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 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 1997 presentation. These reclassifications had no
effect on previously reported net income.
Results of Operations
Net income in 1997 was $18.7 million, or $.76 per share, down from $19.2
million, or $.78 per share, in 1996. Net income in 1995 was $11.2 million, or
$.45 per share. During 1997, the benefit of higher gas prices and a utility rate
increase was more than offset by increased depreciation, depletion and
amortization expense (DD&A) and higher interest costs, resulting in the slight
drop in earnings. The increase in 1996 earnings, as compared to 1995, was due to
improved natural gas prices and increased deliveries in the gas distribution
segment that resulted from colder weather and customer growth. Revenues and
operating income for the Company's major business segments are shown in the
following table.
1997 1996 1995
- --------------------------------------------------------------------------------
(in thousands)
Revenues
Exploration and production $100,129 $ 86,978 $ 63,285
Gas distribution 154,538 143,141 119,855
Energy services and other 83,128 30,225 31,219
Eliminations (61,606) (57,004) (47,534)
- --------------------------------------------------------------------------------
$276,189 $203,340 $166,825
================================================================================
Operating Income
Exploration and production $ 33,303 $ 34,184 $ 20,111
Gas distribution 17,152 14,223 10,833
Energy services and other 1,481 (411) 244
- --------------------------------------------------------------------------------
$ 51,936 $ 47,996 $ 31,188
================================================================================
Exploration and Production
The Company's exploration and production revenues increased 15% in 1997 and
37% in 1996. The increase in 1997 was due to higher average gas prices and an
increase in the Company's oil production. The increase in 1996 was primarily the
result of higher average gas prices and increased sales of gas to the Company's
gas distribution segment.
Operating income of the exploration and production segment was $33.3
million in 1997, down 3% from $34.2 million in 1996. Operating income was $20.1
million in 1995. During 1997, higher DD&A expense offset the effect of improved
gas pricing and higher oil production.
Gas production decreased to 33.4 billion cubic feet (Bcf) in 1997 from 34.8
Bcf in 1996. Gas production was 34.5 Bcf in 1995. A decrease in sales to the
Company's gas distribution systems in 1997 was partially offset by an increase
in sales to unaffiliated purchasers. The production increase in 1996 resulted
from increased sales to the Company's gas distribution systems, partially offset
by a reduction in sales to unaffiliated purchasers.
1997 1996 1995
- --------------------------------------------------------------------------------
Gas Production
Affiliated sales (Bcf) 14.3 16.3 13.9
Unaffiliated sales (Bcf) 19.1 18.5 20.6
- --------------------------------------------------------------------------------
33.4 34.8 34.5
- --------------------------------------------------------------------------------
Average price per Mcf $2.57 $2.26 $1.72
================================================================================
Oil Production
Unaffiliated sales (MBbls) 749 391 229
- --------------------------------------------------------------------------------
Average price per Bbl $19.02 $21.21 $17.15
================================================================================
Gas sales to unaffiliated purchasers were 19.1 Bcf in 1997, up from 18.5
Bcf in 1996 and down from 20.6 Bcf in 1995. Gas production during 1997 from
producing properties acquired in late 1996 and from drilling in New Mexico more
than offset normal declines in production from the Company's other properties.
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
8.6 Bcf in 1997, 10.1 Bcf in 1996, and 8.5 Bcf in 1995. Colder weather in early
1996, along with the resulting need for injections to replenish the utility's
storage facilities, caused higher demand for gas supply by AWG that year. The
Company's gas production provided approximately 64% of AWG's requirements in
1997, 62% in 1996, and 65% in 1995. Most of the sales to AWG's system are
pursuant to a long-term contract entered into in 1978 which was amended and
restated in 1994 as a result of the Gas Cost Settlement, discussed more fully
below under "Regulatory Matters." The sales price under this contract averaged
$3.35 per thousand cubic feet (Mcf) in 1997, $3.03 per Mcf in 1996, and $2.40
per Mcf in 1995. This contract expires July 24, 1998. In March, 1997, AWG filed
a gas supply plan with the Arkansas Public Service Commission (APSC) which
projects system load growth patterns and long range gas supply needs for the
utility's northwest Arkansas system. As part of its long range supply plan, AWG
has proposed to enter into a new intersegment gas supply contract for a similar
portion of its system needs at a price competitive with the cost of alternative
supplies. The APSC has not yet approved AWG's gas supply plan. The Company
expects that the volumes will continue to be sold to AWG. However, it is
possible that the APSC may reject AWG's gas supply plan and require that the gas
supply now provided under this contract be replaced through a competitive
bidding process involving multiple potential suppliers. If this occurs, SEECO's
continued sales of these volumes to AWG, and the price of any such sales, will
depend on the result of this competitive
23
bidding process. 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 5.7 Bcf
in 1997, 6.2 Bcf in 1996, and 5.4 Bcf in 1995. Deliveries to Associated
decreased in 1997 and increased in 1996 due primarily to corresponding changes
in heating weather. Effective October, 1990, one of the Company's exploration
and production subsidiaries entered into a ten-year contract with Associated to
supply a portion of its system requirements at a price to be redetermined
annually. The sales price under this contract was $2.20 per Mcf for the contract
period ended September 30, 1995, $1.785 per Mcf for the contract period ended
September 30, 1996, and $2.225 per Mcf for the contract period ended September
30, 1997. 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 sales price under the contract was $2.54 for the month of
December, 1997.
The overall average price received at the wellhead for the Company's gas
production was $2.57 per Mcf in 1997, $2.26 per Mcf in 1996, and $1.72 per Mcf
in 1995. The increase in the average price received since 1995 primarily
reflects changes in average annual spot market prices and an increase in the
proportionate share of the Company's production sold at spot market prices and
under long-term contracts with market-sensitive pricing.
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 expects the average
price it receives for its total gas production to be generally 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 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. The Company will continue to concentrate on developing and
acquiring gas reserves, but will also selectively seek opportunities to
participate in projects oriented toward oil production.
Oil production during 1997 totaled 749,000 barrels, up from 391,000 barrels
in 1996 and 229,000 barrels in 1995. The increase in 1997 oil production
resulted from the Company's acquisition of oil and gas properties owned by L.B.
Simmons Energy, Inc. (Simmons). The acquisition was effective November 1, 1996,
and added proved reserves of 6 million barrels of oil and 17 Bcf of gas.
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 increased by 8% in 1997 and by 19% in 1996. The
increase in 1997 resulted from an increase in the average utility rate caused by
higher gas prices and a rate increase implemented in late 1996. The increase in
1996 was due both to an increase in the average utility rate caused by higher
gas prices and weather which was 6% colder than in 1995.
Operating income for Southwestern's utility systems increased 21% in 1997
and by 31% in 1996. The increase in 1997 was the result of the full year effect
of a $5.1 million annual rate increase implemented in late 1996 for the
utility's northwest Arkansas system and customer growth of 2% which more than
offset lower deliveries resulting from warmer weather. The increase in 1996 was
primarily caused by colder weather.
1997 1996 1995
- --------------------------------------------------------------------------------
Gas Distribution Systems
Throughput (Bcf)
Sales volumes 27.6 29.9 27.4
Transportation volumes
End-use 6.6 5.5 5.2
Off-system 2.8 3.6 9.8
- --------------------------------------------------------------------------------
37.0 39.0 42.4
- --------------------------------------------------------------------------------
Average number of sales customers 172,200 168,568 164,672
- --------------------------------------------------------------------------------
Heating weather
Degree days 4,131 4,341 4,064
Percent of normal 103% 108% 102%
- --------------------------------------------------------------------------------
Average sales rate per Mcf $5.36 $4.57 $4.12
================================================================================
In 1997, AWG sold 17.4 Bcf to its customers at an average rate of $5.34 per
Mcf, compared to 18.8 Bcf at $4.40 per Mcf in 1996 and 17.1 Bcf at $3.93 per Mcf
in 1995. Additionally, AWG transported 5.0 Bcf in 1997, 4.2 Bcf in 1996, and 4.3
Bcf in 1995 for its end-use customers. Associated sold 10.2 Bcf to its customers
in 1997 at an average rate of $5.39 per Mcf, compared to 11.1 Bcf in 1996 at
$4.87 per Mcf and 10.3 Bcf at $4.45 per Mcf in 1995. Associated transported 1.6
Bcf for its end-use customers in 1997, compared to 1.3 Bcf in 1996 and .9 Bcf in
1995. The decrease in the combined volumes sold and transported in 1997, as
compared to 1996, for both AWG and Associated resulted from warmer weather,
partially offset by increases in the average number of customers. The
fluctuations in the average sales rates reflect changes in the average cost of
gas purchased for delivery to the
24
Company's customers, which are passed through to customers under automatic
adjustment clauses, and a rate increase for AWG that was implemented December,
1996.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, were 13.2 Bcf in both 1997 and 1996 and 13.0 Bcf in
1995. AWG also transported 2.8 Bcf of gas through its gathering system in 1997
for off-system deliveries, all to the NOARK Pipeline System (NOARK), compared to
3.6 Bcf in 1996 and 9.8 Bcf in 1995. The decreases in off-system deliveries in
1997 and 1996 were due to the on-system demands of the Company's gas
distribution systems resulting from the colder than normal weather combined with
normal production declines in the area served by the utility's gathering system.
