Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
Net income in 1996 was $19.2 million, or $.78 per share, up from $11.2
million, or $.45 per share, in 1995. Net income in 1994 was $25.1 million, or
$.98 per share.
The increase in 1996 earnings was evident in both of the Company's
major business segments. The exploration and production segment benefited from
improved natural gas prices while the gas distribution segment increased
deliveries to end-use customers due to colder weather and customer growth. The
decrease in 1995 earnings, as compared to 1994, was caused primarily by the
generally low level of gas prices and a decline in natural gas production.
Revenues and operating income for the Company's major business segments are
shown in the following table.
1996 1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Revenues
Exploration and production $ 87,017 $ 63,603 $ 80,123
Gas distribution 143,141 119,855 127,060
Other 256 256 308
Eliminations (41,188) (30,603) (37,305)
- --------------------------------------------------------------------------------
$189,226 $153,111 $170,186
================================================================================
Operating Income
Exploration and production $ 33,777 $ 20,315 $ 38,888
Gas distribution 14,425 11,013 13,386
Corporate expenses (206) (140) (192)
- --------------------------------------------------------------------------------
$ 47,996 $ 31,188 $ 52,082
================================================================================
Exploration and Production
The Company's exploration and production revenues increased 37% in 1996
and decreased 21% in 1995. 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. The decrease in 1995 was due to lower average gas prices
and a decline in the Company's offshore gas production.
Gas production increased to 34.8 billion cubic feet (Bcf) in 1996 up
from 34.5 Bcf in 1995. Gas production in 1995 decreased by 8% from 37.7 Bcf in
1994. The increase in sales to the Company's gas distribution systems in 1996
was partially offset by a reduction in sales to unaffiliated purchasers. The
production decrease in 1995 was primarily due to decreased sales from the
Company's offshore properties.
1996 1995 1994
- --------------------------------------------------------------------------------
Gas Production
Affiliated sales (Bcf) 16.3 13.9 13.9
Unaffiliated sales (Bcf) 18.5 20.6 23.8
- --------------------------------------------------------------------------------
34.8 34.5 37.7
- --------------------------------------------------------------------------------
Average price per Mcf $2.26 $1.72 $2.04
================================================================================
Oil Production
Unaffiliated sales (MBbls) 391 229 200
- --------------------------------------------------------------------------------
Average price per Bbl $21.21 $17.15 $15.89
================================================================================
Sales to unaffiliated purchasers of gas production were 18.5 Bcf in
1996, down from 20.6 Bcf in 1995 and 23.8 Bcf in 1994. The decreases in sales to
unaffiliated purchasers were primarily the result of declining production from
the Company's Fort Chaffee and Gulf of Mexico properties, partially offset by
sales from producing properties acquired in recent years. Production from the
Company's offshore properties declined to 2.0 Bcf in 1996, from 2.7 Bcf in 1995
and 5.6 Bcf in 1994. Sales to unaffiliated purchasers are made under contracts
which reflect current short-term prices and which are subject to seasonal price
swings.
The 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 Southwestern's gas distribution segment. Intersegment sales to
Arkansas Western Gas Company (AWG), the utility subsidiary which operates the
Company's northwest Arkansas utility system, were 10.1 Bcf in 1996, up from 8.5
Bcf in 1995, and 8.8 Bcf in 1994. The Company's gas production provided
approximately 62% of AWG's requirements in 1996, 65% in 1995, and 64% in 1994.
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 $3.03 per thousand cubic feet (Mcf) in 1996,
$2.40 per Mcf in 1995, and $2.98 per Mcf in 1994. Other sales to AWG are made
under long-term contracts with flexible pricing provisions and short-term
contracts based upon competitive bids.
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 6.2 Bcf
in 1996, 5.4 Bcf in 1995, and 5.1 Bcf in 1994. Deliveries to Associated
increased in 1996 and 1995 due to colder weather in the heating season.
Effective October, 1990, one of the Company's exploration and production
subsidiaries entered into a ten-year contract with Associated to supply its base
load system requirements at a price to be redetermined annually. The sales price
under this contract was $2.385 per Mcf for the contract period ending September
30, 1994, $2.20 per Mcf for the contract period ending September 30, 1995,
$1.785 per Mcf for the contract period ending September 30, 1996, and is
currently $2.225 per Mcf.
