any agency thereof, (b) commercial paper, maturing
not more than one year from the date of issue, or corporate demand notes, in
each case (unless issued by a Lender or its holding company) rated at least A-l
by Standard & Poor's Ratings Group or P-l by Moody's Investors Service, Inc.,
(c) any certificate of deposit (or time deposits represented by such
certificates of deposit) or bankers acceptance, maturing not more than one year
after such time, or overnight Federal Funds transactions that are issued or sold
by a commercial banking institution that is a member of the Federal Reserve
System and has a combined capital and surplus and undivided profits of not less
than $500,000,000, (d) any repurchase agreement entered into with any Lender (or
other commercial banking institution of the stature referred to in clause (c))
which (i) is secured by a fully perfected security interest in any obligation of
the type described in any of clauses (a) through (c) and (ii) has a market value
at the time such repurchase agreement is entered into of not less than 100% of
the repurchase obligation of such Lender (or other commercial banking
institution) thereunder and (e) investments in short-term asset management
accounts offered by any Lender for the purpose of investing in loans to any
corporation (other than the Company or an Affiliate of the Company), state or
municipality, in each case organized under the laws of any state of the United
States or of the District of Columbia.
"Change of Control" means that (i) any Person or group (within the meaning
of Rule 13d-5 under the Securities Exchange Act of 1934, as amended) shall
beneficially own, directly or indirectly, 25% or more of the common stock or
other voting securities of the Borrower; or (ii) Continuing Directors shall fail
to constitute a majority of the Board of Directors of the Borrower. For purposes
of the foregoing, "Continuing Director" means an individual who (x) is a member
of the Board of Directors of the Borrower on the date of this Agreement or (y)
is nominated to be a member of such Board of Directors after the date hereof by
a majority of the Continuing Directors then in office.
"Code" means the Internal Revenue Code of 1986, as amended, reformed or
otherwise modified from time to time.
"Commitment" means, for each Lender, the obligation of such Lender to make
Ratable Loans, and participate in Swing Line Loans, not exceeding the amount set
forth on Schedule 1A or as set forth in any assignment that has become effective
pursuant to Section 12.3.2, as such amount may be modified from time to time
pursuant to the terms hereof.
-3-
"Commitment Fee Rate" means the "Commitment Fee Rate" as determined in
accordance with Schedule 1B.
"Commitment Reduction Date" is defined in Section 2.8.
"Contingent Obligation" of a Person means any agreement, undertaking or
arrangement by which such Person assumes, guarantees, endorses, contingently
agrees to purchase or provide funds for the payment of, or otherwise becomes or
is contingently liable upon, the obligation or liability of any other Person, or
agrees to maintain the net worth or working capital or other financial condition
of any other Person, or otherwise assures any creditor of such other Person
against loss, including, without limitation, any comfort letter, operating
agreement, take or pay contract, application for a Letter of Credit or the
obligations of any such Person as general partner of a partnership with respect
to the liabilities of the partnership.
"Conversion/Continuation Notice" is defined in Section 2.5.
"Controlled Group" means all members of a controlled group of corporations
or other business entities and all trades or businesses (whether or not
incorporated) under common control which, together with the Borrower or any of
its Subsidiaries, are treated as a single employer under Section 414 of the
Code.
"Debt Issuance " means the issuance by the Borrower or any Subsidiary of
any Indebtedness other than:
(a) Indebtedness under the Loan Documents;
(b) Indebtedness existing on the date hereof and extensions,
renewals, refinancings and replacements thereof that do not increase the
outstanding principal amount thereof or result in an earlier maturity date
or a decreased weighted average life thereof;
(c) Indebtedness under the revolving credit facility between the
Borrower and McIlroy Bank & Trust and any extension, renewal, refinancing
or replacement thereof so long as the aggregate principal amount thereof
does not at any time exceed $4,500,000;
(d) Indebtedness of the Borrower to any Subsidiary or of any
Subsidiary to the Borrower or any other Subsidiary;
(e) Indebtedness described in clause (ii), (iii), (v), (vi),
(viii) or (xi) of the definition of "Indebtedness"; and
(f) Indebtedness of the Borrower or any Subsidiary that was
Indebtedness of any other Person existing at the time such other Person
was merged with or became a Subsidiary and extensions, renewals,
refinancings and replacements of any such
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Indebtedness that do not increase the outstanding principal amount thereof
or result in an earlier maturity date or decreased weighted average life
thereof, excluding Indebtedness incurred in connection with, or in
contemplation of, such other Person's merging with or becoming a
Subsidiary.
"Debt to Capitalization Ratio" means the ratio of (a) Total Debt to (b) the
sum of Total Debt plus Stockholders' Equity.
"Default" means an event described in Article VII.
"Designated Proceeds" means, at any time, all Net Cash Proceeds from Asset
Sales received by the Borrower or any Subsidiary after the date of this
Agreement, excluding any portion of such Net Cash Proceeds previously applied to
reduce the Aggregate Commitment pursuant to Section 2.8(b).
"Environmental Laws" means any and all federal, state, local and foreign
statutes, laws, judicial decisions, regulations, ordinances, rules, judgments,
orders, decrees, plans, injunctions, permits, concessions, grants, franchises,
licenses, agreements and other governmental restrictions relating to (i) the
protection of the environment, (ii) the effect of the environment on human
health, (iii) emissions, discharges or releases of pollutants, contaminants,
hazardous substances or wastes into surface water, ground water or land, or (iv)
the manufacture, processing, distribution, use, treatment, storage, disposal,
transport or handling of pollutants, contaminants, hazardous substances or
wastes or the clean-up or other remediation thereof.
"Equity Issuance " means any issuance by the Borrower or any Subsidiary of
any equity securities other than (a) pursuant to and in accordance with stock
option plans or other benefit plans for directors, officers or employees of the
Borrower or any Subsidiary, (b) in connection with a merger, acquisition, joint
venture, asset purchase or other investment by the Borrower or any Subsidiary
permitted under this Agreement or (c) any issuance by a Subsidiary to the
Borrower or to another Subsidiary.
"ERISA" means the Employee Retirement Income Security Act of 1974, as
amended from time to time, and any rule or regulation issued thereunder.
"Eurodollar Advance" means an Advance which, except as otherwise provided
in Section 2.11, bears interest at the applicable Eurodollar Rate.
"Eurodollar Base Rate" means, with respect to a Eurodollar Advance for the
relevant Interest Period, the applicable British Bankers' Association Interest
Settlement Rate for deposits in U.S. dollars appearing on Reuters Screen FRBD as
of 11:00 a.m. (London time) two Business Days prior to the first day of such
Interest Period, and having a maturity equal to such Interest Period, provided
that, (i) if Reuters Screen FRBD is not available to the Administrative Agent
for any reason, the applicable Eurodollar Base Rate for the relevant Interest
Period shall instead be the applicable British Bankers' Association Interest
Settlement Rate for deposits in U.S.
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dollars as reported by any other generally recognized financial information
service as of 11:00 a.m. (London time) two Business Days prior to the first day
of such Interest Period, and having a maturity equal to such Interest Period,
and (ii) if no such British Bankers' Association Interest Settlement Rate is
available to the Administrative Agent, the applicable Eurodollar Base Rate for
the relevant Interest Period shall instead be the rate determined by the
Administrative Agent to be the rate at which Bank One or one of its Affiliate
banks offers to place deposits in U.S. dollars with first-class banks in the
London interbank market at approximately 11:00 a.m. (London time) two Business
Days prior to the first day of such Interest Period, in the approximate amount
of the relevant Eurodollar Loan and having a maturity equal to such Interest
Period.
"Eurodollar Loan" means a Ratable Loan which, except as otherwise provided
in Section 2.11, bears interest at the applicable Eurodollar Rate.
"Eurodollar Rate" means, with respect to a Eurodollar Advance for the
relevant Interest Period, the sum of the Eurodollar Base Rate applicable to such
Interest Period plus the Applicable Margin as in effect from time to time.
"Excluded Taxes" means, in the case of each Lender or applicable Lending
Installation and the Administrative Agent, taxes imposed on its overall net
income, and franchise taxes imposed on it, by (i) the jurisdiction under the
laws of which such Lender or the Administrative Agent is incorporated or
organized or (ii) the jurisdiction in which the Administrative Agent's or such
Lender's principal executive office or such Lender's applicable Lending
Installation is located.
"Exhibit" refers to an exhibit to this Agreement, unless another document
is specifically referenced.
"Federal Funds Effective Rate" means, for any day, an interest rate per
annum equal to the weighted average of the rates on overnight Federal funds
transactions with members of the Federal Reserve System arranged by Federal
funds brokers on such day, as published for such day (or, if such day is not a
Business Day, for the immediately preceding Business Day) by the Federal Reserve
Bank of New York, or, if such rate is not so published for any day which is a
Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago
time) on such day on such transactions received by the Administrative Agent from
three Federal funds brokers of recognized standing selected by the
Administrative Agent in its sole discretion.
"Floating Rate" means, for any day, a rate per annum equal to the Alternate
Base Rate for such day, changing when and as the Alternate Base Rate changes,
plus the Applicable Margin as in effect on such day.
"Floating Rate Advance" means an Advance which, except as otherwise
provided in Section 2.11, bears interest at the Floating Rate.
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"Floating Rate Loan" means a Ratable Loan which, except as otherwise
provided in Section 2.11, bears interest at the Floating Rate.
"Guarantor" means each Subsidiary which is a party to the Subsidiary
Guaranty.
"Indebtedness" of a Person means such Person's (i) obligations for borrowed
money, (ii) obligations representing the deferred purchase price of Property or
services, (iii) obligations, whether or not assumed, secured by Liens or payable
out of the proceeds or production from Property now or hereafter owned or
acquired by such Person, (iv) obligations which are evidenced by notes,
acceptances, or other instruments, (v) obligations of such Person to purchase
accounts, securities or other Property arising out of or in connection with the
sale of the same or substantially similar accounts, securities or Property, (vi)
Capitalized Lease Obligations, (vii) any other obligation for borrowed money or
other financial accommodation which in accordance with Agreement Accounting
Principles would be shown as a liability on the consolidated balance sheet of
such Person, (viii) net liabilities under interest rate swap, exchange or cap
agreements, obligations or other liabilities with respect to accounts or notes,
(ix) Sale and Leaseback Transactions which do not create a liability on the
consolidated balance sheet of such Person, (x) other transactions which are the
functional equivalent, or take the place, of borrowing but which do not
constitute a liability on the consolidated balance sheet of such Person, (xi)
Contingent Obligations and (xii) Mandatorily Redeemable Stock; provided that,
notwithstanding any of the foregoing, accounts payable arising in the ordinary
course of business payable on terms customary in the trade, and Contingent
Obligations in respect thereof, shall not constitute Indebtedness; and provided,
further, that Indebtedness shall not include accounts payable which the Borrower
is required to reflect on its balance sheet in accordance with Agreement
Accounting Principles to the extent that (i) such accounts payable consist
solely of contingent obligations under oil and gas hedge transactions for future
periods and (ii) as of any date of calculation thereof, the volume of oil and
gas subject to such hedge transactions is not greater than 90% of the Borrower's
anticipated production from proved, producing, oil and gas reserves owned by the
Borrower and its Subsidiaries as of such date over the term covered by such
hedge transactions.
"Intercompany Indebtedness" means any Indebtedness of the Borrower owing to
any Subsidiary or of any Subsidiary owing to the Borrower or to any other
Subsidiary; provided that in the case of any Indebtedness owed by the Borrower
or any Subsidiary to a Subsidiary which is not a Wholly-Owned Subsidiary, such
Indebtedness shall constitute Intercompany Indebtedness only to the extent of
the Borrower's ownership percentage (whether direct or indirect) of the
Subsidiary holding such Indebtedness.
"Interest Coverage Ratio" means, for any period of four fiscal quarters of
the Borrower ending on the last day of a fiscal quarter, the ratio of (a) the
sum of (i) the Borrower's consolidated net income before interest, taxes,
depreciation and amortization of non-cash charges, all determined on a
consolidated basis and in accordance with Agreement Accounting Principles for
such period, but excluding, to the extent otherwise included therein, any
non-cash gain or loss on any hedging agreement resulting from the requirements
of SFAS 133, plus (ii) to
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the extent deducted in determining such consolidated net income, any non-cash
charge after the date hereof resulting from any write-down of the Borrower's oil
and gas properties to the full cost ceiling limitation required by the full cost
method of accounting for such properties, to (b) the Borrower's interest expense
for such period.
"Interest Period" means, with respect to a Eurodollar Advance, a period of
one, two, three or six months commencing on a Business Day selected by the
Borrower pursuant to this Agreement. Such Interest Period shall end on the day
which corresponds numerically to such date one, two, three or six months
thereafter, provided that if there is no such numerically corresponding day in
such next, second, third or sixth succeeding month, such Interest Period shall
end on the last Business Day of such next, second, third or sixth succeeding
month. If an Interest Period would otherwise end on a day which is not a
Business Day, such Interest Period shall end on the next succeeding Business
Day, provided that if said next succeeding Business Day falls in a new calendar
month, such Interest Period shall end on the immediately preceding Business Day.
Notwithstanding any other provision of this Agreement, the Borrower may not
select any Interest Period (a) which would end after the scheduled Termination
Date or (b) if, after giving effect to such selection, the aggregate principal
amount of all Eurodollar Loans having Interest Periods ending after any
Commitment Reduction Date would exceed the Aggregate Commitment scheduled to be
in effect at the close of business on such Commitment Reduction Date.
"Investment" of a Person means any loan, advance (other than commission,
travel and similar advances to officers and employees made in the ordinary
course of business), extension of credit (other than accounts receivable arising
in the ordinary course of business on terms customary in the trade) or
contribution of capital by such Person; stocks, bonds, mutual funds, partnership
interests, notes, debentures or other securities owned by such Person; any
deposit accounts and certificate of deposit owned by such Person; and structured
notes, derivative financial instruments and other similar instruments or
contracts owned by such Person.
"Knowledge" means, with respect to the Borrower, the actual knowledge of
(i) any Authorized Officer, (ii) any vice president of the Borrower in charge of
a principal business unit, division or function (such as sales, administration
or finance), (iii) any other officer who performs a policy making function or
(iv) any other person who performs similar policy making functions for the
Borrower.
"Lenders" means the lending institutions listed on the signature pages of
this Agreement and their respective successors and assigns. Unless otherwise
specified, the term "Lenders" includes Bank One in its capacity as Swing Line
Lender.
"Lending Installation" means, with respect to a Lender or the
Administrative Agent, the office, branch, subsidiary or affiliate of such Lender
or the Administrative Agent listed on its administrative questionnaire or on the
signature pages hereof or otherwise selected by such Lender or the
Administrative Agent pursuant to Section 2.18.
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"Letter of Credit" of a Person means a letter of credit or similar
instrument which is issued upon the application of such Person or upon which
such Person is an account party or for which such Person is in any way liable.
"Lien" means any lien (statutory or other), mortgage, pledge,
hypothecation, assignment, deposit arrangement, encumbrance or other security
arrangement (including, without limitation, the interest of a vendor or lessor
under any conditional sale, Capitalized Lease or other title retention
agreement).
"Loan" means a Ratable Loan or a Swing Line Loan.
"Loan Documents" means this Agreement, any Note and the Subsidiary
Guaranty.
"Mandatorily Redeemable Stock" means, with respect to any Person, any share
of such Person's capital stock or other equity interest to the extent that it is
(a) redeemable, payable or required to be purchased or otherwise retired or
extinguished, or convertible into any Indebtedness or other liability of such
Person, (i) at a fixed or determinable date, whether by operation of a sinking
fund or otherwise, (ii) at the option of any Person other than such Person or
(iii) upon the occurrence of a condition not solely within the control of such
Person, such as a redemption required to be made out of future earnings or (b)
convertible into Mandatorily Redeemable Stock.
"Material Adverse Effect" means a material adverse effect on (i) the
business, Property, condition (financial or otherwise) or results of operations
of the Borrower and its Subsidiaries taken as a whole, (ii) the prospect that
the Borrower will have the ability to fully and timely pay the Obligations or
(iii) the validity or enforceability of any of the Loan Documents or the rights
or remedies of the Administrative Agent or the Lenders thereunder.
"Material Group of Subsidiaries" means two or more Subsidiaries which, if
merged as of any relevant date of determination, would constitute a Significant
Subsidiary.
"Multiemployer Plan" means a Plan maintained pursuant to a collective
bargaining agreement or any other arrangement to which the Borrower or any
member of the Controlled Group is a party to which more than one employer is
obligated to make contributions.
"Net Cash Proceeds" means (a) with respect to any Asset Sale, the aggregate
cash proceeds (including cash proceeds received by way of deferred payment of
principal pursuant to a note, installment receivable or otherwise, but only as
and when received) received by the Borrower or any Subsidiary pursuant to such
Asset Sale net of (i) the direct costs relating to such Asset Sale (including
sales commissions and legal, accounting and investment banking fees), (ii) taxes
paid or reasonably estimated by the Borrower to be payable as a result thereof
(after taking into account any available tax credits or deductions and any tax
sharing arrangements), (iii) amounts required to be applied to the repayment of
any Indebtedness secured by a Lien on any asset subject to such Asset Sale and
(iv) the proceeds of any sale of any of the assets listed
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on Schedule 2.8(b) to the extent that such proceeds are applied within 150 days
to acquire oil or gas producing properties; and (b) with respect to any Debt
Issuance or Equity Issuance, the aggregate cash proceeds received by the
Borrower pursuant to such Debt Issuance or Equity Issuance, net of the direct
costs relating to such Debt Issuance or Equity Issuance (including registration
fees, filing fees, underwriting commissions and discounts and legal, accounting
and investment banking fees).
"Non-U.S. Lender" is defined in Section 3.5(iv).
"Note" means a promissory note, substantially in the form of Exhibit E,
issued at the request of a Lender pursuant to Section 2.14.
"Obligations" means all unpaid principal of and accrued and unpaid interest
on the Loans, all accrued and unpaid fees and all expenses, reimbursements,
indemnities and other obligations of the Borrower to the Lenders or to any
Lender, the Administrative Agent or any indemnified party arising under the Loan
Documents.
"Other Taxes" is defined in Section 3.5(ii).
"Participants" is defined in Section 12.2.1.
"Payment Date" means the last day of each March, June, September and
December.
"PBGC" means the Pension Benefit Guaranty Corporation, or any successor
thereto.
"Person" means any natural person, corporation, firm, joint venture,
partnership, limited liability company, association, enterprise, trust or other
entity or organization, or any government or political subdivision or any
agency, department or instrumentality thereof.
"Plan" means an employee pension benefit plan which is covered by Title IV
of ERISA or subject to the minimum funding standards under Section 412 of the
Code as to which the Borrower or any member of the Controlled Group may have any
liability.
"Prime Rate" means a rate per annum equal to the prime rate of interest
announced by Bank One or by its parent, BANK ONE CORPORATION, which is not
necessarily the lowest rate charged to any customer, changing when and as said
prime rate changes.
"Principal Transmission Facility" means any transportation or distribution
facility, including pipelines, of the Borrower or any Subsidiary located in the
United States of America other than (a) any such facility which in the opinion
of the Board of Directors of the Borrower is not of material importance to the
business conducted by the Borrower and its Subsidiaries taken as a whole, or (b)
any such facility in which interests are held by the Borrower or by one or more
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Subsidiaries or by the Borrower and one or more Subsidiaries and by others and
the aggregate interest held by the Borrower and all Subsidiaries does not exceed
50%.
"Productive Property" means any property interest owned by the Borrower or
a Subsidiary in land (including submerged land and rights in and to oil, gas and
mineral leases) located in the United States of America and classified by the
Borrower or such Subsidiary, as the case may be, as productive of crude oil,
natural gas or other petroleum hydrocarbons in paying quantities; provided that
such term shall not include any exploration or production facilities on said
land, including any drilling or producing platform.
"Property" of a Person means any and all property, whether real, personal,
tangible, intangible, or mixed, of such Person, or other assets owned, leased or
operated by such Person.
"Pro Rata Share" means, with respect to any Lender, the percentage which
the amount of such Lender's Commitment is of the Aggregate Commitment (or, if
the Commitments have been terminated, the percentage which the sum of the
principal amount of such Lender's Ratable Loans plus such Lender's participation
interest in the principal amount of all Swing Line Loans is of the aggregate
principal amount of all Loans).
"Purchasers" is defined in Section 12.3.1.
"Ratable Loan" is defined in Section 2.1.
"Regulation D" means Regulation D of the Board of Governors of the Federal
Reserve System as from time to time in effect and any successor thereto or other
regulation or official interpretation of said Board of Governors relating to
reserve requirements applicable to member banks of the Federal Reserve System.
"Regulation U" means Regulation U of the Board of Governors of the Federal
Reserve System as from time to time in effect and any successor or other
regulation or official interpretation of said Board of Governors relating to the
extension of credit by banks for the purpose of purchasing or carrying margin
stocks applicable to member banks of the Federal Reserve System.
"Reportable Event" means a reportable event as defined in Section 4043 of
ERISA and the regulations issued under such section, with respect to a Plan,
excluding, however, such events as to which the PBGC has by regulation waived
the requirement of Section 4043(a) of ERISA that it be notified within 30 days
of the occurrence of such event, provided that a failure to meet the minimum
funding standard of Section 412 of the Code and of Section 302 of ERISA shall be
a Reportable Event regardless of the issuance of any such waiver of the notice
requirement in accordance with either Section 4043(a) of ERISA or Section 412(d)
of the Code.
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"Required Lenders" means Lenders in the aggregate having at least 66-2/3%
of the Aggregate Commitment or, if the Aggregate Commitment has been terminated,
Lenders in the aggregate holding at least 66-2/3% of the aggregate unpaid
principal amount of the outstanding Advances.
"Reserve Requirement" means, with respect to an Interest Period, the daily
average during such Interest Period of the maximum aggregate reserve requirement
(including all basic, supplemental, marginal and other reserves) which is
imposed under Regulation D on Eurocurrency liabilities.
"Sale and Leaseback Transaction" means any sale or other transfer of
Property by any Person with the intent to lease such Property as lessee.
"Schedule" refers to a specific schedule to this Agreement, unless another
document is specifically referenced.
"SEC" means the Securities and Exchange Commission.
"Section" means a numbered section of this Agreement, unless another
document is specifically referenced.
"Securities Proceeds" means the Net Cash Proceeds of any Debt Issuance or
Equity Issuance.