The average transportation rate was approximately $.16 per Mcf, exclusive of
fuel, in 1997 and 1996, and $.13 in 1995.
Gas distribution revenues in future years will be impacted by both customer
growth and rate increases allowed by regulatory commissions. In recent years,
AWG has experienced customer growth of approximately 3% to 4% annually, while
Associated has experienced customer growth of approximately 1% annually. Based
on current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue. In December, 1996, AWG
received approval from the APSC for a rate increase of $5.1 million annually.
The Company received approvals in December, 1997, from the APSC and the Missouri
Public Service Commission (MPSC) for rate increases and tariff changes which
will 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 annual 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 plans to appeal this issue to the courts and 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 current changes, Associated's gathering costs were
recovered from Arkansas customers through its base rates.
Tariffs implemented in Arkansas as a result of both the 1996 and 1997 rate
increases 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.
Energy Services
Operating income for the energy services segment was $1.3 million on
revenues of $82.8 million in 1997, compared to a loss of $.5 million on revenues
of $30.0 million in 1996, and income of $.1 million on revenues of $31.0 million
in 1995. The Company increased its marketing activities when it formed an energy
services group in mid-1996 to better enable the Company to capture downstream
opportunities which arise through marketing and transportation activity. The
Company marketed 36.2 Bcf in 1997, compared to 13.0 Bcf in 1996 and 19.9 Bcf in
1995. 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).
A portion of the activity of the energy services segment involves the NOARK
Pipeline System, Limited Partnership. At December 31, 1997, the Company held a
48% general partnership interest in NOARK. NOARK is a 258-mile long intrastate
gas transmission system which extends across northern Arkansas, crossing three
major interstate pipelines and interconnecting with the Company's distribution
systems. NOARK has 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 for NOARK included in other income was $4.5 million in 1997,
$3.8 million in 1996, and $.7 million in 1995. The 1995 pretax loss included
$2.9 million of income for the Company's share of a $6.0 million settlement of
contract issues with one of NOARK's transporters. Deliveries are currently being
made by NOARK to portions of AWG's distribution system, to Associated, and to
the interstate pipelines with which NOARK interconnects. In 1997, NOARK had an
average daily throughput of 39.8 million cubic feet of gas per day (MMcfd),
compared to 57.5 MMcfd in 1996, and 86 MMcfd in 1995. NOARK has a total
transportation capacity of approximately 141 MMcfd. AWG has a transportation
contract with NOARK for 52.3 MMcfd of firm capacity. The contract expires in
2002 and is renewable annually thereafter until terminated with 180 days'
notice.
The APSC currently regulates NOARK and has established a maximum
transportation rate of approximately $.285 per dekatherm based on its original
construction cost estimate of approximately $73 million. Due to construction
conditions and the addition of a compressor station, the ultimate cost of the
pipeline exceeded the original estimate by approximately $30 million. NOARK's
operating performance has also been negatively impacted by a lack of access to
adequate gas supplies.
As a result of the continuing losses from its investment in NOARK, the
Company investigated various options to improve the financial prospects of the
venture, including an extension
25
to Oklahoma which would access additional gas supply. 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 the integration of NOARK with the Ozark Gas Transmission System
(Ozark). Ozark is a 437-mile interstate pipeline system which begins near
McAlester, Oklahoma and terminates near Searcy, Arkansas. Ozark has a throughput
capacity of approximately 170 MMcfd. Enogex has entered into an agreement to
acquire Ozark from NGC Corporation for $55.0 million and will contribute Ozark
to the NOARK partnership when regulatory approvals are obtained. Enogex has also
acquired the NOARK partnership interests not held by Southwestern. Subject to
approval by the Federal Energy Regulatory Commission, NOARK will be converted to
an interstate pipeline and be operated with Ozark as an integrated system.
In addition to its purchase of Ozark, Enogex will fund the integration
project and an expansion of the combined system at an estimated cost of $15
million. The two pipelines have a minor interconnection and run in general
proximity to each other in western Arkansas, but a larger interconnecting
pipeline and compression will be constructed to enable the Ozark line in
Oklahoma to serve as the supply line for both NOARK and Ozark. The combined
pipelines will have capacity of approximately 330 MMcfd. The integrated system
is expected to be operational in late 1998.
After the integration is complete, Southwestern will have a 25% interest in
the expanded project and Enogex will have a 75% interest. As further explained
in Note 12 to 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 NOARK. As a part of the transaction with Enogex,
$50.4 million of NOARK's 9.74% Senior Secured Notes were prepaid and refinanced
with an interim loan from Enogex. The partners plan to refinance the interim
loan on a permanent basis before the end of 1998. The Company's interest will
continue to bear 60% of the debt service on the existing level of NOARK debt
after its refinancing. 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 eliminate 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.
Regulatory Matters
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 is to begin in 1998 in accordance with a procedural
schedule established by the APSC.
During 1994, the Company entered into a settlement with the Staff of the
APSC and the Office of the Attorney General of the State of Arkansas to resolve
a dispute concerning the Company's pricing of intersegment sales (the Gas Cost
Settlement). The issues involved the price of gas sold under a long-term
contract between AWG and one of the Company's gas producing subsidiaries. The
Gas Cost Settlement, which was effective July 1, 1994, increased the volumes
which could be sold by the Company's exploration and production segment to AWG,
but made the sales price equal to a spot market index plus a premium. The
amended contract provides that volumes equal to the historical level of sales
under the contract be sold at the spot market index plus a premium of $.95 per
Mcf, while incremental sales volumes receive a premium of $.50 per Mcf. As
discussed above in "Exploration and Production," this contract expires July 24,
1998. While the APSC has not yet approved a gas supply plan submitted by AWG to
address the expiration of this contract, the Company anticipates that the
volumes will continue to be sold to AWG. In 1997, approximately 8.2 Bcf (net to
the Company's interest) was sold under the existing contract, compared to
approximately 8.6 Bcf and 7.7 Bcf in 1996 and 1995, respectively.
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. Such exposure has increased in
recent years as a result of a decline in its gas purchase requirements which has
occurred as some of its large business customers converted to a transportation
service offered by AWG and began to obtain their own gas supplies directly from
other sources. The Company expects to be able to continue to satisfactorily
manage its exposure to take-or-pay liabilities.
Operating Costs and Expenses
The Company's operating costs and expenses, exclusive of gas purchases by
the Company's utility and marketing segments, increased by 16% in both 1997 and
1996. The increases in both years were due primarily to increases in operating
and general expenses, and depreciation, depletion and amortization expense.
Increased operating and general expenses primarily relate to the Company's
exploration and production segment. The higher costs in large part represent
increased operating costs associated with the Company's expansion into areas
outside of Arkansas. During 1997, production costs associated with certain oil
properties acquired in November, 1996 accounted for most of the increase in
operating expense. General and administrative expenses have increased in 1997
and 1996 due to inflationary increases in payroll and other costs and from
personnel additions. The increase in DD&A expense for both 1997 and 1996 was
primarily due to an increase in the amortization rate per unit of production in
the exploration and production segment.
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 1997 was $1.06 per Mcfe, up from $.95
26
per Mcfe in 1996 and $.82 per Mcfe in 1995. The increases in the Company's
amortization rate were caused by increases in the Company's average finding
costs. The Company's full cost ceiling is evaluated 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 1997 levels or other
factors, without other mitigating circumstances, could cause a future write-down
of capitalized costs and a noncash charge against future earnings.
Gas purchased for resale by the Company's marketing segment increased to
$63.1 million in 1997, compared to $14.1 million in 1996 and $13.7 million in
1995, due to an increase in volumes marketed and higher per unit gas costs.
Increases in purchased gas costs for the Company's gas distribution segment in
both 1997 and 1996 were due primarily to higher per unit gas costs. Purchased
gas costs for the gas distribution segment are influenced primarily 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 1997 the impact of inflation intensified in the Company's
exploration and production segment as shortages in drilling rigs, third party
services and qualified labor increased. Increased competition in south Louisiana
also had the impact of increasing 3-D seismic and land costs in the area.
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 26% in 1997 and 17% in 1996,
both as compared to prior years, due to increases in long-term debt. The
increases in long-term debt are discussed below in "Liquidity and Capital
Resources." Interest capitalized increased 8% in 1997 and 69% in 1996. The
increase in 1996 was due primarily to higher capital expenditures in 1996 and
1995 in the exploration and production segment where interest is capitalized on
costs excluded from amortization.