18
The overall average price received at the wellhead for the Company's
gas production was $2.26 per Mcf in 1996, $1.72 per Mcf in 1995, and $2.04 per
Mcf in 1994. The fluctuation in the average price received since 1994 reflects
changes in average annual spot market prices, an increase in the proportionate
share of the Company's production sold at spot market prices and under long-term
contracts with market-sensitive pricing, and the effect of the Gas Cost
Settlement. Natural gas prices were generally higher in 1996, as compared to
1995 and 1994 primarily due to colder than normal weather experienced across the
country in the 1995-1996 heating season and the resulting need to replenish
storage inventories during the summer of 1996.
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 premiums over spot prices which it
receives under the long-term contracts covering its intersegment sales. Future
changes in revenues from sales of the Company's gas production will be dependent
upon changes in the market price for gas, access to new markets, maintenance of
existing markets, and additions of new gas reserves.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. 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 which will continue to be developed 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 1996 totaled 391,000 barrels, up from 229,000
barrels in 1995 and 200,000 barrels in 1994. Effective November 1, 1996, the
Company purchased substantially all of the oil and gas properties owned by L.B.
Simmons Energy, Inc. The acquisition added proved reserves of 6 million barrels
of oil and 17 Bcf of gas. As a result of the acquisition, the Company expects
its oil production to more than double during 1997.
Gas Distribution
Gas distribution revenues fluctuate due to the pass-through of cost of
gas increases and decreases, and due to the effects of weather. Because of the
corresponding changes in purchased gas costs, the revenue effect of the
pass-through of gas cost changes has not materially affected net income.
1996 1995 1994
- --------------------------------------------------------------------------------
Gas Distribution Systems
Throughput (Bcf)
Sales volumes 29.9 27.4 26.3
Transportation volumes
End-use 5.5 5.2 4.8
Off-system 3.6 9.8 10.7
- --------------------------------------------------------------------------------
39.0 42.4 41.8
- --------------------------------------------------------------------------------
Average number of sales customers 168,568 164,672 159,897
- --------------------------------------------------------------------------------
Heating weather
Degree days 4,627 4,376 4,161
Percent of normal 105% 99% 95%
- --------------------------------------------------------------------------------
Average sales rate per Mcf $4.57 $4.12 $4.57
================================================================================
Gas distribution revenues increased by 19% in 1996 and decreased by 6%
in 1995. The increase in 1996 was due both to an increase in the average utility
rate and weather which was 6% colder than in 1995. The decrease in 1995 resulted
from lower purchased gas costs, caused in part by the Gas Cost Settlement, which
more than offset the effects of strong customer growth and weather which was 5%
colder than the prior year.
In 1996, AWG sold 18.8 Bcf to its customers at an average rate of $4.40
per Mcf, compared to 17.1 Bcf at $3.93 per Mcf in 1995 and 16.3 Bcf at $4.25 per
Mcf in 1994. Additionally, AWG transported 4.2 Bcf in 1996, 4.3 Bcf in 1995, and
4.0 Bcf in 1994 for its end-use customers. Associated sold 11.1 Bcf to its
customers in 1996 at an average rate of $4.87 per Mcf, compared to 10.3 Bcf in
1995 at $4.45 per Mcf and 10.0 Bcf at $5.10 per Mcf in 1994. Associated
transported 1.3 Bcf for its end-use customers in 1996, compared to .9 Bcf in
1995 and .8 Bcf in 1994. The increase in volumes sold and transported in 1996
for both AWG and Associated resulted from colder weather and from 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
Company's customers which are passed through to customers under automatic
adjustment clauses.
Total deliveries to industrial customers of AWG and Associated,
including transportation volumes, increased for the tenth consecutive year to
13.2 Bcf, up from 13.0 Bcf in 1995 and 12.3 Bcf in 1994. The steady increase
reflects both the success of the Company's industrial marketing efforts and the
continued economic strength of its service territory.
