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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1999
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or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______________ to ______________
Commission file number 1-8246
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SOUTHWESTERN ENERGY COMPANY
(Exact name of Registrant as specified in its charter)
ARKANSAS 71-0205415
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1083 Sain Street, P.O.Box 1408, Fayetteville, Arkansas 72702-1408
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(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code (501) 521-1141
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock - Par Value $.10 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
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The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $181,640,298 based on the New York Stock Exchange - Composite
Transactions closing price on March 8, 2000 of $7 3/8.
The number of shares outstanding as of March 8, 2000, of the
Registrant's Common Stock, par value $.10, was 25,037,773.
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 24, 2000 - PART III.
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SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT on FORM 10-K
For the Year Ended December 31, 1999
TABLE OF CONTENTS
Part I Page
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Item 1. Business 3
Business Strategy 3
Exploration and Production 3
Natural Gas Distribution 10
Marketing and Transportation 13
Other Items 15
Item 2. Properties 16
Item 3. Legal Proceedings 18
Item 4. Submission of Matters to a Vote of Security Holders 19
Executive Officers of the Registrant 19
Part II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters 21
Item 6. Selected Financial Data 22
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 24
Item 7.A. Quantitative and Qualitative Disclosure About Market Risks 34
Item 8. Financial Statements and Supplementary Data 37
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 60
Part III
Item 10. Directors and Executive Officers of the Registrant 60
Item 11. Executive Compensation 61
Item 12. Security Ownership of Certain Beneficial Owners and Management 61
Item 13. Certain Relationships and Related Transactions 61
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K 61
2
Part I
ITEM 1. BUSINESS
Southwestern Energy Company (the "Company" or "Southwestern") is an
integrated energy company primarily focused on natural gas. The Company was
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 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.
2. Natural Gas Distribution - Engaged in the gathering, distribution and
transmission of natural gas to approximately 181,000 customers in northern
Arkansas and parts of Missouri.
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. For segment financial information, see Footnote 12 to the
consolidated financial statements in Part II, Item 8 of this Report.
Business Strategy
The Company's business strategy is to provide long-term growth through
focused exploration and development of oil and natural gas, while creating
additional value through the Company's natural gas distribution, marketing and
transportation activities. 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, moderate-risk exploration and
exploitation in the Permian Basin, and high-potential exploration opportunities
in the Gulf Coast. Additionally, the Company strives to operate its utility
systems safely and efficiently and to improve the competitive position and
profitability of its utility systems. The Company is also committed to enhancing
shareholder value by creating and capturing additional value beyond the wellhead
through its 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, the
Company's exploration and development activities outside Arkansas have expanded
substantially.
During 1998, Southwestern brought in new senior operating management and
replaced over 50% of its professional technical staff to refocus its exploration
and production segment. Additionally in 1998, the Company closed its Oklahoma
City office and moved these operations to its Houston office in an effort to
increase future profitability.
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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.
At December 31, 1999, the Company had proved oil and gas reserves of 354.7
billion cubic feet (Bcf) equivalent, including proved natural gas reserves of
307.5 Bcf and proved oil reserves of 7,859 thousand barrels (MBbls). The
Company's reserve life index averaged nearly 11 years at year-end 1999, with 83%
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 87% of total operating revenues for
this segment in 1999, 89% in 1998, and 86% in 1997.
Areas of Operation
Southwestern engages in gas and oil exploration and production through its
subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company
(SEPCO), and Diamond "M" Production Company (Diamond M). SEECO operates
exclusively in the state of Arkansas and holds a large base of both developed
and undeveloped gas reserves and conducts an ongoing drilling program in the
historically productive Arkansas part of the Arkoma Basin. SEPCO conducts
development drilling and exploration programs in areas outside Arkansas,
including the Permian Basin of Texas and New Mexico, the Gulf Coast areas of
Louisiana and Texas, and the Anadarko Basin of Oklahoma. Diamond M operates
properties in the Permian Basin of Texas.
The following table provides information as to proved reserves, well count,
and gross and net acreage as of December 31, 1999, and annual information as to
production and reserve additions for 1999 for each of the Company's core
operating areas.
Arkoma Mid-Continent Permian Gulf Coast Total
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Proved Reserves:
Gas (Bcf) 200.0 31.7 42.6 33.2 307.5
Oil (MBbls) - 2,275 4,722 862 7,859
Total Reserves (Bcfe) 200.0 45.3 70.9 38.5 354.7
Production (Bcfe) 20.3 4.9 5.2 2.5 32.9
Reserve Additions (Bcfe) 18.2 0.1 23.5 7.5 49.3
Total Gross Wells 794 799 294 77 1,964
Percent Operated 44% 34% 43% 33% 39%
Gross Acreage 290,363 165,649 259,238 94,466 809,716
Net Acreage 231,642 71,071 42,790 39,155 384,658
Arkoma Basin. Southwestern has developed a key competitive position in the
Arkoma since it commenced drilling in the basin in 1943. At December 31, 1999,
the Company had approximately 200.0 Bcf of natural gas reserves in the Arkoma
Basin, representing 65% of the Company's natural gas reserves and 56% of total
reserves on a Bcf equivalent basis. The Company participated in 37 wells during
1999 with a 70% success ratio and an average working interest of 46%. This level
of drilling activity was somewhat lower as compared to prior years, due to cash
flow limitations. During
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1999, the Company's Arkoma drilling program added 18.2 Bcf of gas reserves at a
finding and development cost of $.90 per Mcf. Average net daily production in
1999 was 55.7 million cubic feet equivalent (MMcfe) and production, or lifting
costs, in the basin during 1999 were $.22 per Mcfe (including production taxes).
Southwestern's traditional operating area over the years has been in the
"fairway" part of the basin, which is primarily within the boundaries of its
utility gathering system. Southwestern continued its drilling activities in the
fairway in 1999, completing five wells out of seven drilled and adding 5.7 Bcf
of new reserves. The largest success in this area was the Teague #1-16 well in
Johnson County, Arkansas. This well was drilled to total depth of 4,500 feet and
was placed on production at 1.9 MMcf of gas per day.
The Company also completed extensive mapping of the basin's 26 productive
horizons covering over 2,300 square miles in the fairway that will help
recognize additional or previously untapped reserve potential. In 2000,
Southwestern plans to increase its activity in the fairway by drilling 22 wells
in this gas-rich area.
Additionally, Southwestern has continued to develop new geologic plays and
extend previously identified productive trends outside the fairway area. A
promising new play has been the Ranger Anticline prospect area, located near the
southern edge of the basin. To date, the Company has successfully drilled four
out of five wells in this prospect, targeting the deeper Borum sands that tend
to yield higher production rates and greater reserve potential per well. The
Company currently plans to drill three wells in the prospect area in 2000, but
this number could be increased with positive drilling results during the first
part of the year.
The Company successfully developed another new prospect area during 1999,
its Cherokee prospect, located in the Oklahoma portion of the basin. During
1999, the Company targeted the Red Oak, Brazil, and Spiro sand reservoirs in
this under-explored portion of the basin and completed six wells out of ten
drilled. One well in the prospect, the Calvin Terry #1 in LeFlore County,
Oklahoma, was recently placed on production at 5.8 MMcf per day. The Company
plans further development of this prospect with up to ten additional wells being
drilled in 2000.
Overall, the Company initiated drilling in four promising new prospect
areas in 1999, all located outside of the established fairway area. In 2000, the
Company intends to drill over 50 wells outside of the traditional fairway
drilling area, which includes testing six new prospect areas. In total, the
Company plans to participate in 75 wells in the Arkoma Basin in 2000, doubling
its 1999 activity.
Mid-Continent. The Company's activities in this region are primarily
focused on the Anadarko Basin of Oklahoma. At December 31, 1999, the Company had
approximately 31.7 Bcf of natural gas reserves and 2,275 MBbls of oil reserves
in the region, representing 10% and 29%, respectively, of the Company's total
gas and oil reserves. Average net daily production in 1999 for this region was
13.4 MMcfe. During 1998, the Company closed its Oklahoma City office and moved
these operations to Houston. 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. During 1999 and
the first part of 2000, the Company sold approximately 235 marginal properties
in the Mid-Continent area with estimated remaining reserves of 4.8 Bcfe.
Permian Basin. Through successful drilling results, a small acquisition and
several new joint ventures, Southwestern made meaningful strides in becoming a
more significant player in the Permian Basin in 1999. At December 31, 1999,
Southwestern had proved reserves of 42.6 Bcf of gas and 4,722 MBbls of oil in
the region, representing 14% and 60%,
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respectively, of the Company's total gas and oil reserves. During 1999, average
net daily production in the basin was 14.2 MMcfe and production costs averaged
$.71 per Mcfe. This rate includes higher operating costs from secondary recovery
oil properties acquired by the Company in 1996. Production costs exclusive of
these properties were $.39 per Mcfe in 1999.
The Company successfully completed 18 out of 22 wells drilled in the
Permian in 1999, resulting in a success rate of 82%. At year-end, drilling
operations at seven wells were still in progress. Southwestern's average working
interest in the Permian during 1999 was 24%. Total reserve additions from
drilling and acquisitions were 23.5 Bcfe at a finding cost of $.79 per Mcfe in
1999, while reserve additions through drilling were 10.6 Bcfe at a finding cost
of $.86 per Mcfe.
Southwestern enjoyed meaningful success in its Logan Draw development area
in Eddy County, New Mexico, successfully drilling 11 out of 13 wells there in
1999. Southwestern holds an average 28% working interest in the Logan Draw
development area, which is the combination of the Company's Top Dog, Amber, and
Freight Train prospects. Two notable wells in the Freight Train prospect, the
Amtrack State Com #1 and the Mule Train 16 State #1, are each currently
producing approximately 10.0 MMcfe per day. In 2000, Southwestern plans to drill
11 wells in the Logan Draw area.
The Company continued to successfully develop its Gaucho production unit in
Lea County, New Mexico, completing three out of four wells there in 1999. The
Gaucho #3 well was drilled during the first quarter of 1999 and is currently
producing 9.1 MMcfe per day. Additionally, the Company successfully confirmed
production from younger Atoka sands in three wells in the unit. Until 1999,
hydrocarbons in the Gaucho unit had been exclusively produced from Morrow sand
objectives. Southwestern holds a 50% working interest in the Gaucho unit and
plans to drill two wells in the unit in 2000.
The Company established a stronger presence in the basin with the
acquisition of producing properties from Petro-Quest Exploration effective
September 1, 1999. The transaction added 12.9 Bcfe of reserves for approximately
$9.4 million. This transaction is discussed more fully below under
"Acquisitions."
Additionally, the Company established exploration joint ventures in the
basin with Phillips Petroleum, Stratex, Inc., and Petro-Quest Exploration.
Several drilling opportunities have already been identified and planned for 2000
from these new ventures. Overall, Southwestern plans to participate in over 40
wells in the Permian in 2000, almost doubling its 1999 activity.
Gulf Coast. Southwestern became active in the Gulf Coast in 1990 and this
area continues to be the main focus area of the Company's high impact
exploration activities. At December 31, 1999, Southwestern had proved reserves
of 33.2 Bcf of gas and 862 MBbls of oil in the region, representing 11 percent
of the Company's total reserves on a gas equivalent basis. Average net daily
production in this area was 6.8 MMcfe, compared to 13.2 MMcfe per day in 1998,
with production costs averaging $1.06 per Mcfe during 1999. The decrease in 1999
production was due to the loss of production from certain wells in south
Louisiana.
The Company has built an extensive inventory of 3-D seismic data covering
over 900 miles in the Gulf Coast region of Texas and Louisiana. During 1999, the
Company continued to analyze this seismic data and has generated several
prospects to be drilled in 2000. The Company strives to limit its working
interest participation in its higher-risk Gulf Coast exploration prospects to
50% or less.
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Southwestern commenced drilling on two prospects in its Boure 3-D seismic
project in 1999 with positive results. The Boure 3-D project covers 185 square
miles in Assumption Parish, Louisiana. This seismic data was delivered to and
interpreted by the Company during 1999. In December 1999, the Company announced
its first discovery in the Boure 3-D project. The Dugas & LeBlanc #1 well,
located on the Company's Gloria prospect, was drilled to a total depth of 14,950
feet and encountered three separate sand intervals between 14,400 feet and
14,856 feet in the Lower Miocene Planulina formation. The well is currently
producing 5.4 million cubic feet of gas and 150 barrels of condensate per day
from the lowest sand interval. Southwestern is the operator of the well and
holds a 50% working interest. The Company announced in February 2000 that it had
made another discovery at its North Grosbec prospect. The Brownell-Kidd #1 well
logged approximately 50 feet of net pay sand in the Upper Discorbis interval at
approximately 16,950 feet. The Company is currently completing and testing the
well. Southwestern holds a 25% working interest in the well which is operated by
Petro-Hunt, L.L.C.
In 2000, the Company plans to drill up to two prospects in its East
Atchafalaya 3-D project. This project covers 113 square miles in portions of St.
Martin and Iberia Parishes, Louisiana. Southwestern became involved in the East
Atchafalaya 3-D project in 1995 with Union Pacific Resources Company. To date,
the Company has participated in five wells in the project, with two wells being
completed as producers. The Company drilled one well in the East Atchafalaya
project in 1999, the Panther prospect, which was unsuccessful.
In late 1998, the Company formed a strategic alliance with industry
partners to jointly evaluate and explore a new proprietary 3-D seismic survey in
the Nodosaria Embayment area of Lafayette, St. Landry and Acadia Parishes,
covering over 140 square miles. This seismic data was delivered to the Company
during 1999. Interpretation of the data has identified several exploration leads
and the Company currently plans to test its first prospect in the survey,
Havilah, in April 2000. Southwestern currently has a 27.5% working interest in
the 3-D project and is the operator.
The Company also was successful in leveraging its seismic databank and
regional geologic expertise into additional drilling opportunities for 2000.
Overall, the Company plans to drill seven additional prospects in the Gulf Coast
area in 2000.
Acquisitions
Effective September 1, 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. In addition, Southwestern established an exploration joint venture
agreement with Petro-Quest which will result in additional drilling
opportunities. The transaction strengthens Southwestern's position in the
Permian Basin, which continues to grow as a core operating area for the Company.
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. In 1995, the
Company acquired 4.5 Bcf of gas and 851 MBbls of oil located in the Gulf Coast
for $6.0 million. The Company's current strategy is to pursue selective
acquisitions that would complement its existing operations.
Capital Spending
Southwestern began 2000 with planned capital expenditures for gas and oil
exploration and development of $55.4 million. The Company's capital budget is
balanced between the Company's core areas of operations and is focused more
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on drilling in 2000. Approximately 37% of the Company's total exploration and
development budget for 2000 is allocated to the Company's low-risk development
activities in the Arkoma Basin, 21% is allocated to medium-risk exploration and
exploitation in the Permian Basin, and 24% is allocated to high-potential
exploration in the Gulf Coast. Although no capital was budgeted for acquisitions
in 2000, 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
Natural gas equivalent production averaged 90 million cubic feet per day
(MMcfd) in 1999, compared to 101 MMcfd in 1998, and 104 MMcfd in 1997. The
Company's gas production was 29.4 Bcf in 1999, down from 32.7 Bcf in 1998, and
33.4 Bcf in 1997. The Company also produced 578,000 barrels of oil in 1999,
compared to 703,000 barrels in 1998, and 749,000 barrels in 1997. The decreases
in production in 1999 were the result of lower non-operated production due to
the industry slowdown during late 1998 and early 1999, the decline in production
from certain wells in the Gulf Coast area and production losses from marginal
properties that were sold during the year. The Company expects its equivalent
production in 2000 to increase 5% to 10% over the 1999 level.
The Company's natural gas production received an average wellhead price of
$2.21 per thousand cubic feet (Mcf) in 1999, compared to $2.34 per Mcf in 1998
and $2.57 per Mcf in 1997. Prices received for the Company's oil production
averaged $17.11 per barrel in 1999, compared to $13.60 per barrel in 1998 and
$19.02 per barrel in 1997.
Southwestern's largest single customer for sales of its gas production is
the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas
Western). These sales are made by SEECO. Sales to Arkansas Western accounted for
approximately 31% of total exploration and production revenues in 1999, 38% in
1998, and 43% in 1997. All of the Company's remaining sales are to unaffiliated
purchasers.