The changes in other income in 1997 and 1996, as compared to 1995, relate
primarily to increases in the Company's share of operating losses incurred by
NOARK as discussed above.
The Company's primary information processing systems are currently year
2000 compliant, or upgraded versions that are year 2000 compliant will be
implemented during 1998 at no additional cost to the Company. The Company is
currently in the process of evaluating its remaining information tech-nology
infrastructure for year 2000 compliance. It does not expect the cost to modify
the technology infrastructure to obtain year 2000 compliance to be material to
its financial condition or results of operations, nor does it anticipate any
material disruption in its operations as a result of any year 2000
noncompliance.
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 1997, 1996, and
1995, net cash provided from operating activities totaled $75.4 million, $67.6
million, and $55.9 million, respectively. The primary components of cash
generated from operations are net income, depreciation, depletion and
amortization, and the provision for deferred income taxes. Net cash from
operating activities provided 75% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1997, 77% in 1996, and 59% in 1995.
Capital Expenditures
Capital expenditures totaled $88.8 million in 1997, $124.9 million in 1996,
and $101.6 million in 1995. The Company's exploration and production segment
expenditures included acquisitions of oil and gas producing properties totaling
$45.8 million in 1996 and $6.0 million in 1995. The Company made no producing
property acquisitions in 1997.
1997 1996 1995
- --------------------------------------------------------------------------------
(in thousands)
Capital Expenditures
Exploration and production $73,526 $110,352 $ 82,237
Gas distribution 12,561 12,752 18,523
Other 2,734 1,809 866
- --------------------------------------------------------------------------------
$88,821 $124,913 $101,626
================================================================================
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending will be adequate to allow the Company to maintain its
present markets, explore and develop 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.
Capital spending planned for 1998 totals $74.2 million, a decrease of 16%
from actual 1997 spending, consisting of $59.2 million for exploration and
production, $12.3 million for gas distribution system expenditures, and $2.7
million for general purposes.
Financing Requirements
At year-end 1997, Southwestern's total debt was $299.5 million. This
compares to year-end 1996 total debt of $278.3 million.
Two floating rate revolving credit facilities provide the Company access to
$80.0 million of variable rate long-term capital. These facilities were
temporarily expanded to $120 million in 1996 to provide additional debt
financing to fund the acquisition of the Simmons properties. Borrowings
outstanding under these credit facilities totaled $46.4 million at the end of
1997 and $96.5 million at the end of 1996.
27
In May, 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes
due 2027. The notes may be repaid prior to maturity on May 1, 2009, at the
noteholder's option. In October, 1997, the Company issued $40.0 million of
Medium-Term Notes due 2017 at a weighted average interest rate of 7.21%.
Proceeds from the issuance of these notes were used to repay certain borrowings
under the Company's revolving credit facilities. All of 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.
As explained above in "Energy Services," the Company has severally
guaranteed 60% of the principal and interest payments on approximately $78.2
million of debt payable by NOARK at December 31, 1997. Of the total, Senior
Secured Notes with a principal balance of $50.4 million are now pay-able to the
other general partner of NOARK pursuant to an interim arrangement requiring
annual principal payments of $3.2 million, plus interest on the unpaid balance.
NOARK's remaining debt is pursuant to a $30.0 million unsecured revolving credit
agreement with a group of banks which currently matures April 26, 1998. The
partnership intends during 1998 to refinance the Senior Secured Notes and
revolving credit agreement through a new issue of long-term notes. In 1997, the
Company advanced $5.0 million to NOARK to fund its share of debt service
payments. The Company expects to advance up to $3.6 million to NOARK during 1998
in connection with its guarantees.
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. At the end of 1997, the
capital structure consisted of 57.2% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
42.8% equity, with a ratio of earnings to fixed charges of 2.1. Over the long
term, the Company expects to lower the debt portion of its capital structure by
limiting its routine capital spending.
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 $39.0 million at the end of 1997, up from $31.1
million at the end of 1996. Current assets increased by 21% to $88.0 million in
1997, while current liabilities increased 17% to $49.0 million. The increase in
current assets at December 31, 1997, was due primarily to increases in accounts
receivable, gas storage inventory and under-recovered purchased gas costs. The
increase in accounts receivable was due primarily to higher weather-related
sales at year-end 1997 and increased gas volumes marketed by the energy services
segment. The increase in gas storage inventory at December 31, 1997, was due to
both higher volumes stored and a higher weighted average cost. The increase in
under-recovered purchased gas costs relates to the increased cost of natural gas
purchased during 1997. These costs will be recovered from the Company's utility
customers in subsequent months through automatic cost of gas adjustment clauses
included in the utility's filed rate tariffs. The increase in current
liabilities resulted primarily from an increase in accounts payable due to the
timing of invoices received.
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 and Section 21E of the Securities Exchange Act of
1934. These statements reflect the Company's current views with respect to
future events and performance. The Company believes that its expectations are
based on reasonable assumptions. No assurances, however can be given that its
goals will be achieved. Important factors that could cause actual results to
differ materially from those in the forward-looking statements herein include
(1) the timing and extent of changes in commodity prices for gas and oil and
interest rates, (2) the timing and extent of the Company's success in
discovering, developing, producing, and estimating reserves, (3) the effects of
weather and regulation on the Company's gas distribution segment, and (4)
conditions in capital markets, availability of oil field services, drilling
rigs, and other equipment, as well as other competitive factors during the
periods covered by the forward-looking statements.
28
Reports of Management and
Independent Public Accountants
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 generally accepted accounting principles 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 generally accepted
auditing standards, 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 preformed.
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, 1997 and
1996, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Southwestern Energy Company
and Subsidiaries as of December 31, 1997 and 1996, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 4, 1998
29
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
Operating Revenues
Gas sales $ 190,298 $ 174,738 $ 142,455
Gas marketing 65,435 14,153 14,032
Oil sales 14,258 8,294 3,924
Gas transportation and other 6,198 6,155 6,414
- -----------------------------------------------------------------------------------------------------------------------------
276,189 203,340 166,825
- -----------------------------------------------------------------------------------------------------------------------------
Operating Costs and Expenses
Gas purchases - utility 46,806 42,851 37,133
Gas purchases - marketing 63,054 14,114 13,714
Operating and general 59,167 50,509 44,436
Depreciation, depletion and amortization 48,208 42,394 35,992
Taxes, other than income taxes 7,018 5,476 4,362
- -----------------------------------------------------------------------------------------------------------------------------
224,253 155,344 135,637
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 51,936 47,996 31,188
Interest Expense, Net 16,414 13,044 11,167
Other Income (Expense) (5,017) (4,015) (1,227)
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes and Extraordinary Item 30,505 30,937 18,794
- -----------------------------------------------------------------------------------------------------------------------------
Income Taxes
Current (732) (5,569) (4,908)
Deferred 12,522 17,320 12,167
- -----------------------------------------------------------------------------------------------------------------------------
11,790 11,751 7,259
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 18,715 19,186 11,535
Extraordinary Item - - (295)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 18,715 $ 19,186 $ 11,240
=============================================================================================================================
Basic Earnings Per Share
Income before extraordinary item $.76 $.78 $.46
Extraordinary item - - (.01)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $.76 $.78 $.45
=============================================================================================================================
Weighted Average Common Shares Outstanding 24,738,882 24,705,256 25,130,781
=============================================================================================================================
Dilutive Earnings Per Share
Income before extraordinary item $.76 $.77 $.46
Extraordinary item - - (.01)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $.76 $.77 $.45
=============================================================================================================================
Dilutive Weighted Average Common Shares Outstanding 24,777,906 24,788,587 25,199,258
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
30
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Assets
Current Assets
Cash $ 4,603 $ 2,297
Accounts receivable 45,752 39,928
Income taxes receivable 3,074 6,623
Inventories, at average cost 20,465 17,571
Under-recovered purchased gas costs 9,428 3,030
Other 4,633 3,484
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 87,955 72,933
- -----------------------------------------------------------------------------------------------------------------------------
Investments 7,039 6,557
- -----------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $69,304,000
in 1997 and $53,942,000 in 1996 excluded from amortization 708,094 637,100
Gas distribution systems 212,779 203,070
Gas in underground storage 23,748 25,636
Other 25,319 22,031
- -----------------------------------------------------------------------------------------------------------------------------
969,940 887,837
Less: Accumulated depreciation, depletion and amortization 366,638 319,135
- -----------------------------------------------------------------------------------------------------------------------------
603,302 568,702