"Significant Subsidiary" means, as of any date of determination, each
Subsidiary of the Borrower that meets any of the following criteria:
(i) the Borrower's and its other Subsidiaries' Investments in
and to such Subsidiary (and its respective Subsidiaries), as shown in the
consolidated financial statements of the Borrower and its Subsidiaries
prepared as of the end of the fiscal quarter ended most recently prior to
such date of determination, exceed 10% of the total consolidated assets of
the Borrower and its Subsidiaries; or
(ii) the assets of such Subsidiary (and its respective
Subsidiaries) represent more than 10% of the consolidated assets of the
Borrower and its Subsidiaries as would be shown in the consolidated
financial statements referred to in clause (i) above; or
(iii) such Subsidiary (and its respective Subsidiaries) is
responsible for more than 10% of the consolidated net sales or of the
consolidated net income of the Borrower and its Subsidiaries as reflected
in the financial statements referred to in clause (i) above;
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provided that each such determination of such sales or assets shall be made
after deducting all intercompany transactions which, in accordance with
Agreement Accounting Principles, would be eliminated in preparing consolidated
financial statements for the Borrower and its Subsidiaries.
"Single Employer Plan" means a Plan maintained by the Borrower or any
member of the Controlled Group for employees of the Borrower or any member of
the Controlled Group.
"Specific Proceeds" means the amount of the Net Cash Proceeds received from
any Asset Sale (or series of related Asset Sales) in excess of $1,000,000,
rounded down, if necessary, to an integral multiple of $500,000.
"Stockholders' Equity" means the Borrower's stockholders' equity,
determined in accordance with Agreement Accounting Principles, but without
giving effect to (1) any non-cash charge after the date hereof resulting from
any write-down of the Borrower's oil and gas properties to the full cost ceiling
limitations required by the full cost method of accounting for such properties
and (ii) any non-cash gain or loss on any hedging agreement resulting from the
requirements of SFAS 133.
"Subsidiary" of a Person means (i) any corporation more than 50% of the
outstanding securities having ordinary voting power of which shall at the time
be owned or controlled, directly or indirectly, by such Person or by one or more
of its Subsidiaries or by such Person and one or more of its Subsidiaries, or
(ii) any partnership, limited liability company, association, joint venture or
similar business organization more than 50% of the ownership interests having
ordinary voting power of which shall at the time be so owned or controlled.
Unless otherwise expressly provided, all references herein to a "Subsidiary"
shall mean a Subsidiary of the Borrower.
"Subsidiary Guaranty" means the Subsidiary Guaranty executed by various
Subsidiaries in favor of the Administrative Agent, for the ratable benefit of
the Lenders, substantially in the form of Exhibit F hereto.
"Swing Line Borrowing Notice" is defined in Section 2.6.2.
"Swing Line Commitment" means the obligation of the Swing Line Lender to
make Swing Line Loans up to a maximum principal amount of $15,000,000 at any one
time outstanding.
"Swing Line Lender" means Bank One or such other Lender which may succeed
to its rights and obligations as Swing Line Lender pursuant to the terms of this
Agreement.
"Swing Line Loan" means a loan made available to the Borrower by the Swing
Line Lender pursuant to Section 2.6.
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"Taxes" means any and all present or future taxes, duties, levies,
imposts, deductions, charges or withholdings, and any and all liabilities with
respect to the foregoing, but excluding Excluded Taxes and Other Taxes.
"Termination Date" means July 12, 2004 or such earlier date when the
Aggregate Commitment has been reduced to zero.
"Total Debt" means all Indebtedness of the Borrower and its Subsidiaries,
determined on a consolidated basis in accordance with Agreement Accounting
Principles.
"Total Outstandings" means, at any time, the aggregate principal amount of
all Loans hereunder at such time.
"Transferee" is defined in Section 12.4.
"Type" means, with respect to any Advance, its nature as a Floating Rate
Advance or a Eurodollar Advance.
"Unmatured Default" means an event which but for the lapse of time or the
giving of notice, or both, would, unless cured or waived, constitute a Default.
"Wholly-Owned Subsidiary" of a Person means (i) any Subsidiary all of the
outstanding voting securities of which shall at the time be owned or controlled,
directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries
of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of
such Person, or (ii) any partnership, limited liability company, association,
joint venture or similar business organization 100% of the ownership interests
having ordinary voting power of which shall at the time be so owned or
controlled.
The foregoing definitions shall be equally applicable to both the singular
and plural forms of the defined terms.
ARTICLE II
THE CREDITS
2.1 Commitments. From and including the date of this Agreement and to
the Termination Date, each Lender severally agrees, on the terms and conditions
set forth in this Agreement, to make loans to the Borrower from time to time
(each such loan, a "Ratable Loan") in an amount equal to its Pro Rata Share of
all Ratable Loans requested by the Borrower (but not exceeding in the aggregate
at any one time outstanding the amount of its Commitment). Subject to the terms
of this Agreement, the Borrower may borrow, repay and reborrow at any time prior
to the Termination Date.
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2.2 Types of Advances. Advances may be Floating Rate Advances or
Eurodollar Advances, or a combination thereof, as selected by the Borrower in
accordance with Sections 2.4 and 2.5.
2.3 Minimum Amount of Each Advance. Each Eurodollar Advance shall be
in the amount of $1,000,000 or a higher integral multiple thereof and each
Floating Rate Advance (other than an Advance made to repay Swing Line Loans)
shall be in the amount of $1,000,000 or a higher integral multiple of $500,000,
provided that any Floating Rate Advance may be in the amount of the unused
Aggregate Commitment.
2.4 Method of Selecting Types and Interest Periods for New Advances.
The Borrower shall select the Type of Advance and, in the case of each
Eurodollar Advance, the Interest Period applicable thereto from time to time.
The Borrower shall give the Administrative Agent irrevocable notice (a
"Borrowing Notice") not later than 10:00 a.m. (Chicago time) on the Borrowing
Date of each Floating Rate Advance and three Business Days before the Borrowing
Date of each Eurodollar Advance, specifying:
(i) the Borrowing Date, which shall be a Business Day, of such
Advance,
(ii) the aggregate amount of such Advance,
(iii) the Type of Advance selected, and
(iv) in the case of a Eurodollar Advance, the Interest Period
applicable thereto.
Each Borrowing Notice shall be in writing (or by telephone promptly confirmed in
writing) substantially in the form of Exhibit A. Not later than noon (Chicago
time) on the Borrowing Date for an Advance, each Lender shall make available its
Pro Rata Share of such Advance in funds immediately available in Chicago to the
Administrative Agent at its address specified pursuant to Article XIII. The
Administrative Agent will make the funds so received from the Lenders available
to the Borrower at the Administrative Agent's aforesaid address.
2.5 Conversion and Continuation of Outstanding Advances. Floating Rate
Advances shall continue as Floating Rate Advances unless and until such Floating
Rate Advances are converted into Eurodollar Advances pursuant to this Section
2.5 or are repaid. Each Eurodollar Advance shall continue as a Eurodollar
Advance, until the end of the then applicable Interest Period therefor, at which
time such Eurodollar Advance shall be automatically converted into a Floating
Rate Advance unless (x) such Advance is or was repaid or (y) the Borrower shall
have given the Administrative Agent a Conversion/Continuation Notice requesting
that, at the end of such Interest Period, such Advance continue as a Eurodollar
Advance for the same or another Interest Period. Subject to the terms of Section
2.3, the Borrower may elect from time to time to convert all or any part of any
Advance into an Advance of the other Type. The Borrower shall give the
Administrative Agent irrevocable notice (a "Conversion/Continuation Notice") of
each continuation or conversion of an Advance (other than an automatic
continuation or conversion as
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provided in this Section 2.5) not later than the time specified in Section 2.4
for the making of the Type of Advance to be continued or converted into,
specifying:
(i) the requested date, which shall be a Business Day, of
such conversion or continuation,
(ii) the aggregate amount and Type of the Advance which is to
be converted or continued,
(iii) in the case of conversion of an Advance, the Type of
Advance to be converted into,
(iv) the amount of the Advance which is to be converted or
continued, and
(v) in the case of conversion into or continuation of a
Eurodollar Advance, the duration of the Interest Period
applicable thereto.
Each Conversion/Continuation Notice given by the Borrower shall constitute a
representation and warranty by the Borrower that no Default or Unmatured Default
exists.
2.6 Swing Line Loans.
2.6.1 Amount of Swing Line Loans. Upon the satisfaction of the
applicable conditions precedent set forth in Article IV, from and including the
date of this Agreement and prior to the Termination Date, the Swing Line Lender
agrees, on the terms and conditions set forth in this Agreement, to make Swing
Line Loans to the Borrower from time to time in an aggregate principal amount
not to exceed the Swing Line Commitment, provided that the Total Outstandings
shall not at any time exceed the Aggregate Commitment. Subject to the terms of
this Agreement, the Borrower may borrow, repay and reborrow Swing Line Loans at
any time prior to the Termination Date.
2.6.2 Method of Borrowing. Not later than noon (Chicago time) on the
Borrowing Date of each Swing Line Loan, the Borrower shall deliver to the
Administrative Agent and the Swing Line Lender irrevocable notice (a "Swing Line
Borrowing Notice") specifying (i) the applicable Borrowing Date (which date
shall be a Business Day), and (ii) the aggregate amount of the requested Swing
Line Loan, which shall be an integral multiple of $100,000.
2.6.3 Making of Swing Line Loans. Promptly after receipt of a Swing
Line Borrowing Notice, the Administrative Agent shall notify each Lender by fax,
or other similar form of transmission, of the requested Swing Line Loan. Not
later than 2:00 p.m. (Chicago time) on the applicable Borrowing Date, the Swing
Line Lender shall make available the Swing Line Loan, in funds immediately
available in Chicago, to the Administrative Agent at its address specified
pursuant to Article XIII. The Administrative Agent will promptly make the funds
so received
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from the Swing Line Lender available to the Borrower on the Borrowing Date at
the Administrative Agent's aforesaid address.
2.6.4 Repayment of Swing Line Loans. The Swing Line Lender may, at any
time in its sole discretion, by notice to the Administrative Agent (which shall
promptly notify each Lender), require each Lender (including the Swing Line
Lender) to make a Ratable Loan in the amount of such Lender's Pro Rata Share of
such Swing Line Loan (including, without limitation, any interest accrued and
unpaid thereon), for the purpose of repaying such Swing Line Loan. Not later
than noon (Chicago time) on the date of any notice received pursuant to this
Section 2.6.4, each Lender shall make available its required Ratable Loan, in
funds immediately available in Chicago to the Administrative Agent at its
address specified pursuant to Article XIII. Ratable Loans made pursuant to this
Section 2.6.4 shall initially be Floating Rate Loans and thereafter may be
continued as Floating Rate Loans or converted into Eurodollar Loans in the
manner provided in Section 2.5 and subject to the other conditions and
limitations set forth in this Article II. Unless a Lender shall have notified
the Swing Line Lender, prior to the making of any Swing Line Loan, that any
applicable condition precedent set forth in Article IV had not then been
satisfied, such Lender's obligation to make Ratable Loans pursuant to this
Section 2.6.4 to repay Swing Line Loans shall be unconditional, continuing,
irrevocable and absolute and shall not be affected by any circumstance,
including, without limitation, (a) any set-off, counterclaim, recoupment,
defense or other right which such Lender may have against the Administrative
Agent, the Swing Line Lender or any other Person, (b) the occurrence or
continuance of a Default or Unmatured Default, (c) any adverse change in the
condition (financial or otherwise) of the Borrower, or (d) any other
circumstance, happening or event whatsoever. If any Lender fails to make payment
to the Administrative Agent of any amount due under this Section 2.6.4, the
Administrative Agent shall be entitled to receive, retain and apply against such
obligation the principal and interest otherwise payable to such Lender hereunder
until the Administrative Agent receives such payment from such Lender or such
obligation is otherwise fully satisfied. In addition to the foregoing, if for
any reason any Lender fails to make payment to the Administrative Agent of any
amount due under this Section 2.6.4, such Lender shall be deemed, at the option
of the Administrative Agent, to have unconditionally and irrevocably purchased
from the Swing Line Lender, without recourse or warranty, an undivided interest
and participation in the applicable Swing Line Loan in the amount of such
Ratable Loan, and such interest and participation may be recovered from such
Lender together with interest thereon at the Federal Funds Effective Rate for
each day during the period commencing on the date of demand and ending on the
date such amount is received.
2.7 Commitment Fee; Voluntary Reductions in Aggregate Commitment. The
Borrower agrees to pay to the Administrative Agent for the account of each
Lender a commitment fee at a per annum rate equal to the Commitment Fee Rate on
the daily unused portion of such Lender's Commitment from the date hereof to and
including the Termination Date, payable on each Payment Date hereafter and on
the Termination Date. The Borrower may permanently reduce the Aggregate
Commitment in whole, or in part ratably among the Lenders in accordance with
their respective Pro Rata Shares, in integral multiples of $1,000,000, upon at
least three Business Days' written notice to the Administrative Agent, which
notice shall specify
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the amount of any such reduction, provided that the amount of the Aggregate
Commitment may not be reduced below the Total Outstandings. All accrued
commitment fees shall be payable on the effective date of any termination of the
obligations of the Lenders to make Loans hereunder.
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2.8 Mandatory Reductions in Aggregate Commitment.(a) The Aggregate
Commitment shall be reduced by the following amounts on the following dates
(each a "Commitment Reduction Date"):
Commitment Reduction Date Amount of Reduction
========================= ===================
December 31, 2001 $ 5,000,000
June 30, 2002 $15,000,000
June 30, 2003 $15,000,000
The amount of any Aggregate Commitment reduction pursuant to Section 2.8(b)
shall be applied to reduce any remaining Aggregate Commitment Reductions
contemplated by this subsection (a), commencing with the next succeeding
Aggregate Commitment reduction so contemplated.
(b) Within five Business Days after the receipt by the Borrower or any
Subsidiary of any Specific Proceeds, Designated Proceeds or Securities Proceeds
(any of the foregoing, "Proceeds"), the Aggregate Commitment shall be reduced by
an amount equal to such Proceeds; provided that (i) no such reduction shall be
required from (x) the first $5,000,000 of Designated Proceeds received after the
date of this Agreement; or (y) the first $5,000,000 of Securities Proceeds
received after the date of this Agreement; (ii) the amount of Proceeds to be
applied on any single occasion shall be rounded down, if necessary, to an
integral multiple of $500,000 (it being understood that the amount of the
applicable Proceeds in excess of any such integral multiple shall be applied on
the next date on which such type of Proceeds is applied); and (iii) no Net Cash
Proceeds of any Equity Issuance shall be required to be applied to reduce the
Aggregate Commitment pursuant to this subsection (b) to the extent that, after
applying such Net Cash Proceeds to the prepayment of Indebtedness, the Debt to
Capitalization Ratio would be less than 0.65 to 1.
(c) Notwithstanding subsections (a) and (b) above, no reduction of the
Aggregate Commitment shall be required pursuant to subsection (a) or (b) to the
extent that the Aggregate Commitment would be reduced to less than $125,000,000
as a result thereof.
(d) On any date on which a Change of Control occurs, the Aggregate
Commitment shall be immediately reduced to zero.
2.9 Prepayments.
(a) The Borrower may from time to time prepay, without penalty
or premium, all outstanding Floating Rate Advances or, in an aggregate amount
of $1,000,000 or a higher integral multiple of $500,000 (or, in the case of any
prepayment of an Advance made to repay a Swing Line Loan, in such other amount
as is necessary to repay such Advance in full), any portion of the outstanding
Floating Rate Advances upon notice to the Administrative Agent not later
than 11:00 a.m. (Chicago time) on the date of prepayment. The Borrower may from
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time to time prepay, without penalty or premium, all outstanding Eurodollar
Advances or, in an aggregate amount of $1,000,000 or a higher integral multiple
thereof, any portion of the outstanding Eurodollar Advances upon three Business
Days' prior notice to the Administrative Agent. The Borrower may at any time
pay, without penalty or premium, all outstanding Swing Line Loans or, in the
amount of $100,000 or a higher integral multiple thereof, any portion of the
outstanding Swing Line Loans, with notice to the Administrative Agent and the
Swing Line Lender by 11:00 a.m. (Chicago time) on the date of repayment.
(b) On any date on which the Aggregate Commitment is reduced pursuant
to Section 2.8, the Borrower shall make a prepayment of Loans in the amount, if
any, by which the Total Outstandings exceed the Aggregate Commitment as so
reduced. Any partial prepayment pursuant to this subsection (b) shall be applied
to such Loans as the Borrower may direct or, in the absence of such direction,
as the Administrative Agent may reasonably determine.
(c) Any prepayment of a Eurodollar Loan on a day other than the last
day of an Interest Period therefor shall be subject to Section 3.4.
2.10 Interest Rates, etc. Each Floating Rate Advance shall bear
interest on the outstanding principal amount thereof, for each day from and
including the date such Advance is made or is converted from a Eurodollar
Advance into a Floating Rate Advance pursuant to Section 2.5, to but excluding
the date it is paid or is converted into a Eurodollar Advance pursuant to
Section 2.5, at a rate per annum equal to the Floating Rate for such day. Each
Swing Line Loan shall bear interest on the outstanding principal amount thereof,
for each day from and including the day such Swing Line Loan is made to but
excluding the date it is paid, at a rate per annum equal to the Alternate Base
Rate for such day or such other rate as may be mutually agreed upon by the
Borrower and the Swing Line Lender from time to time; provided that the rate
applicable to any Swing Line Loan on any day shall not be less than the
Eurodollar Rate which would be applicable to a Eurodollar Loan with a one-month
Interest Period beginning on such day (or on the immediately preceding Business
Day). Changes in the rate of interest on that portion of any Advance maintained
as a Floating Rate Advance and on any Swing Line Loan bearing interest at the
Alternate Base Rate will take effect simultaneously with each change in the
Alternate Base Rate. Each Eurodollar Advance shall bear interest on the
outstanding principal amount thereof from and including the first day of each
Interest Period applicable thereto to (but not including) the last day of such
Interest Period at the interest rate determined by the Administrative Agent as
applicable to such Eurodollar Advance based upon the Borrower's selections under
Sections 2.4 and 2.5 and otherwise in accordance with the terms hereof.
2.11 Rates Applicable After Default. Notwithstanding anything to the
contrary herein, during the continuance of a Default or Unmatured Default the
Required Lenders may, at their option, by notice to the Borrower (which notice
may be revoked at the option of the Required Lenders notwithstanding any
provision ofSection 8.2 requiring unanimous consent of the Lenders to changes in
interest rates), declare that no Advance may be made as, converted into or
continued as a Eurodollar Advance. During the continuance of a Default the
Required Lenders
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may, at their option, by notice to the Borrower (which notice may be revoked at
the option of the Required Lenders notwithstanding any provision of Section 8.2
requiring unanimous consent of the Lenders to changes in interest rates),
declare that (i) each Eurodollar Advance shall bear interest for the remainder
of the applicable Interest Period at the rate otherwise applicable to such
Interest Period plus 2% per annum and (ii) each Floating Rate Advance and each
Swing Line Loan shall bear interest at a rate per annum equal to the Floating
Rate in effect from time to time plus 2% per annum, provided that, during the
continuance of a Default under Section 7.1.6 or 7.1.7, the interest rates set
forth in clauses (i) and (ii) above shall be applicable to all Advances and
Swing Line Loans without any election or action on the part of the
Administrative Agent or any Lender.
2.12 Maturity. Any outstanding Advances and Swing Line Loans and all
other accrued and unpaid Obligations shall be paid in full by the Borrower on
the scheduled Termination Date or such earlier date required by Section 2.9 or
Section 8.1.
2.13 Method of Payment. All payments of the Obligations hereunder shall
be made, without setoff, deduction, or counterclaim, in immediately available
funds to the Administrative Agent at the Administrative Agent's address
specified pursuant to Article XIII, or at any other Lending Installation of the
Administrative Agent specified in writing by the Administrative Agent to the
Borrower, by noon (local time) on the date when due and (except for payments
with respect to Swing Line Loans or as otherwise specifically required
hereunder) shall be applied ratably by the Administrative Agent among the
Lenders in accordance with their respective Pro Rata Shares. Each payment
delivered to the Administrative Agent for the account of any Lender shall be
delivered promptly by the Administrative Agent to such Lender in the same type
of funds that the Administrative Agent received at its address specified
pursuant to Article XIII or at any Lending Installation specified in a notice
received by the Administrative Agent from such Lender. The Administrative Agent
is hereby authorized to charge the account of the Borrower maintained with Bank
One for each payment of principal, interest and fees as it becomes due
hereunder.
2.14 Noteless Agreement; Evidence of Indebtedness. (i) Each Lender
shall maintain in accordance with its usual practice an account or accounts
evidencing the indebtedness of the Borrower to such Lender resulting from each
Loan made by such Lender from time to time, including the amounts of principal
and interest payable and paid to such Lender from time to time hereunder.
(ii) The Administrative Agent shall also maintain accounts in which it
will record (a) the amount of each Loan made hereunder, the Type thereof and,
if applicable, each Interest Period with respect thereto, (b) the amount of
any principal or interest due and payable or to become due and payable from
the Borrower to each Lender hereunder and (c) the amount of any sum received by
the Administrative Agent hereunder from the Borrower and each Lender's share
thereof.
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(iii) The entries maintained in the accounts maintained pursuant to
subsections (i) and (ii) above shall be prima facie evidence of the existence
and amounts of the Obligations therein recorded; provided that the failure of
the Administrative Agent or any Lender to maintain such accounts or any error
therein shall not in any manner affect the obligation of the Borrower to repay
the Obligations in accordance with their terms.
(iv) Any Lender may request that its Loans be evidenced by a Note. In
such event, the Borrower shall prepare, execute and deliver to such Lender a
Note payable to the order of such Lender. Thereafter, the Loans evidenced by
such Note and interest thereon shall at all times (including after any
assignment pursuant to Section 12.3) be represented by one or more Notes
payable to the order of the payee named therein or any assignee pursuant to
Section 12.3, except to the extent that any such Lender or assignee subsequently
returns any such Note for cancellation and requests that such Loans once again
be evidenced as described in subsections (i) and (ii) above.
2.15 Telephonic Notices. The Borrower hereby authorizes the Lenders and
the Administrative Agent to extend, convert or continue Advances and Swing Line
Loans, to effect selections of Types of Advances and to transfer funds based on
telephonic notices made by any person or persons the Administrative Agent or any
Lender in good faith believes to be acting on behalf of the Borrower, it being
understood that the foregoing authorization is specifically intended to allow
Borrowing Notices, Swing Line Borrowing Notices and Conversion/Continuation
Notices to be given telephonically. The Borrower agrees to deliver promptly to
the Administrative Agent a written confirmation, if such confirmation is
requested by the Administrative Agent or any Lender, of each telephonic notice
signed by an Authorized Officer. If the written confirmation differs in any
material respect from the action taken by the Administrative Agent and the
Lenders, the records of the Administrative Agent and the Lenders shall govern
absent manifest error.