SEECO's production was 18.9 Bcf in 1999, down from 19.5 Bcf in 1998 and
21.7 Bcf in 1997. SEECO's sales to Arkansas Western were 8.2 Bcf in 1999, down
from 11.3 Bcf in 1998 and 14.3 Bcf in 1997. The decreases in affiliated gas
sales were primarily the result of warmer weather in the utility's service
territory.
Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas
division (AWG) were 5.1 Bcf in 1999, 7.7 Bcf in 1998, and 8.6 Bcf in 1997.
Through these sales, SEECO furnished 37% of the northwest Arkansas system's
requirements in 1999, 59% in 1998, and 64% in 1997. SEECO also delivered
approximately 2.6 Bcf in 1999, 2.0 Bcf in 1998, and 1.0 Bcf in 1997 directly to
certain large business customers of AWG through a transportation service of the
utility subsidiary. Most of the sales to AWG prior to December 1998 were
pursuant to a twenty-year contract between SEECO and AWG, entered into in July
1978, under which the price was frozen between 1984 and 1994. This contract was
amended in 1994 as a result of a settlement reached to resolve certain gas cost
issues before the Arkansas Public Service Commission (APSC). This contract
expired July 24, 1998, but continued on a month-to-month basis through November
1998.
In March 1997, AWG filed a gas supply plan with the APSC which projected
system load growth patterns and long range gas supply needs for the utility's
northwest Arkansas system. The gas supply plan also addressed replacement
supplies for AWG's long-term contract with SEECO. After discussions with the
APSC it was determined that the majority of the utility's future gas supply
needs should be provided through a competitive bidding process. On October 1,
1998, AWG sent requests for proposals to various suppliers requesting bids on
seven different packages of gas supply to be
8
effective December 1, 1998. These bid requests included replacement of the gas
supply and no-notice service previously provided by the long-term gas supply
contract between AWG and SEECO. Eleven potential suppliers returned bids in late
October.
SEECO along with the Company's marketing subsidiary successfully bid on
five of the seven packages with prices based on the Reliant East Index plus a
demand charge. The volumes of gas projected to be sold under these contracts are
approximately equal to the historical annual volumes sold under the expired
long-term contracts, assuming normal weather patterns. However, the volumes to
be sold under these contracts are not fixed as they were under the expired
contract and will fluctuate with the weather-related requirements of AWG. These
contracts provide more of the gas needed during periods of colder weather, and
less of AWG's base system needs. As a result, periods of abnormally warmer
weather, such as 1999 and 1998, result in lower deliveries to AWG by SEECO.
However, charges for no-notice service associated with these contracts are
approximately $6.0 million per year and are received by SEECO regardless of
weather patterns. Other sales to AWG are made under long-term contracts with
flexible pricing provisions.
SEECO's sales to Associated Natural Gas Company (Associated), a division of
Arkansas Western which operates natural gas distribution systems in northeast
Arkansas and parts of Missouri, were 3.1 Bcf in 1999, 3.6 Bcf in 1998, and 5.7
Bcf in 1997. These deliveries accounted for approximately 47% of Associated's
total requirements in 1999, 50% in 1998, and 61% in 1997. In 1998, certain
industrial customers of Associated began buying their gas supply directly from
producers or marketers. This caused a decline in the percentage of Associated's
gas supply provided by SEECO as these volumes were previously purchased by
Associated from SEECO and then delivered to their industrial customers.
Effective October 1990, SEECO entered into a ten-year contract with Associated
to supply a portion of its system requirements at a price to be redetermined
annually. For the contract period beginning October 1, 1997, the contract was
revised to redetermine the sales price monthly based on an index posting plus a
reservation fee. The average price received under the contract was $2.37 for
1999 and 1998 and $2.51 in 1997. Prior to the end of the current contract term
in 2000, Associated will place its gas supply out for competitive bids.
Continued sales of these volumes, and the price of any such sales, could be
impacted by the results of the competitive bidding process and by the pending
sale of the Company's Missouri assets discussed below in "Natural Gas
Distribution."
At present, SEECO's contracts for sales of gas to unaffiliated customers
consist of short-term sales made to customers of the utility subsidiary's
transportation program and spot sales into markets away from the utility's
distribution system. These sales are subject to seasonal price swings. SEECO's
sales to unaffiliated customers are also affected by the demand of the utility
for production on its gathering system. SEECO's sales to unaffiliated purchasers
accounted for approximately 27% of total exploration and production revenues in
1999, 19% in 1998, and 15% in 1997.
The combined gas production of SEPCO and Diamond M was 10.5 Bcf in 1999,
compared to 13.2 Bcf in 1998 and 11.7 Bcf in 1997. Oil production was 578 MBbls
in 1999, compared to 703 MBbls in 1998 and 749 MBbls in 1997. SEPCO's and
Diamond M's gas and oil production is sold under contracts with unaffiliated
purchasers which reflect current short-term prices and which are subject to
seasonal price swings. SEPCO's and Diamond M's combined gas and oil sales
accounted for 42% of total exploration and production revenues in 1999 and 43%
in 1998 and 1997.
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
9
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 Arkoma Basin 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 the basin and its long-time
presence and reputation in this area, the Company believes it will continue to
be successful in acquiring new leases in the Arkoma Basin. While improved
intrastate and interstate pipeline transportation in the basin 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 outside Arkansas.
NATURAL GAS DISTRIBUTION
The Company's subsidiary Arkansas Western Gas Company operates integrated
natural gas distribution systems concentrated primarily in northern Arkansas and
southeast Missouri. The Arkansas Public Service Commission and the Missouri
Public Service Commission (MPSC) regulate the Company's utility rates and
operations. The Company serves approximately 181,000 customers and obtains a
substantial portion of the gas they consume through its Arkoma Basin gathering
facilities.
Arkansas Western consists of two operating divisions. The AWG division
gathers natural gas in the Arkansas River Valley of western Arkansas and
transports the gas through its own transmission and distribution systems,
ultimately delivering it at retail to approximately 112,000 customers in
northwest Arkansas. The Associated division receives its gas from interstate
pipelines and delivers the gas through its own transmission and distribution
systems, ultimately delivering it at retail to approximately 21,000 customers in
northeast Arkansas and 48,000 customers in Missouri. Associated, formerly a
wholly-owned subsidiary of Arkansas Power and Light Company, was acquired and
merged into Arkansas Western effective June 1, 1988.
In October 1999, the Company entered into an agreement to sell its Missouri
utility operations to Atmos Energy for $32.0 million. The transaction is
currently awaiting approval by the MPSC and Federal Energy Regulatory Commission
(FERC). Once approval is obtained and the transaction is closed, the Company
will serve a total of approximately 133,000 customers in northern Arkansas. The
transaction is expected to be closed before mid-year 2000.
Gas Purchases and Supply
AWG purchases its system gas supply through a competitive bidding process
implemented in late 1998, as discussed above, and directly at the wellhead under
long-term contracts. SEECO furnished approximately 37% of AWG's system
requirements in 1999, 59% in 1998, and 64% in 1997. AWG also purchases gas from
unaffiliated producers under take-or-pay contracts. Currently, the Company
believes that it does not have a significant exposure to take-or-pay liabilities
resulting from these contracts. The Company expects to be able to continue to
satisfactorily manage its exposure to take-or-pay liabilities.
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Associated purchases gas for its system supply from unaffiliated suppliers
accessed by interstate pipelines and from affiliates. Purchases from SEECO are
under a ten-year contract with annual price redeterminations. Purchases from
unaffiliated suppliers are under firm contracts with terms between one and three
years. The rates charged by most suppliers include demand components to ensure
availability of gas supply, administrative fees, and a commodity component which
is based on monthly indexed market prices. Associated's gas purchases are
transported through eight pipelines. The pipeline transportation rates include
demand charges to reserve pipeline capacity and commodity charges based on
volumes transported. Associated has also contracted with five interstate
pipelines for storage capacity to meet its peak seasonal demands. These
contracts involve demand charges based on the maximum deliverability, capacity
charges based on the maximum storage quantity, and charges for the quantities
injected and withdrawn.
AWG has no restriction on adding new residential or commercial customers
and will supply new industrial customers that are compatible with the scale of
its facilities. AWG has never denied service to new customers within its service
area or experienced curtailments because of supply constraints. In addition,
Associated has never denied service to new customers within its service area or
experienced curtailments because of supply constraints since the acquisition
date. Curtailment of large industrial customers of AWG and Associated occurs
only infrequently when extremely cold weather requires that systems be dedicated
exclusively to human needs customers.
Markets and Customers
The utility continues to capitalize on the healthy economies and sustained
customer growth found in its service territory. AWG and Associated provide
natural gas to approximately 159,000 residential, 22,000 commercial, and 300
industrial customers, while also providing gas transportation services to
approximately 50 end-use and off-system customers. Total gas throughput during
1999 was 36.3 Bcf, compared to 32.8 Bcf in 1998, and 37.0 in 1997. The increase
during 1999 was the result of higher off-system transportation volumes.
Off-system transportation volumes were 4.8 Bcf in 1999, compared to 1.1 Bcf
transported in 1998, and 2.8 Bcf transported in 1997.
Residential and Commercial. Approximately 84% of the utility's revenues are
from residential and commercial markets. Residential and commercial customers
combined accounted for 51% of total gas throughput for the gas distribution
segment in 1999, compared to 57% in 1998 and 1997. Gas volumes sold to
residential customers were 10.8 Bcf, down from 11.1 Bcf sold in 1998, and 12.6
Bcf sold in 1997. Gas sold to commercial customers totaled 7.6 Bcf in 1999 and
1998 and 8.4 Bcf in 1997. The decrease in residential gas volumes sold in 1999
was due to record warm weather. Weather during the calendar year was 21% warmer
than normal and 8% warmer than in 1998.
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 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 industrial customers,
which are generally smaller concerns using gas for plant heating or product
processing, accounted for 13.1 Bcf in gas deliveries in 1999, 13.0 Bcf in 1998,
and 13.2 Bcf in 1997. No industrial customer accounts for more than 5% of
Arkansas Western's total throughput.
Both AWG and Associated offer a transportation service that allows larger
business customers to obtain their own gas supplies directly from other
suppliers. A total of 40 customers are currently using the Arkansas
transportation service, including AWG's 15 largest customers in northwest
Arkansas. Associated's four largest customers in northeast Arkansas and seven of
Associated's 11 largest Missouri customers are currently using transportation
service.
11
Competition
AWG and Associated have experienced a general trend in recent years toward
lower rates of usage among their customers, largely as a result of conservation
efforts that the Company encourages. Competition is increasingly being
experienced from alternative fuels, primarily electricity, fuel oil, and
propane. A significant amount of fuel switching has not been experienced,
though, as natural gas is generally the least expensive, most readily available
fuel in the service territories of AWG and Associated.
The competition from alternative fuels and, in a limited number of cases,
alternative sources of natural gas have intensified in recent years. Industrial
customers are most likely to consider utilization of these alternatives, as they
are less readily available to commercial and residential customers. In an effort
to provide some pricing alternatives to its large industrial customers with
relatively stable loads, AWG offers an optional tariff to its larger business
customers and to any other large business customer which shows that it has an
alternate source of fuel at a lower price or that one of its direct competitors
has access to cheaper sources of energy. This optional tariff enables those
customers willing to accept the risk of price and supply volatility to direct
AWG to obtain a certain percentage of their gas requirements in the spot market.
Participating customers continue to pay the non-gas cost of service included in
AWG's present tariff for large business customers and agree to reimburse AWG for
any take-or-pay liability caused by spot market purchases on the customers'
behalf.
Regulation
The Company's utility rates and operations are regulated by the APSC and
MPSC. In Arkansas, the Company operates through municipal franchises that are
perpetual by state law. These franchises, however, are not exclusive within a
geographic area. In Missouri, the Company operates through municipal franchises
with various terms of existence.
As the regulatory focus of the natural gas industry shifts from the federal
level to the state level, utilities across the nation are being required to
unbundle their sales services from transportation services in an effort to
promote greater competition. Although no such legislation or regulatory
directives related to natural gas are presently pending in Arkansas or Missouri,
the Company 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 recently passed legislation that will
deregulate the retail sale of electricity in Arkansas as soon as 2002. The
Company is unable to predict the precise impact of any such legislation on its
utility operations. The Company's utility subsidiary has historically maintained
a substantial price advantage over electricity for most applications. However,
when retail electric competition is implemented in Arkansas, it is possible that
some portion of this price advantage may be lost in some markets. As described
in the paragraph above, the Company is taking steps to preserve its competitive
advantage over alternative energy sources, including electricity. When electric
deregulation occurs in Arkansas, legislative or regulatory precedents may be set
that will also affect natural gas utilities in the future. These issues may
include further unbundling of services and the regulatory treatment of stranded
costs.
Gas distribution revenues in future years will be impacted by the sale of
the Company's Missouri assets and by customer growth and rate increases allowed
by regulatory commissions. In recent years, AWG has experienced customer growth
of approximately 2% to 3% annually, while Associated has experienced customer
growth of approximately 1% or less annually. Based on current economic
conditions in the Company's service territories, the Company expects this trend
in customer growth to continue.
12
In December 1996, AWG received approval from the APSC for a rate increase
of $5.1 million annually. The December 1996 rate increase order issued by the
APSC also provided that AWG cause to be filed with the APSC an independent study
of its procedures for allocating costs between regulated and non-regulated
operations, its staffing levels and executive compensation. The independent
study was ordered by the APSC to address issues raised by the Office of the
Attorney General of the State of Arkansas. The study 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 and did not recommend any changes to the rates
currently in effect.
The Company received approvals in December 1997 from the APSC and the MPSC
for rate increases and tariff changes for Associated which will allow the
utility to collect an additional $3.0 million annually. Of the $3.0 million
increase, approximately $2.0 million is in the form of base rate increases and
$1.0 million is related to the increased cost of service of the Company's
gathering plant which is recovered through either the purchased gas adjustment
clause or through direct charges to transportation customers. Rate increase
requests that may be filed in the future will depend on customer growth,
increases in operating expenses, and additional investments in property, plant
and equipment. AWG's rates for gas delivered to its retail customers are not
regulated by the FERC, but its transmission and gathering pipeline systems are
subject to the FERC's regulations concerning open access transportation since
AWG accepted a blanket transportation certificate in connection with its merger
with Associated.
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 AWG
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, the Company
reached agreement with the Staff and the APSC to resolve this issue and to close
several other open dockets. In the settlement agreement, the Company 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 part of the settlement, this docket was
closed with no negative adjustment to the Company.
MARKETING AND TRANSPORTATION
Gas Marketing
The marketing group was formed in mid-1996 to better enable the Company to
capture downstream opportunities which arise through marketing and
transportation activity. Through utilization of Southwestern's existing asset
base, the group's focus is to create and capture value beyond the wellhead. The
merger of the NOARK Pipeline with the Ozark Gas Transmission System discussed
below is expected to afford greater supply and market opportunities, allowing
the group to expand its marketing operations in Oklahoma.
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 $2.1 million in 1999, compared to $1.8 million in 1998 and $1.3
million in 1997. The segment marketed 63.1 Bcf of natural gas in 1999, compared
to 49.6 Bcf in 1998 and 36.2 Bcf in 1997. Of the total volumes marketed,
purchases from the Company's exploration and production subsidiaries accounted
for 31% in 1999, 25% in 1998, and 23% in 1997.
13
NOARK Pipeline
At December 31, 1999, the Company held a 25% general partnership interest
in NOARK. NOARK Pipeline was a 258-mile long intrastate natural gas transmission
system that originated in western Arkansas and terminated in northeast Arkansas,
crossing three major interstate pipelines and interconnecting with the Company's
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. The Company's share of the pretax loss from operations related to
its NOARK investment was $2.0 million in 1999, $3.1 million in 1998, and $4.5
million in 1997.
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. On July 1, 1998, the FERC authorized the operation and integration of
Ozark and NOARK Pipeline as a single, integrated pipeline. The FERC order also
authorized the purchase of Ozark by a subsidiary of Enogex and the construction
of integration facilities. Enogex acquired Ozark and contributed the pipeline
system to the NOARK partnership and also acquired the NOARK partnership
interests not held by Southwestern. Enogex funded the acquisition of Ozark and
the expansion and integration with NOARK Pipeline which resulted in the
Company's interest in the partnership decreasing 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 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 experienced on the project in
the past. The merged pipeline also provides the Company's utility systems with
additional access to gas supply.