- -----------------------------------------------------------------------------------------------------------------------------
Other Assets 12,570 11,998
- -----------------------------------------------------------------------------------------------------------------------------
$ 710,866 $ 660,190
=============================================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Current portion of long-term debt $ 3,071 $ 3,071
Accounts payable 29,903 25,644
Taxes payable 3,893 3,290
Interest payable 2,569 1,628
Customer deposits 5,307 4,904
Other 4,246 3,285
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 48,989 41,822
- -----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 296,472 275,214
- -----------------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 139,256 130,686
Other 4,584 4,527
- -----------------------------------------------------------------------------------------------------------------------------
143,840 135,213
- -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies
- -----------------------------------------------------------------------------------------------------------------------------
Shareholders' Equity
Common stock, $.10 par value; authorized 75,000,000 shares,
issued 27,738,084 shares 2,774 2,774
Additional paid-in capital 21,475 21,336
Retained earnings, per accompanying statements 230,669 217,889
- -----------------------------------------------------------------------------------------------------------------------------
254,918 241,999
Less: Common stock in treasury, at cost, 2,904,519 shares in 1997 and
3,019,200 shares in 1996 32,357 33,603
Unamortized cost of restricted shares issued under stock incentive
plan, 90,375 shares in 1997 and 40,020 shares in 1996 996 455
- -----------------------------------------------------------------------------------------------------------------------------
221,565 207,941
- -----------------------------------------------------------------------------------------------------------------------------
$ 710,866 $ 660,190
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
31
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income $ 18,715 $ 19,186 $ 11,240
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 48,488 42,674 36,272
Deferred income taxes 12,522 17,320 12,167
Equity in loss of partnership 4,523 3,778 696
Change in assets and liabilities:
Increase in accounts receivable (5,824) (4,387) (3,216)
(Increase) decrease in income taxes receivable 3,549 1,598 (6,729)
(Increase) decrease in under-recovered purchased gas costs (6,398) (10,357) 3,700
Increase in inventories (2,894) (2,123) (3,249)
Increase in accounts payable 4,259 1,655 5,319
Net change in other current assets and liabilities (1,584) (1,759) (339)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 75,356 67,585 55,861
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (88,821) (124,913) (101,626)
Investment in partnership (4,962) (1,266) (4,968)
(Increase) decrease in gas stored underground 1,888 (2,190) 4,013
Other items 5,175 55 2,814
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (86,720) (128,314) (99,767)
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt (50,100) 73,600 (29,400)
Payments on other long-term debt (28,643) (6,143) (3,071)
Proceeds from issuance of long-term debt 98,348 - 121,978
Retirement of 10.63% Senior Notes - - (24,958)
Purchase of treasury stock - - (14,259)
Dividends paid (5,935) (5,929) (6,038)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 13,670 61,528 44,252
- -----------------------------------------------------------------------------------------------------------------------------
Increase in cash 2,306 799 346
Cash at beginning of year 2,297 1,498 1,152
- -----------------------------------------------------------------------------------------------------------------------------
Cash at end of year $ 4,603 $ 2,297 $ 1,498
=============================================================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $217,889 $204,632 $199,430
Net income 18,715 19,186 11,240
Cash dividends declared ($.24 per share) (5,935) (5,929) (6,038)
- -----------------------------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $230,669 $217,889 $204,632
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
32
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 1997, 1996 and 1995
(1) Summary of Significant Accounting Policies
Nature of Operations and Consolidation
Southwestern Energy Company (Southwestern or the Company) is a diversified
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.
Approximately 65% of the Company's business is derived from the exploration and
production segment based on operating income. Southwestern's exploration and
production activities are concentrated in Arkansas, Oklahoma, Texas, New Mexico,
Louisiana, and the Gulf Coast (primarily onshore). The gas distribution segment
operates in northern Arkansas and parts of Missouri, and obtains approximately
60% of its gas supply from one of the Company's exploration and production
subsidiaries. The customers of the gas distribution segment consist of
residential, commercial, and industrial users of natural gas. Southwestern's
marketing and transportation business is concentrated in its core areas of
operations.
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,
Arkansas Western Pipeline Company, and A.W. Realty Company. All significant
intercompany accounts and transactions have been eliminated. The Company
accounts for its general partnership interest in the NOARK Pipeline System,
Limited Partnership (NOARK) using the equity method of accounting. In accordance
with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation," the Company recognizes profit on
intercompany sales of gas delivered to storage by its utility subsidiary.
Certain reclassifications have been made to the prior years' financial
statements to conform with the 1997 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Property, Depreciation, Depletion and Amortization
Gas and Oil Properties-The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive)
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 cost of any unproved properties. If
the Company's unamortized costs in oil and gas properties exceed this ceiling
amount, a provision for additional depreciation, depletion and amortization is
required. At December 31, 1997, 1996, and 1995, the Company's cost of oil and
gas properties did not exceed such ceiling amounts.
Gas Distribution Systems-Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of the
gas distribution system is provided using the straight-line method with average
annual rates for plant functions ranging from 2.2% to 5.6%. Gas in underground
storage is stated at average cost.
Other property, plant and equipment is depreciated using the straight-line
method over estimated useful lives ranging from 5 to 40 years.
The Company charges to maintenance or operations the cost of labor,
materials, and other expenses incurred in maintaining the operating efficiency
of its properties. Betterments are added to property accounts at cost.
Retirements are credited to property, plant and equipment at cost and charged to
accumulated depreciation, depletion and amortization with no gain or loss
recognized, except for abnormal retirements.
Capitalized Interest-Interest is capitalized on the costs of unevaluated
gas and oil properties excluded from amortization. In accordance with
established utility regulatory practice, an allowance for funds used during
construction of major projects is capitalized and amortized over the estimated
lives of the related facilities.
Gas Distribution Revenues and Receivables
Customer receivables arise from the sale or transportation of gas by the
Company's gas distribution subsidiary. The Company's gas distribution customers
represent a diversified base of residential, commercial, and industrial users.
Approximately 108,000 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.
33
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. Effective December, 1996, for the Company's northwest Arkansas system,
and effective December, 1997, for the northeast Arkansas system, rate schedules
include a weather normalization clause to lessen the impact of revenue increases
and decreases which might result from weather variations during the winter
heating season. The pass-through of gas costs to customers is not affected by
this normalization clause.
Gas Production Imbalances
The exploration and production subsidiaries record gas sales using the
entitlement method. The entitlement method requires revenue recognition of the
Company's revenue interest share of gas production from properties in which gas
sales are disproportionately allocated to owners because of marketing or other
contractual arrangements. The Company's net imbalance position at December 31,
1997 and 1996 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
The Company has adopted Financial Accounting Standards Board Statement No.
128, "Earnings Per Share" (SFAS No. 128). 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 impact of the adoption of SFAS No. 128 had no effect on reported
earnings per share for 1996 and 1995.
During 1997 the Company issued 117,740 treasury shares under a compensatory
plan and for stock awards and returned to treasury 3,059 shares canceled from an
earlier issue under the compensatory plan. The net effect of these transactions
was a $1.2 million decrease in treasury stock.
(2) Long-Term Debt
Long-term debt as of December 31, 1997 and 1996 consisted of the following:
1997 1996
---------------------------
(in thousands)
Senior Notes
8.69% Series due 1997 $ - $ 22,500
8.86% Series due in annual installments of $3.1 million through 1999 6,143 12,285
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 -
7.21% Series due 2017 40,000 -
- -----------------------------------------------------------------------------------------------------------------------------
253,143 181,785
Other
Variable rate (6.27% at December 31, 1997) unsecured revolving credit arrangements 46,400 96,500
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt 299,543 278,285
Less: Current portion of long-term debt 3,071 3,071
- -----------------------------------------------------------------------------------------------------------------------------
$ 296,472 $ 275,214
=============================================================================================================================
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.
Two variable rate credit facilities provide the Company access to $80.0
million of long-term revolving credit. Borrowings outstanding under these credit
facilities totaled $46.4 million at December 31, 1997, all of which was
classified as long-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 revolving credit facilities expire in 2000. The
Company intends to renew or replace the facilities prior to expiration.
34
The terms of the long-term debt instruments and agreements contain
covenants which impose certain restrictions on the Company, including limitation
of additional indebtedness and restrictions on the payment of cash dividends. At
December 31, 1997, approximately $129.1 million of retained earnings was
available for payment as dividends.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1998 through 2002, are $3.1 million, $3.1 million, $46.4 million,
$2.0 million, and $2.0 million. Total interest payments of $18.8 million, $15.6
million, and $12.9 million were made in 1997, 1996, and 1995, respectively.