AWG also transported 3.6 Bcf of gas through its gathering system in
1996 for off-system deliveries, all to the NOARK Pipeline System (NOARK),
compared to 9.8 Bcf in 1995 and 10.7 Bcf in 1994. The decrease in 1996 was due
to the heavy on-system demands of the Company's gas distribution systems,
resulting from the colder 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 1996 and $.13 per Mcf
in 1995 and 1994.
19
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 3.0% to 4.0%
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 Arkansas Public Service
Commission (APSC) for a rate increase of $5.1 million annually. Tariffs
implemented as a result of this rate increase 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. In January,
1997, the Company filed rate increase requests totaling $5.4 million with the
APSC and the Missouri Public Service Commission (MPSC) for Associated's
operations. The APSC has 10 months and the MPSC has 11 months to respond to the
requests. Rate increase requests which may be filed in the future will depend on
customer growth, increases in operating expenses, and additional investments
in property, plant and equipment.
Regulatory Matters
The December, 1996 order issued by the APSC approving the rate increase
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 be filed contempo-
raneously with AWG's next rate increase request or in accordance with a
procedural schedule to be established by the APSC.
On June 12, 1996, the Circuit Court of Cole County, Missouri overturned
and remanded to the MPSC its order dated July 14, 1995, which had disallowed
recovery of approximately $2.1 million of gas costs incurred by Associated. The
disallowed costs represented amounts paid by Associated under a contract with
one of the Company's gas producing subsidiaries and take-or-pay costs paid to
Associated's interstate pipeline suppliers. The Circuit Court found that there
was not substantial and competent evidence in the record to disallow recovery of
the costs related to the contract with Southwestern's production subsidiary and
that the MPSC was required by federal law to allow Associated to recover the
take-or-pay costs. The MPSC has appealed the decision to the Missouri Court of
Appeals.
The Company does not expect the ultimate outcome of these matters to
have a material adverse impact on the results of operations or the financial
position of the Company.
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 for volumes equal to the
historical level of sales under the contract to be sold at the spot market index
plus a premium of $.95 per Mcf, while incremental sales volumes receive a
premium of $.50 per Mcf. In 1996, approximately 8.6 Bcf (net to the Company's
interest) was sold under the contract, compared to approximately 7.7 Bcf and 8.1
Bcf in 1995 and 1994, respectively.
AWG also purchases gas from unaffiliated producers under take-or-pay
contracts. Currently, the Company believes that it does not have a significant
exposure to liabilities resulting from these contracts, although such exposure
has increased in recent years as a result of a decline in its gas purchase
requirements which has occurred as some of its large business customers
converted to a transportation service offered by AWG and began to obtain their
own gas supplies directly from other sources. The Company expects to be able to
continue to satisfactorily manage its exposure to take-or-pay liabilities.
Operating Costs and Expenses
The Company's operating costs and expenses increased by 16% in 1996 and
by 3% in 1995. The increase in 1996 was due primarily to increases in purchased
gas costs, operating and general expenses, and depreciation, depletion and
amortization expense. Increased purchased gas costs resulted from increased
utility deliveries and higher per unit gas costs. 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. The
trend of increasing operating costs in the exploration and production segment is
expected to continue in the near-term as the Company's exploration and
acquisition activities are directed more to areas outside of Arkansas and as the
Company increases the percentage of oil in its production mix. The increase in
depreciation, depletion and amortization expense was due to an increase in the
amortization rate per unit of production in the exploration and production
segment. The increase in operating costs and expenses in 1995 was due primarily
to increased purchased gas costs related to increased utility deliveries,
increased general and administrative expenses, and increased production costs.
General
20
and administrative expenses increased due to inflationary increases in
payroll and other costs and from personnel additions in the Company's
exploration and production segment. Increased production costs in the
exploration and production segment were related to workovers of producing wells
and higher operating costs associated with the Company's expansion into areas
outside of Arkansas. Purchased gas costs are one of the largest expense items in
each year, typically representing 30% to 40% of the Company's total operating
costs and expenses. Purchased gas costs are influenced primarily by changes in
requirements for gas sales of the gas distribution segment, the price and mix of
gas 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. In recent years the impacts of
inflation have been mitigated by conditions in the industries in which the
Company operates. 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 were up 17% in 1996, as compared to 1995, due to an
increase in long-term debt. The increase in long-term debt is discussed below in
"Liquidity and Capital Resources." Interest capitalized increased by 69% in 1996
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. Interest costs were up 26% in 1995, as compared to 1994, due to
both an increase in long-term debt and higher average interest rates.