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 MMcfd. Deliveries are currently being made by the integrated
pipeline to portions of AWG's distribution system, to Associated, and to the
interstate pipelines with which it interconnects. Before the integration with
Ozark, NOARK Pipeline had an average daily throughput of 27.3 MMcfd in 1998 and
39.8 MMcfd in 1997. For 1999, Ozark Pipeline had an average daily throughput of
167.5 MMcfd. At December 31, 1999, AWG had transportation contracts with Ozark
Pipeline for 82.3 MMcfd of firm capacity. These contracts expire in 2002 and
2003 and are renewable annually thereafter until terminated with 180 days'
notice.
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 of 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
14
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. As discussed
below under "Regulation," FERC's Order No. 636 has generally increased
competition in the transportation segment as end-users are now acquiring their
own supplies and independently arranging for the transportation of those
supplies. The Company believes that 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
Since the mid-1980's, the FERC has issued a series of orders, culminating
in Order No. 636 in April 1992, that have altered the marketing and
transportation of natural gas. Order No. 636 required interstate natural gas
pipelines to "unbundle," or segregate, the sales, transportation, storage and
other components of their existing sales services, and to separately state the
rates for each of the unbundled services. Order No. 636 and subsequent FERC
orders issued in individual pipeline proceedings have been the subject of
appeals, the results of which have generally been supportive of the FERC's open
access policy. Generally, Order No. 636 has eliminated or substantially reduced
the interstate pipelines' roles as wholesalers of natural gas and has
substantially increased competition in natural gas markets.
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 APSC no longer has jurisdiction over NOARK Pipeline's
transportation rates and services. The FERC has initially set the maximum
transportation rate of Ozark Pipeline at $.2455 per dekatherm.
OTHER ITEMS
Environmental Matters
The Company's operations are subject to extensive federal, state and local
laws and regulations, including the Comprehensive Environmental Response,
Compensation and Liability Act, the Clean Water Act, the Clean Air Act and
similar state statutes. These laws and regulations require permits for drilling
wells and the maintenance of bonding requirements in order to drill or operate
wells and also regulate the spacing and location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandoning of wells, the prevention
and cleanup of pollutants and other matters. Southwestern maintains insurance
against costs of clean-up operations, but is not fully insured against all such
risks.
Compliance with environmental laws and regulations has had no material
effect on Southwestern's capital expenditures, earnings, or competitive
position. Although future environmental obligations are not expected to have a
material impact on the results of operations or financial condition of the
Company, there can be no assurance that future developments, such as
increasingly stringent environmental laws or enforcement thereof, will not cause
the Company to incur material environmental liabilities or costs.
Real Estate Development
A. W. Realty Company (AWR) owns an interest in approximately 155 acres of
real estate, most of which is undeveloped. AWR's real estate development
activities are concentrated on a 130-acre tract of land located near the
Company's headquarters in a growing part of Fayetteville, Arkansas. The Company
has owned an interest in this land for many years. The property is zoned for
commercial, office, and multi-family residential development. AWR continues to
review
15
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, 1999, the Company had 686 employees, 97 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 32 ("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 discussion under Item 1 ("Business").
AWG Associated Total
----------------------------------
Gathering 388 - 388
Transmission 805 608 1,413
Distribution 3,123 1,697 4,820
- --------------------------------------------------------------------------------
4,316 2,305 6,621
================================================================================
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.
Leasehold Acreage
Undeveloped Developed
Gross Net Gross Net
------------------------------------------------
Arkoma 100,540 89,035 189,823 142,607
Mid-Continent 61,634 27,127 104,015 43,944
Permian 120,137 22,390 139,101 20,400
Gulf Coast 38,240 19,385 56,226 19,770
- --------------------------------------------------------------------------------
320,551 157,937 489,165 226,721
================================================================================
16
Producing Wells
Gas Oil Total
Gross Net Gross Net Gross Net
------------------------------------------------------
Arkoma 794 383.4 - - 794 383.4
Mid-Continent 242 100.7 557 182.4 799 283.1
Permian 75 11.1 219 132.3 294 143.4
Gulf Coast 56 22.1 21 16.0 77 38.1
- ---------------------------------------------------------------------------------------
1,167 517.3 797 330.7 1,964 848.0
=======================================================================================
Wells Drilled During the Year
Exploratory
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
- ---- ----------------------------------------------------------------
1999 4.0 1.5 4.0 1.6 8.0 3.1
1998 3.0 .5 10.0 3.9 13.0 4.4
1997 2.0 1.3 4.0 3.0 6.0 4.3
Development
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
- ---- ----------------------------------------------------------------
1999 47.0 18.3 15.0 6.1 62.0 24.4
1998 72.0 29.4 10.0 6.4 82.0 35.8
1997 58.0 27.5 24.0 13.5 82.0 41.0
Wells in Progress as of December 31, 1999
Gross Net
----------------
Exploratory 2.0 0.6
Development 10.0 2.0
- --------------------------------------------------------------------------------
Total 12.0 2.6
================================================================================
During 1999, 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 Item 8. 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.
17
ITEM 3. LEGAL PROCEEDINGS
In May 1996, a class action suit was filed against the Company on behalf of
royalty owners alleging improprieties in the disbursements of royalty proceeds.
A trial was held on the class action suit beginning in late September 1998 that
resulted in a verdict against the Company and two of its wholly-owned
subsidiaries, SEECO, Inc. and Arkansas Western Gas Company, in the amount of
$62.1 million. The trial judge subsequently awarded pre-judgment interest in an
amount of $31.1 million, and post-judgment interest accrued from the date of the
judgment at the rate of 10% per annum simple interest. The Company has been
required by the state court to post a judgment bond which now stands at $109.3
million (verdict amount plus pre-judgment interest and 20 months of
post-judgment interest) in order to stay the jury's verdict and proceed with an
appeal process. The bond was placed by a surety company and was collateralized
by unsecured letters of credit.
The verdict was returned following a trial on the issues of the class
action lawsuit brought by certain royalty owners of SEECO, Inc., who contend
that since 1979 the defendants breached implied covenants in certain oil and gas
leases, misrepresented or failed to disclose material facts to royalty owners
concerning gas purchase contracts between the Company's subsidiaries, and failed
to fulfill other alleged common law duties to the members of the royalty owner
plaintiff class. The litigation was commenced in May 1996 and was disclosed by
the Company at that time.
The Company believes that the jury's verdict was wrong as a matter of law
and fact and that incorrect rulings by the trial judge (including evidentiary
rulings and prejudicial jury instructions) provide significant grounds for a
successful appeal. The Company had asked the trial judge to recuse himself due
to his apparent bias toward the plaintiffs and had also filed a motion with the
trial court for judgment notwithstanding the verdict or, in the alternative, for
a new trial. These motions were denied. The Company has filed and will
vigorously prosecute an appeal in the Arkansas Supreme Court. Based on
discussion with outside legal counsel, management of the Company remains
confident that the jury's verdict will be overturned and the case remanded for a
new trial. If the Company is not successful in its appeal from the jury verdict,
the Company's financial condition and results of operations would be materially
and adversely affected. However, management believes that the Company's ultimate
liability, if any, resulting from this case will not be material to its
financial position, but in any one year could be significant to the results of
operations. At December 31, 1999 and 1998, no amounts had been accrued on this
matter.
In its Form 8-K filed July 2, 1996, the Company disclosed that a lawsuit
relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly owned subsidiaries.
The lawsuit, which was brought by a party who was originally included in (but
opted out of) the class action litigation described above, involves claims
similar to those upon which judgment was rendered against the Company and its
subsidiaries. In September 1998, another party who opted out of the class
threatened the Company with similar litigation. While the amounts of these
pending and threatened claims could be significant, management believes, based
on its extensive investigations and trial preparation, that these claims are
without merit and, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations. This
matter went to a non-jury trial as to liability on January 10, 2000 and the
Company is awaiting the court's ruling.
The United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the class action litigation. MMS was included in the class action
litigation against its objections, but has not pursued further action to remove
itself from the class. If MMS does remove itself from the class, its claims may
be brought separately
18
under federal statutes that provide for treble damages and civil penalties. In
such event, the Company believes it would have defenses that were not available
in the class action litigation. While the aggregate amount of MMS's claims could
be significant, management believes, based on its investigations, that the
Company's ultimate liability, if any, will not be material to its consolidated
financial position or results of operations.
As previously reported, the Company's subsidiary, SEPCO, filed suit in 1997
against several parties, including an outside consultant previously employed by
SEPCO, alleging breach of contract, fraud, and other causes of action in
connection with services performed on SEPCO's south Louisiana exploration
projects. On June 23, 1998, the outside consultant filed a counterclaim against
SEPCO. In 1999, this matter was settled for an amount that was not material to
the Company's consolidated financial position or results of operation.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a non-capital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial position or reported results of operations of
the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 1999, 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 and Director 55 3
Alan H. Stevens President and Chief Operating Officer, 55 2
Southwestern Energy Production Company and SEECO, Inc.
Greg D. Kerley Executive Vice President and Chief Financial Officer 44 10
George A. Taaffe, Jr. Senior Vice President and General Counsel, Secretary 53 1
Debbie J. Branch Senior Vice President, Southwestern Energy Services 48 4
Company
Charles V. Stevens Senior Vice President, Arkansas Western Gas Company 50 11
19
Mr. Korell was appointed President in 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. Alan Stevens was appointed to his present position in December 1999. He
joined the Company in January 1998 as Senior Vice President of Southwestern
Energy Production Company and SEECO, Inc. Prior to joining the Company, he was
President and Chief Operating Officer for Petsec Energy during 1997 and was
employed by Occidental Petroleum Company from 1989 to 1997 where he was most
recently Vice President of Worldwide Exploration.
Mr. Kerley was appointed to his present position in December 1999.
Previously, he served as Senior Vice President and Chief Financial Officer since
July 1998, 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. Taaffe joined the Company in his current position in July 1999. Prior
to joining the Company, he served as Vice President and Assistant General
Counsel for Consolidated Natural Gas Company from 1988 to 1999 and Associated
General Counsel for Joy Technologies from 1973 to 1987.
Ms. Branch joined the Company in her present position in 1996. Prior to
joining the Company, she was Executive Vice President of Stalwart Energy Company
from 1994 to 1996 and founder and President of Vesta Energy Company from 1983 to
1993.
Mr. Charles Stevens has served the Company in his present position since
December 1997. Previously, he served as Vice President of Arkansas Western Gas
Company from 1988 to 1997.
All officers are elected at the Annual Meeting of the Board of Directors
for one-year terms or until their successors are duly elected. There are no
arrangements between any officer and any other person pursuant to which he or
she 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.
20
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, 1999, the Company had 2,268 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 1999 1998 1999 1998
- ------------- ------------------------------------------------------
March 31 $ 8.44 $5.31 $12.94 $10.63 $.06 $.06
June 30 $10.56 $6.06 $12.00 $ 8.75 $.06 $.06
September 30 $10.94 $7.50 $10.38 $ 6.75 $.06 $.06
December 31 $ 9.19 $5.63 $ 8.50 $ 5.50 $.06 $.06
The terms of certain of the Company's long-term debt instruments and
agreements impose restrictions on the payment of cash dividends. These covenants
generally limit the payment of dividends in a fiscal year to the total of net
income plus $20.0 million less dividends paid and purchases, redemptions or
retirements of capital stock during the period since January 1, 1990. At
December 31, 1999, $96.4 million of retained earnings was available for payment
as cash dividends. Dividends totaling $6.0 million were paid during 1999.
The Company paid dividends at an annual rate of $.24 per share in 1999 and
1998. While the Board of Directors intends to continue the practice of paying
dividends quarterly, amounts and dates of such dividends as may be declared will
necessarily be dependent upon the Company's future earnings and capital
requirements.
21
ITEM 6. SELECTED FINANCIAL DATA
1999 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------
Financial Review (in thousands)
Operating revenues
Exploration and production $ 75,039 $ 86,232 $100,129 $ 86,978 $ 63,285 $ 79,787
Gas distribution 132,420 134,711 154,155 142,730 119,452 126,667
Energy services and other 137,942 97,795 83,511 30,636 31,622 29,225
Intersegment revenues (65,005) (52,433) (61,606) (57,004) (47,534) (60,055)
- ---------------------------------------------------------------------------------------------------------------------
280,396 266,305 276,189 203,340 166,825 175,624
- ---------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 45,370 39,863 46,806 42,851 37,133 36,395
Gas purchases - marketing 92,851 73,235 63,054 14,114 13,714 5,438
Operating and general 57,957 61,915 59,167 50,509 44,436 42,506
Depreciation, depletion and amortization 41,603 46,917 48,208 42,394 35,992 35,546
Write-down of oil and gas properties - 66,383 - - - -
Taxes, other than income taxes 6,557 6,943 7,018 5,476 4,362 3,657
- ---------------------------------------------------------------------------------------------------------------------
244,338 295,256 224,253 155,344 135,637 123,542
- ---------------------------------------------------------------------------------------------------------------------
Operating income 36,058 (28,951) 51,936 47,996 31,188 52,082
Interest expense, net (17,351) (17,186) (16,414) (13,044) (11,167) (8,867)
Other income (expense) (2,331) (3,956) (5,017) (4,015) (1,227) (2,362)
- ---------------------------------------------------------------------------------------------------------------------
Income before income taxes and
extraordinary item 16,376 (50,093) 30,505 30,937 18,794 40,853
- ---------------------------------------------------------------------------------------------------------------------
Income taxes:
Current 537 (6,029) (732) (5,569) (4,908) 9,288
Deferred 5,912 (13,467) 12,522 17,320 12,167 6,441
- ---------------------------------------------------------------------------------------------------------------------
6,449 (19,496) 11,790 11,751 7,259 15,729
- ---------------------------------------------------------------------------------------------------------------------
Income before extraordinary item 9,927 (30,597) 18,715 19,186 11,535 25,124
Extraordinary item - - - - (295) -
- ---------------------------------------------------------------------------------------------------------------------
Net income $ 9,927 $(30,597) $ 18,715 $ 19,186 $ 11,240 $ 25,124
=====================================================================================================================
Cash flow from operations, net of working
capital changes (in thousands) $ 58,131 $ 93,708 $ 79,483 $ 71,830 $ 56,177 $ 66,857
Return on equity 5.21% n/a 8.45% 9.23% 5.78% 12.35%
=====================================================================================================================
Common Stock Statistics
Basic earnings per share before
extraordinary item $.40 $(1.23) $.76 $.78 $.46 $.98
Basic and diluted earnings per share $.40 $(1.23) $.76 $.78 $.45 $.98
Cash dividends declared and paid per share $.24 $.24 $.24 $.24 $.24 $.24
Book value per share $7.60 $7.45 $8.92 $8.41 $7.87 $7.92
Market price at year-end $6.56 $7.50 $12.88 $15.13 $12.75 $14.88
Number of shareholders of record at
year-end 2,268 2,333 2,379 2,572 2,759 2,875
Average shares outstanding 24,941,550 24,882,170 24,738,882 24,705,256 25,130,781 25,684,110
=====================================================================================================================
22
1999 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands)
Total debt, including current portion $302,200 $283,436 $299,543 $278,285 $210,828 $142,300
Common shareholders' equity 190,356 185,856 221,565 207,941 194,504 203,456
- ---------------------------------------------------------------------------------------------------------------------
Total capitalization $492,556 $469,292 $521,108 $486,226 $405,332 $345,756
- ---------------------------------------------------------------------------------------------------------------------
Total assets $671,446 $647,620 $710,866 $660,190 $569,093 $486,074
- ---------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion
of long-term) 61.35% 60.27% 57.23% 56.96% 51.65% 40.10%
Equity 38.65% 39.73% 42.77% 43.04% 48.35% 59.90%
=====================================================================================================================
Capital Expenditures (in millions)
Exploration and production $59.0 $52.4 $73.5 $110.3 $ 82.2 $55.4
Gas distribution 7.1 10.1 12.6 12.8 18.5 17.6
Other .9 1.9 2.7 1.8 .9 3.9
- ---------------------------------------------------------------------------------------------------------------------
$67.0 $64.4 $88.8 $124.9 $101.6 $76.9
=====================================================================================================================
Exploration and Production
Natural gas:
Production, Bcf 29.4 32.7 33.4 34.8 34.5 37.7
Average price per Mcf $2.21 $2.34 $2.57 $2.26 $1.72 $2.04
Oil:
Production, MBbls 578 703 749 391 229 200
Average price per barrel $17.11 $13.60 $19.02 $21.21 $17.15 $15.89
Total gas and oil production, Bcfe 32.9 36.9 37.9 37.1 35.9 38.9
Average production (lifting) cost per
Mcf equivalent $.44 $.43 $.45 $.29 $.22 $.17
Proved reserves at year-end:
Natural gas, Bcf 307.5 303.7 291.4 297.5 294.9 316.1
Oil, MBbls 7,859 6,850 7,852 8,238 2,152 1,231
Total reserves, Bcf equivalent 354.7 344.8 338.5 346.9 307.8 323.5
=====================================================================================================================
Gas Distribution
Sales and transportation volumes, Bcf:
Residential 10.8 11.1 12.6 13.4 12.1 11.6
Commercial 7.6 7.6 8.4 8.8 7.6 7.2
Industrial 3.5 4.2 6.6 7.7 7.7 7.5
End-use transportation 9.6 8.8 6.6 5.5 5.2 4.8
- ---------------------------------------------------------------------------------------------------------------------
31.5 31.7 34.2 35.4 32.6 31.1
Off-system transportation 4.8 1.1 2.8 3.6 9.8 10.7
- ---------------------------------------------------------------------------------------------------------------------
36.3 32.8 37.0 39.0 42.4 41.8
- ---------------------------------------------------------------------------------------------------------------------
Customers - year-end
Residential 158,606 156,384 154,864 151,880 147,267 144,486
Commercial 21,929 22,229 21,431 20,845 20,109 19,489
Industrial 290 303 311 326 340 348
- ---------------------------------------------------------------------------------------------------------------------
180,825 178,916 176,606 173,051 167,716 164,323
- ---------------------------------------------------------------------------------------------------------------------
Degree days 3,179% 3,472% 4,131% 4,341% 4,064% 3,823%
Percent of normal 79 87 103 108 102 96
=====================================================================================================================
23
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." Certain reclassifications have been made to the prior years'
financial statements to conform with the 1999 presentation. These
reclassifications had no effect on previously reported net income.