(3) Income Taxes
The provision for income taxes included the following components:
1997 1996 1995
------------------------------------------
(in thousands)
Federal:
Current $ (1,614) $ (5,788) $ (5,436)
Deferred 11,422 15,799 11,434
State:
Current 882 219 528
Deferred 1,219 1,833 1,046
Investment tax credit amortization (119) (312) (313)
- ----------------------------------------------------------------------------------------------
Provision for income taxes $ 11,790 $ 11,751 $ 7,259
==============================================================================================
The provision for income taxes was an effective rate of 38.6% in 1997,
38.0% in 1996, and 38.6% in 1995. The following reconciles the provision for
income taxes included in the consolidated statements of income with the
provision which would result from application of the statutory federal tax rate
to pretax financial income:
1997 1996 1995
------------------------------------------
(in thousands)
Expected provision at federal statutory rate of 35% $10,677 $10,828 $6,578
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,365 1,334 1,023
Other (252) (411) (342)
- --------------------------------------------------------------------------------------------------------------
Provision for income taxes $11,790 $11,751 $7,259
==============================================================================================================
The components of the Company's net deferred tax liability as of December 31,
1997 and 1996 were as follows:
1997 1996
--------------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $124,634 $116,036
Stored gas difference 7,133 6,008
Deferred purchased gas costs 5,223 3,907
Prepaid pension costs 1,779 1,637
Book over tax basis in partnerships 6,071 5,099
Other 665 748
- ----------------------------------------------------------------------------------------------
145,505 133,435
- ----------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 754 814
Alternative minimum tax credit carryforward 4,593 2,716
Other 534 437
- ----------------------------------------------------------------------------------------------
5,881 3,967
- ----------------------------------------------------------------------------------------------
Net deferred tax liability $139,624 $129,468
==============================================================================================
Total income tax payments of $4.2 million, $4.0 million, and $.9 million
were made in 1997, 1996, and 1995, respectively.
(4) Pension Plan and Other Postretirement Benefits
Substantially all employees are covered by the Company's defined benefit
pension plan. Benefits are based on years of benefit service and the employee's
"average compensation," as defined. The Company's funding policy is to
contribute amounts which are actuarially determined to provide the plan with
sufficient assets to meet future benefit payment requirements and which are tax
deductible.
Plan assumptions for 1997 and 1996 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 7.5% for the
net pension cost computation, and a salary progression rate of 5%. The
reconciliation of prepaid pension cost at December 31, 1997 utilizes a discount
rate of 7.5% for future settlements.
35
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1997 and 1996:
1997 1996
--------------------------
(in thousands)
Actuarial present value of benefit obligations:
Vested benefits $(32,597) $(30,371)
Nonvested benefits (2,787) (2,574)
- -----------------------------------------------------------------------------------------------
Accumulated benefit obligation (35,384) (32,945)
Effect of projected future compensation levels (11,524) (9,096)
- -----------------------------------------------------------------------------------------------
Projected benefit obligation (46,908) (42,041)
Plan assets at fair value, primarily common stocks and bonds 65,966 56,457
- -----------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 19,058 14,416
Unrecognized net gain (14,336) (9,962)
Unrecognized net asset (586) (769)
Unrecognized prior service cost 352 354
- -----------------------------------------------------------------------------------------------
Prepaid pension cost $ 4,488 $ 4,039
===============================================================================================
Net pension cost for 1997, 1996, and 1995 included the following
components:
1997 1996 1995
----------------------------------------------
(in thousands)
Service costs (benefits earned during the period) $ 1,728 $ 1,520 $ 1,101
Interest cost on projected benefit obligation 3,189 2,850 2,316
Actual return on plan assets (11,635) (8,332) (15,172)
Net amortization and deferral 6,269 3,710 11,699
- -----------------------------------------------------------------------------------------------------
Net pension credit $ (449) $ (252) $ (56)
=====================================================================================================
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $54,000,
$81,000, and $221,000 in 1997, 1996, and 1995, respectively. At December 31,
1997, the supplemental retirement plan had an accrued pension cost of $216,000.
The Company provides postretirement health care and life insurance benefits
to eligible employees. Employees become eligible for these benefits if they meet
age and service requirements. Generally, the benefits paid are a stated
percentage of medical expenses reduced by deductibles and other coverages. Net
postretirement benefit cost for 1997 and 1996 included the following components:
1997 1996
-----------------------
(in thousands)
Service cost of benefits earned during the year $ 90 $ 61
Amortization of transition amount 103 103
Amortization of unrecognized loss 40 4
Interest cost on accumulated postretirement benefit obligation (APBO) 213 161
- ---------------------------------------------------------------------------------------------------
Net postretirement benefit cost $446 $329
===================================================================================================
The APBO as of December 31, 1997 and 1996 was comprised of the following:
1997 1996
---------------------
(in thousands)
Retirees $1,370 $1,037
Active participants, fully eligible 440 326
Other participants 1,257 926
- --------------------------------------------------------------------------------------------------
Total APBO $3,067 $2,289
==================================================================================================
In determining the APBO, an assumed weighted average discount rate of 7.5%
was used for 1997 and 1996. An increase of 10% in the cost of covered health
care benefits was assumed for 1998. This rate is assumed to decrease ratably to
6% over 8 years and remain at that level thereafter. The effect of a one
percentage point increase in the assumed health care cost trend rate for each
future year would increase the total APBO at year-end 1997 by $368,000 and the
1997 net postretirement benefit cost by $39,000.
36
(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:
1997 1996 1995
--------------------------------------------
(in thousands)
Sales $100,129 $ 86,978 $ 63,285
Production (lifting) costs (17,155) (10,607) (7,930)
Depreciation, depletion and amortization (40,340) (35,533) (29,607)
- ---------------------------------------------------------------------------------------------
42,634 40,838 25,748
Income tax expense (16,331) (15,528) (9,862)
- ---------------------------------------------------------------------------------------------
Results of operations $ 26,303 $ 25,310 $ 15,886
=============================================================================================
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 1997, 1996,
and 1995:
1997 1996 1995
-------------------------------------------
(in thousands)
Property acquisition costs $10,911 $ 60,748 $27,715
Exploration costs 33,225 25,436 29,843
Development costs 28,825 23,667 24,429
- ----------------------------------------------------------------------------------------------
Capitalized costs incurred $72,961 $109,851 $81,987
==============================================================================================
Amortization per Mcf equivalent $1.057 $.949 $.817
==============================================================================================
Capitalized interest is included as part of the cost of oil and gas
properties. The Company capitalized $4.5 million, $4.1 million, and $2.5 million
during 1997, 1996, and 1995, 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 $6.0 million, $5.9 million, and $4.4 million during 1997, 1996, and
1995, respectively. These internal costs were directly related to acquisition,
exploration and development activities and are included as part of the cost of
oil and gas properties.
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 1997 and 1996:
1997 1996
--------------------------
(in thousands)
Proved properties $628,549 $575,458
Unproved properties 79,545 61,642
- -------------------------------------------------------------------------------------
Total capitalized costs 708,094 637,100
Less: Accumulated depreciation, depletion and amortization 281,595 241,237
- -------------------------------------------------------------------------------------
Net capitalized costs $426,499 $395,863
=====================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1997. Included in these costs is
$5.1 million representing leasehold and seismic costs related to the remaining
unevaluated portion of acreage located on the Fort Chaffee military reservation.
These costs are expected to be evaluated and subjected to amortization within
the next several years as this acreage is further explored and developed. Also
included in these costs is $37.2 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.