The change in other income in 1996, as compared to 1995, relates primarily
to an increase in the Company's share of operating losses incurred by NOARK. The
change in other income during 1995, as compared to 1994, relates to a decrease
in the Company's share of operating losses incurred by NOARK and accruals for
potential liabilities relating to certain regulatory gas cost issues and other
legal matters. The Company, through a subsidiary, holds a 48% general
partnership interest in NOARK and is the pipeline's operator. (See Note 7 of the
financial statements for additional discussion). NOARK became operational in
late 1992 and extends across northern Arkansas, crossing three major interstate
pipelines. NOARK has been operating below capacity and generating losses since
it was placed in service. The Company's share of the pretax loss from operations
for NOARK included in other income was $3.8 million in 1996, $.7 million in
1995, and $2.8 million in 1994. The 1995 pretax loss included $2.9 million of
income for the Company's share of a $6.0 million settlement of contract issues
with one of NOARK's transporters, as discussed below. Deliveries are currently
being made by NOARK to portions of AWG's distribution system, to Associated, and
to the interstate pipelines with which NOARK interconnects. In 1996, NOARK had
an average daily throughput of 58 million cubic feet of gas per day (MMcfd),
compared to 86 MMcfd in 1995 and 82 MMcfd in 1994. NOARK has a total
transportation capacity of approximately 141 MMcfd. AWG has contracted for 41
MMcfd of firm capacity on NOARK under a ten-year transportation contract, with
six years remaining on its original term. The contract is renewable year-to-year
until terminated by 180 days' notice. NOARK also had a five-year transportation
contract with Vesta Energy Company (Vesta) covering the marketer's commitment
for 50 MMcfd of firm transportation. The Company's exploration and production
segment was supplying 25 MMcfd of the volumes transported by Vesta under that
agreement. In late 1993, Vesta filed suit against NOARK, the Company, and
certain of its affiliates, and, effective January 1, 1994, ceased transporting
gas under its contract with NOARK. In late 1995, the suit was settled prior to
going to trial. In exchange for a $6.0 million payment to NOARK, Vesta was
released from its obligations under its firm transportation agreement and its
contract with the Company's affiliates.
The APSC has established a maximum transportation rate of approximately
$.285 per dekatherm for NOARK based on its original construction cost estimate
of approximately $73 million. Due to construction conditions and the addition of
a compressor station, the ultimate cost of the pipeline exceeded the original
estimate by approximately $30 million. NOARK competes primarily with two
interstate pipelines in its gathering area. One of those elected to become an
open access transporter subsequent to NOARK's start of construction. The
increased availability of transportation service has intensified the competitive
environment within which NOARK operates. The Company expects further losses from
its equity investment in NOARK until the pipeline is able to increase its level
of throughput and until improvement occurs in the competitive conditions which
determine the transportation rates NOARK can charge. Southeastern Michigan Gas
Enterprises, Inc. (SEMCO), the other general partner in NOARK which owns a 32%
interest, has announced it recorded an after-tax writedown in 1996 of $21
million related to its NOARK investment and loan guarantees. SEMCO indicated it
will seek to sell its interest in the pipeline to a company better positioned to
take advantage of opportunities which the pipeline could present. The Company
and the partners of NOARK are continuing to investigate options which would
improve NOARK's future financial prospects, including an extension into Oklahoma
that would provide additional access to gas supply. Until these options are
fully investigated, the Company is unable to determine whether its investment in
NOARK might be impaired or whether any loss might be incurred on its several
guarantees of NOARK's debt. However, management continues to believe that no
write-down of its investment in NOARK is appropriate at this time and that it
will realize its investment in NOARK over the life of the system.