RESULTS OF OPERATIONS
The Company reported net income of $9.9 million, or $.40 per share, for
1999, compared to a net loss of $30.6 million, or $1.23 per share, for 1998 and
net income of $18.7 million, or $.76 per share, in 1997. The loss for 1998
reflects the impact of an after-tax, non-cash ceiling test write-down of the
Company's oil and gas properties of $40.5 million, or $1.63 per share. Excluding
the non-cash charge, the Company would have recognized net income of $9.9
million, or $.40 per share in 1998. Results for 1999 reflect decreased oil and
gas production and the effects of record warm weather offset by lower operating
and general expenses and lower depreciation, depletion and amortization expense.
During 1998 earnings were negatively impacted by lower wellhead prices for both
oil and gas and by unseasonably warm weather. Revenues and operating income for
the Company's major business segments are shown in the following table.
1999 1998 1997
---------------------------------
(in thousands)
Revenues
Exploration and production $ 75,039 $ 86,232 $100,129
Gas distribution 132,420 134,711 154,155
Marketing 137,526 97,175 82,807
Other 416 620 704
Eliminations (65,005) (52,433) (61,606)
- --------------------------------------------------------------------------------
$280,396 $266,305 $276,189
================================================================================
Operating Income
Exploration and production $ 16,451 $(47,273)(1) $ 33,303
Gas distribution 17,187 16,029 16,941
Marketing 2,142 1,800 1,315
Other 278 493 377
- --------------------------------------------------------------------------------
$ 36,058 $(28,951) $ 51,936
================================================================================
<FN>
(1) Includes a $66.4 million pre-tax write-down of oil and gas properties.
</FN>
Exploration and Production
The Company's exploration and production revenues decreased 13% in 1999 and
14% in 1998. The decrease in 1999 was due to lower volumes of oil and gas
produced and a lower average gas price received while the decrease in 1998 was
due primarily to lower average oil and gas prices.
24
Operating income of the exploration and production segment was $16.5
million in 1999, compared to $19.1 million in 1998 excluding the impact of the
non-cash write-down of oil and gas properties, and $33.3 million in 1997. The
decrease in 1999 was due primarily to an 11% decrease in equivalent oil and gas
production volumes. The decrease in 1998 was primarily due to lower average gas
and oil prices, which were down 9% and 28%, respectively, from their levels in
1997.
Gas and oil production totaled 32.9 billion cubic feet equivalent (Bcfe) in
1999, 36.9 Bcfe in 1998 and 37.9 Bcfe in 1997. The decreases in production were
due to the combined effects of production declines in the Company's outside
operated properties resulting from the industry slowdown that began in 1998,
production declines in some of the Company's Gulf Coast properties, and the loss
of production from marginal properties that were sold in 1999.
1999 1998 1997
---------------------
Gas Production
Affiliated sales (Bcf) 8.2 11.3 14.3
Unaffiliated sales (Bcf) 21.2 21.4 19.1
- --------------------------------------------------------------------------------
29.4 32.7 33.4
- --------------------------------------------------------------------------------
Average price per Mcf $2.21 $2.34 $2.57
================================================================================
Oil Production
Unaffiliated sales (MBbls) 578 703 749
- --------------------------------------------------------------------------------
Average price per Bbl $17.11 $13.60 $19.02
================================================================================
Total Production (Bcfe) 32.9 36.9 37.9
================================================================================
Gas sales to unaffiliated purchasers were 21.2 Bcf in 1999, down slightly
from 21.4 Bcf in 1998 and up from 19.1 Bcf in 1997. Sales to unaffiliated
purchasers are primarily made under contracts which reflect current short-term
prices and which are subject to seasonal price swings.
Intersegment sales to Arkansas Western Gas Company (AWG), the utility
subsidiary which operates the Company's northwest Arkansas utility system, were
5.1 Bcf in 1999, 7.7 Bcf in 1998, and 8.6 Bcf in 1997. Unseasonably warm weather
during 1999 and 1998 decreased AWG's demand for the Company's gas supply. The
Company's gas production provided approximately 40% of AWG's requirements in
1999, and 60% in 1998 and 1997.
Prior to December 1998, most of the sales to AWG's system were pursuant to
an intersegment long-term contract entered into in 1978 with SEECO, Inc. (SEECO)
which was amended and restated in 1994 as the result of a settlement between the
Company, the Staff of the Arkansas Public Service Commission (APSC) and the
office of the Attorney General of the state of Arkansas. The sales price under
the amended contract averaged $2.99 per thousand cubic feet (Mcf) through
November of 1998, and $3.46 per Mcf in 1997.
On October 1, 1998, AWG sent requests for proposals to various suppliers
requesting bids on seven different packages of gas supply to be effective
December 1, 1998. These bid requests included replacement of the gas supply and
no-notice service previously provided by the long-term gas supply contract
between AWG and SEECO discussed above.
25
SEECO along with the Company's marketing subsidiary successfully bid on five of
the seven 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
sold under these contracts would be approximately equal to the historical annual
volumes sold under the expired long-term contract. However, under the new
contracts, the Company supplies most of AWG's no-notice service and less of its
routine base requirements than it had under the previous contract. During
periods of warmer weather, as in 1999 and 1998, less total gas volumes will be
sold to AWG than compared to periods of normal or colder weather. The total
premium over the Reliant East Index under these contracts is estimated to be
approximately $1.0 million lower (after tax) than the annual premium earned
under the expired long-term contract. The majority of the premium is received
through monthly demand charges which will be received regardless of volumes
actually delivered. Other sales to AWG are made under long-term contracts with
flexible pricing provisions.
The Company's intersegment sales to Associated Natural Gas Company
(Associated), a division of AWG which operates the Company's natural gas
distribution systems in northeast Arkansas and parts of Missouri, were 3.1 Bcf
in 1999, 3.6 Bcf in 1998, and 5.7 Bcf in 1997. Deliveries to Associated
decreased in 1999 and 1998 due primarily to corresponding changes in heating
weather. Effective October 1990, SEECO entered into a ten-year contract with
Associated to supply a portion of its system requirements at a price to be
redetermined annually. For the contract period beginning October 1, 1997, the
contract was revised to redetermine the sales price monthly based on an index
posting plus a reservation fee. The average price received under the contract
was $2.37 for 1999 and 1998 and $2.51 for 1997. Prior to the end of the current
contract term in 2000, Associated will place its gas supply out for competitive
bids. Continued sales of these volumes to Associated, and the price of any such
sales, will depend on the results of this competitive bidding process.
Additionally, future volumes could be impacted by the sale of Associated's
Missouri properties as discussed further in the "Gas Distribution" section
below.
The overall average price received for the Company's gas production was
$2.21 per Mcf in 1999, $2.34 per Mcf in 1998, and $2.57 per Mcf in 1997. 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 $.06
per Mcf in 1999, added $.19 per Mcf to the average gas price in 1998 and lowered
the 1997 average gas price $.05 per Mcf.
The Company periodically enters into hedging activities with respect to a
portion of its projected crude oil and natural gas production through a variety
of financial arrangements intended to support oil and gas prices at targeted
levels and to minimize the impact of price fluctuations (see Note 8 of the
financial statements for additional discussion). The Company's policies prohibit
speculation with derivatives and limit swap agreements to counterparties with
appropriate credit standings. Disregarding the impact of hedges, the Company
expects the average price it receives for its total gas production to be
slightly higher than average spot market prices due to the prices it receives
under the contracts covering its intersegment sales which are long-term and
provide swing services to the Company's utility systems. Future changes in
revenues from sales of the Company's gas production will be dependent upon
changes in the market price for gas, access to new markets, maintenance of
existing markets, and additions of new gas reserves.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. The Company is unable to
predict changes in the market demand and price for natural gas, including
changes which may be induced by the effects of weather on demand of both
affiliated and unaffiliated customers for the Company's
26
production. Additionally, the Company holds a large amount of undeveloped
leasehold acreage and producing acreage, and has an inventory of drilling leads,
prospects and seismic data which will continue to be developed and evaluated in
the future. The Company's exploration programs have been directed primarily
toward natural gas in recent years.
Gas Distribution
Gas distribution revenues fluctuate due to the pass-through of gas supply
cost changes and due to the effects of weather. Because of the corresponding
changes in purchased gas costs, the revenue effect of the pass-through of gas
cost changes has not materially affected net income. Gas distribution revenues
decreased 2% in 1999 and 13% in 1998 due to the effects of warmer weather.
Weather in 1999 was 21% warmer than normal and 8% warmer than the prior year.
Weather in 1998 was 13% warmer than normal and 16% warmer than the prior year.
Operating income for Southwestern's utility systems increased 7% in 1999
and decreased 5% in 1998. The increase in 1999 was due to the Company's efforts
in reducing operating costs and to customer growth. The decrease in 1998 was due
to the effects of warmer weather, partially offset by a $3.0 million rate
increase approved in December 1997 for the Company's northeast Arkansas and
Missouri systems, and customer growth.
1999 1998 1997
-----------------------------
Gas Distribution Systems
Throughput (Bcf)
Sales volumes 21.9 22.9 27.6
Transportation volumes
End-use 9.6 8.8 6.6
Off-system 4.8 1.1 2.8
- --------------------------------------------------------------------------------
36.3 32.8 37.0
- --------------------------------------------------------------------------------
Average number of sales customers 177,274 174,642 172,200
- --------------------------------------------------------------------------------
Heating weather
Degree days 3,179 3,472 4,131
Percent of normal 79% 87% 103%
Average sales rate per Mcf $5.67 $5.57 $5.36
================================================================================
In 1999, AWG sold 14.5 Bcf to its customers at an average rate of $5.47 per
Mcf, compared to 15.1 Bcf at $5.37 per Mcf in 1998 and 17.4 Bcf at $5.34 per Mcf
in 1997. Additionally, AWG transported 6.2 Bcf in 1999, 6.0 Bcf in 1998, and 5.0
Bcf in 1997 for its end-use customers. Associated sold 7.4 Bcf to its customers
in 1999 at an average rate of $6.06 per Mcf, compared to 7.8 Bcf in 1998 at
$5.95 per Mcf and 10.2 Bcf at $5.39 per Mcf in 1997. Associated transported 3.4
Bcf for its end-use customers in 1999, compared to 2.8 Bcf in 1998 and 1.6 Bcf
in 1997. The decrease in the combined volumes sold and transported for end-use
customers in both 1999 and 1998 for the utility systems resulted from warmer
weather, partially offset by customer growth. 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, and rate increases implemented in 1997.
27
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, were 13.1 Bcf in 1999, 13.0 Bcf in 1998 and 13.2 Bcf in
1997. AWG also transported 4.8 Bcf of gas through its gathering system in 1999
for off-system deliveries, all to the Ozark Gas Transmission System, compared to
1.1 Bcf in 1998 and 2.8 Bcf in 1997. The increase in off-system deliveries in
1999 was due to decreased on-system demands of the Company's gas distribution
systems for the Company's gas production due to warmer than normal heating
weather. The average transportation tariff was approximately $.10 per Mcf,
exclusive of fuel, in 1999, $.11 per Mcf in 1998 and $.16 per Mcf in 1997.
In October 1999, the Company signed a definitive agreement to sell its
Missouri gas distribution assets for $32.0 million. The net book value of the
assets being sold is approximately $28.0 million. Proceeds from the sale will be
used to reduce the Company's outstanding debt. The sale requires regulatory
approval and is expected to close in the first half of 2000. After closing, the
Company's operating results for its gas distribution segment will be lower
reflecting the asset divestiture and the loss of Missouri customers. However,
the Company does not expect the sale to have a material negative impact on
earnings as the loss in operating income should be primarily offset by a
corresponding decrease in interest expense. The Company currently serves
approximately 48,000 customers in Missouri. The Company will continue to operate
its gas distribution systems in Arkansas where it currently serves approximately
133,000 customers.
Gas distribution revenues in future years will be impacted by the sale of
the Company's Missouri assets, customer growth and rate increases allowed by the
APSC. In recent years, AWG has experienced customer growth of approximately 2%
to 3% annually, while Associated has experienced customer growth of
approximately 1% or less annually. Based on current economic conditions in the
Company's service territories, the Company expects this trend in customer growth
to continue. The Company received approvals in December 1997 from the APSC and
the Missouri Public Service Commission (MPSC) for rate increases and tariff
changes which allow the utility to collect an additional $3.0 million annually.
Of the $3.0 million total, approximately $2.0 million is in the form of base
rate increases and $1.0 million is related to the increased cost of service of
the Company's gathering plant which is recovered through either the purchased
gas adjustment clause or through direct charges to transportation customers.
In its order approving the Missouri changes, the MPSC further ordered
Associated to modify its purchased gas adjustment tariff to remove any specific
language referencing recovery of the cost of service of its gathering
facilities. The MPSC order provided that Associated should base gathering
charges to its customers on competitive market conditions and that it would be
allowed recovery from its sales and transportation customers of all prudently
incurred gathering costs without reference to its cost of service. The MPSC will
review these gathering costs annually as part of its review of Associated's gas
costs. Associated believes that the MPSC lacks statutory authority to approve
charges which are not based on historical cost of service. Associated appealed
this issue to the circuit court which ruled in favor of the MPSC. The Company
has appealed the lower court's decision to the Missouri Court of Appeals. The
Company intends to bill its ratepayers gas gathering costs based on its cost of
service until the matter is resolved. If usage of the Company's gathering system
to obtain system gas supply or to source gas delivered to its industrial
customers should decrease, then recovery of these gathering costs would decrease
as well. Gathering costs have been recovered in this manner from Missouri
customers since Associated's 1990 rate case. Prior to the 1997 changes,
Associated's gathering costs were recovered from Arkansas customers through its
base rates.
28
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
investments in property, plant and equipment. See "Regulatory Matters" below for
additional discussion related to the Company's gas distribution segment.