1997 1996 1995 Prior Total
------------------------------------------------------------------------------
(in thousands)
Property acquisition c $ 8,123 $ 7,738 $4,224 $5,983 $26,068
Exploration costs 18,551 9,270 4,417 1,780 34,018
Capitalized interest 4,318 3,538 644 718 9,218
- ------------------------------------------------------------------------------------------------------------------
$30,992 $20,546 $9,285 $8,481 $69,304
==================================================================================================================
37
(6) Natural Gas and Oil Reserves (Unaudited)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1997, 1996, and 1995:
1997 1996 1995
---------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
- ----------------------------------------------------------------------------------------------------------------------------
Proved reserves, beginning of year 297,467 8,238 294,876 2,152 316,098 1,231
Revisions of previous estimates 861 (51) (11,772) 74 (25,970) (199)
Extensions, discoveries, and other additions 26,430 426 16,429 61 34,801 498
Production (33,355) (749) (34,758) (391) (34,515) (229)
Acquisition of reserves in place 76 - 32,713 6,350 4,462 851
Disposition of reserves in place (101) (12) (21) (8) - -
- ----------------------------------------------------------------------------------------------------------------------------
Proved reserves, end of year 291,378 7,852 297,467 8,238 294,876 2,152
============================================================================================================================
Proved, developed reserves:
Beginning of year 255,234 7,804 248,714 1,975 261,690 1,116
End of year 252,393 7,312 255,234 7,804 248,714 1,975
============================================================================================================================
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, 1997, 1996, and 1995:
1997 1996 1995
----------------------------------------------
(in thousands)
Future cash inflows $ 973,536 $1,340,804 $ 751,261
Future production and development costs (197,021) (187,825) (106,092)
Future income tax expense (261,173) (398,625) (229,064)
- -------------------------------------------------------------------------------------------------------------------
Future net cash flows 515,342 754,354 416,105
10% annual discount for estimated timing of cash flows (256,279) (383,410) (212,583)
- -------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 259,063 $ 370,944 $ 203,522
===================================================================================================================
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
1997, 1996, and 1995:
1997 1996 1995
--------------------------------------------
(in thousands)
Standardized measure, beginning of year $370,944 $203,522 $189,492
Sales and transfers of gas and oil produced, net of production costs (82,975) (76,371) (55,355)
Net changes in prices and production costs (173,730) 185,234 39,928
Extensions, discoveries, and other additions,
net of future production and development costs 41,267 40,264 49,471
Acquisition of reserves in place 116 98,245 7,962
Revisions of previous quantity estimates 646 (19,839) (29,851)
Accretion of discount 55,852 31,043 28,733
Net change in income taxes 62,186 (80,662) (9,073)
Changes in production rates (timing) and other (15,243) (10,492) (17,785)
- -----------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $259,063 $370,944 $203,522
=============================================================================================================================
38
(7) Investment in Unconsolidated Partnership
At December 31, 1997, the Company held a 48% general partnership interest
in NOARK. NOARK is a 258-mile long intrastate gas transmission system which
extends across northern Arkansas. In January, 1998, the Company entered into an
agreement with Enogex Inc. (Enogex) which will result in the expansion of NOARK
and provide 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 is a 437-mile interstate pipeline system
which begins in eastern Oklahoma and terminates in eastern Arkansas. Enogex has
entered into a separate agreement to acquire the Ozark system and will
contribute it to the NOARK partnership. Enogex has also acquired the NOARK
partnership interests not owned by Southwestern. The acquisition of Ozark and
its integration with NOARK is subject to approval by the Federal Energy
Regulatory Commission (FERC). Management expects to obtain approval from FERC in
1998 at which time NOARK will be converted to an interstate pipeline and be
operated in combination with Ozark. Enogex will fully fund the acquisition of
Ozark and the expansion and integration with NOARK. After the integration is
complete, the Company will own a 25% interest in the partnership and the
expanded project and Enogex will own a 75% interest. The parties expect the
integrated system to be operational by late 1998.
The Company's investment in NOARK totaled $7.0 million at December 31, 1997
and $6.5 million at December 31, 1996. The Company's investment in NOARK
includes advances of $5.0 million made during 1997, $1.3 million made during
1996, and $5.0 million made during 1995, primarily to provide certain minimum
cash balances to service NOARK's long-term debt.
In connection with the Enogex transaction, the Company and a previous
general partner converted certain of their loans to the 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. See Note 12 for further discussion of
NOARK's funding requirements and the Company's investment in NOARK.
NOARK's financial position at December 31, 1997 and 1996 is summarized
below, including an unaudited pro forma balance sheet that presents the effects
of the reorganization of the partnership (excluding the pending contribution and
integration of the Ozark system) as if such transactions had occurred at
December 31, 1997:
Pro Forma
1997 1997 1996
---------------------------------------------
(in thousands)
Current assets $ 1,923 $ 923 $ 925
Noncurrent assets 101,448 92,856 95,490
- -----------------------------------------------------------------------------------------------
$ 103,371 $ 93,779 $ 96,415
===============================================================================================
Current liabilities $ 4,594 $ 9,762 $ 7,668
Long-term debt 75,000 75,000 79,150
Loans from general partners - 21,885 13,615
Partners' capital (deficit) 23,777 (12,868) (4,018)
- -----------------------------------------------------------------------------------------------
$ 103,371 $ 93,779 $ 96,415
===============================================================================================
The Company's share of NOARK's pretax loss, before the effect of accrued
interest expense on general partner loans, was $4.5 million, $3.8 million, and
$.7 million for 1997, 1996, and 1995, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
income. The 1995 pretax loss included $2.9 million of income for the Company's
share of a $6.0 million settlement of contract issues with one of NOARK's
transporters.
NOARK's results of operations for 1997, 1996, and 1995 are summarized
below:
1997 1996 1995
---------------------------------------------
(in thousands)
Operating revenues $ 4,963 $ 5,114 $11,657
Pretax loss $ (8,850) $(8,106) $(2,167)
===============================================================================================
(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 and Customer Deposits-The carrying amount is a reasonable estimate of
fair value.
Long-Term Debt-The fair value of the Company's long-term debt is estimated
based on the expected current rates which would be offered to the Company for
debt of the same maturities.
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.
39
The carrying amounts and estimated fair values of the Company's financial
instruments as of December 31, 1997 and 1996 were as follows:
1997 1996
------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Cash $4,603 $4,603 $2,297 $2,297
Customer deposits $5,307 $5,307 $4,904 $4,904
Long-term debt $299,543 $304,392 $278,285 $279,692
Commodity hedges $1,442 $2,454 $518 $(1,717)
=============================================================================================================================
Anticipated regulatory treatment of the excess of fair value over carrying
value of the portion of the Company's long-term debt attributable to its
regulatory activities, if such debt were settled at amounts approximating those
above, would dictate that these amounts be used to increase the Company's rates
over a prescribed amortization period. Accordingly, any settlement would not
result in a material impact on the Company's financial position or results of
operations.
Price Risk Management
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 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, 1997, the Company had outstanding natural gas price swaps
on total notional volumes of 2.2 Bcf. Of the total, the Company will receive
fixed prices ranging from $2.49 to $3.27 per MMBtu on 2.0 Bcf. Under contracts
covering the remaining .2 Bcf, the Company will make average fixed price
payments of $2.42 per MMBtu and receive variable prices based on the NYMEX
futures market. The Company held outstanding basis swaps on a notional volume of
1.9 Bcf. At December 31, 1996, the Company had outstanding natural gas price
swaps on total notional volumes of 12.1 Bcf. Of the total, the Company received
fixed prices ranging from $2.11 to $2.82 per MMBtu on 11.5 Bcf. Under contracts
covering the remaining .6 Bcf, the Company made average fixed price payments of
$3.21 per MMBtu and received variable prices based on the NYMEX futures market.
At December 31, 1996, the Company held outstanding basis swaps on a no-tional
volume of 5.5 Bcf. The Company also had outstanding a price swap on a notional
volume of 450,000 barrels of crude oil for calendar year 1997 at a fixed price
of $20.75 per barrel. During 1997, the Company recognized losses from price risk
management activities of $2.7 million, which were offset by corresponding
revenue receipts from physical transactions. In 1996 and 1995, the Company
recognized price risk management losses of $3.4 million and $.6 million,
respectively.
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, 1997,
the Company had a crude oil price floor of $18.00 per barrel (based on the NYMEX
futures market) on total notional volumes of 1,450,000 barrels covering
production during calendar years 1998 through 2001. At December 31, 1996, the
Company had a fixed-priced collar agreement for a notional volume of 5.6 Bcf
covering the period April through October, 1997, which provided a floor price of
$2.00 per MMBtu and a ceiling price of $2.80 per MMBtu.
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 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
1,275,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock and cash awards, the shares related to which in the
aggregate do not exceed 1,275,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The types of incentives which may
be awarded are comprehensive and are intended to enable the Board of Directors
to structure the most appropriate incentives and to address changes in income
tax laws which may be enacted over the term of the plan.
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.
40
The Company's 1985 Nonqualified Stock Option Plan expired in 1992, except
with respect to awards then outstanding. The following table summarizes stock
option activity for the years 1997, 1996, and 1995:
1997 1996 1995
------------------------------------------------------------------------------------
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 1,501,641 $13.39 1,552,558 $13.39 1,411,558 $13.50
Granted 433,248 $12.58 129,000 $14.89 186,000 $13.22
Exercised 56,850 $5.96 6,000 $12.81 - -
Canceled 258,925 $13.82 173,917 $14.51 45,000 $16.03
- -----------------------------------------------------------------------------------------------------------------------------
Options outstanding at December 31 1,619,114 $13.37 1,501,641 $13.39 1,552,558 $13.39
=============================================================================================================================
Options exercisable at December 31 521,782 $12.61 588,695 $11.71 472,224 $10.71
=============================================================================================================================
All options are issued at fair market value at the date of grant and expire
ten years from the date of grant. The options outstanding at December 31, 1997
had a range of exercise prices from $5.58 to $17.50 and a weighted average
remaining contractual life of 7.2 years. Options generally vest to employees and
directors over a three to four year period from the date of grant. Of the total
options outstanding, 510,000 performance accelerated options were granted in
1994 at an option price of $14 5/8. These options vest over a four-year period
beginning six years from the date of grant or earlier if certain corporate
performance criteria are achieved.
The Company has granted 114,686 shares of restricted stock to employees
through 1997. Of this total, 75,007 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.