21
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 1996, 1995,
and 1994, net cash pro-vided from operating activities totaled $67.6 million,
$55.9 million, and $66.6 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 77% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1996, 59% in 1995, and 92% in 1994.
Capital Expenditures
Capital expenditures totaled $124.9 million in 1996, $101.6 million in
1995, and $76.9 million in 1994. The Company's exploration and production
segment expenditures included acquisitions of oil and gas producing properties
totaling $45.8 million in 1996, $6.0 million in 1995 and $13.9 million in 1994.
In November, 1996, the Company acquired substantially all of the oil and gas
properties owned by L.B. Simmons Energy, Inc. ("Simmons") for $30.9 million. The
properties acquired from Simmons are located principally in Oklahoma and west
Texas.
1996 1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Capital Expenditures
Exploration and production $110,352 $ 82,237 $55,449
Gas distribution 12,752 18,523 17,577
Other 1,809 866 3,828
- --------------------------------------------------------------------------------
$124,913 $101,626 $76,854
================================================================================
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending will be adequate to allow the Company to maintain its
present markets, explore and develop existing gas and oil properties as well as
generate new drilling prospects, and finance improvements necessary due to
normal customer growth in its gas distribution segment.
Capital spending planned for 1997 totals $90.3 million, a decrease of
28% from 1996, consisting of $55.4 million for exploration and production, $20.0
million for producing property acquisitions, $12.3 million for gas distribution
system expenditures, and $2.6 million for general purposes.
Financing Requirements
Two floating rate revolving credit facilities provide the Company
access to $80.0 million of variable rate long-term capital. These facilities
have been temporarily expanded to $120.0 million to provide additional debt
financing to fund the acquisition of the Simmons properties. Borrowings
outstanding under these credit facilities totaled $96.5 million at the end of
1996 and $22.9 million at the end of 1995. The Company expects to refinance a
portion of this outstanding balance on a long-term basis during 1997.
In December, 1995, the Company issued $125.0 million of 6.70% Senior
Notes due 2005 under a $250.0 million shelf registration statement filed with
the Securities and Exchange Commission in November, 1995. Proceeds from the
issuance of these notes were used primarily to repay certain borrowings under
the Company's revolving credit facilities. In February, 1997, the Company filed
a supplement to the registration statement for the issuance of up to $125.0
million of Medium-Term Notes, representing the remaining available capacity
under the shelf registration statement. Debt securities may be issued in the
future under the shelf registration statement as circumstances dictate. The
Company's public notes are rated BBB+ by Standard and Poor's and Baa2 by Moody's
Investors Service.
The Company and an affiliate of the other general partner of NOARK are
required to severally guarantee the availability of certain minimum cash
balances to service NOARK's 9.7375% Senior Secured Notes. These notes are held
by a major insurance company which also has a 20% limited partnership interest
in NOARK. The notes had a balance of $53.6 million at December 31, 1996, with
final maturity in 2009. NOARK also has an unsecured long-term revolving credit
agreement with a group of banks which provides the partnership access to $30.0
million of additional funds. Amounts outstanding under this credit arrangement
were $28.7 million at December 31, 1996, and $23.2 million at December 31, 1995.
Amounts borrowed under the long-term revolving credit agreement are severally
guaranteed by the Company and an affiliate of the other general partner. The
Company's share of the several guarantee of the notes and the line of credit is
60%. In 1996, the Company advanced $1.3 million to NOARK to fund its share of
debt service payments. The Company expects to advance approximately $4.8 million
to NOARK during 1997 in connection with its guarantees. The anticipated
contributions in 1997 are more than the 1996 amount due to the receipt by NOARK
of the $6.0 million settlement payment from Vesta in December, 1995, as
discussed above. The cash received was used by NOARK to pay down its revolving
credit facility. The credit facility was used in 1996 to help fund NOARK's
long-term debt service payments before additional partner advances were
required.
22
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 1996, the
capital structure consisted of 57.0% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
43.0% equity, with a ratio of earnings to fixed charges of 2.3.
