UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K/A
(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
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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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1
Explanatory Note:
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This Form 10-K/A amends our Annual Report on Form 10-K filed March 29,
2002. We have included certain changes in this Form 10-K/A in order to correct
the presentation of comprehensive income for the year ended December 31, 2001,
to properly reflect amounts associated with hedging activities (see Note 1 to
the accompanying financial statements). This correction had no effect on the
Company's previously reported net income, earnings per share or cash flows, nor
did it have any impact on the Company's balance sheet. This filing also includes
the opinion of PricewaterhouseCoopers LLP on their audit of the Company's
financial statements as of December 31, 2001 and 2000 and for each of the three
years in the period ended December 31, 2001. The Company announced on June 20,
2002 that it had engaged PricewaterhouseCoopers LLP as its new independent
accountants replacing Arthur Andersen LLP. Except as set forth in the preceding
sentences, we have not materially updated or revised the information in our
Annual Report.
2
TABLE OF CONTENTS
Part I pg
Item 1 Business 4
Business strategy 4
Exploration and production 4
Natural gas distribution 10
Marketing and transportation 13
Other items 15
Item 2 Properties 15
Item 3 Legal proceedings 17
Item 4 Submission of matters to a vote of security holders 18
Executive officers of the registrant 18
Part II
Item 5 Market for registrant's common equity and related
stockholder matters 19
Item 6 Selected financial data 20
Item 7 Management's discussion and analysis of financial
condition and results of operations 22
Item 7A Quantitative and qualitative disclosure about
market risks 31
Item 8 Financial statements and supplementary data 34
Item 9 Changes in and disagreements with accountants on
accounting and financial disclosure 58
Part III
Item 10 Directors and executive officers of the registrant 59
Item 11 Executive compensation 59
Item 12 Security ownership of certain beneficial owners
and management 59
Item 13 Certain relationships and related transactions 59
Part IV
Item 14 Exhibits, financial statement schedules, and reports
on Form 8-K 60
3
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 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.
4
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
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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. Lifting costs continued
to be low during 2001 at $.32 per Mcf (including production taxes). After
5
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.
6
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.
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%.
7
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.
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.
8
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 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
9
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 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]
10
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 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
11
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.
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
12
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 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.
13
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.
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.
14
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.
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
================================================================================
15
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
================================================================================
16
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.
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.
17
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, Chief Executive Officer 57 5
and Chairman of the Board
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.
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.
18
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.
19
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.
20
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.
21
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
22
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.
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
23
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 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
24
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.
25
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 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
26
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. 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.
27
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 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).
28
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.
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)
29
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.
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
30
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.
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
31
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" 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
--------------------------------------
32
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.
33
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
pg.
Reports of Management and Independent Public Accountants 35
Consolidated Statements of Operations for the years ended
December 31, 2001, 2000 and 1999 36
Consolidated Balance Sheets as of December 31, 2001 and 2000 38
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 40
Consolidated Statements of Retained Earnings for the years ended
December 31, 2001, 2000 and 1999 41
Consolidated Statements of Comprehensive Income (Loss) for the
years ended December 31, 2001, 2000 and 1999 42
Notes to Consolidated Financial Statements, December 31, 2001,
2000 and 1999 43
34
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, PricewaterhouseCoopers 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 PricewaterhouseCoopers
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:
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, cash flows, retained earnings and
comprehensive income (loss) present fairly, in all material respects, the
financial position of Southwestern Energy Company and its subsidiaries at
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 of
America. 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 of these statements in
accordance with auditing standards generally accepted in the United States of
America, which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company has
corrected its statement of comprehensive income (loss) for the year ended
December 31, 2001, which statement was previously audited by other auditors.
As discussed in Note 8 to the consolidated financial statments, 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."
PricewaterhouseCoopers LLP
Tulsa, Oklahoma
September 12, 2002
35
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
36
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.
37
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
---------------------------------------------------------------------------------------------------------------------------------
38
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.
39
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.