The Company adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS No. 123) in 1996. 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 and earnings per share would have been reduced to
the pro forma amounts indicated below:
1997 1996
-------------------------
(in thousands)
Net income
As reported $18,715 $19,186
Pro forma $18,378 $19,055
Basic earnings per share
As reported $.76 $.78
Pro forma $.74 $.77
Diluted earnings per share
As reported $.76 $.77
Pro forma $.74 $.77
===================================================================================
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 1.7% to 2.0%; expected volatility of 26.2% to
26.8%; risk-free interest rate of 5.7% to 6.8%; and expected lives of 6 years.
41
(10) Common Stock Purchase Rights
One common share purchase right is attached to each outstanding share of
the Company's common stock. Each right entitles the holder to purchase one share
of common stock at an exercise price of $25.00, subject to adjustment. These
rights will become exercisable in the event that a person or group acquires or
commences a tender offer for 20% or more of the Company's outstanding shares or
the Board determines that a holder of 10% or more of the Company's outstanding
shares presents a threat to the best interests of the Company. At no time will
these rights have any voting power.
If any person or entity actually acquires 20% of the common stock (10% or
more if the Board determines such acquiror is adverse), rightholders (other than
the 20% or 10% stockholder) will be entitled to buy, at the right's then current
exercise price, the Company's common stock with a market value of twice the
exercise price. Similarly, if the Company is acquired in a merger or other
business combination, each right will entitle its holder to purchase, at the
right's then current exercise price, a number of the surviving company's common
shares having a market value at that time of twice the right's exercise price.
The rights may be redeemed by the Board for $.003 per right prior to the
time that they become exercisable. In the event, however, that redemption of the
rights is considered in connection with a proposed acquisition of the Company,
the Board may redeem the rights only on the recommendation of its independent
directors (nonmanagement directors who are not affiliated with the proposed
acquiror). These rights expire in 1999.
41
(11) Segment Information
Intersegment sales by the exploration and production segment to the gas
distribution segment are priced in accordance with terms of existing contracts
and current market conditions. Following is industry segment data for the years
ended December 31, 1997, 1996, and 1995:
1997 1996 1995
--------------------------------------------
(in thousands)
Revenues
Exploration and production $100,129 $ 86,978 $ 63,285
Gas distribution 154,538 143,141 119,855
Energy services and other 83,128 30,225 31,219
Eliminations (61,606) (57,004) (47,534)
- -----------------------------------------------------------------------------------------------
$276,189 $203,340 $166,825
===============================================================================================
Intersegment Revenues
Exploration and production $ 43,471 $ 40,416 $ 29,811
Gas distribution 443 516 536
Energy services and other 17,692 16,072 17,187
- -----------------------------------------------------------------------------------------------
$ 61,606 $ 57,004 $ 47,534
===============================================================================================
Operating Income
Exploration and production $ 33,303 $ 34,184 $ 20,111
Gas distribution 17,152 14,223 10,833
Energy services and other 1,481 (411) 244
- -----------------------------------------------------------------------------------------------
$ 51,936 $ 47,996 $ 31,188
===============================================================================================
Identifiable Assets
Exploration and production $460,193 $423,321 $346,514
Gas distribution 206,285 197,880 183,410
Other 44,388 38,989 39,169
- -----------------------------------------------------------------------------------------------
$710,866 $660,190 $569,093
===============================================================================================
Depreciation, Depletion and Amortization
Exploration and production $ 40,340 $ 35,533 $ 29,607
Gas distribution 6,651 5,792 5,338
Other 1,217 1,069 1,047
- -----------------------------------------------------------------------------------------------
$ 48,208 $ 42,394 $ 35,992
===============================================================================================
Capital Additions
Exploration and production $ 73,526 $110,352 $ 82,237
Gas distribution 12,561 12,752 18,523
Other 2,734 1,809 866
- -----------------------------------------------------------------------------------------------
$ 88,821 $124,913 $101,626
===============================================================================================
(12) Contingencies and Commitments
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on approximately $78.2 million of
debt incurred in connection with the construction of the existing NOARK
pipeline. The Company's share of the several guarantee is 60%. Of the total
debt, Senior Secured Notes with a fixed interest rate of 9.74% and principal
balance of $50.4 million were outstanding at December 31, 1997, pursuant to a
long-term arrangement requiring annual principal payments of $3.2 million
together with interest on the unpaid balance. The remaining debt is pursuant to
a $30.0 million unsecured revolving credit agreement with a group of banks which
currently matures April 26, 1998. In connection with the partnership changes
discussed further in Note 7, NOARK also prepaid its 9.74% Senior Secured Notes
in January, 1998. The notes were refinanced with Senior Secured Notes payable to
the other general partner of NOARK. The partnership intends to refinance its
Senior Secured Notes and revolving credit agreement through a new issue of
long-term debt during 1998. Additionally, the Company's gas distribution
subsidiary has a transportation contract with NOARK for firm capacity of 52.3
MMcfd. The contract expires in 2002, and is renewable year-to-year thereafter
until terminated by 180 days' notice.
Under the several guarantee, the Company is required to fund its share of
NOARK's debt service which is not funded by either operations of the pipeline or
by the available line of credit. As a result of the expected integration of
NOARK 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.
42
In May, 1996, a lawsuit was filed against the Company involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties. In a related matter, a class action suit was filed against the
Company in May, 1996 on behalf of royalty owners alleging improprieties in the
disbursements of royalty proceeds. The Company feels these claims are
substantially without merit and intends to vigorously contest the claims brought
in each matter. While the amount of the potential claims is significant in the
aggregate, management believes, based on its investigation, that the Company's
ultimate liability, if any, will not be material to its consolidated financial
position or results of operations.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial condition or reported results of operations
of the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
(13) Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1997 and 1996:
Quarter Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
1997
------------------------------------------------------------
Operating revenues $88,919 $51,244 $48,644 $87,382
Operating income $25,094 $5,089 $3,121 $18,632
Net income (loss) $12,319 $29 $(1,267) $7,634
Basic and diluted earnings (loss) per share $.50 $.00 $(.05) $.31
1996
------------------------------------------------------------
Operating revenues $64,864 $36,382 $34,424 $67,670
Operating income $19,518 $8,073 $4,260 $16,145
Net income $9,334 $2,791 $212 $6,849
Basic and diluted earnings per share $.38 $.11 $.01 $.28
========================================================================================================
43
Financial and Operating Statistics
Southwestern Energy Company and Subsidiaries
1997 1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------
Financial Review (in thousands)
Operating revenues:
Exploration and production $100,129 $ 86,978 $ 63,285 $ 79,787 $ 79,374 $ 60,554
Gas distribution 154,538 143,141 119,855 127,060 131,892 117,495
Energy services and other 83,128 30,225 31,219 28,832 262 256
Intersegment revenues (61,606) (57,004) (47,534) (60,055) (36,684) (34,475)
- -----------------------------------------------------------------------------------------------------------------------------
276,189 203,340 166,825 175,624 174,844 143,830
- -----------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 46,806 42,851 37,133 36,395 42,962 35,848
Gas purchases - marketing 63,054 14,114 13,714 5,438 - -
Operating and general 59,167 50,509 44,436 42,506 40,093 34,970
Depreciation, depletion and amortization 48,208 42,394 35,992 35,546 30,944 23,880
Taxes, other than income taxes 7,018 5,476 4,362 3,657 3,281 3,144
- -----------------------------------------------------------------------------------------------------------------------------
224,253 155,344 135,637 123,542 117,280 97,842
- -----------------------------------------------------------------------------------------------------------------------------
Operating income 51,936 47,996 31,188 52,082 57,564 45,988
Interest expense, net (16,414) (13,044) (11,167) (8,867) (9,025) (9,983)
Other income (expense) (5,017) (4,015) (1,227) (2,362) (1,657) (421)
- -----------------------------------------------------------------------------------------------------------------------------
Income before income taxes, extraordinary item and
the cumulative effect of accounting change 30,505 30,937 18,794 40,853 46,882 35,584
- -----------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current (732) (5,569) (4,908) 9,288 13,704 7,403
Deferred 12,522 17,320 12,167 6,441 6,128 5,916
- -----------------------------------------------------------------------------------------------------------------------------
11,790 11,751 7,259 15,729 19,832 13,319
- -----------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and
cumulative effect of accounting change 18,715 19,186 11,535 25,124 27,050 22,265
Extraordinary item - - (295) - - -
Cumulative effect of change in accounting for
income taxes - - - - 10,126 -
- -----------------------------------------------------------------------------------------------------------------------------
Net income $ 18,715 $ 19,186 $ 11,240 $25,124 $ 37,176 $ 22,265
=============================================================================================================================
Cash flow from operations, net of working
capital changes (in thousands) $ 75,356 $ 67,585 $ 55,861 $66,613 $ 70,199 $ 49,730
Return on equity 8.45% 9.23% 5.78% 12.35% 14.66%(1) 14.53%
Gross profit margin 18.80% 23.60% 18.70% 29.66% 32.92% 31.97%
Net profit margin 6.78% 9.44% 6.74% 14.31% 15.47%(1) 15.48%
=============================================================================================================================
Common Stock Statistics(2)
Basic earnings per share before extraordinary item
and cumulative effect of accounting change $.76 $.78 $.46 $.98 $1.05 $.87
Basic earnings per share $.76 $.78 $.45 $.98 $1.44 $.87
Cash dividends declared and paid per share $.24 $.24 $.24 $.24 $.22 $.20
Book value per share $8.92 $8.41 $7.87 $7.92 $7.18 $5.97
Market price at year-end $12.88 $15.13 $12.75 $14.88 $18.00 $12.96
Number of shareholders of record at year-end 2,379 2,572 2,759 2,875 3,005 2,930
Average shares outstanding 24,738,882 24,705,256 25,130,781 25,684,110 25,684,110 25,683,963
============================================================================================================================
(1)Before the cumulative effect of accounting change.