During 1997, the percentage of debt in the Company's capital structure
is expected to remain at approximately the current level as the Company funds
expenditures which will not generate cash flow until future periods, such as the
acquisition and interpretation of seismic data and the drilling of exploratory
wells. Over the longer term, the Company expects to lower the debt portion of
its capital structure through its policy of adjusting its routine capital
spending.
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 $31.1 million at the end of 1996, up from
$18.5 million at the end of 1995. Current assets increased by 14% to $72.9
million in 1996, while current liabilities decreased 8% to $41.8 million. The
increase in current assets at December 31, 1996, was due primarily to increases
in accounts receivable and under-recovered purchased gas costs. The increase in
accounts receivable was due to higher weather-related sales at year-end 1996 and
higher average gas prices. The decrease in current liabilities resulted
primarily from a decrease in over-recovered purchased gas costs. The Company had
under-recovered $3.0 million of purchased gas costs at December 31, 1996, which
will be recovered from its utility customers through automatic cost of gas
adjustment clauses included in its filed rate tariffs. This amount was
classified as a current asset. At December 31, 1995 the Company had
over-recovered purchased gas costs in the amount of $7.3 million. This amount
was classified as a current liability.
Information Regarding Forward-Looking Statements
This discussion and analysis of financial condition and results of
operations and the information provided elsewhere in this Annual Report include
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The Company
believes that its expectations are based on reasonable assumptions. No
assurances, however, can be given that its goals will be achieved. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements herein include (1) the timing and extent of changes
in commodity prices for gas and oil and interest rates, (2) the extent of the
Company's success in discovering, developing, and producing reserves, (3) the
effects of weather and regulation on the Company's gas distribution segment, and
(4) conditions in capital markets, availability of oil field services, drilling
rigs, and other equipment, as well as other competitive factors during the
periods covered by the forward-looking statements.
23
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, 1996 and
1995, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1996.
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, 1996 and 1995, and the results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
Arthur Andersen LLP
Tulsa, Oklahoma
February 5, 1997
24
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1996 1995 1994
- -----------------------------------------------------------------------------------------------
($in thousands, except per share amounts)
Operating Revenues
Gas sales $ 174,738 $ 142,455 $ 160,463
Oil sales 8,294 3,924 3,178
Gas transportation 4,210 4,964 4,721
Other 1,984 1,768 1,824
- -----------------------------------------------------------------------------------------------
189,226 153,111 170,186
- -----------------------------------------------------------------------------------------------
Operating Costs and Expenses
Purchased gas costs 42,851 37,133 36,395
Operating and general 50,509 44,436 42,506
Depreciation, depletion and amortization 42,394 35,992 35,546
Taxes, other than income taxes 5,476 4,362 3,657
- -----------------------------------------------------------------------------------------------
141,230 121,923 118,104
- -----------------------------------------------------------------------------------------------
Operating Income 47,996 31,188 52,082
- -----------------------------------------------------------------------------------------------
Interest Expense
Interest on long-term debt 15,982 12,984 9,962
Other interest charges 1,204 639 504
Interest capitalized (4,142) (2,456) (1,599)
- -----------------------------------------------------------------------------------------------
13,044 11,167 8,867
- -----------------------------------------------------------------------------------------------
Other Income (Expense) (4,015) (1,227) (2,362)
- -----------------------------------------------------------------------------------------------
Income Before Income Taxes and Extraordinary Item 30,937 18,794 40,853
- -----------------------------------------------------------------------------------------------
Income Taxes
Current (5,569) (4,908) 9,288
Deferred 17,320 12,167 6,441
- -----------------------------------------------------------------------------------------------
11,751 7,259 15,729
- -----------------------------------------------------------------------------------------------
Income Before Extraordinary Item 19,186 11,535 25,124
Extraordinary Loss Due to Early Retirement
of Debt (Net of $185 Tax Benefit) - (295) -
- -----------------------------------------------------------------------------------------------
Net Income $ 19,186 $ 11,240 $ 25,124
===============================================================================================
Earnings Per Share
Income before extraordinary item $.78 $.46 $.98
Extraordinary loss due to early retirement
of debt (net of $185 tax benefit) - (.01) -
- -----------------------------------------------------------------------------------------------
Net Income $.78 $.45 $.98
===============================================================================================
Weighted Average Common Shares Outstanding 24,705,256 25,130,781 25,684,110
===============================================================================================
The accompanying notes are an integral part of the financial statements.