2.16 Interest Payment Dates; Interest and Fee Basis. Interest accrued
on each Floating Rate Advance and Swing Line Loan shall be payable on each
Payment Date, on any date on which such Floating Rate Advance or Swing Line Loan
is prepaid, whether due to acceleration or otherwise, and at maturity. Interest
accrued on each Eurodollar Advance shall be payable on the last day of each
applicable Interest Period, on any date on which such Advance is prepaid,
whether by acceleration or otherwise, or is converted into a Floating Rate
Advance, and at maturity. Interest accrued on each Eurodollar Advance having an
Interest Period longer than three months shall also be payable on the last day
of each three-month interval during such Interest Period. Interest and
commitment fees shall be calculated for actual days elapsed on the basis of a
360-day year, except that interest accruing at the Prime Rate shall be
calculated for actual days elapsed on the basis of a 365, or when appropriate
366, day year. Interest shall be payable for the day an Advance or a Swing
Line Loan is made but not for the day of any payment on the amount paid if
payment is received prior to noon (local time) at the place of payment. If any
payment of principal of or interest on an Advance or a Swing Line Loan shall
become due on a day which is not a Business Day, such payment shall be made on
the next
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succeeding Business Day and, in the case of a principal payment, such extension
of time shall be included in computing interest in connection with such payment.
2.17 Notification of Advances, Interest Rates, Prepayments and
Commitment Reductions. Promptly after receipt thereof, the Administrative Agent
will notify each Lender of the contents of each Aggregate Commitment reduction
notice, Borrowing Notice, Swing Line Borrowing Notice, Conversion/Continuation
Notice, and repayment notice received by it hereunder. The Administrative Agent
will notify each Lender of the interest rate applicable to each Eurodollar
Advance promptly upon determination of such interest rate and will give each
Lender prompt notice of each change in the Alternate Base Rate.
2.18 Lending Installations. Each Lender may book its Loans at any
Lending Installation selected by such Lender and may change its Lending
Installation from time to time. All terms of this Agreement shall apply to any
such Lending Installation and the Loans and any Notes issued hereunder shall be
deemed held by each Lender for the benefit of any such Lending Installation.
Each Lender may, by written notice to the Administrative Agent and the Borrower
in accordance with Article XIII, designate replacement or additional Lending
Installations through which Loans will be made by it and for whose account Loan
payments are to be made.
2.19 Non-Receipt of Funds by the Administrative Agent. Unless the
Borrower or Lender, as the case may be, notifies the Administrative Agent prior
to the date on which it is scheduled to make payment to the Administrative Agent
of (i) in the case of a Lender, the proceeds of a Loan or (ii) in the case
of the Borrower, a payment of principal, interest or fees to the Administrative
Agent for the account of the Lenders, that it does not intend to make such
payment, the Administrative Agent may assume that such payment has been made.
The Administrative Agent may, but shall not be obligated to, make the amount of
such payment available to the intended recipient in reliance upon such
assumption. If such Lender or the Borrower, as the case may be, has not in
fact made such payment to the Administrative Agent, the recipient of such
payment shall, on demand by the Administrative Agent, repay to the
Administrative Agent the amount so made available together with interest
thereon in respect of each day during the period commencing on the date such
amount was so made available by the Administrative Agent until the date the
Administrative Agent recovers such amount at a rate per annum equal to (x) in
the case of payment by a Lender, the Federal Funds Effective Rate for such
day for the first three days and, thereafter, the interest rate applicable to
the relevant Loan or (y) in the case of payment by the Borrower, the interest
rate applicable to the relevant Loan.
2.20 Replacement of Lender. If the Borrower is required pursuant to
Section 3.1, 3.2 or 3.5 to make any additional payment to any Lender or if any
Lender's obligation to make or continue, or to convert Advances into, Eurodollar
Advances shall be suspended pursuant to Section 3.3 (any Lender so affected an
"Affected Lender"), the Borrower may elect, if such amounts continue to be
charged or such suspension is still effective, to replace such Affected Lender
as a Lender party to this Agreement, provided that no Default or Unmatured
Default shall have occurred and be continuing at the time of such replacement,
and provided, further, that,
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concurrently with such replacement, (i) another bank or other entity which is
reasonably satisfactory to the Borrower and the Administrative Agent shall
agree, as of such date, to purchase for cash the Advances and other Obligations
due to the Affected Lender pursuant to an assignment substantially in the form
of Exhibit C and to become a Lender for all purposes under this Agreement and to
assume all obligations of the Affected Lender to be terminated as of such date
and to comply with the requirements of Section 12.3 applicable to assignments,
and (ii) the Borrower shall pay to such Affected Lender in same day funds on the
day of such replacement (A) all interest, fees and other amounts then accrued
but unpaid to such Affected Lender by the Borrower hereunder to and including
the date of termination, including without limitation payments due to such
Affected Lender under Sections 3.1, 3.2 and 3.5, and (B) an amount, if any,
equal to the payment which would have been due to such Lender on the day of such
replacement under Section 3.4 had the Loans of such Affected Lender been prepaid
on such date rather than sold to the replacement Lender.
ARTICLE III
YIELD PROTECTION; TAXES
3.1 Yield Protection. (a) If, on or after the date of this Agreement,
(x) the adoption of or any change in any law or any governmental or
quasi-governmental rule, regulation, policy, guideline or directive (whether or
not having the force of law), or (y) any change in the interpretation or
administration thereof by any governmental or quasi-governmental authority,
central bank or comparable agency charged with the interpretation or
administration thereof, or (z) compliance by any Lender or applicable Lending
Installation with any request or directive (whether or not having the force of
law) issued on or after the date hereof of any such authority, central bank or
comparable agency:
(i) subjects any Lender or any applicable Lending
Installation to any Taxes, or changes the basis of
taxation of payments (other than with respect to Excluded
Taxes) to any Lender in respect of its Eurodollar Loans,
or
(ii) imposes or increases or deems applicable any reserve,
assessment, insurance charge, special deposit or similar
requirement against assets of, deposits with or for the
account of, or credit extended by, any reserves and
assessments taken into account in determining the
interest rate applicable to Eurodollar Advances), or
(iii) imposes any other condition the result of which is to
increase the cost to any Lender or any applicable Lending
Installation of making, funding or maintaining its
Eurodollar Loans or reduces any amount receivable by any
Lender or any applicable Lending Installation i
connection with its Eurodollar Loans, or requires any
Lender or any applicable Lending Installation to make any
payment
-24-
calculated by reference to the amount of Eurodollar Loans
held or interest received by it, by an amount deemed
material by such Lender,
and the result of any of the foregoing is to increase the cost to such Lender or
applicable Lending Installation of making or maintaining its Eurodollar Loans or
Commitment or to reduce the return received by such Lender or applicable Lending
Installation in connection with such Eurodollar Loans or Commitment, then,
within 15 days of demand by such Lender, the Borrower shall pay such Lender such
additional amount or amounts as will compensate such Lender for such increased
cost or reduction in amount received. A Lender shall not be entitled to demand
compensation or be compensated hereunder to the extent that such compensation
relates to any period of time more than 60 days prior to the date upon which
such Lender first notified the Borrower of the occurrence of the event entitling
such Lender to such compensation (unless, and to the extent, that any such
compensation so demanded shall relate to the retroactive application of any
event so notified to the Borrower).
(b) Without limiting subsection (a) above, any Lender may require the
Borrower to pay, contemporaneously with each payment of interest on any
Eurodollar Loan of such Lender, additional interest on such Eurodollar Loan at a
rate per annum determined by such Lender up to but not exceeding the excess of
(i) (A) the applicable Eurodollar Base Rate divided by (B) one minus the Reserve
Requirement over (ii) the applicable Eurodollar Base Rate. Any Lender wishing to
require payment of such additional interest (x) shall so notify the Borrower and
the Administrative Agent, in which case such additional interest on the
Eurodollar Loans of such Lender shall be payable to such Lender at the place
indicated in such notice with respect to each Interest Period commencing at
least three Business Days after the giving of such notice and (y) shall notify
the Borrower at least five Business Days prior to each date on which interest is
payable on any Eurodollar Loan of the amount then due it under this Section 3.1.
3.2 Changes in Capital Adequacy Regulations. If a Lender determines
the amount of capital required or expected to be maintained by such Lender, any
Lending Installation of such Lender or any corporation controlling such Lender
is increased as a result of a Change, then, within 15 days of demand by such
Lender, the Borrower shall pay such Lender the amount necessary to compensate
for any shortfall in the rate of return on the portion of such increased capital
which such Lender determines is attributable to this Agreement, its Loans or its
Commitment to make Loans hereunder (after taking into account such Lender's
policies as to capital adequacy). "Change" means (i) any change after the date
of this Agreement in the Risk-Based Capital Guidelines or (ii) any adoption of
or change in any other law, governmental or quasi-governmental rule, regulation,
policy, guideline, interpretation, or directive (whether or not having the force
of law) after the date of this Agreement which affects the amount of capital
required or expected to be maintained by any Lender or any Lending Installation
or any corporation controlling any Lender. "Risk-Based Capital Guidelines" means
(i) the risk-based capital guidelines in effect in the United States on the date
of this Agreement, including transition rules, and (ii) the corresponding
capital regulations promulgated by regulatory authorities outside the United
States implementing the July 1988 report of the Basle Committee on Banking
Regulation and Supervisory Practices Entitled "International Convergence of
Capital
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Measurements and Capital Standards," including transition rules, and any
amendments to such regulations adopted prior to the date of this Agreement.
3.3 Availability of Types of Advances. If any Lender reasonably
determines that maintenance of its Eurodollar Loans at a suitable Lending
Installation would violate any applicable law, rule, regulation, or directive,
whether or not having the force of law, or if the Required Lenders reasonably
determine that (i) deposits of a type and maturity appropriate to match fund
Eurodollar Advances are not available or (ii) the Eurodollar Base Rate does not
accurately reflect the cost of obtaining funds to make or maintain Eurodollar
Advances, then the Administrative Agent shall suspend the availability of
Eurodollar Advances and require any affected Eurodollar Advances to be repaid or
converted to Floating Rate Advances (on or before the date required by such law,
rule, regulation or directive), subject to the payment of any funding
indemnification amounts required by Section 3.4.
3.4 Funding Indemnification. If any payment of a Eurodollar Advance
occurs on a date which is not the last day of the applicable Interest Period,
whether because of acceleration, prepayment or otherwise, or a Eurodollar
Advance is not made, continued or converted on a date specified by the Borrower
for any reason other than default by the Lenders, the Borrower will indemnify
each Lender for any loss or cost incurred by it resulting therefrom, including,
without limitation, any loss or cost in liquidating or employing deposits
acquired to fund or maintain such Eurodollar Rate Advance.
3.5 Taxes. (i) All payments by the Borrower to or for the account of
any Lender or the Administrative Agent hereunder or under any Note shall be made
free and clear of and without deduction for any and all Taxes. If the Borrower
shall be required by law to deduct any Taxes from or in respect of any sum
payable hereunder to any Lender or the Administrative Agent, (a) the sum payable
shall be increased as necessary so that after making all required deductions
(including deductions applicable to additional sums payable under this Section
3.5) such Lender or the Administrative Agent (as the case may be) receives an
amount equal to the sum it would have received had no such deductions been made,
(b) the Borrower shall make such deductions, (c) the Borrower shall pay the full
amount deducted to the relevant authority in accordance with applicable law and
(d) the Borrower shall furnish to the Administrative Agent the original copy of
a receipt evidencing payment thereof within 30 days after such payment is made.
(ii) In addition, the Borrower hereby agrees to pay any present or
future stamp or documentary taxes and any other excise or property taxes,
charges or similar levies which arise from any payment made hereunder or under
any Note or from the execution or delivery of, or otherwise with respect to,
this Agreement or any Note ("Other Taxes").
(iii) The Borrower hereby agrees to indemnify the Administrative Agent
and each Lender for the full amount of Taxes or Other Taxes (including, without
limitation, any Taxes or Other Taxes imposed on amounts payable under this
Section 3.5) paid by the Administrative Agent or such Lender and any liability
(including penalties, interest and expenses) arising therefrom or
-26-
with respect thereto. Payments due under this indemnification shall be made
within 30 days of the date the Administrative Agent or such Lender makes demand
therefor pursuant to Section 3.6.
(iv) Each Lender that is not incorporated under the laws of the United
States of America or a state thereof (each a "Non-U.S. Lender") agrees that it
will, not less than ten Business Days after the date of this Agreement, (i)
deliver to each of the Borrower and the Administrative Agent two duly completed
copies of United States Internal Revenue Service Form W-8 BEN or W-8 ECI,
certifying in either case that such Lender is entitled to receive payments under
this Agreement without deduction or withholding of any United States federal
income taxes, and (ii) deliver to each of the Borrower and the Administrative
Agent a United States Internal Revenue Form W-8 or W-9, as the case may be, and
certify that it is entitled to an exemption from United States backup
withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of
the Borrower and the Administrative Agent (x) renewals or additional copies of
such form (or any successor form) on or before the date that such form expires
or becomes obsolete, and (y) after the occurrence of any event requiring a
change in the most recent forms so delivered by it, such additional forms or
amendments thereto as may be reasonably requested by the Borrower or the
Administrative Agent. All forms or amendments described in the preceding
sentence shall certify that such Lender is entitled to receive payments under
this Agreement without deduction or withholding of any United States federal
income taxes, unless an event (including without limitation any change in
treaty, law or regulation) has occurred prior to the date on which any such
delivery would otherwise be required which renders all such forms inapplicable
or which would prevent such Lender from duly completing and delivering any such
form or amendment with respect to it and such Lender advises the Borrower and
the Administrative Agent that it is not capable of receiving payments without
any deduction or withholding of United States federal income tax.
(v) For any period during which a Non-U.S. Lender has failed to
provide the Borrower with an appropriate form pursuant to subsection (iv), above
(unless such failure is due to a change in treaty, law or regulation, or any
change in the interpretation or administration thereof by any governmental
authority, occurring subsequent to the date on which a form originally was
required to be provided), such Non-U.S. Lender shall not be entitled to
indemnification under this Section 3.5 with respect to Taxes imposed by the
United States; provided that, should a Non-U.S. Lender which is otherwise
exempt from or subject to a reduced rate of withholding tax become subject to
Taxes because of its failure to deliver a form required under subsection (iv),
above, the Borrower shall take such steps as such Non-U.S. Lender shall
reasonably request to assist such Non-U.S. Lender to recover such Taxes.
(vi) Any Lender that is entitled to an exemption from or reduction
of withholding tax with respect to payments under this Agreement or any Note
pursuant to the law of any relevant jurisdiction or any treaty shall deliver to
the Borrower (with a copy to the Administrative Agent), at the time or times
prescribed by applicable law, such properly completed and executed documentation
prescribed by applicable law as will permit such payments to be made without
withholding or at a reduced rate.
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(vii) If the U.S. Internal Revenue Service or any other governmental
authority of the United States or any other country or any political subdivision
thereof asserts a claim that the Administrative Agent did not properly withhold
tax from amounts paid to or for the account of any Lender (because the
appropriate form was not delivered or properly completed, because such Lender
failed to notify the Administrative Agent of a change in circumstances which
rendered its exemption from withholding ineffective, or for any other reason),
such Lender shall indemnify the Administrative Agent fully for all amounts paid,
directly or indirectly, by the Administrative Agent as tax, withholding
therefor, or otherwise, including penalties and interest, and including taxes
imposed by any jurisdiction on amounts payable to the Administrative Agent under
this subsection, together with all costs and expenses related thereto (including
attorneys fees and time charges of attorneys for the Administrative Agent, which
attorneys may be employees of the Administrative Agent). The obligations of the
Lenders under this Section 3.5(vii) shall survive the payment of the Obligations
and termination of this Agreement.
3.6 Lender Statements; Survival of Indemnity. To the extent
reasonably possible, each Lender shall designate an alternate Lendin
Installation with respect to its Eurodollar Loans to reduce any liability of
the Borrower to such Lender under Sections 3.1, 3.2 and 3.5 or to avoid the
unavailability of Eurodollar Advances under Section 3.3, so long as such
designation is not, in the reasonable judgment of such Lender, disadvantageous
to such Lender. Each Lender shall deliver a written statement of such Lender to
the Borrower (with a copy to the Administrative Agent) as to the amount due, if
any, under Section 3.1, 3.2, 3.4 or 3.5. Such written statement shall set
forth in reasonable detail the calculations upon which such Lender determined
such amount and shall be rebuttable presumptive evidence of the amount thereof.
Determination of amounts payable under such Sections in connection with a
Eurodollar Loan shall be calculated as though each Lender funded its Eurodollar
Loan through the purchase of a deposit of the type and maturity corresponding to
the deposit used as a reference in determining the Eurodollar Base Rate
applicable to such Eurodollar Loan, whether in fact that is the case or not. The
obligations of the Borrower under Sections 3.1, 3.2, 3.4 and 3.5 shall survive
payment of the Obligations and termination of this Agreement.
ARTICLE IV
CONDITIONS PRECEDENT
4.1 Initial Loan. The Lenders (or, if applicable, the Swing Line
Lender) shall not be required to make the initial Loan hereunder unless (a)
concurrently with the making of such Loan, the Borrower shall have paid in full
all principal, interest, fees and other amounts payable under the Credit
Agreement dated as of July 17, 2000 among between the Borrower, various lenders
and Bank One, as administrative agent, and (b) the Borrower shall have furnished
to the Administrative Agent with sufficient copies for the Lenders:
(i) Copies of the articles or certificate of incorporation or other
organizational documents of the Borrower and each Guarantor,
together with all amendments,
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and a certificate of good standing, each certified by the
appropriate governmental officer in its jurisdiction of
organization.
(ii) Copies certified by the Secretary or Assistant Secretary of the
Borrower and each Guarantor, of its by-laws (to the extent
applicable) and of its Board of Directors' resolutions, members'
resolutions or similar documents authorizing the execution of the
Loan Documents to which the Borrower or such Guarantor is a party.
(iii) An incumbency certificate, executed by the Secretary or Assistant
Secretary of the Borrower and each Guarantor, which shall identify
by name and title and bear the signatures of the officers of the
Borrower or such Guarantor authorized to sign the Loan Documents
to which the Borrower or such Guarantor is a party, upon which
certificate the Administrative Agent and the Lenders shall be
entitled to rely until informed of any change in writing by the
Borrower or such Guarantor.
(iv) Evidence, in form and substance satisfactory to the Administrative
Agent, that the Borrower has obtained all governmental approvals
necessary for it to enter into the Loan Documents.
(v) A certificate, signed by an Authorized Officer, stating that on
the initial Borrowing Date (x) no Default or Unmatured Default has
occurred and is continuing and (y) the representations and
warranties set forth in Article V are true and correct as of such
date.
(vi) A written opinion of counsel to the Borrower and the Guarantors,
addressed to the Lenders in substantially the form of Exhibit B.
(vii) Any Notes requested by a Lender pursuant to Section 2.14 payable
to the order of each such requesting Lender.
(viii) Written money transfer instructions, in substantially the form of
Exhibit D, addressed to the Administrative Agent and signed by an
Authorized Officer, together with such other related money
transfer authorizations as the Administrative Agent may have
reasonably requested.
(ix) The Subsidiary Guaranty signed by sufficient Subsidiaries so that
the Borrower is in compliance with Section 6.3.4.
(x) Copies, certified as being correct and complete by an Authorized
Officer, of the Indenture dated as of December 1, 1995, between
the Borrower and Bank One (then known as The First National Bank
of Chicago), as trustee, and all supplements thereto.
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(xi) Such other documents as any Lender or its counsel may have
reasonably requested.
4.2 Each Loan. No Lender shall be required to make any Loan (other
than a Ratable Loan made to repay a Swing Line Loan pursuant to Section 2.6.4)
unless on the applicable Borrowing Date:
(i) No Default or Unmatured Default exists or will result therefrom.
(ii) The representations and warranties contained in Article V are true
and correct as of such Borrowing Date except to the extent any
such representation or warranty is stated to relate solely to an
earlier date, in which case such representation or warranty shall
have been true and correct on and as of such earlier date.
(iii) All legal matters incident to the making of such Loan shall be
reasonably satisfactory to the Administrative Agent and its
counsel.
Each Borrowing Notice with respect to an Advance and each request for a
Swing Line Loan shall constitute a representation and warranty by the Borrower
that the conditions contained in subsections (i) and (ii) above have been
satisfied. For the avoidance of doubt, the conversion or continuation of a
Ratable Loan shall not constitute the making of a Loan.
ARTICLE V
REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants to the Lenders that:
5.1 Organization. The Borrower and each of its Subsidiaries are duly
organized, validly existing and in good standing under the laws of the states of
their organization and have all requisite authority to conduct their respective
businesses in each jurisdiction in which the failure to have such authority,
singly or in the aggregate, could reasonably be expected to have a Material
Adverse Effect. The Borrower and each of its Subsidiaries have full power and
authority to carry on their business as now conducted.
5.2 Authorization and Validity. The Borrower and each Guarantor has
the power and authority and egal right to execute and deliver the Loan
Documents to which it is a party and to perform its obligations thereunder. The
execution and delivery by the Borrower and each Guarantor of the Loan Documents
to which it is a party have been duly authorized by proper organizational
proceedings, and the Loan Documents to which the Borrower and such Guarantor
is a party constitute legal, valid and binding obligations of the Borrower or
such Guarantor, as the case may be, enforceable against the Borrower or such
Guarantor, as the case may be, in accordance with their terms, except as
enforceability may be limited by bankruptcy, insolvency or similar laws
affecting the enforcement of creditors' rights generally.
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5.3 Financial Statements. The December 31, 2000 and the March 31,
2001 consolidated financial statements of the Borrower and the Subsidiaries
heretofore delivered to the Administrative Agent and the Lenders were prepared
in accordance with generally accepted accounting principles in effect on the
date such statements were prepared and fairly present the financial position and
results of operations of the Borrower and its Subsidiaries at such dates and the
consolidated results of their operations for the periods then ended.
5.4 Subsidiaries. Schedule 5.4 hereto contains an accurate list of
all of the presently existing Subsidiaries, setting forth their respective
jurisdictions of organization and the percentage of their respective capital
stock or membership interests owned by the Borrower or other Subsidiaries. All
of the issued and outstanding shares of capital stock of each corporate
Subsidiary have been duly authorized and issued and are fully paid and
nonassessable.