Marketing
Operating income for the marketing segment was $2.1 million on revenues of
$137.5 million in 1999, compared to $1.8 million on revenues of $97.2 million in
1998, and $1.3 million on revenues of $82.8 million in 1997. The Company
increased its marketing activities when it formed a marketing group in mid-1996
to better enable the Company to capture downstream opportunities which arise
through marketing and transportation activity. The Company marketed 63.1 Bcf in
1999, compared to 49.6 Bcf in 1998 and 36.2 Bcf in 1997. The Company enters into
hedging activities with respect to its gas marketing activities to provide
margin protection (see Note 8 of the financial statements for additional
discussion).
NOARK Pipeline
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
long intrastate gas transmission system which extended across northern Arkansas,
crossing three major interstate pipelines and 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. The
Company's share of the pretax loss from operations included in other income
related to its NOARK investment was $2.0 million in 1999, $3.1 million in 1998,
and $4.5 million in 1997. The improvement in the 1999 results primarily reflects
the benefits of the integration of the NOARK Pipeline System with the Ozark Gas
Transmission System. The integration of the two systems was completed in
November, 1998. The improvement in the 1998 pretax loss reflects a lower
interest rate on NOARK's debt which resulted from a refinancing discussed below
in "Liquidity and Capital Resources."
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 the Company's
interest in the partnership decreasing 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. As a result of the
changes discussed above, 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.
Ozark Pipeline, the new integrated system, became operational November 1,
1998, and includes 749 miles of pipeline with a total throughput capacity of 330
MMcfd. Deliveries are currently being made by the integrated pipeline to
portions of AWG's distribution system, to Associated, and to the interstate
pipelines with which it interconnects.
29
In 1999 Ozark Pipeline had an average daily throughput of 167.5 million cubic
feet of gas per day (MMcfd). In 1998, NOARK had an average daily throughput of
27.3 MMcfd before the integration with Ozark, compared to average daily
throughput of 39.8 MMcfd in 1997. At December 31, 1999, the Company's gas
distribution subsidiary has transportation contracts with Ozark Pipeline for
82.3 MMcfd of firm capacity. These contracts expire in 2002 and 2003 and are
renewable annually thereafter until terminated with 180 days' notice.
As further explained in Note 11 of the financial statements, the Company
has severally guaranteed 60% of NOARK's currently outstanding debt. This debt
financed a portion of the original cost to construct the NOARK Pipeline.
Regulatory Matters
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 AWG
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 the Company
reached agreement with the Staff and the APSC to resolve this issue and to close
several other dockets that had remained open. In the settlement agreement, the
Company 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 and that was previously disclosed by the Company
where the Staff had recommended the disallowance of approximately $3.1 million
of gas supply costs. As part of the settlement, this docket was closed with no
negative adjustment to the Company.
A December 1996 rate increase order issued by the APSC also provided that
AWG cause to be filed with the APSC an independent study of its procedures for
allocating costs between regulated and non-regulated operations, its staffing
levels and executive compensation. The independent study was ordered by the APSC
to address issues raised by the Office of the Attorney General of the State of
Arkansas. The study 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
and did not recommend any changes to the rates currently in effect.
The Company is subject to continuing reviews of its gas supply costs by the
APSC and the MPSC and currently has open issues with the MPSC. However, the
Company believes that none of these issues will have a material adverse effect
on the Company's financial condition or results of operations.
AWG also purchases gas from unaffiliated producers under take-or-pay
contracts. The Company believes that it does not have a significant exposure to
liabilities resulting from these contracts and expects to be able to continue to
satisfactorily manage its exposure to take-or-pay liabilities.
Operating Costs and Expenses
The Company's operating costs and expenses, exclusive of gas purchases by
the Company's utility and marketing segments and the non-cash write-down of oil
and gas properties in 1998, decreased by 8% in 1999 and increased by 1%
30
in 1998. The decrease in 1999 was primarily due to a 6% decrease in operating
and general costs and an 11% decrease in depreciation, depletion and
amortization (DD&A) expense. The comparative decrease in operating and general
expenses was due primarily to costs recorded in 1998 for severance related costs
and other costs associated with the closing of the Company's Oklahoma City
exploration and production office, and to decreased oil and gas production. DD&A
expense also decreased due to the decline in production. In 1998, a 5% increase
in operating and general expenses due to inflationary increases and the
severance costs discussed above was largely offset by a decrease in DD&A
expense. The decrease in DD&A expense resulted primarily from a decline in
volumes produced and a second quarter write-down of oil and gas properties which
lowered the net cost basis of that segment's depreciable assets and the
amortization rate per unit of production.
The Company follows the full cost method of accounting for the exploration,
development, and acquisition of oil and gas properties. DD&A is calculated using
the units-of-production method. The Company's annual gas and oil production, as
well as the amount of proved reserves owned by the Company and the costs
associated with adding those reserves, are all components of the amortization
calculation. The DD&A rate in 1999 averaged $1.00 per Mcfe, compared to $1.04
per Mcfe in 1998 and $1.06 per Mcfe in 1997. The overall decreases in the
Company's average amortization rate were caused by the mid-year 1998 write-down
of the Company's oil and gas properties to the full cost ceiling limitation. The
Company evaluates its full cost ceiling position at the end of each quarter.
Market prices, production rates, levels of reserves, and the evaluation of costs
excluded from amortization all influence the calculation of the full cost
ceiling. A decline in oil and gas prices from year-end 1999 levels or other
factors, without other mitigating circumstances, could cause an additional
future write-down of capitalized costs and a non-cash charge against future
earnings.
Gas purchased for resale by the Company's marketing segment increased to
$92.9 million in 1999, compared to $73.2 million in 1998 and $63.1 million in
1997, due to an increase in volumes marketed. Changes in purchased gas costs for
the gas distribution segment are caused by changes in requirements for gas
sales, the price and mix of gas purchased, and the timing of recoveries of
deferred purchased gas costs.
Inflation impacts the Company by generally increasing its operating costs
and the costs of its capital additions. The effects of inflation on the
Company's operations in recent years have been minimal due to low inflation
rates. However, during late 1999 and continuing into 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 increased. Additionally, delays inherent in the rate-making
process prevent the Company from obtaining immediate recovery of increased
operating costs of its gas distribution segment.
Other Costs and Expenses
Interest costs, net of capitalization, were up 1% in 1999 and 5% in 1998,
both as compared to prior years. The increases in both 1999 and 1998 were
primarily due to the lower level of capitalized interest related to the
Company's oil and gas properties. Interest capitalized decreased 15% in 1999 and
13% in 1998. The changes in capitalized interest are due primarily to the change
in the level of costs excluded from amortization in the exploration and
production segment.
31
The changes in other income in 1999, 1998, and 1997 relate primarily to
changes in the Company's share of operating losses incurred by NOARK, as
discussed above. Additionally, in 1999 and 1998 the Company recorded certain
costs related to a judgment bond that the Company was required to post after
receiving an adverse verdict in October 1998. See Note 11 of the financial
statements and Part I, Item 3, "Legal Proceedings," of this Form 10-K for
additional information regarding the class action lawsuit.
The previously discussed second quarter 1998 write-down of the Company's
oil and gas properties resulted in a deferred tax benefit of $25.9 million.
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 leasehold and seismic 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.
YEAR 2000
The Company has not experienced any material negative effects in its
results of operation or financial condition related to year 2000. The Company is
continuing to monitor its systems and the activities of third parties for year
2000 irregularities, however no material problems have been encountered to date.
There have been no material changes in the costs previously disclosed to address
the Company's year 2000 compliance effort.
LIQUIDITY AND CAPITAL RESOURCES
The Company continues to depend principally on internally generated funds
as its major source of liquidity. However, the Company has sufficient ability to
borrow additional funds to meet its short-term seasonal needs for cash, to
finance a portion of its routine spending, if necessary, or to finance other
extraordinary investment opportunities which might arise. In 1999, 1998, and
1997, net cash provided from operating activities totaled $58.1 million, $93.7
million, and $79.5 million, respectively. The primary components of cash
generated from operations are net income, depreciation, depletion and
amortization, write-down of oil and gas properties and the provision for
deferred income taxes. Net cash from operating activities provided 89% of the
Company's capital requirements for routine capital expenditures, cash dividends,
and scheduled debt retirements in 1999, 125% in 1998, and 79% in 1997.
Capital Expenditures
Capital expenditures totaled $67.0 million in 1999, $64.4 million in 1998,
and $88.8 million in 1997. The Company's exploration and production segment
expenditures included acquisitions of oil and gas producing properties totaling
$9.4 million in 1999. The Company made no producing property acquisitions in
1998 or 1997.
1999 1998 1997
-----------------------------
(in thousands)
Capital Expenditures
Exploration and production $59,004 $52,376 $73,526
Gas distribution 7,124 10,108 12,561
Other 839 1,875 2,734
- --------------------------------------------------------------------------------
$66,967 $64,359 $88,821
================================================================================
32
Capital investments planned for 2000 total $62.7 million, consisting of
$55.4 million for exploration and production, $6.8 million for gas distribution
system expenditures, and $.5 million for general purposes.
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital 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.
Financing Requirements
At year-end 1999, Southwestern's total debt was $302.2 million, including
$7.5 million classified as short-term debt. This compares to year-end 1998 total
debt of $283.4 million. Revolving credit facilities with two banks provide the
Company access to $80.0 million of variable rate capital, including two floating
rate facilities that provide the Company access to $60.0 million of long-term
capital and another facility that provides the Company access to $20.0 million
of short-term capital. Borrowings outstanding under the long-term credit
facilities totaled $47.7 million at the end of 1999 and $34.9 million at the end
of 1998. Borrowings under the short-term facility were $7.5 million at December
31, 1999. There were no short-term borrowings at December 31, 1998.
In 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes due
2027 and $40.0 million of 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's public notes are rated BBB+ by Standard and Poor's and Baa2 by
Moody's.
The Company remains confident that it will prevail in its appeal of the
royalty owners proceeding described in Part I, Item 3, "Legal Proceedings," of
this Form 10-K. However, the agreement under which unsecured letters of credit
have been provided to collateralize the appeal bond would require the Company to
reimburse its lenders for the full amount drawn under the letters of credit if
it were to lose the appeal. Under these circumstances the Company's ability to
borrow money would be restricted and existing financing agreements could be
impacted through cross default provisions.
In connection with the Enogex transaction in 1998 discussed above under
"NOARK Pipeline," the Company and a previous general partner converted certain
of their loans to the NOARK partnership, plus accrued interest, into equity, and
contributed approximately $10.7 million to the partnership to fund costs
incurred in connection with the prepayment of NOARK's 9.74% Senior Secured
notes. The Company's share of the contribution was $6.5 million and is the
primary reason for the increase in investments during 1998. 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 which began in December
1998. 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%. The Company advanced $2.3 million to
NOARK to fund its share of debt service payments in 1999 and advanced $2.2
million in 1998.
Under its existing debt agreements, the Company may not issue long-term
debt in excess of 65% of its total capital and may not issue total debt in
excess of 70% of its total capital. To issue additional long-term debt, the
Company must also have, after giving effect to the debt to be issued, a ratio of
earnings to fixed charges of at least 1.5 or higher (for any
33
period of 12 consecutive months within the preceding 24 months). At the end of
1999, the capital structure consisted of 61.4% debt (including short-term debt
but excluding the Company's several guarantee of NOARK's obligations) and 38.6%
equity, with a ratio of earnings to fixed charges of 1.6. Over the long term,
the Company expects to lower the debt portion of its capital structure by
limiting its routine capital spending. In 2000 the proceeds from the sale of the
Company's Missouri gas distribution assets, as discussed above under "Gas
Distribution," will be used to pay down outstanding debt.
Working Capital
The Company maintains access to funds which may be needed to meet seasonal
requirements through the revolving lines of credit explained above. The Company
had net working capital of $13.9 million at the end of 1999, compared to $17.5
million at the end of 1998. Current assets decreased by 3% to $70.2 million in
1999, while current liabilities increased 3% to $56.3 million. The decrease in
current assets at December 31, 1999, was due primarily to decreases in gas
inventory in underground storage and prepaid expenses. The increase in current
liabilities resulted from an increase in short-term debt partially offset by a
decrease in accounts payable due to the timing of payments made.
FORWARD-LOOKING INFORMATION
All statements, other than historical financial information, included in
this discussion and analysis of financial condition and results of operations
may be deemed to be forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, 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, the effects of weather and regulation on the
Company's gas distribution segment, increased competition, legal and economic
factors, 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
changes in commodity prices and interest rates, as well as credit risk
concentrations. The Company uses natural gas and crude oil swap agreements and
options to reduce the volatility of earnings and cash flow due to fluctuations
in the prices of natural gas and oil. The Board of Directors has approved risk
management policies and procedures to utilize financial products for the
reduction of defined commodity price risks. These policies prohibit speculation
with derivatives and limit swap agreements to counterparties with acceptable
credit standings.
Credit Risks
The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of trade receivables and derivative contracts
associated with commodities trading. Concentrations of credit risk with respect
to receivables are limited due to the large number of customers and their
dispersion across geographic areas. No single customer accounts for greater than
5% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
34
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, 1999 for borrowings
under the Company's revolving credit facilities. 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. There were no interest rate swaps outstanding at December 31, 1999.
Expected Maturity Date Fair Value
----------------------------------------------------------- ----------
2000 2001 2002 2003 2004 Thereafter Total 12/31/99
----------------------------------------------------------- ----------
($ in millions)
Fixed Rate - $2.0 $2.0 $2.0 $2.0 $239.0 $247.0 $234.0
Average Interest Rate - 9.36% 9.36% 9.36% 9.36% 7.17% 7.25%
Variable Rate $7.5 $30.0 $17.7 - - - $55.2 $55.2
Average Interest Rate 6.45% 6.02% 6.45% - - - 6.22%
Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production and marketing activity against
the inherent price risks of adverse price fluctuations or locational pricing
differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps include (1) transactions in which one
party will pay a fixed price (or variable price) for a notional quantity in
exchange for receiving a variable price (or fixed price) based on a published
index (referred to as price swaps), and (2) transactions in which parties agree
to pay a price based on two different indices (referred to as basis swaps).
The primary market risk related to these derivative contracts is the
volatility in market prices for natural gas and crude oil. However, this market
risk is offset by the gain or loss recognized upon the related sale of the
natural gas or oil that is hedged. Credit risk relates to the risk of loss as a
result of non-performance by the Company's counterparties. The counterparties
are 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) or 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 are calculated as the contractual payments for the quantity of gas or
oil to be exchanged under futures contracts and do not represent amounts
recorded in the Company's financial statements. The
35
"Fair Value" represents values for the same contracts using comparable market
prices at December 31, 1999. At December 31, 1999, the "Carrying Amount" of
these financial instruments exceeded the "Fair Value" by $.4 million.
Expected Maturity Date
-----------------------------------------------------------
2000 2001 2002
-----------------------------------------------------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-----------------------------------------------------------
Natural Gas
Swaps with a fixed price receipt
Contract volume (Bcf) 15.6 .7 .5
Weighted average price per Mcf $2.34 $2.57 $2.57
Contract amount (in millions) $36.6 $35.9 $1.7 $1.8 $1.2 $1.2
Swaps with a fixed price payment
Contract volume (Bcf) .2 - -
Weighted average price per Mcf $2.68 - -
Contract amount (in millions) $.7 $.6 - - - -
Basis swaps
Contract volume (Bcf) .1 - -
Weighted average basis difference
per Mcf $.11 - -
Contract amount (in millions) - - - - - -
Oil
Price floor
Contract volume (MBbls) 350(1) 325 -
Weighted average price per Bbl $18.00 $18.00 -
Contract amount (in millions) $6.3 $6.5 $5.9 $6.4 - -
Swaps with a fixed price receipt
Contract volume (MBbls) 96 72 -
Weighted average price per Bbl $18.87 $17.49 -
Contract amount (in millions) $1.8 $1.5 $1.3 $1.2 - -
<FN>
(1) Subsequent to December 31, 1999, the Company offset its position relating to
the $18.00 per barrel floor on a notional amount of 320,837 barrels covering
eleven months of 2000 production and replaced the floor with a crude oil swap to
receive a fixed price of $24.02 per barrel.