40
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
41
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) - -
Change in value of derivative instruments 42,726 - -
---------------------------------------------------------------------------------------------------------
Comprehensive income (loss) $ 41,087 $ (46,687) $ 9,927
---------------------------------------------------------------------------------------------------------
Reconciliation of accumulated other
comprehensive income (loss):
Balance, beginning of year $ - $ - $ -
Cumulative effect of 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 2001 Consolidated Statement of comprehensive Income (Loss) was restated to
correct the presentation of comprehensive income, as discussed in Footnote 1 to
Consolidated Financial Statements.
The accompanying notes are an integral part of the financial statements.
42
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
43
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.
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. At December 31, 2001, the Company had
overproduction of 1.6 Bcf valued at $4.3 million and underproduction of 1.7 Bcf
valued at $4.9 million. At December 31, 2000, the Company had overproduction of
1.6 Bcf valued at $4.4 million and underproduction of 1.7 Bcf valued at $4.9
million.
Income Taxes
44
Deferred income taxes are provided to recognize the income tax effect of
reporting certain transactions in different years for income tax and financial
reporting purposes.
Risk Management
The Company uses derivative financial instruments to manage defined
commodity price risks and 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.
Additionally, payment of dividends is precluded under the Company's revolving
debt aggreement.
Comprehensive Income
Southwestern, in the accompanying financial statments, has corrected its
presentation of comprehensive income for the year ended December 31, 2001, to
properly reflect amounts associated with hedging activities. This change
resulted in an increase of $22.9 million to previously reported comprehensive
income for the year ended December 31, 2001, to yield corrected comprehensive
income of $41.1 million. This correction had no effect on the Company's
previously reported net income, earnings per share or cash flows, nor did it
have any impact on the Company's balance sheet.
(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
-------------------------------------------------------------------------------------------------------------
45
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 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)
------------------------------------------------------------------------------------------------------
46
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 $ 142,007 $ 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
------------------------------------------------------------------------------------------------------
169,794 164,609
------------------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 721 884
Alternative minimum tax credit carryforward 3,026 3,046
Net operating loss carryforward 41,922 63,449
Other 2,939 1,671
------------------------------------------------------------------------------------------------------
48,608 69,050
------------------------------------------------------------------------------------------------------
Net deferred tax liability $ 121,186 $ 95,559
------------------------------------------------------------------------------------------------------
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. The Company's
net operating loss carryforward at December 31, 2001, was $110.3 million with an
expiration date of December 31, 2020. The Company also had an alternative
minimum tax credit carryforward of $3.0 million and a statutory percentage
depletion carryforward of $2.8 million at December 31, 2001.
(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:
47
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
--------------------------------------------------------------------------------------------------------
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%
48
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
---------------------------------------------------------------------------------------------
49
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
50
The "Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves" (standardized measure) is a disclosure required by
SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." The
standardized measure does not purport to present the fair market value of a
company's proved gas and oil reserves. In addition, there are uncertainties
inherent in estimating quantities of proved reserves. Substantially all
quantities of gas and oil reserves owned by the Company were estimated or
audited by the independent petroleum engineering firm of K & A Energy
Consultants, Inc.
Following is the standardized measure relating to proved gas and oil
reserves at December 31, 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
51
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.
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.
(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:
52
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.
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
53
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 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
-------------------------------------------------------------------
54
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
------------------------------------------------------------------------------------------------------------
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 for 2001 and 2000 and a dividend yield of 2.3%
for 1999; expected volatility of 46.4% for 2001, 44.0% for 2000 and 38.6% for
1999; risk-free interest rate of 4.8% for 2001, 6.0% for 2000 and 6.2% for 1999;
and expected lives of 6 years for all option grants. The fair values of the
option grants for each of the years 2001, 2000 and 1999 were $.8 million, $2.6
million and $1.1 million, respectively.