(2)All share and per share data have been restated to reflect the effect of a
three-for-one stock split distributed in 1993.
44
1997 1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands)
Long-term debt, including current portion $299,543 $278,285 $210,828 $142,300 $127,000 $143,335
Common shareholders' equity 221,565 207,941 194,504 203,456 184,530 153,233
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization $521,108 $486,226 $405,332 $345,756 $311,530 $296,568
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $710,866 $660,190 $569,093 $486,074 $445,454 $427,175
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 57.23% 56.96% 51.65% 40.10% 40.19% 48.31%
Equity 42.77% 43.04% 48.35% 59.90% 59.81% 51.69%
=============================================================================================================================
Capital Expenditures (in millions)
Exploration and production $73.5 $110.3 $ 82.2 $55.4 $37.4 $30.8
Gas distribution 12.6 12.8 18.5 17.6 19.9 12.2
Other 2.7 1.8 .9 3.9 1.9 1.9
- -----------------------------------------------------------------------------------------------------------------------------
$88.8 $124.9 $101.6 $76.9 $59.2 $44.9
=============================================================================================================================
Exploration and Production
Natural gas:
Production, Bcf 33.4 34.8 34.5 37.7 35.7 25.8
Average price per Mcf $2.57 $2.26 $1.72 $2.04 $2.18 $2.26
Oil:
Production, MBbls 749 391 229 200 97 120
Average price per barrel $19.02 $21.21 $17.15 $15.89 $17.20 $19.75
Average production (lifting) cost per Mcf equivalent $.45 $.29 $.22 $.17 $.18 $.16
Proved reserves at year-end:
Natural gas, Bcf 291.4 297.5 294.9 316.1 318.8 312.3
Oil, MBbls 7,852 8,238 2,152 1,231 479 359
Total reserves, Bcf equivalent 338.5 346.9 307.8 323.5 321.7 314.5
=============================================================================================================================
Gas Distribution
Sales and transportation volumes, Bcf:
Residential 12.6 13.4 12.1 11.6 12.9 10.8
Commercial 8.4 8.8 7.6 7.2 7.8 6.6
Industrial 6.6 7.7 7.7 7.5 6.1 6.1
End-use transportation 6.6 5.5 5.2 4.8 5.6 5.2
- -----------------------------------------------------------------------------------------------------------------------------
34.2 35.4 32.6 31.1 32.4 28.7
Off-system transportation 2.8 3.6 9.8 10.7 11.7 2.5
- -----------------------------------------------------------------------------------------------------------------------------
37.0 39.0 42.4 41.8 44.1 31.2
- -----------------------------------------------------------------------------------------------------------------------------
Customers - year-end
Residential 154,864 151,880 147,267 144,486 140,761 136,895
Commercial 21,431 20,845 20,109 19,489 19,121 18,819
Industrial 311 326 340 348 348 357
- -----------------------------------------------------------------------------------------------------------------------------
176,606 173,051 167,716 164,323 160,230 156,071
- -----------------------------------------------------------------------------------------------------------------------------
Degree days 4,131 4,341 4,064 3,823 4,598 3,720
Percent of normal 103% 108% 102% 96% 115% 93%
=============================================================================================================================
45
Shareholder Information
Annual Meeting
The Annual Meeting of Shareholders of Southwestern Energy Company will be held
at the Northwest Arkansas Holiday Inn in Springdale, Arkansas, on Thursday, May
21, 1998, at 11:00 a.m. Central Daylight Time.
Stock Exchange Listing
Southwestern Energy Company's common stock is traded on the New York Stock
Exchange under the symbol SWN and is listed in alphabetical quotation listings
in most major newspapers as SowestEngy.
Independent Public Accountants
Arthur Andersen LLP
6450 South Lewis
Suite 300
Tulsa, Oklahoma 74136-1068
Financial Information
Financial analysts and investors who need additional information should contact
Stanley D. Green, Executive Vice President - Finance and Corporate Development,
at corporate headquarters, 501-521-1141.
Transfer Agent and Registrar
First Chicago Trust Company of New York
525 Washington Blvd.
Jersey City, NJ 07310
Phone 1-800-446-2617
Dividend Reinvestment Plan
Southwestern Energy Company offers holders of record
of its common stock the opportunity to purchase additional shares through its
Dividend Reinvestment Plan. Dividends and/or optional cash investments of up to
$1,000 monthly may be used to purchase additional shares of the Company's stock
for nominal service and broker's fees. Information about the Plan is available
from the administrator:
First Chicago Trust Company of New York
P.O. Box 2598
Jersey City, NJ 07303-2598
Phone 1-800-446-2617
Annual Report
The 1997 Annual Report filed with the Securities and Exchange Commission on Form
10-K is available to shareholders upon request by writing to the Secretary at
corporate headquarters.
Market Prices and Quarterly Dividends Paid
Range of Market Prices Cash Dividends Paid
- -----------------------------------------------------------------------------------------------------
1997 1996 1997 1996
- ------------------------------------------------------------------------------------------------------
March 31 $15.75 $13.25 $13.25 $10.63 $.06 $.06
June 30 $13.75 $11.63 $14.75 $11.88 $.06 $.06
September 30 $14.31 $12.00 $16.13 $13.63 $.06 $.06
December 31 $13.13 $11.25 $17.38 $14.25 $.06 $.06
- ------------------------------------------------------------------------------------------------------
Market prices represent transactions on the New York Stock Exchange.
46
Southwestern Energy Company and Subsidiaries
APPENDIX to 1997 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in four
areas; the Arkoma Basin, the Anadarko Basin, the Gulf Coast, and the Permian
Basin. The Arkoma Basin is located in the central section of western Arkansas
and the central section of eastern Oklahoma. Southwestern's activities are
concentrated in the historically productive Arkansas section of the Arkoma
Basin. The Anadarko Basin covers most of the western part of Oklahoma and
extends to the northwest into the northern panhandle of Texas and the panhandle
area of Oklahoma. The Permian Basin is located in west Texas and the southeast
corner of New Mexico. Southwestern's Gulf Coast operations include both onshore
and offshore activity along both the Texas and Louisiana coasts.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where it also provides distribution
service to communities in that area, including the towns of Ozark and
Clarksville. AWG's transmission and distribution lines extend north and supply
communities in the northwest part of the state, including the towns of
Fayetteville, Springdale, and Rogers. AWG's service area also extends east to
the Harrison and Mountain Home areas. This eastern section of the AWG system
receives a portion of its gas supply from a lateral line off of the NOARK
Pipeline System (NOARK) as discussed below. Through its division, Associated
Natural Gas Company (Associated), AWG provides distribution of natural gas to
communities in northeast Arkansas and parts of Missouri. Major communities
served in northeast Arkansas include Blytheville, Piggott, and Osceola. The
Associated distribution system also serves the "bootheel" area in southeast
Missouri, including the communities of Sikeston, New Madrid, and Caruthersville
and extends north to the Jackson area. In addition, Associated provides service
to Butler, Missouri, near the state's western border and Kirksville, Missouri,
near the state's northern border through connections off of interstate pipelines
in those areas.
Description of NOARK Pipeline System Operating Area:
Southwestern Energy Pipeline Company owns a general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Company's gathering and
transmission pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Forth Smith, at
the Fort Chaffee military reservation, and extends east through the Arkoma Basin
and across northern Arkansas. A lateral from NOARK extends north and connects to
AWG's distribution line in the Mountain Home area. NOARK crosses three
interstate pipelines in northeast Arkansas and ends at an interconnection with
Arkansas Western Pipeline Company's 8-mile interstate pipeline at the
Arkansas/Missouri border. This pipeline transports gas from NOARK to
Associated's distribution system.
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
- -----------------------------------------------------------------------------------------------------------
Gathering 442 -- 442
Transmission 753 606 1,359
Distribution 3,016 1,651 4,667
- -----------------------------------------------------------------------------------------------------------
4,211 2,257 6,468
===========================================================================================================