</FN>
36
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Reports of Management and Independent Public Accountants 38
Consolidated Statements of Income for the years ended December 31, 1999, 1998, and 1997 39
Consolidated Balance Sheets as of December 31, 1999 and 1998 40
Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998, and 1997 41
Consolidated Statements of Retained Earnings for the years ended December 31, 1999, 1998, and 1997 41
Notes to Consolidated Financial Statements, December 31, 1999, 1998, and 1997 42
37
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 auditors, Arthur Andersen LLP. In accordance with auditing standards
generally accepted in the United States, the independent auditors obtained a
sufficient understanding of the Company's internal controls to plan their audit
and determine the nature, timing, and extent of other tests to be performed.
The Audit Committee of the Board of Directors, composed solely of outside
directors, meets with management, internal auditors, and Arthur Andersen LLP to
review planned audit scopes and results and to discuss other matters affecting
internal accounting controls and financial reporting. The independent auditors
have direct access to the Audit Committee and periodically meet with it without
management representatives present.
Report of Independent Public Accountants
To the Board of Directors and Shareholders of Southwestern Energy Company:
We have audited the consolidated balance sheets of SOUTHWESTERN ENERGY
COMPANY (an Arkansas corporation) AND SUBSIDIARIES as of December 31, 1999 and
1998, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1999.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwestern Energy Company
and Subsidiaries as of December 31, 1999 and 1998, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 4, 2000
38
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1999 1998 1997
- --------------------------------------------------------------------------------------
(in thousands, except per share amounts)
Operating Revenues
Gas sales $165,898 $172,790 $190,298
Gas marketing 96,570 76,367 65,435
Oil sales 9,891 9,557 14,258
Gas transportation and other 8,037 7,591 6,198
- --------------------------------------------------------------------------------------
280,396 266,305 276,189
- --------------------------------------------------------------------------------------
Operating Costs and Expenses
Gas purchases - utility 45,370 39,863 46,806
Gas purchases - marketing 92,851 73,235 63,054
Operating and general 57,957 61,915 59,167
Depreciation, depletion and amortization 41,603 46,917 48,208
Write-down of oil and gas properties - 66,383 -
Taxes, other than income taxes 6,557 6,943 7,018
- --------------------------------------------------------------------------------------
244,338 295,256 224,253
- --------------------------------------------------------------------------------------
Operating Income (Loss) 36,058 (28,951) 51,936
- --------------------------------------------------------------------------------------
Interest Expense
Interest on long-term debt 19,735 19,600 19,818
Other interest charges 923 1,470 1,083
Interest capitalized (3,307) (3,884) (4,487)
- --------------------------------------------------------------------------------------
17,351 17,186 16,414
- --------------------------------------------------------------------------------------
Other Income (Expense) (2,331) (3,956) (5,017)
- --------------------------------------------------------------------------------------
Income (Loss) Before Provision (Benefit)
for Income Taxes 16,376 (50,093) 30,505
- --------------------------------------------------------------------------------------
Provision (Benefit) for Income Taxes
Current 537 (6,029) (732)
Deferred 5,912 (13,467) 12,522
- --------------------------------------------------------------------------------------
6,449 (19,496) 11,790
- --------------------------------------------------------------------------------------
Net Income (Loss) $ 9,927 $(30,597) $ 18,715
======================================================================================
Basic Earnings (Loss) Per Share $.40 $(1.23) $.76
======================================================================================
Weighted Average Common Shares Outstanding 24,941,550 24,882,170 24,738,882
======================================================================================
Diluted Earnings (Loss) Per Share $.40 $(1.23) $.76
======================================================================================
Diluted Weighted Average Common Shares
Outstanding 24,947,021 24,882,170 24,777,906
======================================================================================
The accompanying notes are an integral part of the financial statements
39
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 1999 1998
- --------------------------------------------------------------------------------
(in thousands)
Assets
Current Assets
Cash $ 1,240 $ 1,622
Accounts receivable 43,339 40,655
Inventories, at average cost 21,520 22,812
Other 4,073 7,182
- --------------------------------------------------------------------------------
Total current assets 70,172 72,271
- --------------------------------------------------------------------------------
Investments 14,180 14,015
- --------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method,
including $37,554,000 in 1999 and $53,110,000 in
1998 excluded from amortization 816,199 758,863
Gas distribution systems 222,145 217,680
Gas in underground storage 28,712 24,279
Other 28,826 27,643
- --------------------------------------------------------------------------------
1,095,882 1,028,465
Less: Accumulated depreciation, depletion and
amortization 519,927 478,790
- --------------------------------------------------------------------------------
575,955 549,675
- --------------------------------------------------------------------------------
Other Assets 11,139 11,659
- --------------------------------------------------------------------------------
$ 671,446 $ 647,620
================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Short-term debt $ 7,500 $ 1,536
Accounts payable 33,069 37,780
Taxes payable 3,506 3,408
Interest payable 2,483 2,471
Customer deposits 6,021 5,635
Other 3,767 3,956
- --------------------------------------------------------------------------------
Total current liabilities 56,346 54,786
- --------------------------------------------------------------------------------
Long-Term Debt, less current portion 294,700 281,900
- --------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 126,902 121,413
Other 3,142 3,665
- --------------------------------------------------------------------------------
130,044 125,078
- --------------------------------------------------------------------------------
Commitments and Contingencies
- --------------------------------------------------------------------------------
Shareholders' Equity
Common stock, $.10 par value; authorized
75,000,000 shares, issued 27,738,084 shares 2,774 2,774
Additional paid-in capital 20,732 21,249
Retained earnings, per accompanying statements 198,044 194,102
- --------------------------------------------------------------------------------
221,550 218,125
Less: Common stock in treasury, at cost, 2,700,391
shares in 1999 and 2,803,527 shares in 1998 30,083 31,248
Unamortized cost of restricted shares issued
under stock incentive plan, 188,781 shares
in 1999 and 133,172 shares in 1998 1,111 1,021
- --------------------------------------------------------------------------------
190,356 185,856
- --------------------------------------------------------------------------------
$ 671,446 $ 647,620
================================================================================
The accompanying notes are an integral part of the financial statements.
40
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income (loss) $ 9,927 $(30,597) $ 18,715
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 42,971 48,267 49,271
Write-down of oil and gas properties - 66,383 -
Deferred income taxes 5,912 (13,467) 12,522
Equity in loss of partnership 2,008 3,087 4,523
Change in assets and liabilities:
(Increase) decrease in accounts receivable (2,684) 5,097 (5,824)
Decrease in income taxes receivable 1,658 1,066 3,549
(Increase) decrease in under-recovered
purchased gas costs (273) 10,931 (6,398)
(Increase) decrease in inventories 1,292 (2,347) (2,894)
Increase (decrease) in accounts payable (4,711) 7,877 4,259
Net change in other current assets and
liabilities 2,031 (2,589) 1,760
- ----------------------------------------------------------------------------------------
Net cash provided by operating activities 58,131 93,708 79,483
- ----------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (66,967) (64,359) (88,821)
Investment in partnership (2,273) (10,062) (4,962)
(Increase) decrease in gas stored underground (4,433) (531) 1,888
Other items 2,380 340 1,048
- ----------------------------------------------------------------------------------------
Net cash used in investing activities (71,293) (74,612) (90,847)
- ----------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt 12,800 (11,500) (50,100)
Proceeds from revolving short-term debt 7,500 - -
Proceeds from issuance of long-term debt - - 98,348
Payments on other long-term debt (1,535) (4,607) (28,643)
Dividends paid (5,985) (5,970) (5,935)
- ----------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 12,780 (22,077) 13,670
- ----------------------------------------------------------------------------------------
Increase (decrease) in cash (382) (2,981) 2,306
Cash at beginning of year 1,622 4,603 2,297
- ----------------------------------------------------------------------------------------
Cash at end of year $ 1,240 $ 1,622 $ 4,603
========================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1999 1998 1997
- ----------------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $194,102 $230,669 $217,889
Net income (loss) 9,927 (30,597) 18,715
Cash dividends declared ($.24 per share) (5,985) (5,970) (5,935)
- ----------------------------------------------------------------------------------------
Retained Earnings, end of year $198,044 $194,102 $230,669
========================================================================================
The accompanying notes are an integral part of the financial statements.
41
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 1999, 1998, and 1997
(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, New Mexico, Texas, Oklahoma, Louisiana, and the Gulf Coast (primarily
onshore). The gas distribution segment operates in northern Arkansas and parts
of Missouri, and under normal weather conditions obtains 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.
In late 1999, the Company entered into a definitive agreement to sell its
Missouri gas distribution assets for $32.0 million. The Company's basis in these
assets is approximately $28.0 million. The sale requires regulatory approval and
is expected to close in the first half of 2000. The Company currently serves
approximately 48,000 customers in Missouri. Proceeds from the sale of the
Missouri assets will be used to reduce the Company's outstanding debt. The
Company does not expect a material impact on its continuing results of
operations due to this sale as interest savings from the reduction in debt are
expected to generally offset the reduction in net income.
The consolidated financial statements include the accounts of Southwestern
Energy Company and its wholly-owned subsidiaries, Southwestern Energy Production
Company, SEECO, Inc., Arkansas Western Gas Company, Southwestern Energy Services
Company, Diamond "M" Production Company, Southwestern Energy Pipeline Company,
A.W. Realty Company, and Arkansas Western Pipeline Company. All significant
intercompany accounts and transactions have been eliminated. The Company
accounts for its general partnership interest in the NOARK Pipeline System,
Limited Partnership (NOARK) using the equity method of accounting. In accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation," the Company recognizes profit on
intercompany sales of gas delivered to storage by its utility subsidiary.
Certain reclassifications have been made to the prior years' financial
statements to conform with the 1999 presentation. These reclassifications had no
effect on previously recorded net income.
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.
42
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 June 30, 1998, the Company recognized
a $40.5 million non-cash charge to earnings by recording a write-down of its oil
and gas properties of $66.4 million and a related reduction in the provision for
deferred income taxes of $25.9 million. At December 31, 1999, 1998, and 1997,
the Company's net book value of oil and gas properties did not exceed the
ceiling amounts. Market prices, production rates, levels of reserves, and the
evaluation of costs excluded from amortization all influence the calculation of
the full cost ceiling. A decline in oil and gas prices from year-end 1999 levels
or other factors, without other mitigating circumstances, could cause an
additional future write-down of capitalized costs and a noncash charge to
earnings.
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 1.8% to 6.0%. 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 gas distribution customers
represent a diversified base of residential, commercial, and industrial users.
Approximately 112,000 of these customers are served in northwest Arkansas and
approximately 69,000 are served in northeast Arkansas and Missouri. The Company
records gas distribution revenues on an accrual basis, as gas volumes are used,
to provide a proper matching of revenues with expenses.
43
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 for the Company's Arkansas systems include a weather
normalization clause to lessen the impact of revenue increases and decreases
which might result from weather variations during the winter heating season. The
pass-through of gas costs to customers is not affected by this normalization
clause.
Gas Production Imbalances
The exploration and production subsidiaries record gas sales using the
entitlement method. The entitlement method requires revenue recognition of the
Company's revenue interest share of gas production from properties in which gas
sales are disproportionately allocated to owners because of marketing or other
contractual arrangements. The Company's net imbalance position at December 31,
1999 and 1998 was not significant.
Income Taxes
Deferred income taxes are provided to recognize the income tax effect of
reporting certain transactions in different years for income tax and financial
reporting purposes.
Risk Management
The Company has limited involvement with derivative financial instruments
and does not use them for trading purposes. They are used to manage defined
commodity price risks. The Company uses commodity swap agreements and options to
hedge sales of natural gas and crude oil. Gains and losses resulting from
hedging activities are recognized when the related physical transactions are
recognized. Gains or losses from commodity swap agreements and options that do
not qualify for accounting treatment as hedges are recognized currently as other
income or expense. See Note 8 for a discussion of the Company's commodity
hedging activity.
Earnings Per Share and Shareholders' Equity
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 1,275,899 shares of common stock with a weighted average exercise
price of $12.97 per share at December 31, 1999, and options for 951,047 shares
with an average exercise price of $14.61 at December 31, 1997, that were not
included in the calculation of diluted shares because they would have had an
anti-dilutive effect. There were options for 1,634,901 shares with a weighted
average exercise price of $12.15 outstanding at December 31, 1998. Due to the
Company's net loss for 1998 any incremental shares would have an anti-dilutive
effect and were, therefore, not considered.
During 1999 and 1998, the Company issued 105,436 and 105,488 treasury
shares, respectively, under a compensatory plan and for stock awards and
returned to treasury 2,300 and 4,496 shares, respectively, canceled from earlier
issues under the compensatory plan. The net effect of these transactions was a
$1.2 million decrease in 1999 and a $1.1 million decrease in 1998 in treasury
stock.
44
(2) DEBT
Debt balances as of December 31, 1999 and 1998 consisted of the following:
1999 1998
--------------------
(in thousands)
Senior Notes
8.86% Series $ - $ 1,536
9.36% Series due in annual installments of $2.0
million beginning 2001 22,000 22,000
6.70% Series due 2005 125,000 125,000
7.625% Series due 2027, putable at the holders'
option in 2009 60,000 60,000
7.21% Series due 2017 40,000 40,000
- --------------------------------------------------------------------------------
247,000 248,536
Other
Variable rate (6.18% at December 31, 1999) unsecured
revolving credit arrangements 47,700 34,900
- --------------------------------------------------------------------------------
Total long-term debt 294,700 283,436
Less: Current portion of long-term debt - 1,536
- --------------------------------------------------------------------------------
Long-term debt $294,700 $281,900
================================================================================
Short-term note payable $ 7,500 $ -
================================================================================
The Company has several prepayment options under the terms of certain of
its Senior Notes. Prepayments made without premium are subject to certain
limitations. Other prepayment options involve the payment of premiums based in
some instances on market interest rates at the time of prepayment.
Revolving credit facilities with two banks provide the Company access to
$80.0 million of variable rate capital. Of this amount, long-term variable rate
credit facilities provide the Company access to $60.0 million of revolving
credit. Borrowings outstanding under these long-term credit facilities totaled
$47.7 million at December 31, 1999. The Company also has a short-term variable
rate credit facility which provides the Company access to $20.0 million of
revolving credit. Borrowings outstanding under this credit facility were $7.5
million at December 31, 1999, all of which were classified as short-term debt.
Each facility allows the Company four interest rate options - the floating prime
rate, a fixed rate tied to either short-term certificate of deposit or
Eurodollar rates, or a fixed rate based on the lenders' cost of funds. The
short-term revolving credit facility expires in 2000 and the long-term revolving
credit facilities expire in 2001 and 2002. The Company intends to renew or
replace the facilities prior to expiration.
The terms of the debt instruments and agreements contain covenants which
impose certain restrictions on the Company, including limitation of additional
indebtedness and restrictions on the payment of cash dividends. At December 31,
1999, approximately $96.4 million of retained earnings was available for payment
as dividends.
Aggregate maturities of long-term debt for each of the years ending
December 31, 2000 through 2004, are $0, $32.0 million, $19.7 million, $2.0
million, and $2.0 million. Total interest payments were $19.6 million in 1999
and 1998, and $18.8 million in 1997.
45
(3) INCOME TAXES
The provision (benefit) for income taxes included the following components:
1999 1998 1997
------------------------------
(in thousands)
Federal:
Current $ - $ (6,673) $(1,614)
Deferred 5,236 (10,098) 11,422
State:
Current 537 644 882
Deferred 795 (3,250) 1,219
Investment tax credit amortization (119) (119) (119)
- --------------------------------------------------------------------------------
Provision (benefit) for income taxes $6,449 $(19,496) $11,790
================================================================================
The provision (benefit) for income taxes was an effective rate of 39.4% in
1999, 38.9% in 1998, and 38.6% in 1997. The following reconciles the provision
(benefit) for income taxes included in the consolidated statements of income
with the provision (benefit) which would result from application of the
statutory federal tax rate to pretax financial income:
1999 1998 1997
------------------------------
(in thousands)
Expected provision (benefit) at federal
statutory rate of 35% $5,732 $(17,532) $10,677
Increase (decrease) resulting from:
State income taxes, net of federal
income tax effect 866 (1,694) 1,365
Other (149) (270) (252)
- --------------------------------------------------------------------------------
Provision (benefit) for income taxes $6,449 $(19,496) $11,790
================================================================================
The components of the Company's net deferred tax liability as of December
31, 1999 and 1998 were as follows:
1999 1998
--------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $123,516 $109,538
Stored gas 8,267 7,583
Deferred purchased gas costs 2,289 1,997
Prepaid pension costs 2,086 2,036
Book over tax basis in partnerships 10,133 8,647
Other 415 1,091
- --------------------------------------------------------------------------------
146,706 130,892
- --------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 705 647
Alternative minimum tax credit carryforward 3,127 3,034
Net operating loss carryforward 16,808 6,949
Other 1,155 1,234
- --------------------------------------------------------------------------------
21,795 11,864
- --------------------------------------------------------------------------------
Net deferred tax liability $124,911 $119,028
================================================================================
46
Total income tax payments of $.6 million, $3.3 million, and $4.2 million
were made in 1999, 1998, and 1997, respectively.