The Company granted 299,850 shares, 149,925 shares and 100,225 shares of
restricted stock in 2001, 2000 and 1999, respectively. The fair values of the
grants were $2.9 million for 2001, $1.1 million for 2000 amnd $.6 million for
1999. Of the 752,995 shares granted to date, 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. Compensation expense related to the
amortization of restricted stock grants was $.6 million for both 2001 and 2000,
and $.5 million for 1999. 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
55
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.
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
56
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.
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the
years ended December 31, 2001 and 2000:
57
---------------------------------------------------------
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
Income (loss) before extraodinary item $ 9,186 $ (63,309) $ (754) $ 9,080
Net income (loss) $ 9,186 $ (64,199) $ (754) $ 9,080
Basic and diluted earnings (loss) per share:
Income (loss) before extraordinary item $.37 $(2.53) $(.03) $.36
Net income (loss) $.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
58
On June 20, 2002 the Board of Directors of Southwestern determined, upon
the recommendation of its Audit Committee, to appoint PricewaterhouseCoopers LLP
("PwC") as Southwestern's independent public accountants, replacing Arthur
Andersen LLP, which Southwestern dismissed on the same date. This determination
followed Southwestern's decision, announced on March 29, 2002, to seek proposals
from other independent public accountants to audit its financial statements for
the fiscal year ended December 31, 2002.
The audit reports of Andersen on the consolidated financial statements of
Southwestern and subsidiaries as of and for the fiscal years ended December 31,
2001 and December 31, 2000 did not contain any adverse opinion or disclaimer of
opinion, nor were they qualified or modified as to uncertainty or audit scope.
In addition, there were no modifications as to accounting principles except that
the audit reports of Andersen contained an explanatory paragraph with respect to
the change in the method of accounting for derivative instruments effective
January 1, 2001 as required by the Financial Accounting Standards Board.
During Southwestern's two most recent fiscal years ended December 31, 2001
and through June 20, 2002, there were no disagreements between Southwestern and
Andersen on any matter of accounting principles or practices, financial
statement disclosure, or auditing scope or procedure, which disagreements, if
not resolved to Andersen's satisfaction, would have caused Andersen to make
reference to the subject matter of the disagreement in connection with their
reports; and there were no reportable events, as described in Item 304(a) (1)
(v) of Regulation S-K.
Southwestern provided Andersen with a copy of the foregoing disclosures and
Andersen provided the Company a letter dated June 20, 2002, stating that it had
no basis for disagreement with such statements. This letter was filed as Exhibit
16.1 to the Company's report on Form 8-K dated June 20, 2002.
During Southwestern's two most recent fiscal years and through June 20,
2002, Southwestern did not consult PwC with respect to the application of
accounting principles to a specified transaction, either completed or proposed,
or the type of audit opinion that might be rendered on Southwestern's
consolidated financial statements, or any other matters or reportable events
listed in Items 304(a) (2) (i) and (ii) of Regulation S-K.
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.
59
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.
60
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: September 24, 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 September 24, 2002.
/s/ Harold M. Korell Director, Chairman, President
------------------------------------ and Chief Executive Officer
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
------------------------------------
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
61
CERTIFICATION
-------------
I, Harold M. Korell, Chief Executive Officer of Southwestern Energy
Company, certify that:
1. I have reviewed this amended annual report on Form 10-K/A of
Southwestern Energy Company;
2. Based on my knowledge, this amended annual report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amended annual report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this amended annual report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amended annual report.
Date: September 24, 2002
/s/ HAROLD M. KORELL
----------------------------
Harold M. Korell
Chief Executive Officer
62
CERTIFICATION
-------------
I, Greg D. Kerley, Chief Financial Officer of Southwestern Energy Company,
certify that:
1. I have reviewed this amended annual report on Form 10-K/A of
Southwestern Energy Company;
2. Based on my knowledge, this amended annual report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amended annual report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this amended annual report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amended annual report.
Date: September 24, 2002
/s/ GREG D. KERLEY
----------------------------
Greg D. Kerley
Chief Financial Officer
63
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
64
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).
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 PricewatehouseCoopers LLP (filed herewith).
65