5.5 ERISA. Each Plan is in material compliance with, an has been
administered in material compliance with, all applicable provisions of ERISA,
the Code and any other applicable federal or state law, except where the failure
to so comply would not (individually or in the aggregate) reasonably be expected
to have a Material Adverse Effect, and no event or condition has occurred and is
continuing as to which the Borrower is under an obligation to furnish a report
to the Administrative Agent and the Lenders under Section 6.1(d) and which would
reasonably be expected (individually or in the aggregate) to have a Material
Adverse Effect.
5.6 Defaults. No Default or Unmatured Default has occurred and is
continuing.
5.7 Accuracy of Information. No information, exhibit or report
furnished by the Borrower or any Subsidiary to the Administrative Agent or any
Lender in connection with the negotiation of this Agreement contains any
material misstatement of fact or omitted to state a material fact necessary to
make the statements contained therein not misleading.
5.8 Regulation U. Neither the Borrower nor any Subsidiary is engaged
principally, or as one of its important activities, in the business of extending
credit for the purpose of purchasing or carrying Margin Stock. Margin Stock
constitutes less than 25% of the consolidated assets of the Borrower and its
Subsidiaries which are subject to any limitation on sale or pledge or any other
restriction hereunder. No part of the proceeds of any Loan will be used to
purchase or carry any Margin Stock in violation of Regulation U.
5.9 No Adverse Change. Since March 31, 2001 there has been no change
in the business, property, condition (financial or otherwise) or results of
operations of the Borrower and its Subsidiaries which could reasonably be
expected to have a Material Adverse Effect.
5.10 Taxes. The Borrower and its Subsidiaries have filed all United
States federal tax returns and all other tax returns which, to the Knowledge of
the Borrower, are required to be filed and have paid all taxes due pursuant to
said returns or material taxes due pursuant to any assessment received by the
Borrower or any Subsidiary, except in both cases such taxes, if any, as are
being contested in good faith and as to which adequate reserves have been
provided in
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accordance with Agreement Accounting Principles. The charges, accruals and
reserves on the books of the Borrower and its Subsidiaries in respect of any
taxes or other governmental charges are adequate in accordance with Agreement
Accounting Principles.
5.11 Liens. There are no Liens on any of the properties or assets of
the Borrower or any Subsidiary except (i) Liens permitted by Section 6.3.5 and
(ii) with respect to properties and assets other than Productive Properties,
Principal Transmission Facilities and the stock of any Subsidiary, Liens that
could not, individually or in the aggregate, reasonably be expected to have a
Material Adverse Effect. All easements, rights of way, licenses and other real
property rights required for operation of the businesses of the Borrower and its
Subsidiaries (collectively the "Rights of Way") are owned free and clear of any
Lien, other than Liens permitted by this Agreement and Liens already on any
parcel of real property with respect to which the Rights of Way have been
granted, which will not, in the aggregate, at any time materially detract from
the value of the Rights of Way or materially impair the use of the Rights of Way
in the operation of the businesses of the Borrower and its Subsidiaries.
5.12 Compliance with Orders. Neither the Borrower nor any Subsidiary is
in default under the terms of any order of any federal or state court or
administrative agency by which it or any of its properties may be bound, except
for any defaults which could not, individually or in the aggregate, be
reasonably expected to have a Material Adverse Effect.
5.13 Litigation. Except as set forth in Schedule 5.13, there are no
actions at law or in equity pending or, to the Knowledge of the Borrower,
threatened involving the likelihood of any judgment or liability against the
Borrower or any Subsidiary which could reasonably be expected to have a Material
Adverse Effect.
5.14 Burdensome Agreements. The Borrower is not a party to any contract
or agreement which, in the opinion of management of the Borrower, could
reasonably be expected to have a Material Adverse Effect.
5.15 No Conflict. Neither the execution and delivery by the Borrower or
any Guarantor of the Loan Documents to which it is a party, nor the consummation
of the transactions therein contemplated, nor compliance with the provisions
thereof will conflict with or result in the breach of any of the terms,
conditions or provisions of, or constitute a default under, the charter or
bylaws of the Borrower or any Subsidiary, or any indenture, loan agreement or
other agreement or instrument to which the Borrower or any Subsidiary is a party
or by which it may be bound, or result in creation of any Lien on any property
of the Borrower or any Subsidiary, and neither the Borrower nor any Subsidiary
is in default (after the expiration of any applicable grace period) in the
performance, observance or fulfillment of any of the obligations, covenants or
conditions contained in (i) any agreement to which it is a party, which default
could reasonably be expected to have a Material Adverse Effect, or (ii) any
agreement or instrument evidencing or governing Indebtedness in a principal
amount exceeding $5,000,000.
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5.16 Title to Properties. The Borrower and its Subsidiaries have good
and marketable title to all real properties purported to be owned by them and
good title to all other assets purported to be owned by them, subject to such
minor defects as are common to property of the type owned by the Borrower and
its Subsidiaries and Liens permitted by this Agreement and such defects and
Liens in the aggregate do not materially interfere with or impair the Borrower's
or any Subsidiary's business as presently conducted.
5.17 Public Utility Holding Company Act. The Borrower and the
Subsidiaries are exempt from registration under the provisions of the Public
Utility Holding Company Act of 1935 pursuant to Section 3(a) thereof.
5.18 Regulatory Approval. No consent or authorization of, filing with,
or any other act by or in respect of any Person is required in connection with
the enforceability, execution, delivery, performance or validity of this
Agreement or the transactions contemplated thereby.
5.19 Negative Pledge. Except as set forth in Schedule 5.19 hereto,
neither the Borrower nor any Subsidiary is subject to any agreement, indenture,
instrument, undertaking or security (other than this Agreement) which prohibits
the creation, incurrence or sufferance to exist of any Lien.
5.20 Investment Company Act. The Borrower is not an "investment
company" or a Borrower "controlled" by an "investment company", within the
meaning of the Investment Company Act of 1940, as amended.
5.21 Compliance with Laws. The Borrower and its Subsidiaries have all
franchises, licenses and permits necessary for the conduct of their respective
businesses, and are in compliance with all laws, rules, regulations, orders,
writs, judgments, injunctions, decrees or awards to which it may be subject,
including, without limitation, (i) all provisions of ERISA, which, if violated,
might result in a Lien or charge upon any property of the Borrower or any
Subsidiary, and (ii) all material provisions of the Occupational Safety and
Health Act of 1970 and the rules and regulations thereunder and applicable
statutes, regulations, orders and restrictions relating to environmental
standards or controls, except to the extent that failure to maintain or comply
with any of the foregoing, singly and in the aggregate, could not reasonably be
expected to have a Material Adverse Effect.
ARTICLE VI
COVENANTS
During the term of this Agreement, unless the Required Lenders shall
otherwise consent in writing:
6.1 Information. The Borrower will furnish to each Lender:
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(a) As soon as reasonably practicable and in any event within
120 days after the close of each of its fiscal years, financial statements
of the Borrower for such fiscal year on a consolidated and consolidating
basis (consolidating statements need not be certified by such accountants)
for itself and its Subsidiaries, including balance sheets as of the end of
such period, statements of income and statements of retained earnings,
and statements of cash flows, and, as to the consolidated statements,
prepared in accordance with generally accepted accounting principles
(except as expressly set forth therein) and accompanied by an unqualified
(as to going concern or the scope of the audit) opinion of independent
certified public accountants of recognized standing, which opinion shall
state that such audit was conducted in accordance with generally accepted
auditing standards and said financial statements fairly present the
financial condition and results of operation of the Borrower as at the end
of, and for, such fiscal year and a certificate of said accountants that,
in the course of their examination necessary for their opinion, they have
obtained no knowledge of any Default or Unmatured Default relating to
accounting matters, or if, in the opinion of such accountants, any such
Default or Unmatured Default shall exist, said certificate shall state the
nature and status thereof; provided that delivery pursuant to subsection
(e) below of copies of the Annual Report on Form 10-K of the Borrower for
such fiscal year filed with the Securities and Exchange Commission
(together with copies of the financial statements required to be included
therein) shall be deemed to satisfy the requirement of this subsection
(a) to deliver consolidated financial statements (but not the requirement
to deliver consolidating statements or the accountants' certificate as to
the presence or absence of any Default or Unmatured Default).
(b) As soon as reasonably practicable and in any event within
60 days after the close of each of the first three quarterly accounting
periods of each of its fiscal years, for itself and its Subsidiaries,
consolidated and consolidating unaudited balance sheets as at the close of
each such period and consolidated and consolidating statements of income
and statements of retained earnings and statements of cash flows for the
period from the beginning of such fiscal year to the end of such quarter;
provided that delivery pursuant to subsection (e) below of copies of the
Quarterly Report on Form 10-Q of the Borrower for such quarterly period
filed with the Securities and Exchange Commission shall be deemed to
satisfy the requirements of this subsection (b) to deliver consolidated
financial statements (but not the requirement to deliver the certificate of
the Borrower's chief financial officer or chief accounting officer with
respect thereto).
(c) Simultaneously with the delivery of each set of financial
statements referred to in Sections 6.1(a) and 6.1(b), a certificate of the
chief financial officer or the chief accounting officer of the Borrower in
the form of Exhibit G (i) setting forth in reasonable detail the
calculations required to establish whether the Borrower was in compliance
with the requirements of Section 6.4 on the date of such financial
statements, (ii) stating whether there exists on the date of such
certificate any Default and or Unmatured Default and, if any Default or
Unmatured Default then exists setting forth the details thereof and the
action which the Borrower is taking or proposes to take with respect
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thereto, and (iii) stating that such financial statements fairly reflect in
all material respects the financial conditions and results of operations of
the Borrower and its Subsidiaries as of the date of the delivery of such
financial statements and for the period covered thereby.
(d) As soon as possible and in any event within 10 Business
Days after the Borrower has Knowledge that any of the events or conditions
specified below has occurred or exists with respect to any Plan or
Multiemployer Plan, a statement, signed by the chief financial officer or
chief accounting officer of the Borrower, describing said event or
condition and the action which the Borrower or applicable member of the
Controlled Group proposes to take with respect thereto (and a copy of any
report or notice required to be filed with or given to the PBGC by the
Borrower or applicable member of the Controlled Group with respect to such
event or condition):
(i) the occurrence of any Reportable Event with
respect to any Plan, or any waiver shall be requested under
Section 412(d) of the Code for any Plan,
(ii) the distribution under Section 4041(c) of ERISA
of a notice of intent to terminate any Plan, or any action taken
by the Borrower or any member of the Controlled Group to terminate
any Plan under Section 4041(c) of ERISA,
(iii) the institution by PBGC of proceedings under
Section 4042 of ERISA for the termination of, or the appointment
of a trustee to administer, any Plan, or the receipt by the
Borrower or any member of the Controlled Group of a notice
from any Multiemployer Plan that such action has been taken by
PBGC with respect to such Multiemployer Plan,
(iv) the complete or partial withdrawal from a
Multiemployer Plan by the Borrower or any member of the Controlled
Group that could reasonably be expected to result in liability of
the Borrower or such member under Section 4201 or 4204 of ERISA
(including the obligation to satisfy secondary liability as a
result of a purchaser default) having a Material Adverse Effect,
or the receipt by the Borrower or any member of the Controlled
Group of notice from a Multiemployer Plan that it is in
reorganization or insolvency pursuant to Section 4241 or 4245 of
ERISA or that it intends to terminate or has terminated under
Section 4041A of ERISA,
(v) the institution of a proceeding by a fiduciary of
any Multiemployer Plan against the Borrower or any member of
the Controlled Group to enforce Section 515 of ERISA, which
proceeding is not dismissed within 30 days, or
(vi) the adoption of an amendment to any Plan that,
pursuant to Section 401(a)(29) of the Code or Section 307 of
ERISA, would result in the loss of tax-exempt status of the trust
of which such Plan is a part if the Borrower or any
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member of the Controlled Group fails to timely provide security to
the Plan in accordance with the provisions of said Sections.
(e) Promptly upon the filing thereof, copies of al
registration statements and annual, quarterly, monthly or other regular
reports which the Borrower or any of its Subsidiaries files with the
Securities and Exchange Commission.
(f) Promptly upon the furnishing thereof to all shareholders
of the Borrower generally, copies of all financial statements, reports and
proxy statements so furnished.
(g) Promptly upon receipt thereof, one copy of each written
audit report submitted to the Borrower or any Subsidiary by
independent accountants resulting from (i) any annual or interim audit
submitted after the occurrence and during the continuance of a Default or
Unmatured Default and (ii) any special audit submitted at any time, in
each case, made by them of the books of the Borrower or any Subsidiary.
(h) As soon as available and in any event not later than
April 30 of each calendar year, an engineering and economic analysis of the
producing properties of the Borrower and its Subsidiaries prepared by an
independent firm of consulting petroleum engineers and in form, substance
and detail consistent with past practice.
(i) Promptly and in any event within five Business Days after
an Authorized Officer obtains knowledge thereof, notice of the occurrence
of a Default or Unmatured Default, together with the details of such event
and the actions, if any, the Borrower has taken or intends to take with
respect thereto.
(j) Such other information (including nonfinancial
information) as the Administrative Agent or any Lender may from time t
time reasonably request.
6.2 Affirmative Covenants. The Borrower will, and will cause each
Subsidiary, to:
6.2.1 Reports and Inspection. Keep proper books and records in good
order in accordance with sound business practice and prepare its financial
statements in accordance with Agreement Accounting Principles and permit the
Administrative Agent or any Lender, at its own expense, by its representatives
and agents, to inspect any of the properties, books and financial records of the
Borrower and each Subsidiary, to examine and make copies of the books of
accounts and other financial records of the Borrower and each Subsidiary, and to
discuss the affairs, finances and accounts of the Borrower and each Subsidiary
with, and to be advised as to the same by, their respective officers at such
reasonable times and intervals during regular business hours as the
Administrative Agent or such Lender may designate, provided that such inquiry
shall be limited to the purpose of evaluating the Borrower's financial
condition or compliance with this Agreement.
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6.2.2 Conduct of Business. Carry on and conduct its principal business
of exploration for, and production, transportation, distribution, refinement,
processing, storage, marketing and gathering of oil and other hydrocarbons and
petroleum, and natural, synthetic or other gas in substantially the same manner
and in substantially the same fields of enterprise as it is presently conducted;
and do all things necessary to remain duly organized, validly existing and in
good standing as a domestic corporation or limited liability company in its
jurisdiction of organization (unless the existence or ownership by the Borrower
of any Subsidiary shall be discontinued as a result of a merger, consolidation
or sale of assets as permitted by Section 6.3.2) and maintain all requisite
authority to conduct its business in each jurisdiction in which the failure to
have such authority could reasonably be expected to have a Material Adverse
Effect.
6.2.3 Insurance. Maintain insurance with reputable insurance companies
or associations in such forms and amounts and covering such risks as are
customary for companies of established reputation and similar size engaged in
similar businesses and owning and operating similar properties; provided that it
is agreed that, as of the date of this Agreement, the insurance coverage of the
Borrower and its Subsidiaries set forth on Schedule 6.2 hereto satisfies the
requirements of this Section 6.2.3.
6.2.4 Taxes. Promptly pay and discharge all material taxes, assessments
and governmental charges or levies imposed upon the Borrower or any Subsidiary
(but in the case of a Subsidiary, only to the extent that such Subsidiary's
assets shall be sufficient for the purpose), respectively, or upon or in respect
of all or any part of the property and business of the Borrower or any
Subsidiary, and all due and payable claims for work, labor or materials, which
if unpaid might become a Lien upon any property of the Borrower or any
Subsidiary (other than claims against any such Subsidiary in a proceeding under
any bankruptcy or similar law), provided that the Borrower or such Subsidiary
shall not be required to pay any such tax, assessment, charge, levy or claim if
the validity thereof shall concurrently be contested in good faith by
appropriate proceedings and if the Borrower or such Subsidiary shall set aside
on its or their books reserves deemed by it or them to be required with respect
thereto in accordance with generally accepted accounting principles.
6.2.5 Compliance with Laws. Maintain all franchises, licenses and
permits necessary for the conduct of its businesses, and comply with all laws,
rules, regulations, orders, writs, judgments, injunctions, decrees or awards to
which it may be subject, including, without limitation, (i) all provisions of
ERISA, which, if violated, might result in a Lien or charge upon any property of
the Borrower or any Subsidiary, and (ii) all material provisions of the
Occupational Safety and Health Act of 1970 and the rules and regulations
thereunder and applicable statutes, regulations, orders and restrictions
relating to environmental standards or controls, except to the extent that
failure to maintain or comply with any of the foregoing, singly and in the
aggregate, could not reasonably be expected to have a Material Adverse Effect.
6.2.6 Maintenance of Properties. Do all things necessary to maintain,
preserve, protect and keep its material properties (whether owned in fee or a
leasehold interest) in good repair, working order and condition, and make all
proper repairs, renewals and replacements so that its
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business carried on in connection therewith may be properly conducted at all
times; provided that, subject to Section 6.3.2 and all other terms of this
Agreement, nothing in this Section 6.2.6 shall prevent the Borrower or any of
its Subsidiaries from discontinuing the operation and maintenance of any of its
properties (x) if such discontinuance is, in the judgment of the Borrower or
such Subsidiary, desirable in the conduct of its business or (y) if such
discontinuance or disposal could not reasonably be expected to have a Material
Adverse Effect.
6.2.7 Additional Guarantors. On the date on which any Subsidiary which
is not an original signatory to the Subsidiary Guaranty delivers to the
Administrative Agent a counterpart of the Subsidiary Guaranty, cause such
Subsidiary to deliver such supporting documents (including documents of the
types described in clauses (i), (ii), (iii) and (vi) of Section 4.1(b)) as the
Administrative Agent or any Lender may reasonably request in support thereof.
6.3 Negative Covenants. The Borrower will not, nor (where applicable)
will it permit any Subsidiary to:
6.3.1 Restricted Payments. Declare or pay any dividends on its capital
stock (other than dividends payable in its own capital stock) or redeem,
repurchase or otherwise acquire or retire any of its capital stock at any time
outstanding or any warrants, rights or options to purchase or acquire any shares
of its capital stock or permit any Subsidiary to purchase any shares of stock of
the Borrower, except that any Subsidiary may declare and pay dividends to the
Borrower or another Wholly-Owned Subsidiary.
6.3.2 Merger and Sale of Assets. Merge or consolidate with or into any
other Person or lease, sell or otherwise dispose of all, or substantially all,
of its property, assets (other than inventory, physical assets sold in the
ordinary course of business or obsolete, worn out or excess property) or
business to any other Person except that:
(1) the Borrower may merge or consolidate with or sell all of its assets to
any other solvent corporation, provided that (i) the surviving, continuing or
resulting corporation (if not the Borrower) shall (x) expressly assume by a
written instrument reasonably satisfactory to the Administrative Agent and the
Lenders (which shall be provided with an opportunity to review and comment upon
it prior to the consummation of any transaction) the due and punctual payment of
the principal of all Obligations and the due performance and observance of all
covenants, conditions and agreements on the part of the Borrower under this
Agreement, (y) deliver to the Administrative Agent and the Lenders an opinion of
counsel, in form and substance reasonably satisfactory to the Administrative
Agent and the Lenders, to the effect that such written instrument has been duly
authorized, executed and delivered by such surviving, continuing or resulting
corporation and constitutes a legal, valid and binding instrument enforceable
against such surviving, continuing or resulting corporation in accordance with
its terms, and to such further effects as the Administrative Agent and the
Lenders may reasonably request, and (z) have an investment grade rating from
Moody's Investors Service, Inc. and Standard & Poor's Rating Group, (ii) the
surviving, continuing or resulting corporation shall be a corporation organized
and existing under the laws of the United States of America or any State
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thereof or the District of Columbia, and (iii) immediately after such
merger, consolidation or sale, no Default or Unmatured Default would exist;
(2) any Subsidiary may merge into the Borrower or another Subsidiary which
is a Wholly-Owned Subsidiary, and may sell, lease or otherwise dispose of any of
its assets to the Borrower or another Subsidiary which is a Wholly-Owned
Subsidiary;
(3) any Subsidiary may merge or consolidate with any entity other than the
Borrower or another Subsidiary, provided that (i) the surviving, continuing or
resulting entity shall be a Subsidiary, and (ii) immediately after such merger
or consolidation, no Default or Unmatured Default would exist; and
(4) the Borrower may sell, lease or otherwise dispose of all or any part of
its assets to any Person, and any Subsidiary may sell, lease or otherwise
dispose of all or any part of its assets to any Person other than the Borrower
or another Subsidiary, in each case for a consideration which represents the
fair value at the time of such sale or other disposition, provided that (x)
immediately after such sale, lease or other disposition (and the application of
the proceeds thereof as provided in clause (y)) no Default or Unmatured Default
would exist and (y) to the extent applicable, the Net Cash Proceeds of such
sale, lease or other disposition are applied as required by Sections 2.8 and
2.9; and provided, further, that neither the Borrower nor any Subsidiary shall
sell, lease or otherwise dispose of any asset if, after giving effect to such
transaction, the aggregate fair market value of all assets sold, leased or
otherwise disposed of by the Borrower and its Subsidiaries in any fiscal year of
the Borrower (minus all Net Cash Proceeds thereof applied t reduce the Aggregate
Commitment pursuant to Section 2.8(b)) would exceed 7.5% of the Borrower's
consolidated assets as of the beginning of such fiscal year.
Without imiting clause (4) above, the Borrower will not permit Arkansas
Western Gas Company to (x) cease to be a Subsidiary of the Borrower; and (y)
sell all or any Substantial Portion (as defined below) of its assets. For
purposes of the foregoing, "Substantial Portion" means, with respect to Arkansas
Western Gas Company, assets which (i) represent more than 20% of the
consolidated tangible assets of Arkansas Western Gas Company and its
Subsidiaries as at the beginning of the fiscal year in which any determination
is to be made or (ii) are responsible for more than 20% of the consolidated net
earnings of Arkansas Western Gas Company and its Subsidiaries for the fiscal
year preceding the fiscal year in which any determination is to be made.