(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
The Company applies SFAS No. 132, "Employers' Disclosures about Pensions
and Other Postretirement Benefits." Substantially all employees are covered by
the Company's defined benefit pension and postretirement benefit plans. The
following provides a reconciliation of the changes in the plans' benefit
obligations, fair value of assets, and funded status as of December 31, 1999 and
1998:
Other Postretirement
Pension Benefits Benefits
--------------------------------------------
1999 1998 1999 1998
--------------------------------------------
(in thousands)
Change in Benefit Obligations:
Benefit obligation at January 1 $59,194 $47,257 $ 3,832 $ 3,067
Service cost 1,881 2,060 99 87
Interest cost 4,130 3,644 261 242
Amendments 5,560 - - -
Actuarial loss (gain) (5,359) 7,920 (255) 616
Benefits paid (3,891) (1,687) (178) (180)
- ------------------------------------------------------------------------------------------
Benefit obligation at December 31 $61,515 $59,194 $ 3,759 $ 3,832
==========================================================================================
Change in Plan Assets:
Fair value of plan assets at January 1 $71,518 $65,966 $ 345 $ -
Actual return on plan assets 2,838 7,168 20 (12)
Employer contributions - - 428 537
Benefit payments (3,878) (1,616) (178) (180)
- ------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $70,478 $71,518 $ 615 $ 345
==========================================================================================
Funded Status:
Funded status at December 31 $ 8,963 $12,324 $(3,144) $(3,487)
Unrecognized net actuarial (gain) loss (9,237) (7,441) 926 1,284
Unrecognized prior service cost 5,417 308 - -
Unrecognized transition obligation (220) (403) 1,265 1,368
- ------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $ 4,923 $ 4,788 $ (953) $ (835)
==========================================================================================
The benefit obligation and fair value of plan assets at December 31, 1999
include $5.5 million to $6.0 million related to employees of the Company's
Missouri gas distribution segment that will be transferred in 2000 upon closing
the sale of the Company's Missouri gas distribution assets.
The Company's supplemental retirement plan has an accumulated benefit
obligation in excess of plan assets. The plan's accumulated benefit obligation
was $233,000 and $198,000 at December 31, 1999 and 1998, respectively. There are
no plan assets in the supplemental retirement plan due to the nature of the
plan.
47
Net periodic pension and other postretirement benefit costs include the
following components for 1999, 1998, and 1997:
Other Postretirement
Pension Benefits Benefits
-------------------------------------------------------------
1999 1998 1997 1999 1998 1997
-------------------------------------------------------------
(in thousands)
Service cost $ 1,881 $ 2,060 $ 1,744 $ 99 $ 87 $ 90
Interest cost 4,130 3,644 3,213 261 242 213
Expected return on plan assets (6,259) (5,863) (5,007) (28) - -
Amortization of transition obligation (183) (183) (183) 103 103 103
Recognized net actuarial (gain) loss (142) (150) (211) 111 55 40
Amortization of prior service costs 451 46 49 - - -
- -------------------------------------------------------------------------------------------------------
$ (122) $ (446) $ (395) $546 $487 $446
=======================================================================================================
Prior to 1998, the Company's pension plans provided for benefits based on
years of benefit service and the employee's "average compensation" as defined.
During 1998, the Company amended its plans to become "cash balance" plans on a
prospective 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.
During 1998, the Company established trusts to partially fund its postretirement
benefit obligations.
The weighted average assumptions used in the measurement of the Company's
benefit obligations for 1999 and 1998 are as follows:
Other Postretirement
Pension Benefits Benefits
-------------------------------------------------
1999 1998 1999 1998
-------------------------------------------------
Discount rate 7.50% 6.75% 7.50% 6.75%
Expected return on plan assets 9.00% 9.00% 5.00% 5.00%
Rate of compensation increase 4.50% 5.00% n/a n/a
=====================================================================================
For measurement purposes a 9% annual rate of increase in the per capita
cost of covered medical benefits and an 8% annual rate of increase in the per
capita cost of dental benefits was assumed for 2000. 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.
48
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% Increase 1% Decrease
--------------------------
(in thousands)
Effect on the total service and interest
cost components $ 46 $ (39)
Effect on postretirement benefit obligation $400 $(344)
================================================================================
(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:
1999 1998 1997
-------------------------------
(in thousands)
Sales $ 75,039 $ 86,232 $100,129
Production (lifting) costs (14,039) (15,807) (17,155)
Depreciation, depletion and amortization (34,230) (39,444) (40,777)
Write-down of oil and gas properties - (66,383) -
- --------------------------------------------------------------------------------
26,770 (35,402) 42,197
Income tax benefit (expense) (10,528) 13,913 (16,161)
- --------------------------------------------------------------------------------
Results of operations $ 16,242 $(21,489) $ 26,036
================================================================================
The results of operations shown above exclude overhead and interest costs.
Income tax expense is calculated by applying the statutory tax rates to the
revenues less costs, including depreciation, depletion and amortization, and
after giving effect to permanent differences and tax credits.
The table below sets forth capitalized costs incurred in gas and oil
property acquisition, exploration, and development activities during 1999, 1998,
and 1997:
1999 1998 1997
-----------------------------
(in thousands)
Property acquisition costs $19,845 $12,729 $10,911
Exploration costs 19,519 14,273 33,225
Development costs 19,059 24,709 28,825
- --------------------------------------------------------------------------------
Capitalized costs incurred $58,423 $51,711 $72,961
================================================================================
Amortization per Mcf equivalent $1.004 $1.039 $1.057
================================================================================
Capitalized interest is included as part of the cost of oil and gas
properties. The Company capitalized $3.3 million, $3.9 million, and $4.5 million
during 1999, 1998, and 1997, 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 $7.4 million, $7.7 million, and $6.0 million during 1999, 1998, and
1997, 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.
49
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 1999 and 1998:
1999 1998
-------------------
(in thousands)
Proved properties $774,473 $703,669
Unproved properties 41,726 55,194
- --------------------------------------------------------------------------------
Total capitalized costs 816,199 758,863
Less: Accumulated depreciation, depletion and amortization 419,517 386,384
- --------------------------------------------------------------------------------
Net capitalized costs $396,682 $372,479
================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1999. Included in these costs is
$13.2 million related to 3-D seismic projects in south Louisiana. These costs
and subsequent costs to be incurred will be evaluated over several years as the
seismic data is interpreted and the acreage is explored. The remaining costs
excluded from amortization are related to properties which are not individually
significant and on which the evaluation process has not been completed. The
Company is, therefore, unable to estimate when these costs will be included in
the amortization computation.
1999 1998 1997 Prior Total
------------------------------------------------
(in thousands)
Property acquisition costs $ 5,814 $4,661 $1,454 $3,276 $15,205
Exploration costs 5,308 3,992 6,934 1,729 17,963
Capitalized interest 411 910 1,556 1,509 4,386
- --------------------------------------------------------------------------------
$11,533 $9,563 $9,944 $6,514 $37,554
================================================================================
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1999, 1998, and 1997:
1999 1998 1997
-----------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
-----------------------------------------------------------
Proved reserves, beginning of year 303,667 6,850 291,378 7,852 297,467 8,238
Revisions of previous estimates (7,464) 1,155 1,064 (696) 861 (51)
Extensions, discoveries, and other additions 34,730 225 44,814 442 26,430 426
Production (29,444) (578) (32,668) (703) (33,355) (749)
Acquisition of reserves in place 9,762 576 - - 76 -
Disposition of reserves in place (3,728) (369) (921) (45) (101) (12)
- ----------------------------------------------------------------------------------------------------------
Proved reserves, end of year 307,523 7,859 303,667 6,850 291,378 7,852
==========================================================================================================
Proved, developed reserves:
Beginning of year 258,092 6,370 252,393 7,312 255,234 7,804
End of year 250,290 7,154 258,092 6,370 252,393 7,312
==========================================================================================================
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, 1999, 1998, and 1997:
1999 1998 1997
-----------------------------------
(in thousands)
Future cash inflows $ 989,997 $ 820,522 $ 973,536
Future production and development costs (227,361) (176,130) (197,021)
Future income tax expense (247,408) (206,097) (261,173)
- -----------------------------------------------------------------------------------------------
Future net cash flows 515,228 438,295 515,342
10% annual discount for estimated timing of cash flows (253,153) (215,502) (256,279)
- -----------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 262,075 $ 222,793 $ 259,063
===============================================================================================
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
1999, 1998, and 1997:
1999 1998 1997
- ----------------------------------------------------------------------------------------
(in thousands)
Standardized measure, beginning of year $222,793 $259,063 $370,944
Sales and transfers of gas and oil produced, net of
production costs (61,000) (70,425) (82,975)
Net changes in prices and production costs 48,506 (71,400) (173,730)
Extensions, discoveries, and other additions, net of
future production and development costs 48,279 61,146 41,267
Acquisition of reserves in place 14,765 - 116
Revisions of previous quantity estimates (612) (3,024) 646
Accretion of discount 32,447 38,445 55,852
Net change in income taxes (17,015) 23,714 62,186
Changes in production rates (timing) and other (26,088) (14,726) (15,243)
- ----------------------------------------------------------------------------------------
Standardized measure, end of year $262,075 $222,793 $259,063
========================================================================================
51
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
At December 31, 1999, the Company held a 25% general partnership interest
in the NOARK Partnership. NOARK Pipeline was formerly a 258-mile long intrastate
gas transmission system which extended across northern Arkansas. In January
1998, the Company entered into an agreement with Enogex Inc. (Enogex) that
resulted in the expansion of the NOARK Pipeline and provided the pipeline with
access to Oklahoma gas supplies through an integration of NOARK with the Ozark
Gas Transmission System (Ozark). Enogex is a subsidiary of OGE Energy Corp.
Ozark was a 437-mile interstate pipeline system which began in eastern Oklahoma
and terminated in eastern Arkansas. Enogex acquired the Ozark system and
contributed it to the NOARK partnership. 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 $14.0 million at December 31,
1999 and $13.8 million at December 31, 1998. The Company's investment in NOARK
includes advances of $2.3 million made during 1999, $10.1 million made during
1998, and $5.0 million made during 1997. Advances in 1998 included the Company's
share of costs related to the prepayment of NOARK's Senior Secured Notes. Other
advances are made primarily to provide certain minimum cash balances 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.
NOARK's financial position at December 31, 1999 and 1998 is summarized
below:
1999 1998
--------------------
(in thousands)
Current assets $ 7,056 $ 9,535
Noncurrent assets 178,195 175,361
- --------------------------------------------------------------------------------
$185,251 $184,896
================================================================================
Current liabilities $ 10,413 $ 8,576
Long-term debt 75,000 77,000
Partners' capital 99,838 99,320
- --------------------------------------------------------------------------------
$185,251 $184,896
================================================================================
The Company's share of NOARK's pretax loss, before the effect of accrued
interest expense on general partner loans, was $2.0 million, $3.1 million, and
$4.5 million for 1999, 1998, and 1997, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
income.
NOARK's results of operations for 1999, 1998, and 1997 are summarized
below:
1999 1998 1997
-------------------------------
(in thousands)
Operating revenues $40,358 $17,445 $ 4,963
Pretax net loss $(3,564) $(4,114) $(8,850)
================================================================================
52
(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 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, 1999 and 1998 were as
follows:
1999 1998
----------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------------------------------------------
(in thousands)
Cash $1,240 $1,240 $1,622 $1,622
Customer deposits $6,021 $6,021 $5,635 $5,635
Short-term debt $7,500 $7,500 $1,536 $1,536
Long-term debt $294,700 $289,193 $281,900 $290,621
Commodity hedges $640 $(399) $1,276 $8,227
================================================================================
Derivatives and Price Risk Management
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the hedged
item in the income statement, and requires that a company must formally
document, designate, and assess the effectiveness of transactions that receive
hedge accounting.
In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133." SFAS No. 137 delayed the required implementation date of
SFAS No. 133 by one year. SFAS No. 133 is now effective for fiscal years
beginning after June 15, 2000. SFAS No. 133, as amended, must be applied to (a)
derivative instruments and (b) certain derivative instruments embedded in all
hybrid contracts or, at a company's option, only hybrid contracts that were
issued, acquired, or substantively modified after either January 1, 1998 or
January 1, 1999 (a company may elect either transition date).
The Company has not yet quantified the impacts of adopting SFAS No. 133 on
its financial statements, nor has it determined the method of adoption. However,
it should be noted that SFAS No. 133 could increase volatility in future
reported earnings and other comprehensive income.
The Company uses natural gas and crude oil swap agreements and options to
reduce the volatility of earnings and cash flow due to fluctuations in the
prices of natural gas and oil. The Board of Directors has approved risk
management
53
policies and procedures to utilize financial products for the reduction of
defined commodity price risks. These policies prohibit speculation with
derivatives and limit swap agreements to counterparties with appropriate credit
standings.
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production and marketing activity against
the inherent price risks of adverse price fluctuations or locational pricing
differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps include (1) transactions in which one
party will pay a fixed price (or variable price) for a notional quantity in
exchange for receiving a variable price (or fixed price) based on a published
index (referred to as price swaps), and (2) transactions in which parties agree
to pay a price based on two different indices (referred to as basis swaps).
At December 31, 1999, the Company had outstanding natural gas price swaps
on total notional volumes of 17.0 Bcf. Of the total, the Company will receive
fixed prices ranging from $2.13 to $2.87 per MMBtu on 16.8 Bcf. Under contracts
covering the remaining .2 Bcf, the Company will make average fixed price
payments of $2.68 per MMBtu and receive variable prices based on the NYMEX
futures market. At December 31, 1999, the Company held outstanding basis swaps
on a notional volume of .1 Bcf. At December 31, 1999, the Company also had
outstanding crude oil swaps to receive fixed prices of $18.87 per barrel in 2000
and $17.49 per barrel in 2001 on notional volumes of 96,000 barrels and 72,000
barrels, respectively. The Company's price risk management activities reduced
revenues $1.1 million in 1999, increased revenues $7.4 million in 1998, and
decreased revenues $2.7 million in 1997.
The Company uses options to fix a floor, a ceiling, or both a floor and
ceiling (a "collar") for prices on its production volumes. At December 31, 1999,
the Company had a crude oil price floor of $18.00 per barrel (based on the NYMEX
futures market) on total notional volumes of 675,000 barrels covering production
during calendar years 2000 through 2001. Subsequent to December 31, 1999 the
Company offset its position relating to the $18.00 per barrel floor on a
notional amount of 320,837 barrels covering eleven months of 2000 production and
replaced the floor with a crude oil swap to receive a fixed price of $24.02 per
barrel.
The primary market risk related to these derivative contracts is the
volatility in market prices for natural gas and crude oil. However, this market
risk is offset by the gain or loss recognized upon the related sale of the
natural gas or oil that is hedged. Credit risk relates to the risk of loss as a
result of non-performance by the Company's counterparties. The counterparties
are 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 1993 Stock Incentive Plan (1993 Plan)
provides for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan provides for grants of options, shares of
restricted stock, and stock bonuses that in the aggregate do not exceed
1,700,000 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 do not exceed 1,700,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The types of incentives which may
be awarded are comprehensive and are intended to enable the Board of Directors
to structure the most appropriate incentives and to address changes in income
tax laws which may be enacted over the term of the plan. The Company has also
awarded stock option grants outside the 1993 Plan to certain non-officer
employees and to certain officers at the time of their hire.