6.3.3 Liens. Create, incur, assume or suffer to exist any Lien on (a)
any Productive Property, (b) any Principal Transmission Facility or (c) any
shares of stock of any Subsidiary, except:
(i) Liens for taxes, assessments or governmenta
charges or levies on its property if the same shall not at the
time be delinquent or thereafter can be paid without penalty or,
provided the Borrower or any Subsidiary knew or should have known
of such Liens, are being actively contested in good faith and by
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appropriate proceedings and for which adequate reserves shall have
been set aside on its books in accordance with Agreement
Accounting Principles,
(ii) Liens imposed by law, such as carriers',
warehousemen's, operators', royalty, surface damages and
mechanics' liens and other similar liens arising in the ordinary
course of business which secure payment of obligations not more
than 60 days past due or which are being contested in good faith
by appropriate proceedings and for which adequate reserves shall
have been set aside on its books in accordance with Agreement
Accounting Principles,
(iii) Liens incurred in the ordinary course of business
(a) arising out of pledges or deposits under workmen's
compensation laws, unemployment insurance, old age pensions, or
other social security or retirement benefits, or similar
legislation, (b) to secure the performance of letters of credit,
bids, tenders, sales contracts, leases (including rent security
deposits), statutory obligations, surety, appeal and performance
bonds, joint operating agreements or other similar agreements and
other similar obligations not incurred in connection with the
borrowing of money, the obtaining of advances or the payment of
the deferred purchase price of property or (c) consisting of
deposits which secure public or statutory obligations of the
Borrower or any Subsidiary, or surety, custom or appeal bonds to
which the Borrower or any Subsidiary is a party, or the payment of
contested taxes or import duties of the Borrower or any
Subsidiary,
(iv) utility easements, building restrictions and such
other encumbrances or charges against real property as are of a
nature generally existing with respect to properties of a similar
character and which do not in any material way affect the
marketability of the same or interfere with the use thereof in the
business of the Borrower or the Subsidiaries,
(v) Liens on drilling equipment and facilities in
order to secure the financing for the construction of such
equipment and facilities not constructed as of the date hereof,
provided that such financing is permitted pursuant to Section 6.4,
(vi) attachment, judgment and other similar Liens
arising in connection with court proceedings; provided the
execution or other enforcement of such Liens is effectively
stayed or the claims secured thereby are being actively contested
in good faith and by appropriate proceedings; and provided,
further, the Borrower or any Subsidiary knew or should have
known of such Liens,
(vii) Liens on property of a Subsidiary, provided such
Liens secure only obligations owing to the Borrower or a
Wholly-Owned Subsidiary,
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(viii) purchase money mortgages or other mortgages or
other Liens on assets of the Borrower or any Subsidiary securing
Indebtedness hereafter incurred by the Borrower or such Subsidiary
for the acquisition of such assets, provided no such mortgage or
other Lien shall extend to any other property (unless such
mortgage or Lien is permitted under another clause of this Section
6.3.3) and the amount thereby secured shall not exceed the
purchase price of such asset plus interest, if any, accrued
thereon and shall be permitted pursuant to Section 6.4,
(ix) Liens on property hereafter acquired (including
shares of stock hereafter acquired of any Person (including any
Person in which the Borrower or any Subsidiary already owns an
interest)) existing at the time of acquisition and liens assumed
by the Borrower or a Subsidiary as a result of a merger of another
entity into the Borrower or a Subsidiary or the acquisition by the
Borrower or a Subsidiary of the assets and liabilities of another
entity, provided that in each case such Liens shall not have been
created in anticipation of such transaction,
(x) any right which any municipal or governmental body
or agency may have by virtue of any franchise, license, contract
or statute to purchase, or designate a purchaser of or order the
sale of, any property of the Borrower or any Subsidiary upon
payment of reasonable compensation therefor or to terminate any
franchise, license or other rights or to regulate the property
and business of the Borrower or any Subsidiary,
(xi) easements or reservations in respect of any
property of the Borrower or any Subsidiary for the purpose of
rights-of-way and similar purposes, reservations, restrictions,
covenants, party wall agreements, conditions of record and other
encumbrances (other than to secure the payment of money)
and minor irregularities or deficiencies in the record and
evidence of title, which in the reasonable opinion of the Borrower
(at the time of the acquisition of the property affected or
subsequently) will not interfere in any material way with the
proper operation and development of the property affected thereby,
(xii) Liens existing on the date hereof and set forth on
Schedule 5.19 hereto,
(xiii) Liens on property to secure all or any part of the
cost of construction, alteration or repair of any building,
equipment or other improvement on all or any part of such
property, including any pipeline, or to secure any Indebtedness
incurred prior to, at the time of, or within 360 days after, the
completion of such construction, alteration or repair to provide
funds for the payment of all or any part of such cost,
(xiv) rights of lessors under oil, gas or mineral leases
arising in the ordinary course of business,
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(xv) any extension, renewal or replacement (or
successive extensions, renewals or replacements), in whole or in
part, of any Lien referred to in the foregoing clauses;
provided that the principal amount of Indebtedness secured thereby
shall not exceed the principal amount of Indebtedness so secured
at the time of such extension, renewal or replacement and such
extension, renewal or replacement Lien shall be limited to all
or a part of the property which secured the Lien so extended,
renewed or replaced (plus improvements on such property),
(xvi) Liens which may hereafter be attached to
undeveloped real estate not containing oil or gas reserves
presently owned by the Borrower in the ordinary course of the
Borrower's real estate sales, development and rental activities,
(xvii) Liens not otherwise permitted by the foregoing
clauses of this Section 6.3.3 securing Indebtedness in an
aggregate principal amount which, at the time of incurrence, does
not exceed 5% of Stockholders' Equity as of the end of the most
recently completed fiscal quarter of the Borrower as shown on the
consolidated balance sheet related thereto, and
(xviii) Liens not otherwise permitted by the foregoing
clauses of this Section 6.3.3 in an aggregate principal amount in
excess of 5% of Stockholders' Equity; provided that at the time
such Lien is created, the Obligations will be secured pari passu
with the obligations such Lien is securing pursuant to
documentation in form and substance satisfactory to the
Administrative Agent and the Lenders (drafts of which
documentation shall be furnished to the Administrative Agent and
the Lenders sufficiently in advance to provide the Administrative
Agent and the Lenders with an opportunity to review and comment
upon it prior to the granting of any such Lien).
6.3.4 Subsidiary Guarantors. Permit more than 10% of the consolidated
assets of the Borrower and its Subsidiaries (excluding Arkansas Western Gas
Company) to be owned by, or more than 10% of the consolidated earnings of the
Borrower and its Subsidiaries (excluding Arkansas Western Gas Company) for the
most recent period of four consecutive fiscal quarters (beginning with the
period ending June 30, 2001) to be earned by, Subsidiaries (other than Arkansas
Western Gas Company) which are not Guarantors. For the avoidance of doubt,
Arkansas Western Gas Company shall not be required to be a Guarantor.
6.3.5 Investments. Make, incur, assume or suffer to exist any Investment
in any other Person, except (without duplication) the following:
(a) Cash Equivalent Investments;
(b) Investments existing on the date of this Agreement;
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(c) in the ordinary course of business, Investments by the Company in
any Subsidiary or by any Subsidiary in the Company or any other Subsidiary;
(d) bank deposits in the ordinary course of business;
(e) Investments in Persons involved in oil and gas exploration and
production and related businesses in the ordinary course of business consistent
with past practice; and
(f) other Investments in an aggregate amount not at any time exceeding
$5,000,000.
6.3.6 Indebtedness of Arkansas Western Gas Company. Permit the aggregate
outstanding principal amount of all Indebtedness of Arkansas Western Gas Company
and its Subsidiaries (excluding (i) Indebtedness outstanding on the date hereof
and renewals, extensions and refinancings thereof so long as the principal
amount thereof is not increased and (ii) Indebtedness to the Borrower or another
Wholly-Owned Subsidiary) to exceed $20,000,000.
6.4 Financial Covenants. The Borrower will not:
6.4.1 Debt to Capitalization Ratio. Permit the Debt to Capitalization
Ratio at any time during any period set forth below to exceed the applicable
ratio set forth below:
Period Maximum Debt to Capitalization Ratio
=============================== ====================================
The date hereof through 3/30/02 0.75 to 1.0
3/31/02 through 3/30/03 0.70 to 1.0
3/31/03 through 3/30/04 0.65 to 1.0
Thereafter 0.60 to 1.0;
provided that if on any date prior to March 30, 2003 the Borrower is not
required to reduce the Aggregate Commitment upon receipt of proceeds of any
Equity Issuance pursuant to clause (iii) of the proviso to Section 2.8(b), the
maximum Debt to Capitalization Ratio shall be reduced to 0.65 to 1.0 during the
period from such date through March 30, 2003.
6.4.2 Interest Coverage Ratio. Permit the Interest Coverage Ratio as of
the last day of any fiscal quarter of the Borrower to be less than the
applicable ratio set forth below:
Fiscal Quarter Ending Minimum Interest Coverage Ratio
=============================== ====================================
6/30/01 through 12/31/02 3.75 to 1.0
3/31/03 through 12/31/03 4.00 to 1.0
Thereafter 5.00 to 1.0.
6.4.3 Net Worth. Permit Stockholder's Equity at any time to be less
than the sum of (a) $135,000,000 plus (b) 50% of consolidated net income of the
Borrower and its Subsidiaries for
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each fiscal year of the Borrower (and, if applicable, the completed portion of
the then-current fiscal year for which the Borrower has delivered financial
statements pursuant to Section 6.1(b)) ending after the date of this Agreement,
without giving effect to any loss in any such fiscal year (or, if applicable,
the completed portion of the then-current fiscal year), excluding, in the case
of the Borrower's 2001 fiscal year, the first fiscal quarter of such year, plus
(c) 75% of the net proceeds of any Equity Issuance after the date of this
Agreement.
ARTICLE VII
DEFAULTS
7.1 Events of Default. The occurrence and continuance of any one or
more of the following events shall constitute a Default:
7.1.1 Representations and Warranties. Any representation or warranty
made or deemed made by or on behalf of the Borrower to the Administrative Agent
or any Lender in this Agreement or in any certificate or instrument delivered in
connection herewith shall be materially false as of the date on which made.
7.1.2 Payment Default. Nonpayment of any principal, interest, fee or
other obligation hereunder within ten days after the same becomes due.
7.1.3 Breach of Certain Covenants. The breach by the Borrower of (i)
any of the terms or provisions of Section 6.1(i), 6.3.1, 6.3.2 or 6.4 or (ii)
any of the terms or provisions of Section 6.3.3 which is not remedied within ten
days after written notice from the Administrative Agent.
7.1.4 Other Breach of this Agreement. The breach by the Borrower
(other than a breach which constitutes a Default under Section 7.1.1, 7.1.2 or
7.1.3) of any term or provision of this Agreement which is not remedied within
30 days after written notice from the Administrative Agent.
7.1.5 ERISA. An event or condition specified in Section 6.1(d) shall
occur or exist with respect to any Plan or any Multiemployer Plan and, as a
result or such event or condition, together with all other such events or
conditions then outstanding, the Borrower or any member or the Controlled Group
shall incur, or shall be reasonably likely to incur, a liability to any Plan,
any Multiemployer Plan or the PBGC (or any combination of the foregoing) that
would have a Material Adverse Effect.
7.1.6 Cross-Default. Failure of the Borrower or any Significant
Subsidiary to pay any Indebtedness when due (after giving effect to any period
of grace set forth in any agreement under which such Indebtedness was created or
is governed); or the default by the Borrower or any Significant Subsidiary in
the performance of any other term, provision or condition contained in any
agreement under which any of their respective Indebtedness was created or is
governed, the effect of which is to cause, or to permit the holder or holders of
such Indebtedness
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to cause, such Indebtedness to become due prior to its stated maturity; or any
Indebtedness of the Borrower or any Significant Subsidiary shall become due and
payable or be required to be prepaid (other than by a regularly scheduled
payment) prior to the stated maturity thereof; provided that, in each case, the
principal amount of Indebtedness as to which such a payment default shall occur
and be continuing, or such a failure to perform or other event causing or
permitting acceleration shall occur and be continuing, exceeds $5,000,000.
7.1.7 Voluntary Bankruptcy, etc. The Borrower, or any Significant
Subsidiary or a Material Group of Subsidiaries shall (i) not pay, or admit in
writing its inability to pay, its debts generally as they become due, (ii) make
an assignment for the benefit of creditors, (iii) apply for, seek, consent to,
or acquiesce in, the appointment of a receiver, custodian, trustee, examiner,
liquidator or similar official for the Borrower, such Significant Subsidiary or
such Material Group of Subsidiaries, (iv) institute any proceeding seeking an
order for relief under the Federal bankruptcy laws as now or hereafter in effect
or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution,
winding up, liquidation, reorganization, arrangement, adjustment or composition
of it or its debts under any law relating to bankruptcy, insolvency or
reorganization or relief of debtors or (v) take any action to authorize or
effect any of the foregoing actions set forth in this Section 7.1.7.
7.1.8 Involuntary Bankruptcy, etc. Without the application, approval
or consent of the Borrower, the applicable Significant Subsidiary or the
applicable Material Group of Subsidiaries, a receiver, trustee, examiner,
liquidator or similar official shall be appointed for the Borrower, any
Significant Subsidiary or such Material Group of Subsidiaries, or a proceeding
described in Section 7.1.7(iv) shall be instituted against the Borrower, any
Significant Subsidiary or such Material Group of Subsidiaries and such
appointment continues undischarged or such proceeding continues undismissed or
unstayed for a period of 60 consecutive days.
7.1.9 Judgments. The Borrower or any Significant Subsidiary shall fail
within 30 days to pay, bond or otherwise discharge any final judgment or order
for the payment of money in excess of $2,500,000, which is not stayed on appeal
or otherwise being appropriately contested in good faith.
7.1.10 Environmental Matters. The Borrower, any Significant Subsidiary
or any Material Group of Subsidiaries shall suffer any adverse determination
pertaining to the release by the Borrower, any Significant Subsidiary or any
other Person of any toxic or hazardous waste or substance into the environment,
or any violation of any federal, state or local environmental, health or safety
law or regulation, which, in either case, could reasonably be expected to have a
Material Adverse Effect.
7.1.11 Subsidiary Guaranty. The Subsidiary Guaranty shall fail to
remain in full force or effect or any action shall be taken to discontinue or to
assert the invalidity or unenforceability of the Subsidiary Guaranty, or any
Guarantor shall deny that it has any further liability under the Subsidiary
Guaranty or shall give notice to such effect (excluding any Guarantor which
ceases to be a Subsidiary as a result of a transaction permitted by this
Agreement).
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ARTICLE VIII
ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES;
RELEASES OF GUARANTORS
8.1 Acceleration. If any Default described in Section 7.1.6 or 7.1.7
occurs with respect to the Borrower, the obligations of the Lenders to make
Loans hereunder shall automatically terminate and the Obligations shall
immediately become due and payable without any election or action on the part of
the Administrative Agent or any Lender. If any other Default occurs, the
Required Lenders (or the Administrative Agent with the consent of the Required
Lenders) may terminate or suspend the obligations of the Lenders to make Loans
hereunder, or declare the Obligations to be due and payable, or both, whereupon
the Obligations shall become immediately due and payable, without presentment,
demand, protest or notice of any kind, all of which the Borrower hereby
expressly waives.
If, within 30 days after acceleration of the maturity of the Obligations
or termination of the obligations of the Lenders to make Loans hereunder as a
result of any Default (other than any Default as described in Section 7.1.6 or
7.1.7 with respect to the Borrower) and before any judgment or decree for the
payment of the Obligations due shall have been obtained or entered, the Required
Lenders (in their sole discretion) shall so direct, the Administrative Agent
shall, by notice to the Borrower, rescind and annul such acceleration and/or
termination.
8.2 Amendments. Subject to the provisions of this Article VIII, the
Required Lenders (or the Administrative Agent with the consent in writing of the
Required Lenders) and the Borrower may enter into agreements supplemental hereto
for the purpose of adding to or modifying any provision in any Loan Document or
changing in any manner the rights of the Lenders or the Borrower hereunder or
waiving any Default hereunder; provided that no such supplemental agreement
shall, without the consent of all of the Lenders:
(i) Extend the final maturity of any Loan or forgive
all or any portion of the principal amount
thereof, or reduce the rate or extend the time of
payment of interest or fees thereon.
(ii) Reduce the percentage specified in the definition
of Required Lenders.
(iii) Extend the Termination Date, or reduce the amount
or extend the payment date for, the mandatory
payments required under Section 2.12, or increase
the amount of the Aggregate Commitment or of the
Commitment of any Lender hereunder, or permit the
Borrower to assign its rights under this
Agreement.
(iv) Amend the last paragraph of Section 6.3.2 or this
Section 8.2.
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(v) Release any Guarantor from its obligations under
the Subsidiary Guaranty (except as provided in
Section 8.4).
No amendment of any provision of this Agreement relating to the Administrative
Agent shall be effective without the written consent of the Administrative
Agent. No amendment of any provision of this Agreement relating to the Swing
Line Lender or any Swing Line Loan shall be effective without the written
consent of the Swing Line Lender. The Administrative Agent may waive payment of
the fee required under Section 12.3.2 without obtaining the consent of any other
party to this Agreement.
8.3 Preservation of Rights. No delay or omission of the Lenders or
the Administrative Agent to exercise any right under the Loan Documents shall
impair such right or be construed to be a waiver of any Default or an
acquiescence therein, and the making of a Loan notwithstanding the existence of
a Default or the inability of the Borrower to satisfy the conditions precedent
to such Loan shall not constitute any waiver or acquiescence. Any single or
partial exercise of any such right shall not preclude other or further exercise
thereof or the exercise of any other right, and no waiver, amendment or other
variation of the terms, conditions or provisions of the Loan Documents
whatsoever shall be valid unless in writing signed by the Lenders required
pursuant to Section 8.2, and then only to the extent in such writing
specifically set forth. All remedies contained in the Loan Documents or by law
afforded shall be cumulative and all shall be available to the Administrative
Agent and the Lenders until the Obligations have been paid in full.
8.4 Releases of Guarantors. The Lenders hereby authorize the
Administrative Agent to, and the Administrative Agent agrees that it will,
release any Guarantor from its obligations under the Subsidiary Guaranty so long
as (a) no Default or Unmatured Default exists or will result therefrom and (b)
either (i) such Guarantor ceases to be a Subsidiary as a result of a transaction
permitted hereunder or (ii) the Borrower requests such release in writing and,
after giving effect thereto, the Borrower will be in compliance with Section
6.3.4. In determining whether any such release is permitted, the Administrative
Agent may rely on a certificate from the Borrower. The Administrative Agent
shall promptly notify the Lenders of any such release.
ARTICLE IX
GENERAL PROVISIONS
9.1 Survival of Representations. All representations and warranties of
the Borrower contained in this Agreement shall survive the making of the Loans
herein contemplated.
9.2 Governmental Regulation. Anything contained in this Agreement to
the contrary notwithstanding, no Lender shall be obligated to extend credit to
the Borrower in violation of any limitation or prohibition provided by any
applicable statute or regulation.
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9.3 Headings. Section headings in the Loan Documents are for
convenience of reference only, and shall not govern the interpretation of any of
the provisions of the Loan Documents.
9.4 Entire Agreement. The Loan Documents embody the entire agreement
and understanding among the Borrower, the Administrative Agent and the Lenders
and supersede all prior agreements and understandings among the Borrower, the
Administrative Agent and the Lenders relating to the subject matter thereof.
9.5 Several Obligations; Benefits of this Agreement. The respective
obligations of the Lenders hereunder are several and not joint and no Lender
shall be the partner or agent of any other (except to the extent to which the
Administrative Agent is authorized to act as such). The failure of any Lender to
perform any of its obligations hereunder shall not relieve any other Lender from
any of its obligations hereunder. This Agreement shall not be construed so as to
confer any right or benefit upon any Person other than the parties to this
Agreement and their respective successors and assigns, provided that the parties
hereto expressly agree that the Arranger shall enjoy the benefits of the
provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth
therein and shall have the right to enforce such provisions on its own behalf
and in its own name to the same extent as if it were a party to this Agreement.
9.6 Expenses; Indemnification. (i) The Borrower shall reimburse the
Administrative Agent and the Arranger for all reasonable costs, internal charges
and out-of-pocket expenses (including, subject to any limit on fees which is
separately agreed to, reasonable attorneys' fees and reasonable time charges of
attorneys for the Administrative Agent, which attorneys may be employees of the
Administrative Agent) paid or incurred by the Administrative Agent or the
Arranger in connection with the preparation, negotiation, execution, delivery,
syndication, review, amendment, modification, and administration of the Loan
Documents. The Borrower also agrees to reimburse the Administrative Agent, the
Arranger and the Lenders for all reasonable costs, internal charges and
out-of-pocket expenses (including reasonable attorneys' fees and reasonable time
charges of attorneys for the Administrative Agent, the Arranger and the Lenders,
which attorneys may be employees of the Administrative Agent, the Arranger or
any Lender) paid or incurred by the Administrative Agent, the Arranger or any
Lender in connection with the collection and enforcement of the Loan Documents.
(ii) The Borrower hereby further agrees to indemnify the Administrative
Agent, the Arranger, each Lender, their respective affiliates, and each of their
directors, officers and employees against all losses, claims, damages,
penalties, judgments, liabilities and reasonable expenses (including, without
limitation, all reasonable expenses of litigation or preparation therefor
whether or not the Administrative Agent, the Arranger, any Lender or any
affiliate is a party thereto) which any of them may pay or incur arising out of
or relating to this Agreement, the other Loan Documents, the transactions
contemplated hereby or the direct or indirect application or proposed
application of the proceeds of any Loan hereunder except to the extent that they
are determined in a final non-appealable judgment by a court of competent
jurisdiction to have resulted from the gross negligence or willful misconduct of
the party seeking
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indemnification. The obligations of the Borrower under this Section 9.6 shall
survive the termination of this Agreement.
9.7 Numbers of Documents. All statements, notices, closing documents,
and requests hereunder shall be furnished to the Administrative Agent with
sufficient counterparts so that the Administrative Agent may furnish one to each
of the Lenders.
9.8 Accounting. Except as provided to the contrary herein, all
accounting terms used herein shall be interpreted and all accounting
determinations hereunder shall be made in accordance with Agreement Accounting
Principles.
9.9 Severability of Provisions. Any provision in any Loan Document
that is held to be inoperative, unenforceable, or invalid in any jurisdiction
shall, as to that jurisdiction, be inoperative, unenforceable, or invalid
without affecting the remaining provisions in that jurisdiction or the
operation, enforceability, or validity of that provision in any other
jurisdiction, and to this end the provisions of all Loan Documents are declared
to be severable.
9.10 Nonliability of Lenders. The relationship between the Borrower on
the one hand and the Lenders and the Administrative Agent on the other hand
shall be solely that of borrower and lender. None of the Administrative Agent,
the Arranger or any Lender shall have any fiduciary responsibilities to the
Borrower. None of the Administrative Agent, the Arranger or any Lender
undertakes any responsibility to the Borrower to review or inform the Borrower
of any matter in connection with any phase of the Borrower's business or
operations. The Borrower agrees that none of the Administrative Agent, the
Arranger or any Lender shall have liability to the Borrower (whether sounding in
tort, contract or otherwise) for losses suffered by the Borrower in connection
with, arising out of, or in any way related to, the transactions contemplated
and the relationship established by the Loan Documents, or any act, omission or
event occurring in connection therewith, unless it is determined in a final
non-appealable judgment by a court of competent jurisdiction that such losses
resulted from the gross negligence or willful misconduct of the party from which
recovery is sought. None of the Administrative Agent, the Arranger or any Lender
shall have any liability with respect to, and the Borrower hereby waives,
releases and agrees not to sue for, any special, indirect or consequential
damages suffered by the Borrower in connection with, arising out of, or in any
way related to the Loan Documents or the transactions contemplated thereby.
9.11 Confidentiality. Each Lender agrees to hold any confidential
information which it may receive from the Borrower pursuant to this Agreement in
confidence, except for disclosure (i) to the extent permitted by law or
regulation, to its Affiliates and to other Lenders and their respective
Affiliates, (ii) to legal counsel, accountants, and other professional advisors
to such Lender or to a Transferee, (iii) to regulatory officials, (iv) to any
Person as required by law, regulation, or legal process, (v) to any Person in
connection with any legal proceeding to which such Lender is a party to the
extent required by law, regulation or legal process, (vi) permitted by Section
12.4, (vii) to rating agencies if required by such agencies in connection with a
rating relating to the Advances hereunder, and (viii) to the extent required in
connection with the
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exercise of any remedy or any enforcement of this Agreement by such Lender or
the Administrative Agent.
9.12 Nonreliance. Each Lender hereby represents that it is not relying
on or looking to any margin stock (as defined in Regulation U of the Board of
Governors of the Federal Reserve System) for the repayment of the Loans provided
for herein.
9.13 Disclosure. The Borrower and each Lender hereby (i) acknowledge
and agree that Bank One and/or its Affiliates from time to time may hold
investments in, make other loans to or have other relationships with the
Borrower and its Affiliates, and (ii) waive any liability of Bank One or such
Affiliate of Bank One to the Borrower or any Lender, respectively, arising out
of or resulting from such investments, loans or relationships other than
liabilities arising out of the gross negligence or willful misconduct of Bank
One or its Affiliates.
ARTICLE X
THE ADMINISTRATIVE AGENT
10.1 Appointment; Nature of Relationship. Bank One is hereby appointed
by each of the Lenders as the Administrative Agent hereunder and under each
other Loan Document, and each of the Lenders irrevocably authorizes the
Administrative Agent to act as the contractual representative of such Lender
with the rights and duties expressly set forth herein and in the other Loan
Documents. The Administrative Agent agrees to act as Administrative Agent
upon the express conditions contained in this Article X. Notwithstanding the
use of the defined term "Administrative Agent," it is expressly understood
and agreed that the Administrative Agent shall not have any fiduciary
responsibilities to any Lender by reason of this Agreement or any other Loan
Document and that Administrative Agent is merely acting as the contractual
representative of the Lenders with only those duties as are expressly set
forth in this Agreement and the other Loan Documents. In its capacity as
the Administrative Agent, (i) the Administrative Agent does not assume any
fiduciary duties to any of the Lenders, (ii) the Administrative Agent is a
"representative" of the Lenders within the meaning of Section 9-105 of the
Uniform Commercial Code and (iii) the Administrative Agent is acting as an
independent contractor, the rights and duties of which are limited to those
expressly set forth in this Agreement and the other Loan Documents. Each of
the Lenders hereby agrees to assert no claim against the Administrative Agent
on any agency theory or any other theory of liability for breach of fiduciary
duty, all of which claims each Lender hereby waives.
10.2 Powers. The Administrative Agent shall have and may exercise such
powers under the Loan Documents as are specifically delegated to the
Administrative Agent by the terms of each thereof, together with such powers as
are reasonably incidental thereto. The Administrative Agent shall not have any
implied duties to the Lenders, or any obligation to the Lenders to take any
action thereunder except any action specifically provided by the Loan Documents
to be taken by the Administrative Agent.
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10.3 General Immunity. Neither the Administrative Agent nor any of the
Administrative Agent's directors, officers, agents or employees shall be liable
to the Borrower, the Lenders or any Lender for any action taken or omitted to be
taken by it or them hereunder or under any other Loan Document or in connection
herewith or therewith except to the extent such action or inaction is determined
in a final non-appealable judgment by a court of competent jurisdiction to have
arisen from the gross negligence or willful misconduct of such Person.
10.4 No Responsibility for Loans, Recitals, etc. Neither the
Administrative Agent nor any of the Administrative Agent's directors, officers,
agents or employees shall be responsible for or have any duty to ascertain,
inquire into, or verify (a) any statement, warranty or representation made in
connection with any Loan Document or any borrowing hereunder; (b) the
performance or observance of any of the covenants or agreements of any obligor
under any Loan Document, including, without limitation, any agreement by an
obligor to furnish information directly to each Lender; (c) the satisfaction of
any condition specified in Article IV, except for the receipt of items required
to be delivered solely to Administrative Agent; (d) the existence or possible
existence of any Default or Unmatured Default; (e) the validity, enforceability,
effectiveness, sufficiency or genuineness of any Loan Document or any other
instrument or writing furnished in connection therewith; or (f) the financial
condition of the Borrower or of any of the Borrower's Subsidiaries. The
Administrative Agent shall not have any duty to disclose to the Lenders
information that is not required to be furnished by the Borrower to the
Administrative Agent at such time, but is voluntarily furnished by the Borrower
to the Administrative Agent (either in its capacity as the Administrative Agent
or in its individual capacity).
10.5 Action on Instructions of Lenders. The Administrative Agent shall
in all cases be fully protected in acting, or in refraining from acting,
hereunder and under any other Loan Document in accordance with written
instructions signed by the Required Lenders (or, when expressly required
hereunder, all of the Lenders), and such instructions and any action taken or
failure to act pursuant thereto shall be binding on all of the Lenders.
The Lenders hereby acknowledge that the Administrative Agent shall not be
under any duty to take any discretionary action permitted to be taken by
it pursuant to the provisions of this Agreement or any other Loan Document
unless it shall be requested in writing to do so by the Required Lenders.
Each Administrative Agent shall be fully justified in failing or refusing to
take any action hereunder and under any other Loan Document unless it shall
first be indemnified to its satisfaction by the Lenders (ratably in accordance
with their respective Pro Rata Shares) against any and all liability, cost
and expense that it may incur by reason of taking or continuing to take any such
action. The Administrative Agent agrees, upon the request of any Lender at any
time an Unmatured Default exists, to give a written notice to the Borrower of
the type described in Section 7.1.3 or 7.1.4.
10.6 Employment of Agents and Counsel. The Administrative Agent may
execute any of its duties as Administrative Agent hereunder and under any other
Loan Document by or through employees, agents, and attorneys-in-fact and shall
not be answerable to the Lenders, except as to money or securities received by
it or its authorized agents, for the default or
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misconduct of any such agents or attorneys-in-fact selected by it with
reasonable care. The Administrative Agent shall be entitled to advice of counsel
concerning the contractual arrangement between the Administrative Agent and the
Lenders and all matters pertaining to the Administrative Agent's duties
hereunder and under any other Loan Document.
10.7 Reliance on Documents; Counsel. The Administrative Agent shall be
entitled to rely upon any Note, notice, consent, certificate, affidavit, letter,
telegram, statement, paper or document believed by it to be genuine and correct
and to have been signed or sent by the proper person or persons, and, in respect
to legal matters, upon the opinion of counsel selected by the Administrative
Agent, which counsel may be employees of the Administrative Agent.
10.8 Administrative Agent's Reimbursement and Indemnification. The
Lenders agree to reimburse and indemnify the Administrative Agent, ratably in
accordance with their respective Pro Rata Shares, (i) for any amounts not
reimbursed by the Borrower for which the Administrative Agent is entitled to
reimbursement by the Borrower under the Loan Documents, (ii) for any other
expenses incurred by the Administrative Agent on behalf of the Lenders, in
connection with the preparation, execution, delivery, administration and
enforcement of the Loan Documents (including, without limitation, for any
expenses incurred by the Administrative Agent in connection with any dispute
between the Administrative Agent and any Lender or between two or more of the
Lenders) and (iii) for any liabilities, obligations, losses, damages, penalties,
actions, judgments, suits, costs, expenses or disbursements of any kind and
nature whatsoever which may be imposed on, incurred by or asserted against the
Administrative Agent in any way relating to or arising out of the Loan Documents
or any other document delivered in connection therewith or the transactions
contemplated thereby (including, without limitation, for any such amounts
incurred by or asserted against the Administrative Agent in connection with any
dispute between the Administrative Agent and any Lender or between two or more
of the Lenders), or the enforcement of any of the terms of the Loan Documents or
of any such other documents, provided that (i) no Lender shall be liable to the
Administrative Agent for any of the foregoing to the extent any of the foregoing
is found in a final non-appealable judgment by a court of competent jurisdiction
to have resulted from the gross negligence or willful misconduct of the
Administrative Agent and (ii) any indemnification required pursuant to Section
3.5(vii) shall, notwithstanding the provisions of this Section 10.8, be paid by
the relevant Lender in accordance with the provisions thereof. The obligations
of the Lenders under this Section 10.8 shall survive payment of the Obligations
and termination of this Agreement.
10.9 Notice of Default. The Administrative Agent shall be deemed to
have knowledge or notice of the occurrence of any Default or Unmatured Default
hereunder unless the Administrative Agent has received written notice from a
Lender or the Borrower referring to this Agreement describing such Default or
Unmatured Default and stating that such notice is a "notice of default". In the
event that the Administrative Agent receives such a notice, the Administrative
Agent shall give prompt notice thereof to the Lenders.
10.10 Rights as a Lender. In the event the Administrative Agent is a
Lender, the Administrative Agent shall have the same rights and powers hereunder
and under any other Loan
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Document with respect to its Commitment and its Loans as any Lender and may
exercise the same as though it were not the Administrative Agent, and the term
"Lender" or "Lenders" shall, at any time when the Administrative Agent is a
Lender, unless the context otherwise indicates, include the Administrative Agent
in its individual capacity. The Administrative Agent and its Affiliates may
accept deposits from, lend money to, and generally engage in any kind of trust,
debt, equity or other transaction, in addition to those contemplated by this
Agreement or any other Loan Document, with the Borrower or any of its
Subsidiaries in which the Borrower or such Subsidiary is not restricted hereby
from engaging with any other Person. The Agent, in its individual capacity, is
not obligated to remain a Lender.
10.11 Lender Credit Decision. Each Lender acknowledges that it has,
independently and without reliance upon the Administrative Agent, the Arranger
or any other Lender and based on the financial statements prepared by the
Borrower and such other documents and information as it has deemed appropriate,
made its own credit analysis and decision to enter into this Agreement and the
other Loan Documents. Each Lender also acknowledges that it will, independently
and without reliance upon the Administrative Agent, the Arranger or any other
Lender and based on such documents and information as it shall deem appropriate
at the time, continue to make its own credit decisions in taking or not taking
action under this Agreement and the other Loan Documents.
10.12 Successor Administrative Agent. The Administrative Agent may
resign at any time by giving written notice thereof to the Lenders and the
Borrower, such resignation to be effective upon the appointment of a successor
Administrative Agent, or, if no successor Administrative Agent has been
appointed, forty-five days after the retiring Administrative Agent gives notice
of its intention to resign. The Administrative Agent may be removed at any time
with or without cause by written notice received by the Administrative Agent
from the Required Lenders, such removal to be effective on the date specified by
the Required Lenders. Upon any resignation or removal of the Administrative
Agent, the Required Lenders shall have the right (with, so long as no Default or
Unmatured Default exists, the consent of the Borrower, which shall not be
unreasonably withheld) to appoint, on behalf of the Borrower and the Lenders, a
successor Administrative Agent. If no successor Administrative Agent shall have
been so appointed by the Required Lenders within thirty days after the resigning
Administrative Agent's giving notice of its intention to resign, then the
resigning Administrative Agent may appoint, on behalf of the Borrower and the
Lenders, a successor Administrative Agent. Notwithstanding the previous
sentence, the Administrative Agent may at any time without the consent of any
Lender and with the consent of the Borrower, not to be unreasonably withheld or
delayed, appoint any of its Affiliates which is a commercial bank as a successor
Administrative Agent hereunder. If the Administrative Agent has resigned or been
removed and no successor Administrative Agent has been appointed, the Lenders
may perform all the duties of the Administrative Agent hereunder and the
Borrower shall make all payments in respect of the Obligations to the applicable
Lender and for all other purposes shall deal directly with the Lenders. No
successor Administrative Agent shall be deemed to be appointed hereunder until
such Administrative Agent has accepted the appointment. Any such successor
Administrative Agent shall be a commercial bank having capital and retained
earnings of at least $100,000,000. Upon the acceptance of any appointment
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as Administrative Agent hereunder by a successor Administrative Agent, such
successor Administrative Agent shall thereupon succeed to and become vested with
all the rights, powers, privileges and duties of the resigning or removed
Administrative Agent. Upon the effectiveness of the resignation or removal of
the Administrative Agent, the resigning or removed Administrative Agent shall be
discharged from its duties and obligations hereunder and under the Loan
Documents. After the effectiveness of the resignation or removal of the
Administrative Agent, the provisions of this Article X shall continue in effect
for the benefit of the such Person in respect of any actions taken or omitted to
be taken by such Person while such Person was acting as Administrative Agent
hereunder and under the other Loan Documents. In the event that there is a
successor to the Administrative Agent by merger, or the Administrative Agent
assigns its duties and obligations to an Affiliate pursuant to this Section
10.12, then the term "Prime Rate" as used in this Agreement shall mean the prime
rate, base rate or other analogous rate of the new Administrative Agent.
10.13 Delegation to Affiliates. The Borrower and the Lenders agree that
the Administrative Agent may delegate any of its duties under this Agreement to
any of its respective Affiliates. Any such Affiliate (and such Affiliate's
directors, officers, agents and employees) which performs duties in connection
with this Agreement shall be entitled to the same benefits of the
indemnification, waiver and other protective provisions to which the
Administrative Agent is entitled under Articles IX and X.
10.14 Other Agents. No Lender identified on the cover page or the
signature pages of this Agreement or otherwise herein, or in any amendment
hereof or other document related hereto, as being the "Syndication Agent" shall
have any right, power, obligation, liability, responsibility or duty under this
Agreement in such capacity other than those applicable to all Lenders. Each
Lender acknowledges that it has not relied, and will not rely, on any Person so
identified in deciding to enter into this Agreement or in taking or refraining
from taking any action hereunder or pursuant hereto.
ARTICLE XI
SETOFF; RATABLE PAYMENTS
11.1 Setoff. In addition to, and without limitation of, any rights of
the Lenders under applicable law, if the Borrower becomes insolvent, however
evidenced, or any Default occurs, any and all deposits (including all account
balances, whether provisional or final and whether or not collected or
available) and any other Indebtedness at any time held or owing by any Lender or
any Affiliate of any Lender to or for the credit or account of the Borrower may
be offset and applied toward the payment of the Obligations owing to such
Lender, whether or not the Obligations, or any part thereof, shall then be due.
11.2 Ratable Payments. If any Lender, whether by setoff or otherwise,
has payment made to it upon its Ratable Loans or its participation in Swing Line
Loans (other than payments
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received pursuant to Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than
that received by any other Lender, such Lender agrees, promptly upon demand, to
purchase a portion of the Loans (or participations in Swing Line Loans) held by
the other Lenders so that after such purchase each Lender will hold its Pro Rata
Share of all Ratable Loans (and participations in Swing Line Loans). If any
Lender, whether in connection with setoff or amounts which might be subject to
setoff or otherwise, receives collateral or other protection for its Obligations
or such amounts which may be subject to setoff, such Lender agrees, promptly
upon demand, to take such action necessary such that all Lenders share in the
benefits of such collateral ratably in proportion to their respective Pro Rata
Shares. In case any such payment is disturbed by legal process, or otherwise,
appropriate further adjustments shall be made.
ARTICLE XII
BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS
12.1 Successors and Assigns. The terms and provisions of the Loan
Documents shall be binding upon and inure to the benefit of the Borrower and the
Lenders and their respective successors and assigns, except that (i) the
Borrower shall not have the right to assign its rights or obligations under the
Loan Documents and (ii) any assignment by any Lender must be made in compliance
with Section 12.3. The parties to this Agreement acknowledge that clause (ii) of
the foregoing sentence relates only to absolute assignments and does not
prohibit assignments creating security interests, including, without limitation,
any pledge or assignment by any Lender of all or any portion of its rights under
this Agreement and any Note to a Federal Reserve Bank; provided that no such
pledge or assignment creating a security interest shall release the transferor
Lender from its obligations hereunder unless and until the parties thereto have
complied with the provisions of Section 12.3. The Administrative Agent may treat
the Person which made any Loan or which holds any Note as the owner thereof for
all purposes hereof unless and until such Person complies with Section 12.3;
provided that the Administrative Agent may in its discretion (but shall not be
required to) follow instructions from the Person which made any Loan or which
holds any Note to direct payments relating to such Loan or Note to another
Person. Any assignee of the rights to any Loan or any Note agrees by acceptance
of such assignment to be bound by all the terms and provisions of the Loan
Documents. Any request, authority or consent of any Person, who at the time of
making such request or giving such authority or consent is the owner of the
rights to any Loan (whether or not a Note has been issued in evidence thereof),
shall be conclusive and binding on any subsequent holder or assignee of the
rights to such Loan.
12.2 Participations.
12.2.1 Permitted Participants; Effect. Any Lender may, in the ordinary
course of its business and in accordance with applicable law, at any time sell
to one or more banks or other entities ("Participants") participating interests
in any Loan owing to such Lender, any Note held by such Lender, any Commitment
of such Lender or any other interest of such Lender under the
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Loan Documents. In the event of any such sale by a Lender of participating
interests to a Participant, such Lender's obligations under the Loan Documents
shall remain unchanged, such Lender shall remain solely responsible to the other
parties hereto for the performance of such obligations, such Lender shall remain
the owner of its Loans and the holder of any Note issued to it in evidence
thereof for all purposes under the Loan Documents, all amounts payable by the
Borrower under this Agreement (including under Article III) shall be determined
as if such Lender had not sold such participating interests, and the Borrower
and the Administrative Agent shall continue to deal solely and directly with
such Lender in connection with such Lender's rights and obligations under the
Loan Documents.
12.2.2 Voting Rights. Each Lender shall retain the sole right to
approve, without the consent of any Participant, any amendment, modification or
waiver of any provision of the Loan Documents other than any amendment,
modification or waiver with respect to any Loan or Commitment in which such
Participant has an interest which forgives principal, interest or fees or
reduces the interest rate or fees payable with respect to any such Loan or
Commitment, extends the Termination Date, postpones any date fixed for any
regularly scheduled payment of principal of, or interest or fees on, any such
Loan or Commitment or releases any Guarantor from its obligations under the
Subsidiary Guaranty (except as provided in Section 8.4).
12.3 Assignments.
12.3.1 Permitted Assignments. Any Lender may, in the ordinary course of
its business and in accordance with applicable law, at any time assign to one or
more banks or other entities ("Purchasers") all or any part of its rights and
obligations under the Loan Documents. Such assignment shall be substantially in
the form of Exhibit C or in such other form as may be agreed to by the parties
thereto. The consents of the Borrower and the Administrative Agent (which
consents shall not be unreasonably withheld or delayed by any such party) shall
be required prior to an assignment becoming effective with respect to a
Purchaser which is not a Lender or an Affiliate thereof; provided that if a
Default has occurred and is continuing, the consent of the Borrower shall not be
required; provided, further, that no assignment shall be permitted if, as of the
date thereof, any event or circumstance exists which would result in the
Borrower being obligated to pay any greater amount hereunder to the Purchaser
than the Borrower is obligated to pay to the assigning Lender. Each such
assignment with respect to a Purchaser which is not a Lender or an Affiliate
thereof shall (unless each of the Borrower and the Administrative Agent
otherwise consents) be in an amount not less than the lesser of (i) $5,000,000
or (ii) the remaining amount of the assigning Lender's Commitment (calculated as
at the date of such assignment) or outstanding Ratable Loans and participations
in Swing Line Loans (if the Commitments has been terminated).
12.3.2 Effect; Effective Date. Upon (i) delivery to the Administrative
Agent of an assignment, together with any consents required by Section 12.3.1,
and (ii) payment of a $4,000 fee to the Administrative Agent for processing such
assignment (unless such fee is waived by the Administrative Agent), such
assignment shall become effective on the effective date specified in such
assignment. The assignment shall contain a representation by the Purchaser to
the effect
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that none of the consideration used to make the purchase of the Commitment and
Loans under the applicable assignment agreement constitutes "plan assets" as
defined under ERISA and that the rights and interests of the Purchaser in and
under the Loan Documents will not be "plan assets" under ERISA. On and after the
effective date of such assignment, such Purchaser shall for all purposes be a
Lender party to this Agreement and any other Loan Document executed by or on
behalf of the Lenders and shall have all the rights and obligations of a Lender
under the Loan Documents, to the same extent as if it were an original party
hereto, and no further consent or action by the Borrower, the Lenders or the
Administrative Agent shall be required to release the transferor Lender with
respect to the percentage of the Aggregate Commitment and Loans assigned to such
Purchaser. Upon the consummation of any assignment to a Purchaser pursuant to
this Section 12.3.2, the transferor Lender, the Administrative Agent and the
Borrower shall, if the transferor Lender or the Purchaser desires that its Loans
be evidenced by Notes, make appropriate arrangements so that new Notes or, as
appropriate, replacement Notes are issued to such transferor Lender and new
Notes or, as appropriate, replacement Notes, are issued to such Purchaser, in
each case in principal amounts reflecting their respective Commitments, as
adjusted pursuant to such assignment.
12.4 Dissemination of Information. The Borrower authorizes each Lender
to disclose to any Participant or Purchaser or any other Person acquiring an
interest in the Loan Documents by operation of law (each a "Transferee") and any
prospective Transferee any and all information in such Lender's possession
concerning the creditworthiness of the Borrower and its Subsidiaries, including
without limitation any information contained in any Reports; provided that each
Transferee and prospective Transferee agrees to be bound by Section 9.11 of this
Agreement.