54
The Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors provides for annual stock option grants of 12,000 shares (with 12,000
limited SARs) to each non-employee director. Options may be awarded under the
plan on no more than 240,000 shares.
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 1999, 1998, and 1997 and provide information for
options outstanding at December 31, 1999:
1999 1998 1997
------------------------------------------------------------------
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 1,634,901 $12.15 1,619,114 $13.37 1,501,641 $13.39
Granted 562,250 $6.18 394,900 $8.00 433,248 $12.58
Exercised 1,333 $7.31 22,200 $5.58 56,850 $5.96
Canceled 134,619 $12.68 356,913 $13.48 258,925 $13.82
- --------------------------------------------------------------------------------------------------------
Options outstanding at December 31 2,061,199 $10.49 1,634,901 $12.15 1,619,114 $13.37
========================================================================================================
Options Outstanding Options Exercisable
----------------------------------------------------------------------
Weighted
Weighted Average 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 - $9.44 880,550 $6.59 9.5 110,758 $7.35
$10.06 - $13.38 636,934 $12.09 6.1 480,153 $12.14
$14.00 - $17.50 543,715 $14.95 5.4 393,048 $15.09
- -----------------------------------------------------------------------------------------------
2,061,199 $10.49 7.4 983,959 $12.78
===============================================================================================
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 six years from the date of grant or earlier if certain corporate
performance criteria are achieved.
The Company has granted 303,240 shares of restricted stock to employees
through 1999. Of this total, 260,690 shares vest over a three-year period and
the remaining shares vest over a five-year period. The related compensation
expense is being amortized over the vesting periods. As of December 31, 1999,
103,213 shares have vested to employees and 11,246 shares have been cancelled
and returned to treasury shares.
55
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:
1999 1998 1997
------------------------------
Net income (loss), in thousands
As reported $9,927 $(30,597) $18,715
Pro forma $9,241 $(31,201) $18,378
Basic earnings (loss) per share
As reported $.40 $(1.23) $.76
Pro forma $.37 $(1.25) $.74
Diluted earnings (loss) per share
As reported $.40 $(1.23) $.76
Pro forma $.37 $(1.25) $.74
================================================================================
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions: dividend yield of 2.3% to 4.0%; expected volatility of 37.0% to
39.0%; risk-free interest rate of 6.0% to 6.6%; and expected lives of 6 years.
(10) COMMON STOCK PURCHASE RIGHTS
In 1999, the Company's Common Share Purchase Rights Plan was amended and
extended for an additional ten years. Per the terms of the amended plan, one
common share purchase right is attached to each outstanding share of the
Company's common stock. Each right entitles the holder to purchase one share of
common stock at an exercise price of $40.00, subject to adjustment. These rights
will become exercisable in the event that a person or group acquires or
commences a tender or exchange offer for 15% or more of the Company's
outstanding shares or the Board determines that a holder of 10% or more of the
Company's outstanding shares presents a threat to the best interests of the
Company. At no time will these rights have any voting power.
If any person or entity actually acquires 15% of the common stock (10% or
more if the Board determines such acquiror is adverse), rightholders (other than
the 15% or 10% stockholder) will be entitled to buy, at the right's then current
exercise price, the Company's common stock with a market value of twice the
exercise price. Similarly, if the Company is acquired in a merger or other
business combination, each right will entitle its holder to purchase, at the
right's then current exercise price, a number of the surviving company's common
shares having a market value at that time of twice the right's exercise price.
The rights may be redeemed by the Board for $.01 per right or exchanged for
common shares on a one-for-one basis prior to the time that they become
exercisable. In the event, however, that redemption of the rights is considered
in connection with a proposed acquisition of the Company, the Board may redeem
the rights only on the recommendation
56
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, 1999 and
1998, the principal outstanding for these Notes was $77.0 million and $79.0
million, respectively. The Notes were issued in June 1998 and require
semi-annual principal payments of $1.0 million. The proceeds from the issuance
of the Notes were used to repay temporary financing provided by the other
general partner and outstanding amounts under an unsecured revolving credit
agreement. The temporary financing provided by the other general partner was
incurred in connection with the prepayment in early 1998 of NOARK's 9.74% Senior
Secured notes. 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 82.3 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.
In May 1996, a class action suit was filed against the Company on behalf of
royalty owners alleging improprieties in the disbursements of royalty proceeds.
A trial was held on the class action suit beginning in late September 1998 that
resulted in a verdict against the Company and two of its wholly-owned
subsidiaries, SEECO, Inc. and Arkansas Western Gas Company, in the amount of
$62.1 million. The trial judge subsequently awarded pre-judgment interest in an
amount of $31.1 million, and post-judgment interest accrued from the date of the
judgment at the rate of 10% per annum simple interest. The Company has been
required by the state court to post a judgment bond which now stands at $109.3
million (verdict amount plus pre-judgment interest and 20 months of
post-judgment interest) in order to stay the jury's verdict and proceed with an
appeal process. The bond was placed by a surety company and was collateralized
by unsecured letters of credit.
The verdict was returned following a trial on the issues of the class
action lawsuit brought by certain royalty owners of SEECO, Inc., who contend
that since 1979 the defendants breached implied covenants in certain oil and gas
leases, misrepresented or failed to disclose material facts to royalty owners
concerning gas purchase contracts between the Company's subsidiaries, and failed
to fulfill other alleged common law duties to the members of the royalty owner
plaintiff class. The litigation was commenced in May 1996 and was disclosed by
the Company at that time.
The Company believes that the jury's verdict was wrong as a matter of law
and fact and that incorrect rulings by the trial judge (including evidentiary
rulings and prejudicial jury instructions) provide significant grounds for a
successful appeal. The Company had asked the trial judge to recuse himself due
to his apparent bias toward the plaintiffs and had also filed a motion with the
trial court for judgment notwithstanding the verdict or, in the alternative, for
a new trial. These motions were denied. The Company has filed and will
vigorously prosecute an appeal in the Arkansas Supreme Court. Based on
discussions with outside legal counsel management remains confident that the
jury's verdict will be overturned and the case remanded for a new trial. If the
Company is not successful in its appeal from the jury verdict, the Company's
financial condition and results of operations would be materially and adversely
affected. However,
57
management believes that the Company's ultimate liability, if any, resulting
from this case will not be material to its financial position, but in any one
year could be significant to the results of operations. At December 31, 1999 and
1998, no amounts had been accrued on this matter.
In its Form 8-K filed July 2, 1996, the Company disclosed that a lawsuit
relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
The lawsuit, which was brought by a party who was originally included in (but
opted out of) the class action litigation described above, involves claims
similar to those upon which judgment was rendered against the Company and its
subsidiaries. In September 1998, another party who opted out of the class
threatened the Company with similar litigation. While the amounts of these
pending and threatened claims could be significant, management believes, based
on its extensive investigations and trial preparation, that these claims are
without merit, and that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations. This
matter went to a non-jury trial as to liability on January 10, 2000 and the
Company is awaiting the court's ruling.
The United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the class action litigation. MMS was included in the class action
litigation against its objections, but has not pursued further action to remove
itself from the class. If MMS does remove itself from the class, its claims may
be brought separately under federal statutes that provide for treble damages and
civil penalties. In such event, the Company believes it would have defenses that
were not available in the class action litigation. While the aggregate amount of
MMS's claims could be significant, management believes, based on its
investigations, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations.
As previously reported, the Company's subsidiary, Southwestern Energy
Production Company (SEPCO), filed suit in 1997 against several parties,
including an outside consultant previously employed by SEPCO, alleging breach of
contract, fraud, and other causes of action in connection with services
performed on SEPCO's south Louisiana exploration projects. On June 23, 1998, the
outside consultant filed a counterclaim against SEPCO. In 1999, this matter was
settled for an amount that was not material to the Company's consolidated
financial position or results of operations.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial 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.
58
(12) SEGMENT INFORMATION
The Company applies SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information." The Company's reportable business segments
have been identified based on the differences in products or services provided.
Revenues for the exploration and production segment are derived from the
production and sale of natural gas and crude oil. Revenues for the gas
distribution segment arise from the transportation and sale of natural gas at
retail. The marketing segment generates revenue through the marketing of both
Company and third party produced gas volumes.
Summarized financial information for the Company's reportable segments is
shown in the following table. The "Other" column includes items related to
non-reportable segments (real estate and pipeline operations) and corporate
items.
Exploration
and Gas
Production Distribution Marketing Other Total
-----------------------------------------------------------
(in thousands)
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
===============================================================================================================
1998
Revenues from external customers $ 55,347 $134,579 $76,367 $ 12 $266,305
Intersegment revenues 30,885 132 20,808 608 52,433
Operating income (loss) (47,273) 16,029 1,800 493 (28,951)
Depreciation, depletion and amortization expense 39,444 7,296 41 136 46,917
Write-down of oil and gas properties 66,383 - - - 66,383
Interest expense (1) 10,906 5,299 38 943 17,186
Provision (benefit) for income taxes (1) (23,238) 4,028 704 (990) (19,496)
Assets 408,193 192,396 8,905 38,126(2) 647,620
Capital expenditures 52,376 10,108 8 1,867 64,359
===============================================================================================================
1997
Revenues from external customers $ 56,658 $153,993 $65,435 $ 103 $276,189
Intersegment revenues 43,471 162 17,372 601 61,606
Operating income 33,303 16,941 1,315 377 51,936
Depreciation, depletion and amortization expense 40,777 7,227 26 178 48,208
Interest expense (1) 10,090 5,484 100 740 16,414
Provision (benefit) for income taxes (1) 9,054 4,157 476 (1,897) 11,790
Assets 460,193 204,223 7,085 39,365(2) 710,866
Capital expenditures 73,526 12,561 45 2,689 88,821
===============================================================================================================
<FN>
(1) Interest expense and the provision (benefit) for income taxes by segment is
an allocation of corporate amounts as debt and income tax expense (benefit) are
incurred at the corporate level.
(2) Other assets includes 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.
</FN>
59
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, 1999 and 1998:
Quarter Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
1999
----------------------------------------------------
Operating revenues $78,220 $56,039 $60,400 $85,737
Operating income $19,929 $1,541 $1,664 $12,924
Net income (loss) $9,132 $(1,704) $(1,935) $4,434
Basic and diluted earnings (loss) per share $.37 $(.07) $(.08) $.18
1998
----------------------------------------------------
Operating revenues $82,956 $56,334 $53,551 $73,464
Operating income (loss) $19,923 $(63,835) $2,914 $12,047
Net income (loss) $9,072 $(42,058) $(1,331) $3,720
Basic and diluted earnings (loss) per share $.37 $(1.70) $(.05) $.15
===================================================================================================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no changes in or disagreements with accountants on
accounting and financial disclosure.
Part III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The definitive Proxy Statement to holders of the Company's Common Stock in
connection with the solicitation of proxies to be used in voting at the Annual
Meeting of Shareholders on May 24, 2000 (the 2000 Proxy Statement), is hereby
incorporated by reference for the purpose of providing information about the
identification of directors. Refer to the sections "Election of Directors" and
"Security Ownership of Directors, Nominees, and Executive Officers" for
information concerning the directors.
Information concerning executive officers is presented in Part I, Item 4 of
this Form 10-K.
60
ITEM 11. EXECUTIVE COMPENSATION
The 2000 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 2000 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about security ownership of certain beneficial
owners and management. Refer to the sections "Security Ownership of Certain
Beneficial Owners" and "Security Ownership of Directors, Nominees, and Executive
Officers" for information about security ownership of certain beneficial owners
and management.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The 2000 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about related transactions. Refer to the
section "Security Ownership of Directors, Nominees, and Executive Officers" for
information about transactions with members of the Company's Board of Directors.
Part IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) The 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 63 and 64)
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 20, 1999, referencing a
press release issued on October 19, 1999, announcing the sale of the Company's
Missouri utility assets to Atmos Energy for $32.0 million.
61
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused the report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
---------------------------
(Registrant)
Dated: March 29, 2000 BY: /s/ Greg D. Kerley
---------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 29, 2000.
/s/ Harold M. Korell President, Chief Executive Officer
- --------------------------- and Director
Harold M. Korell
/s/ Greg D. Kerley Executive Vice President
- --------------------------- and Chief Financial Officer
Greg D. Kerley
/s/ Stanley T. Wilson Controller and Chief Accounting Officer
- ---------------------------
Stanley T. Wilson
/s/ Charles E. Scharlau Director and Chairman
- ---------------------------
Charles E. Scharlau
/s/ Lewis E. Epley, Jr. Director
- ---------------------------
Lewis E. Epley, Jr.
/s/ John Paul Hammerschmidt Director
- ---------------------------
John Paul Hammerschmidt
/s/ Robert L. Howard Director
- ---------------------------
Robert L. Howard
/s/ Kenneth R. Mourton Director
- ---------------------------
Kenneth R. Mourton
Supplemental Information to be Furnished With Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered Securities
Pursuant of Section 12 of the Act.
Not Applicable
62
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 (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).
Material Contracts:
10.1 Gas Purchase Contract between SEECO, Inc. and Associated Natural Gas
Company, dated October 1, 1990, and as amended September 30, 1997
(original contract incorporated by reference to Exhibit 10 to Annual
Report on Form 10-K for the year ended December 31, 1990; amendment
incorporated by reference to Exhibit 10.2 to Annual Report on Form
10-K for the year ended December 31, 1997).
10.2 Compensation Plans:
(a) Summary of Southwestern Energy Company Annual and Long-Term
Incentive Compensation Plan, effective January 1, 1985, as
amended July 10, 1989 (replaced by Southwestern Energy Company
Incentive Compensation Plan, effective January 1, 1993) (original
plan incorporated by reference to Exhibit 10 to Annual Report on
Form 10-K for the year ended December 31, 1984; first amendment
thereto incorporated by reference to Exhibit 10 to Annual Report
on Form 10-K for the year ended December 31, 1989).
(b) 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).
(c) Nonqualified Stock Option Plan, effective February 22, 1985, as
amended July 10, 1989 (replaced by Southwestern Energy Company
1993 Stock Incentive Plan, dated April 7, 1993) (original plan
incorporated by reference to Exhibit 10 to Annual Report on Form
10-K for the year ended December 31, 1985; amended plan
incorporated by reference to Exhibit 10 to Annual Report on Form
10-K for the year ended December 31, 1989).
(d) Southwestern Energy Company 1993 Stock Incentive Plan, dated
April 7, 1993 and Amended and Restated as of February 18, 1998
(incorporated by reference to Exhibit 10.2(d) to Annual Report on
Form 10-K for the year ended December 31, 1998).
(e) Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors, dated April 7, 1993 (incorporated by reference to the
appendix filed with the Company's definitive Proxy Statement to
holders of the Registrant's Common Stock in connection with the
solicitation of proxies to be used in voting at the Annual
Meeting of Shareholders on May 26, 1993).
63
Exhibit
No. Description
------- -----------
10.3 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).
10.4 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).
10.5 Southwestern Energy Company Nonqualified Retirement Plan, effective
October 4, 1995 (incorporated by reference to Exhibit 10.7 to Annual
Report of Form 10-K for the year ended December 31, 1995).
10.6 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).
10.7 Employment Agreement for Harold M. Korell, effective April 28, 1997
(incorporated by reference to Exhibit 10.15 to Annual Report on Form
10-K for the year ended December 31, 1997).
10.8 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).
10.9 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).
10.10 Omnibus Project Agreement of NOARK Pipeline System, Limited
Partnership by and among Southwestern Energy Pipeline Company,
Southwestern Energy Company, Enogex Arkansas Pipeline Corporation,
and Enogex Inc., dated January 12, 1998 (incorporated by reference to
Exhibit 10.17 to Annual Report on Form 10-K for the year ended
December 31, 1997).
10.11 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).
10.12 Asset Sale and Purchase Agreement by and among Southwestern Energy
Company, Arkansas Western Gas Company and Atmos Energy Corporation,
dated October 15, 1999 (filed herewith).
21. Subsidiaries of the Registrant (incorporated by reference to Exhibit
21 to Annual Report on Form 10-K for the year ended December 31,
1996).
23. Consent of Arthur Andersen LLP (filed herewith).
27. Financial Data Schedule for the year ended December 31, 1999 (filed
herewith).
64