12.5 Tax Treatment. If any interest in any Loan Document is transferred
to any Transferee which is organized under the laws of any jurisdiction other
than the United States or any State thereof, the transferor Lender shall cause
such Transferee, concurrently with the effectiveness of such transfer, to comply
with the provisions of Section 3.5(iv) and the Borrower shall not be required to
indemnify such Transferee pursuant to Section 3.5 hereof for any Taxes withheld
as a result of the failure of the Transferee to so comply.
ARTICLE XIII
NOTICES
13.1 Notices. Except as otherwise permitted by Section 2.15 with
respect to borrowing notices, all notices, requests and other communications to
any party hereunder shall be in writing (including electronic transmission,
facsimile transmission or similar writing) and shall be given to such party: (x)
in the case of the Borrower or the Administrative Agent, at its address or
facsimile number set forth on the signature pages hereof, (y) in the case of any
Lender, at its address or facsimile number set forth in its administrative
questionnaire or (z) in the case of any party, at such other address or
facsimile number as such party may hereafter specify for the
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purpose by notice to the Administrative Agent and the Borrower in accordance
with the provisions of this Section 13.1. Each such notice, request or other
communication shall be effective (i) if given by facsimile transmission, when
transmitted to the facsimile number specified in this Section 13.1 and
confirmation of receipt is received, or (ii) if given by any other means, when
delivered (or, in the case of electronic transmission, received) at the address
specified in this Section 13.1; provided that notices to the Administrative
Agent under Article II shall not be effective until received.
13.2 Change of Address. The Borrower, the Administrative Agent and any
Lender may each change the address for service of notice upon it by a notice in
writing to the other parties hereto.
ARTICLE XIV
COUNTERPARTS
This Agreement may be executed in any number of counterparts, all of
which taken together shall constitute one agreement, and any of the parties
hereto may execute this Agreement by signing any such counterpart. This
Agreement shall be effective when it has been executed by the Borrower, the
Administrative Agent and the Lenders and each party has notified the
Administrative Agent by facsimile transmission or telephone that it has taken
such action.
ARTICLE XV
CHOICE OF LAW; CONSENT TO JURISDICTION;
WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE
15.1 CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A
CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE CONSTRUED IN ACCORDANCE WITH
THE INTERNAL LAWS (INCLUDING, WITHOUT LIMITATION, 735 ILCS SECTION 105/5-1 ET
SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE
STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL
BANKS.
15.2 CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS
TO THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE
COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR
RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT
ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED
IN ANY SUCH COURT AND IRREVOCABLY
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WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER HAVE AS TO THE VENUE OF ANY SUCH
SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A COURT OR THAT SUCH COURT IS AN
INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT THE RIGHT OF THE ADMINISTRATIVE
AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE BORROWER IN THE COURTS OF
ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE BORROWER AGAINST THE
ADMINISTRATIVE AGENT OR ANY LENDER OR ANY AFFILIATE OF THE ADMINISTRATIVE AGENT
OR ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING
OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN
A COURT IN CHICAGO, ILLINOIS.
15.3 WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT AND
EACH LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING,
DIRECTLY OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR
OTHERWISE) IN ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN
DOCUMENT OR THE RELATIONSHIP ESTABLISHED THEREUNDER.
15.4 Maximum Interest Rate. No provision of the Loan Documents shall
require the payment or permit the collection of interest in excess of the
maximum permitted by applicable law ("Maximum Rate"). If any interest in excess
of the Maximum Rate is provided for or shall be adjudicated to be provided for
in the Notes or otherwise in connection with this Agreement, the provisions of
this Section 15.4 shall govern and prevail and neither the Borrower nor the
sureties, guarantors, successors or assigns of the Borrower shall be obligated
to pay the excess amount of the interest or any other excess sum paid for the
use, forbearance, or detention of sums loaned. In the event the Administrative
Agent or any Lender ever receives, collects or applies as interest any amount in
excess of the Maximum Rate, the amount by which such amount exceeds the Maximum
Rate shall be applied as a payment and reduction of the principal of
indebtedness evidenced by the Loans, and, if the principal amount of the Loans
has been paid in full, any remaining excess shall forthwith be paid to the
Borrower.
-59-
IN WITNESS WHEREOF, the Borrower, the Lenders, the Administrative Agent
and the Syndication Agent have executed this Agreement as of the date first
above written.
SOUTHWESTERN ENERGY COMPANY
By:_____________________________________
Executive Vice President and
Chief Financial Officer
2350 N. Sam Houston Parkway East
Suite 300
Houston, Texas 77032
Attention: Greg Kerley
Fax: 281-618-4757
S-1
BANK ONE, NA,
Individually and as Administrative Agent
By:_____________________________________
Title:_______________________________
1 Bank One Plaza
Chicago, Illinois 60670
Attention: Madeleine Pember
Fax: 312-732-9727
S-2
ROYAL BANK OF CANADA,
Individually and as Syndication Agent
By:_____________________________________
Title:_______________________________
Royal Bank of Canada
2800 Post Oak Boulevard
Suite 5700
Houston, Texas 77056
Attention: Jason York
Fax: 713-403-5624
S-3
FLEET NATIONAL BANK
By:_____________________________________
Title:_______________________________
Mail Stop: MA DE 10008D
100 Federal Street
Boston, MA 02110
Attention: Stephen Hoffman
Fax: 617-434-3652
S-4
WELLS FARGO BANK TEXAS, N.A.
By:_____________________________________
Title:_______________________________
Wells Fargo Bank Texas, N.A.
1000 Louisiana St.
3rd Floor
Houston, TX 77002
Attention: Alan Smith
Fax: 713-739-1087
S-5
COMPASS BANK
By:_____________________________________
Title:_______________________________
Compass Bank
24 Greenway Plaza
Suite 1400A
Houston, TX 77046
Attention: Dorothy Marchand
Fax: 713-968-8292
S-6
HIBERNIA NATIONAL BANK
By:_____________________________________
Title:_______________________________
Hibernia National Bank
213 W. Vermilion St.
2nd Floor
Lafayette, Louisiana 70501
Attention: David R. Reid
Fax: 337-268-4566
S-7
Lender Amount of Commitment
============================ =====================
Bank One, NA $ 55,000,000
Royal Bank of Canada $ 40,000,000
Fleet National Bank $ 25,000,000
Wells Fargo Bank Texas, N.A. $ 15,000,000
Compass Bank $ 15,000,000
Hibernia National Bank $ 10,000,000
Aggregate Commitment $160,000,000
SCHEDULE 1B
PRICING SCHEDULE
LEVEL I LEVEL II LEVEL III LEVEL IV LEVEL V
STATUS STATUS STATUS STATUS STATUS
------- -------- --------- -------- -------
Commitment Fee Rate 17.5 20.0 25.0 30.0 30.0
(basis points)
Applicable Margin 87.5 137.5 150.0 175.0 250.0
for Eurodollar Rate
(basis points)
Applicable Margin 0.0 0.0 0.0 25.0 100.0
for Floating Rate
(basis points)
For the purposes of this Schedule, the following terms have the following
meanings, subject to the final paragraph of this Schedule:
"Level I Status" exists at any date if, on such date, the Borrower's
Moody's Rating is Baa1 or better or the Borrower's S&P Rating is BBB+ or better.
"Level II Status" exists at any date if, on such date, (i) the Borrower has
not qualified for Level I Status and (ii) the Borrower's Moody's Rating is Baa2
or better or the Borrower's S&P Rating is BBB or better.
"Level III Status" exists at any date if, on such date, (i) the Borrower
has not qualified for Level I Status or Level II Status and (ii) the Borrower's
Moody's Rating is Baa3 or better or the Borrower's S&P Rating is BBB- or better.
"Level IV Status" exists at any date if, on such date, (i) the Borrower has
not qualified for Level I Status , Level II Status or Level III Status and (ii)
the Borrower's Moody's Rating is Ba1 or better or the Borrower's S&P Rating is
BB+ or better.
"Level V Status" exists at any date if, on such date, the Borrower has not
qualified for Level I Status, Level II Status, Level III Status , or Level IV
Status.
"Moody's Rating" means, at any time, the rating issued by Moody's Investors
Service, Inc. and then in effect with respect to the Borrower's senior unsecured
long-term public debt securities without third-party credit enhancement.
"S&P Rating" means, at any time, the rating issued by Standard and Poor's
Rating Services, a division of The McGraw Hill Companies, Inc., and then in
effect with respect to the
Borrower's senior unsecured long-term public debt securities without third-party
credit enhancement.
"Status" means Level I Status, Level II Status, Level III Status, Level IV
Status or Level V Status.
The Applicable Margin and Commitment Fee Rate shall be determined in
accordance with the foregoing table based on the Borrower's Status as determined
from its then-current Moody's and S&P Ratings. The credit rating in effect on
any date for the purposes of this Schedule is that in effect at the close of
business on such date. If at any time the Borrower has no Moody's Rating or no
S&P Rating, Level V Status shall exist.
If the Borrower is split-rated and the ratings differential is one level,
the higher rating will apply. If the Borrower is split-rated and the ratings
differential is two levels or more, the intermediate rating at the midpoint will
apply. If there is no midpoint, the higher of the two intermediate ratings will
apply.
SCHEDULE 2.8(a)
EXCLUDED ASSET SALES
A.W. Realty Sale
An undivided 2/3 interest in Lot1-B of Vantage Square, a Joint Venture, or a
portion of Lot 1-B yet to be determined. Lot 1-B containing 5.86 acres is
located in the northeast quarter of the northeast quarter of Section 26,
Township 17 north, range 30 west of Washington County, Arkansas. Anticipated
sales proceeds of approximately $1.2 million.
SCHEDULE 2.8(b)
ASSETS TO BE SWAPPED
Southwestern Energy Production Company's working interest in approximately 250
oil and gas producing properties in the Anadarko Basin of Oklahoma. Properties
would be anticipated to be sold at a price ranging from $20 million to $30
million.
SCHEDULE 5.4
SUBSIDIARIES
Arkansas Western Gas Company
Southwestern Energy Production Company
Southwestern Energy Pipeline Company
SEECO, Inc.
A.W. Realty Company
Southwestern Energy Services Company
Diamond M Production Company
All of the above are 100% wholly-owned by the Company and are Arkansas
corporations.
Arkansas Gas Gathering Company, an Arkansas corporation, is 100% wholly-owned by
SEECO, Inc.
Overton Partners, LLC, an Arkansas limited liability company, is 100%
wholly-owned by Southwestern Energy Production Company.
SCHEDULE 5.13
LITIGATION
On August 25, 2000, a class action suit was filed against the Borrower and its
subsidiaries in Sebastian County, Arkansas, on behalf of all mineral owners who
own or owned a royalty and/or overriding royalty interest in oil and gas leases
or other agreements in certain sections of Franklin County, Arkansas. The
Borrower was granted authority in 1968 by the Arkansas Oil and Gas Commission to
operate a gas storage facility in one section of Franklin County. Based upon
subsequently developed geological data, the Borrower sought authority to expand
this area and was granted authority by the Arkansas Oil and Gas Commission to
operate gas storage in additional sections. Plaintiffs are challenging the
storage agreements that the Borrower obtained from the mineral interest owners
in 1968, 1999 and 2000 to operate the gas storage facility known as "Stockton."
Plaintiffs allege various wrongful, intentional and fraudulent acts relating to
the operation of the storage pool beginning in 1968 and continuing to the
present and allege that the above-referenced agreements from the mineral owners
were obtained through misrepresentation and fraud. The Borrower has owned and
operated the Stockton storage unit through its Arkansas Western Gas Company
subsidiary until 1994, at which time it was transferred to its subsidiary,
SEECO, Inc. Plaintiffs claim ownership rights in the gas that the Borrower has
stored in the storage pool in an amount in excess of $5 million in actual
damages, interest, attorney's fees and punitive damages. The Borrower and its
outside counsel believe that this action is without merit and does not meet the
requirements for a class action. The Borrower believes that plaintiffs claim to
the storage gas, which the Borrower has injected into the storage facility, has
no merit and is not supported by the Arkansas gas storage statute under which
the Borrower operates this facility. While the amount of this claim could be
significant, management believes, based upon its investigation, that this claim
is without merit and that the Borrower's ultimate liability, if any, will not be
material to its consolidated financial position, but in any one period it could
be significant to its results of operations.
SCHEDULE 5.19
NEGATIVE PLEDGES
Listed below are all of the documents evidencing Indebtedness of
Southwestern Energy Company and its Subsidiaries which contain limitations on
the creation, incurrence, or assumption of Liens on any of their properties.
Indenture dated as of December 1, 1995, between the Borrower and Bank One,
NA (then known as The First National Bank of Chicago), as Trustee.
SCHEDULE 6.2
INSURANCE
1. Property "all risk" insurance including earthquake coverage for
buildings, personal property, equipment and inventory. Minimum limit of
$15,000,000.
2. Workers' Compensation with Statutory Limits and Employer's Liability
with $1,000,000 per accident or occupational disease covering all
employees in compliance with the laws of the States of Arkansas,
Oklahoma, New Mexico and Texas. Such policy is endorsed to provide
United States Longshoremen's & Harbor Workers' Compensation Act and
Maritime Coverages.
3. Comprehensive General Liability Insurance with bodily injury and death
limits of $1,000,000 for injury to or death of one person and
$2,000,000 for the death or injury of more than one person in one
occurrence and property damage limits of $1,000,000 for each
occurrence.
4. Automobile Public Liability Insurance covering bodily injury or death
and property damage of at least $1,000,000 per occurrence, combined
single limit.
5. Control of Well Coverage with $10,000,000 combined single limit for
operator's extra expense/care, custody and control;
redrilling/recompletion; and seepage, pollution and containment.
6. Umbrella Liability Insurance with minimum limits of at least
$30,000,000 to apply in excess of the primary limits of the above
stated policies.
EXHIBIT A
FORM OF BORROWING NOTICE
Reference is made to the Credit Agreement dated as of July 12, 2001 (as from
time to time amended, the "Agreement") among Southwestern Energy Company, an
Arkansas corporation (the "Borrower"), various financial institutions, and Bank
One, NA, as Administrative Agent (the "Administrative Agent"). Capitalized terms
used but not defined herein have the respective meanings given to such terms in
the Agreement. Pursuant to the Agreement, the Borrower hereby requests that an
Advance in the amount of $_________ to be made on ____________, ____. The
Borrower requests that the Advance to be made hereunder shall be [a Floating
Rate Advance] [a Eurodollar Advance] [and shall have an Interest Period of
_______________.]
The Borrower certifies that:
(a) The representations and warranties of the Borrower set forth in
Article V of the Agreement are true and correct on and as of the date hereof,
with the same effect as though such representations and warranties had been made
on and as of the date hereof or, if such representations and warranties are
expressly limited to particular dates, as of such particular dates.
(b) No Default or Unmatured Default exists or will result from the
Borrower's receipt and application of the proceeds of the Advance requested
hereby.
IN WITNESS WHEREOF, this instrument is executed as of _________, ____.
SOUTHWESTERN ENERGY COMPANY
By:________________________________
Name:______________________________
Title:_____________________________
EXHIBIT B
FORM OF OPINION
July 12, 2001
The Administrative Agent and the Lenders who are parties to the Credit Agreement
described below.
Gentlemen/Ladies:
I am counsel for Southwestern Energy Company (the "Borrower"), and have
represented the Borrower and the Subsidiaries of the Borrower listed on Schedule
1 (the "Guarantors") in connection with its execution and delivery of a Credit
Agreement dated as of July 12, 2001 (the "Agreement") among the Borrower, the
Lenders named therein, and Bank One, NA, as Administrative Agent, and providing
for Advances in an aggregate principal amount not exceeding $160,000,000 at any
one time outstanding. All capitalized terms used in this opinion and not
otherwise defined herein shall have the meanings attributed to them in the
Agreement.
I have examined the Borrower's and each Guarantor's **[describe
constitutive documents of Borrower and Guarantors and appropriate evidence of
authority to enter into the transaction]**, the Loan Documents and such other
matters of fact and law which we deem necessary in order to render this opinion.
Based upon the foregoing, it is our opinion that:
l. Each of the Borrower and its Subsidiaries is a corporation, partnership
or limited liability company duly and properly incorporated or organized, as the
case may be, validly existing and (to the extent such concept applies to such
entity) in good standing under the laws of its jurisdiction of incorporation or
organization and has all requisite authority to conduct its business in each
jurisdiction in which its business is conducted.
2. The execution and delivery by the Borrower and each Guarantor of the
Loan Documents to which it is a party and the performance by the Borrower and
each Guarantor of its obligations thereunder have been duly authorized by proper
corporate or limited liability company proceedings on the part of the Borrower
and each Guarantor and will not:
(a) require any consent of the Borrower's or any Guarantor's
shareholders or members (other than any such consent as has already been
given and remains in full force and effect);
(b) violate (i) any law, rule, regulation, order, writ, judgment,
injunction, decree or award binding on the Borrower or any of its
Subsidiaries or (ii) the Borrower's
or any Subsidiary's articles or certificate of incorporation, articles
or certificate of organization, bylaws, or operating or other management
agreement, as the case may be, or (iii) the provisions of any indenture,
instrument or agreement to which the Borrower or any of its Subsidiaries
is a party or is subject, or by which it, or its Property, is bound, or
conflict with or constitute a default thereunder; or
(c) result in, or require, the creation or imposition of any Lien
in, of or on the Property of the Borrower or a Subsidiary pursuant to
the terms of any indenture, instrument or agreement binding upon the
Borrower or any of its Subsidiaries.
3. The Loan Documents to which the Borrower or any Guarantor is a party
have been duly executed and delivered by the Borrower or such Guarantor, as the
case may be, and constitute legal, valid and binding obligations of the Borrower
enforceable against the Borrower or such Guarantor, as the case may be, in
accordance with their terms except to the extent the enforcement thereof may be
limited by bankruptcy, insolvency or similar laws affecting the enforcement of
creditors' rights generally and subject also to the availability of equitable
remedies if equitable remedies are sought.
4. Except for the litigation disclosed in Borrower's Form 10-K for the
year ended December 31, 2000 and updated in the Borrower's most recent Form
10-Q, there is no litigation, arbitration, governmental investigation,
proceeding or inquiry pending or, to the best of our knowledge after due
inquiry, threatened against the Borrower or any of its Subsidiaries which,
if adversely determined, could reasonably be expected to have a Material Adverse
Effect.
5. No order, consent, adjudication, approval, license, authorization, or
validation of, or filing, recording or registration with, or exemption by, or
other action in respect of any governmental or public body or authority, or any
subdivision thereof, which has not been obtained by the Borrower or any of its
Subsidiaries, is required to be obtained by the Borrower or any of its
Subsidiaries in connection with the execution and delivery of the Loan
Documents, the borrowings under the Agreement, the payment and performance by
the Borrower of the Obligations, or the legality, validity, binding effect or
enforceability of any of the Loan Documents.
This opinion may be relied upon by the Administrative Agent, the Lenders
and their participants, assignees and other transferees.
Very truly yours,
EXHIBIT C
ASSIGNMENT AGREEMENT
This Assignment Agreement (this "Assignment Agreement") between (the
"Assignor") and (the "Assignee") is dated as of , 20___. The parties hereto
agree as follows:
1. PRELIMINARY STATEMENT. The Assignor is a party to a Credit Agreement
(which, as it may be amended, modified, renewed or extended from time to time is
herein called the "Credit Agreement") described in Item 1 of Schedule 1 attached
hereto ("Schedule 1"). Capitalized terms used herein and not otherwise defined
herein shall have the meanings attributed to them in the Credit Agreement.
2. ASSIGNMENT AND ASSUMPTION. The Assignor hereby sells and assigns to the
Assignee, and the Assignee hereby purchases and assumes from the Assignor, an
interest in and to the Assignor's rights and obligations under the Credit
Agreement and the other Loan Documents, such that after giving effect to such
assignment the Assignee shall have purchased pursuant to this Assignment
Agreement the percentage interest specified in Item 3 of Schedule 1 of all
outstanding rights and obligations under the Credit Agreement and the other Loan
Documents relating to the facilities listed in Item 3 of Schedule 1. The
aggregate Commitment (or Loans, if the Commitments have been terminated)
purchased by the Assignee hereunder is set forth in Item 4 of Schedule 1.
3. EFFECTIVE DATE. The effective date of this Assignment Agreement (the
"Effective Date") shall be the later of the date specified in Item 5 of Schedule
1 or two Business Days (or such shorter period agreed to by the Administrative
Agent) after this Assignment Agreement, together with any consents required
under the Credit Agreement, are delivered to the Administrative Agent. In no
event will the Effective Date occur if the payments required to be made by the
Assignee to the Assignor on the Effective Date are not made on the proposed
Effective Date.
4. PAYMENT OBLIGATIONS. In consideration for the sale and assignment of
Loans hereunder, the Assignee shall pay the Assignor, on the Effective Date, the
amount agreed to by the Assignor and the Assignee. On and after the Effective
Date, the Assignee shall be entitled to receive from the Administrative Agent
all payments of principal, interest and fees with respect to the interest
assigned hereby. The Assignee will promptly remit to the Assignor any interest
on Loans and fees received from the Administrative Agent which relate to the
portion of the Commitment or Loans assigned to the Assignee hereunder for
periods prior to the Effective Date and not previously paid by the Assignee to
the Assignor. In the event that either party hereto receives any payment to
which the other party hereto is entitled under this Assignment Agreement, then
the party receiving such amount shall promptly remit it to the other party
hereto.
5. RECORDATION FEE. The Assignor and Assignee each agree to pay one-half
of the recordation fee required to be paid to the Administrative Agent in
connection with this Assignment Agreement unless otherwise specified in Item 6
of Schedule 1.
6. REPRESENTATIONS OF THE ASSIGNOR; LIMITATIONS ON THE ASSIGNOR'S
LIABILITY. The Assignor represents and warrants that (i) it is the legal and
beneficial owner of the interest being assigned by it hereunder, (ii) such
interest is free and clear of any adverse claim created by the Assignor and
(iii) the execution and delivery of this Assignment Agreement by the Assignor is
duly authorized. It is understood and agreed that the assignment and assumption
hereunder are made without recourse to the Assignor and that the Assignor makes
no other representation or warranty of any kind to the Assignee. Neither the
Assignor nor any of its officers, directors, employees, agents or attorneys
shall be responsible for (i) the due execution, legality, validity,
enforceability, genuineness, sufficiency or collectability of any Loan Document,
including without limitation, documents granting the Assignor and the other
Lenders a security interest in assets of the Borrower or any guarantor, (ii) any
representation, warranty or statement made in or in connection with any of the
Loan Documents, (iii) the financial condition or creditworthiness of the
Borrower or any guarantor, (iv) the performance of or compliance with any of the
terms or provisions of any of the Loan Documents, (v) inspecting any of the
property, books or records of the Borrower, (vi) the validity, enforceability,
perfection, priority, condition, value or sufficiency of any collateral securing
or purporting to secure the Loans or (vii) any mistake, error of judgment, or
action taken or omitted to be taken in connection with the Loans or the Loan
Documents.
7. REPRESENTATIONS AND UNDERTAKINGS OF THE ASSIGNEE. The Assignee (i)
confirms that it has received a copy of the Credit Agreement, together with
copies of the financial statements requested by the Assignee and such other
documents and information as it has deemed appropriate to make its own credit
analysis and decision to enter into this Assignment Agreement, (ii) agrees that
it will, independently and without reliance upon the Administrative Agent, the
Assignor or any other Lender and based on such documents and information at it
shall deem appropriate at the time, continue to make its own credit decisions in
taking or not taking action under the Loan Documents, (iii) appoints and
authorizes the Administrative Agent to take such action as agent on its behalf
and to exercise such powers under the Loan Documents as are delegated to the
Administrative Agent by the terms thereof, together with such powers as are
reasonably incidental thereto, (iv) confirms that the execution and delivery of
this Assignment Agreement by the Assignee is duly authorized, (v) agrees that it
will perform in accordance with their terms all of the obligations which by the
terms of the Loan Documents are required to be performed by it as a Lender, (vi)
agrees that its payment instructions and notice instructions are as set forth in
the attachment to Schedule 1, (vii) confirms that none of the funds, monies,
assets or other consideration being used to make the purchase and assumption
hereunder are "plan assets" as defined under ERISA and that its rights, benefits
and interests in and under the Loan Documents will not be "plan assets" under
ERISA, (viii) agrees to indemnify and hold the Assignor harmless against all
losses, costs and expenses (including, without limitation, reasonable attorneys'
fees) and liabilities incurred by the Assignor in connection with or arising in
any manner from the Assignee's nonperformance of the
2
obligations assumed under this Assignment Agreement, and (ix) if applicable,
attaches the forms prescribed by the Internal Revenue Service of the United
States certifying that the Assignee is entitled to receive payments under
the Loan Documents without deduction or withholding of any United States federal
income taxes.
8. GOVERNING LAW. This Assignment Agreement shall be governed by the
internal law, and not the law of conflicts, of the State of Illinois.
9. NOTICES. Notices shall be given under this Assignment Agreement in the
manner set forth in the Credit Agreement. For the purpose hereof, the addresses
of the parties hereto (until notice of a change is delivered) shall be the
address set forth in the attachment to Schedule 1.
10. COUNTERPARTS; DELIVERY BY FACSIMILE. This Assignment Agreement may be
executed in counterparts. Transmission by facsimile of an executed counterpart
of this Assignment Agreement shall be deemed to constitute due and sufficient
delivery of such counterpart and such facsimile shall be deemed to be an
original counterpart of this Assignment Agreement.
IN WITNESS WHEREOF, the duly authorized officers of the parties hereto have
executed this Assignment Agreement by executing Schedule 1 hereto as of the date
first above written.
3
SCHEDULE 1
to Assignment Agreement
1. Description and Date of Credit Agreement:
Credit Agreement dated as of July 12, 2001 among Southwestern Energy
Company, the lenders named therein including the Assignor, and Bank
One, NA individually and as Administrative Agent for such lender, as it
may be amended from time to time.
2. Date of Assignment Agreement: __________, 20__
3. Amounts (As of Date of Item 2 above):
a. Assignee's percentage
of Aggregate Commitment
(Advances) purchased
under the Assignment
Agreement** ____%
b. Amount of
Assignor's Commitment
purchased
under the Assignment
Agreement** $____
4. Assignee's Commitment (or Loans
with respect to terminated
Commitments) purchased
hereunder: $___________________
5. Proposed Effective Date: ____________________
6. Non-standard Recordation Fee
Arrangement
N/A***
[Assignor/Assignee
to pay 100% of fee]
[Fee waived by Administrative Agent]
Accepted and Agreed:
[NAME OF ASSIGNOR] [NAME OF ASSIGNEE]
By:______________________ By:______________________
Title____________________ Title:___________________
4
ACCEPTED AND CONSENTED TO****
SOUTHWESTERN ENERGY COMPANY
By:__________________________
Title:_______________________
** Percentage taken to 10 decimal places
*** If fee is split 50-50, pick N/A as option
**** Delete if not required by Credit Agreement
ACCEPTED AND CONSENTED
TO BY BANK ONE, NA,
as Administrative Agent
By:__________________________
Title:_______________________
5
Attachment to SCHEDULE 1 to ASSIGNMENT AGREEMENT
ADMINISTRATIVE INFORMATION SHEET
Attach Assignor's Administrative Information Sheet, which must
include notice addresses for the Assignor and the Assignee
(Sample form shown below)
ASSIGNOR INFORMATION
Contact:
Name:__________________ Telephone No.:__________________________
Fax No.:________________ Telex No.:______________________________
Answerback:_____________________________
Payment Information:
Name & ABA # of Destination Bank: ___________________________________
Account Name & Number for Wire Transfer:_____________________________
_____________________________________________________________________
Other Instructions:__________________________________________________
Address for Notices for Assignor:____________________________________
ASSIGNEE INFORMATION
Credit Contact:
Name:____________________ Telephone No.:__________________________
Fax No.:__________________ Telex No.:______________________________
Answerback:_____________________________
Key Operations Contacts:
Booking Installation: Booking Installation:
Name: Name:
Telephone No.: Telephone No.:
Fax No.: Fax No.:
Telex No.: Telex No.:
Answerback: Answerback:
6
Payment Information:
Name & ABA # of Destination Bank:
Account Name & Number for Wire Transfer:_____________________________
Other Instructions:
Address for Notices for Assignee:
7
BANK ONE INFORMATION
Assignee will be called promptly upon receipt of the signed agreement.
Initial Funding Contact: Subsequent Operations Contact:
Name: Name:
Telephone No.: (312) Telephone No.: (312)
Fax No.: (312) Fax No.: (312)
Bank One Telex No.: 190201 (Answerback: FNBC UT)
Initial Funding Standards:
Libor Fund 2 days after rates are set.
Bank One Wire Instructions: Bank One, NA, ABA # 071000013
LS2 Incoming Account # 481152860000
Ref:________________
Address for Notices for Bank One: 1 Bank One Plaza, Chicago, IL 60670
Attn: Agency Compliance Division,
Suite IL1-0353
Fax No. (312) 7322038 or (312) 7324339
8
EXHIBIT D
LOAN/CREDIT RELATED MONEY TRANSFER INSTRUCTION
To Bank One, NA,
as Administrative Agent (the "Administrative Agent")
under the Credit Agreement
Described Below.
Re: Credit Agreement, dated as of July 12, 2001 (as the same may be amended
or modified, the "Credit Agreement"), among Southwestern Energy Company (the
"Borrower"), the Lenders named therein and the Administrative Agent. Capitalized
terms used herein and not otherwise defined herein shall have the meanings
assigned thereto in the Credit Agreement.
The Administrative Agent is specifically authorized and directed to act
upon the following standing money transfer instructions with respect to the
proceeds of Advances or other extensions of credit from time to time until
receipt by the Administrative Agent of a specific written revocation of such
instructions by the Borrower, provided that the Administrative Agent may
otherwise transfer funds as hereafter directed in writing by the Borrower in
accordance with Section 13.1 of the Credit Agreement or based on any telephonic
notice made in accordance with Section 2.15 of the Credit Agreement.
Facility Identification Number(s)_____________________________________
Customer/Account Name: [Borrower]
Transfer Funds To_____________________________________________________
_____________________________________________________
For Account No._______________________________________________________
Reference/Attention To________________________________________________
Authorized Officer (Customer Representative) Date____________
______________________________________________ ____________________
(Please Print) Signature
Bank Officer Name Date____________
______________________________________________ ____________________
(Please Print) Signature
(Deliver Completed Form to Credit Support Staff For Immediate Processing)
EXHIBIT E
NOTE
[Date]
Southwestern Energy Company, an Arkansas corporation (the "Borrower"),
promises to pay to the order of ____________________________________ (the
"Lender") the aggregate unpaid principal amount of all Loans made by the Lender
to the Borrower pursuant to Article II of the Agreement (as hereinafter
defined), in immediately available funds at the main office of Bank One, NA in
Chicago, Illinois, as Administrative Agent, together with interest on the unpaid
principal amount hereof at the rates and on the dates set forth in the
Agreement. The Borrower shall pay the principal of and accrued and unpaid
interest on the Loans in full on the Termination Date.
The Lender shall, and is hereby authorized to, record on the schedule
attached hereto, or to otherwise record in accordance with its usual practice,
the date and amount of each Loan and the date and amount of each principal
payment hereunder.
This Note is one of the Notes issued pursuant to, and is entitled to
the benefits of, the Credit Agreement dated as of July 12, 2001 (which, as it
may be amended or modified and in effect from time to time, is herein called the
"Agreement"), among the Borrower, the lenders party thereto, including the
Lender, and Bank One, NA, as Administrative Agent, to which Agreement reference
is hereby made for a statement of the terms and conditions governing this Note,
including the terms and conditions under which this Note may be prepaid or its
maturity date accelerated. This Note is guaranteed pursuant to the Subsidiary
Guaranty, as more specifically described in the Agreement. Capitalized terms
used herein and not otherwise defined herein are used with the meanings
attributed to them in the Agreement.
Notwithstanding anything to the contrary in this Note, no provision of
this Note shall require the payment or permit the collection of interest in
excess of the maximum permitted by applicable law ("Maximum Rate"). If any
interest in excess of the Maximum Rate is provided for or shall be adjudicated
to be so provided, in this Note or otherwise in connection with the loan
transaction, the provisions of this paragraph shall govern and prevail, and
neither the Borrower nor the sureties, guarantors, successors or assigns of the
Borrower shall be obligated to pay the excess of the interest or any other
excess sum paid for the use, forbearance, or detention of sums loaned. If for
any reason interest in excess of the Maximum Rate shall be deemed charged,
required or permitted by any court of competent jurisdiction, the excess shall
be applied as payment and reduction of the principal of indebtedness evidenced
by this Note, and, if the principal amount has been paid in full, any remaining
excess shall forthwith be paid to the Borrower.
This Note shall be construed in accordance with the internal laws (and
not the law of conflicts) of the State of Illinois, but giving effect to Federal
laws applicable to national banks.
SOUTHWESTERN ENERGY COMPANY
By:________________________________
Print Name:________________________
Title:_____________________________
2
SCHEDULE OF LOANS AND PAYMENTS OF PRINCIPAL
TO
NOTE
DATED___________, 2001
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i
EXHIBIT G
FORM OF COMPLIANCE CERTIFICATE
The undersigned, the _________________ of Southwestern Energy Company
(the "Borrower") hereby (a) delivers this Certificate pursuant to Section 6.1(c)
of the Credit Agreement dated as of July 12, 2001 (the "Agreement"; capitalized
terms used but not defined herein have the respective meanings given thereto in
the Agreement) among the Borrower, various financial institutions and Bank One,
NA, as Administrative Agent, and (b) certifies to each Lender as follows:
1. Attached as Schedule I are the financial statements of the Borrower as
of and for the Fiscal Year Quarter (check one) ended ________________, ______.
2. Such financial statements have been prepared in accordance with
Agreement Accounting Principles and fairly present in all material respects the
financial condition of the Borrower as of the date indicated therein and the
results of operations for the respective periods covered thereby.
3. Attached as Schedule II are detailed calculations used by the Borrower
to establish whether the Borrower was in compliance with the requirements of
Section 6.4 of the Agreement on the date of the financial statements attached as
Schedule I.
4. Unless otherwise disclosed on Schedule III, neither a Default nor an
Unmatured Default has occurred which is in existence on the date hereof or, if
any Default or Unmatured Default is disclosed on Schedule III, the Borrower has
taken or proposes to take the action to cure such Default or Unmatured Default
set forth on Schedule III.
5. Except as described on Schedule IV, the representations and warranties
of the Borrower set forth in the Agreement are true and correct on and as of the
date hereof, with the same effect as though such representations and warranties
had been made on and as of the date hereof or, if such representations and
warranties are expressly limited to particular dates, as of such particular
dates.
IN WITNESS WHEREOF, the undersigned has duly executed this Certificate as
of ________________, _______.
SOUTHWESTERN ENERGY COMPANY
By:________________________________
Name:______________________________
Title:_____________________________
Schedule I
Financial Statements
(to be attached)
Schedule II
Compliance Calculations
(to be attached)
Schedule III
Defaults/Remedial Action
(to be attached)
Schedule IV
Qualifications to Representations and Warranties
TABLE OF CONTENTS
ARTICLE I
DEFINITIONS....................................................................1
ARTICLE II
THE CREDITS...................................................................14
2.1 Commitments.....................................................14
2.2 Types of Advances...............................................14
2.3 Minimum Amount of Each Advance..................................14
2.4 Method of Selecting Types and Interest Periods for
New Advances....................................................15
2.5 Conversion and Continuation of Outstanding Advances.............15
2.6 Swing Line Loans................................................16
2.6.1 Amount of Swing Line Loans..........................16
2.6.2 Method of Borrowing.................................16
2.6.3 Making of Swing Line Loans..........................16
2.6.4 Repayment of Swing Line Loans.......................16
2.7 Commitment Fee; Voluntary Reductions in Aggregate Commitment....17
2.8 Mandatory Reductions in Aggregate Commitment....................18
2.9 Prepayments.....................................................18
2.10 Interest Rates, etc.............................................19
2.11 Rates Applicable After Default..................................19
2.12 Maturity........................................................20
2.13 Method of Payment...............................................20
2.14 Noteless Agreement; Evidence of Indebtedness....................20
2.15 Telephonic Notices..............................................21
2.16 Interest Payment Dates; Interest and Fee Basis..................21
2.17 Notification of Advances, Interest Rates, Prepayments and
Commitment Reductions...........................................22
2.18 Lending Installations...........................................22
2.19 Non-Receipt of Funds by the Administrative Agent................22
2.20 Replacement of Lender...........................................22
ARTICLE III
YIELD PROTECTION; TAXES.......................................................23
3.1 Yield Protection................................................23
3.2 Changes in Capital Adequacy Regulations.........................24
3.3 Availability of Types of Advances...............................25
3.4 Funding Indemnification.........................................25
3.5 Taxes...........................................................25
3.6 Lender Statements; Survival of Indemnity........................27
i
ARTICLE IV
CONDITIONS PRECEDENT..........................................................27
4.1 Initial Loan....................................................27
4.2 Each Loan.......................................................29
ARTICLE V
REPRESENTATIONS AND WARRANTIES................................................29
5.1 Organization....................................................29
5.2 Authorization and Validity......................................29
5.3 Financial Statements............................................29
5.4 Subsidiaries....................................................30
5.5 ERISA...........................................................30
5.6 Defaults........................................................30
5.7 Accuracy of Information.........................................30
5.8 Regulation U....................................................30
5.9 No Adverse Change...............................................30
5.10 Taxes...........................................................30
5.11 Liens...........................................................31
5.12 Compliance with Orders..........................................31
5.13 Litigation......................................................31
5.14 Burdensome Agreements...........................................31
5.15 No Conflict.....................................................31
5.16 Title to Properties.............................................31
5.17 Public Utility Holding Company Act..............................32
5.18 Regulatory Approval.............................................32
5.19 Negative Pledge.................................................32
5.20 Investment Company Act..........................................32
5.21 Compliance with Laws............................................32
ARTICLE VI
COVENANTS.....................................................................32
6.1 Information.....................................................32
6.2 Affirmative Covenants...........................................35
6.2.1 Reports and Inspection..............................35
6.2.2 Conduct of Business.................................35
6.2.3 Insurance...........................................36
6.2.4 Taxes...............................................36
6.2.5 Compliance with Laws................................36
6.2.6 Maintenance of Properties...........................36
6.2.7 Additional Guarantors...............................37
6.3 Negative Covenants..............................................37
6.3.1 Restricted Payments.................................37
6.3.2 Merger and Sale of Assets...........................37
ii
6.3.3 Liens...............................................38
6.3.4 Subsidiary Guarantors...............................41
6.3.5 Investments.........................................41
6.3.6 Indebtedness of Arkansas Western Gas Company........42
6.4 Financial Covenants.............................................42
6.4.1 Debt to Capitalization Ratio........................42
6.4.2 Interest Coverage Ratio.............................42
6.4.3 Net Worth...........................................42
ARTICLE VII
DEFAULTS......................................................................43
7.1 Events of Default...............................................43
7.1.1 Representations and Warranties.....................43
7.1.2 Payment Default.....................................43
7.1.3 Breach of Certain Covenants.........................43
7.1.4 Other Breach of this Agreement......................43
7.1.5 ERISA...............................................43
7.1.6 Cross-Default.......................................43
7.1.7 Voluntary Bankruptcy, etc...........................44
7.1.8 Involuntary Bankruptcy, etc.........................44
7.1.9 Judgments...........................................44
7.1.10 Environmental Matters...............................44
7.1.11 Subsidiary Guaranty.................................44
ARTICLE VIII
ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES; RELEASES OF GUARANTORS........45
8.1 Acceleration....................................................45
8.2 Amendments......................................................45
8.3 Preservation of Rights..........................................46
8.4 Releases of Guarantors..........................................46
ARTICLE IX
GENERAL PROVISIONS............................................................46
9.1 Survival of Representations.....................................46
9.2 Governmental Regulation.........................................46
9.3 Headings........................................................46
9.4 Entire Agreement................................................47
9.5 Several Obligations; Benefits of this Agreement.................47
9.6 Expenses; Indemnification.......................................47
9.7 Numbers of Documents............................................48
9.8 Accounting......................................................48
9.9 Severability of Provisions......................................48
iii
9.10 Nonliability of Lenders.........................................48
9.11 Confidentiality.................................................48
9.12 Nonreliance.....................................................49
9.13 Disclosure......................................................49
ARTICLE X
THE ADMINISTRATIVE AGENT......................................................49
10.1 Appointment; Nature of Relationship.............................49
10.2 Powers..........................................................49
10.3 General Immunity................................................49
10.4 No Responsibility for Loans, Recitals, etc......................50
10.5 Action on Instructions of Lenders...............................50
10.6 Employment of Agents and Counsel................................50
10.7 Reliance on Documents; Counsel..................................51
10.8 Administrative Agent's Reimbursement and Indemnification........51
10.9 Notice of Default...............................................51
10.10 Rights as a Lender..............................................51
10.11 Lender Credit Decision..........................................52
10.12 Successor Administrative Agent..................................52
10.13 Delegation to Affiliates........................................53
10.14 Other Agents....................................................53
ARTICLE XI
SETOFF; RATABLE PAYMENTS......................................................53
11.1 Setoff..........................................................53
11.2 Ratable Payments................................................53
ARTICLE XII
BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS.............................54
12.1 Successors and Assigns..........................................54
12.2 Participations..................................................54
12.2.1 Permitted Participants: Effect......................54
12.2.2 Voting Rights.......................................55
12.3 Assignments.....................................................55
12.3.1 Permitted Assignments...............................55
12.3.2 Effect; Effective Date..............................55
12.4 Dissemination of Information....................................56
12.5 Tax Treatment...................................................56
iv
ARTICLE XIII
NOTICES.......................................................................56
13.1 Notices.........................................................56
13.2 Change of Address...............................................57
ARTICLE XIV
COUNTERPARTS..................................................................57
ARTICLE XV
CHOICE OF LAW; CONSENT TO JURISDICTION; WAIVER OF JURY TRIAL;
MAXIMUM INTEREST RATE.........................................................57
15.1 CHOICE OF LAW...................................................57
15.2 CONSENT TO JURISDICTION.........................................57
15.3 WAIVER OF JURY TRIAL............................................58
15.4 Maximum Interest Rate...........................................58
v
SCHEDULES
Schedule 1A Commitments
Schedule 1B Pricing Schedule
Schedule 2.8(a) Excluded Asset Sales
Schedule 2.8(b) Assets to be Swapped
Schedule 5.4 Subsidiaries
Schedule 5.13 Litigation
Schedule 5.19 Negative Pledges
Schedule 6.2 Insurance
EXHIBITS
Exhibit A Form of Borrowing Notice
Exhibit B Form of Opinion of Counsel to Borrower
Exhibit C Form of Assignment Agreement
Exhibit D Form of Money Transfer Instructions
Exhibit E Form of Note
Exhibit F Form of Subsidiary Guaranty
Exhibit G Form of Compliance Certificate
vi
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
------------------------------
State of
Incorporation or
Subsidiary Name Organization
--------------- ----------------
Arkansas Western Gas Company Arkansas
Seeco, Inc. Arkansas
Southwestern Energy Production Company Arknasas
Diamond "M" Production Company Delaware
Southwestern Energy Services Company Arkansas
Southwestern Energy Pipeline Company Arkansas
Arkansas Western Pipeline Company Arkansas
A.W. Realty Company Arkansas
Overton Partners, L.P. Texas
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 4, 2002, included in this Form 10-K, into the Company's
previously filed Registration Statements on Form S-8 (File Nos. 333-03787,
333-03789, 333-64961, 333-96161, 333-42484 and 333-69720).
Arthur Andersen LLP
Tulsa, Oklahoma
March 29, 2002
Exhibit 99.1
SOUTHWESTERN ENERGY COMPANY
2350 N. Sam Houston Parkway East
Suite 300
Houston, Texas 77032
LETTER TO COMMISSION PURSUANT TO TEMPORARY NOTE 3T
March 29, 2002
Securities and Exchange Commission
450 Fifth Street, N.W.
Washington, D.C. 20549
Ladies and Gentlemen:
Pursuant to Temporary Note 3T to Article 3 of Regulation S-X, Southwestern
Energy Company has obtained a letter of representation from Arthur Andersen LLP
stating that the December 31, 2001 audit was subject to their quality control
system for the U.S. accounting and auditing practice to provide reasonable
assurance that the engagement was conducted in compliance with professional
standards, that there was appropriate continuity of Arthur Andersen LLP
personnel working on the audit and availability of national office consultation.
Availability of personnel at foreign affiliates of Arthur Andersen LLP is not
relevant to this audit.
Very truly yours,
Southwestern Energy Company
Greg D. Kerley
Executive Vice President
and Chief Financial Officer