25
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 1996 1995
- ------------------------------------------------------------------------------------------------------------------
(in thousands)
Assets
Current Assets
Cash $ 2,297 $ 1,498
Accounts receivable 39,928 35,541
Income taxes receivable 6,623 8,221
Inventories, at average cost 17,571 15,448
Under-recovered purchased gas costs, net 3,030 -
Other 3,484 3,188
- ------------------------------------------------------------------------------------------------------------------
Total current assets 72,933 63,896
- ------------------------------------------------------------------------------------------------------------------
Investments 6,557 9,114
- ------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $53,942,000
in 1996 and $51,337,000 in 1995 excluded from amortization 637,100 527,149
Gas distribution systems 203,070 193,258
Gas in underground storage 25,636 23,446
Other 22,031 19,717
- ------------------------------------------------------------------------------------------------------------------
887,837 763,570
Less: Accumulated depreciation, depletion and amortization 319,135 277,751
- ------------------------------------------------------------------------------------------------------------------
568,702 485,819
- ------------------------------------------------------------------------------------------------------------------
Other Assets 11,998 10,264
- ------------------------------------------------------------------------------------------------------------------
$ 660,190 $ 569,093
==================================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Current portion of long-term debt $ 3,071 $ 3,071
Accounts payable 25,644 23,989
Taxes payable 3,290 2,422
Customer deposits 4,904 4,619
Over-recovered purchased gas costs, net - 7,327
Other 4,913 3,982
- ------------------------------------------------------------------------------------------------------------------
Total current liabilities 41,822 45,410
- ------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 275,214 207,757
- ------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 128,895 115,461
Deferred investment tax credits 1,791 2,103
Other 4,527 3,858
- ------------------------------------------------------------------------------------------------------------------
135,213 121,422
- ------------------------------------------------------------------------------------------------------------------
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 21,336 21,272
Retained earnings, per accompanying statements 217,889 204,632
- ------------------------------------------------------------------------------------------------------------------
241,999 228,678
Less: Common stock in treasury, at cost, 3,019,200 shares in 1996 and
3,036,735 shares in 1995 33,603 33,795
Unamortized cost of restricted shares issued under stock incentive
plan, 40,020 shares in 1996 and 34,807 shares in 1995 455 379
- ------------------------------------------------------------------------------------------------------------------
207,941 194,504
- ------------------------------------------------------------------------------------------------------------------
$ 660,190 $ 569,093
==================================================================================================================
The accompanying notes are an integral part of the financial statements.
26
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income $ 19,186 $ 11,240 $ 25,124
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 42,674 36,272 35,825
Deferred income taxes 17,320 12,167 6,441
Equity in loss of partnership 3,778 696 2,818
Change in assets and liabilities:
(Increase) decrease in accounts receivable (4,387) (3,216) 2,569
(Increase) decrease in income taxes receivable 1,598 (6,729) (5,354)
Increase in inventories (2,123) (3,249) (2,619)
Increase in accounts payable 1,655 5,319 2,556
Increase (decrease) in taxes payable 868 214 (379)
Increase in customer deposits 285 387 305
Increase (decrease) in over-recovered purchased gas costs (10,357) 3,700 (560)
Net change in other current assets and liabilities (2,912) (940) (113)
- ----------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 67,585 55,861 66,613
- ----------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (124,913) (101,626) (76,854)
Investment in partnership (1,266) (4,968) (2,319)
(Increase) decrease in gas stored underground (2,190) 4,013 542
Other items 55 2,814 3,200
- ----------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (128,314) (99,767) (75,431)
- ----------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt 73,600 (29,400) 21,300
Payments on other long-term debt (6,143) (3,071) (6,000)
Net proceeds from issuance of Senior Notes - 121,978 -
Retirement of 10.63% Senior Notes and prepayment premium - (24,958) -
Purchase of treasury stock - (14,259) -
Dividends paid (5,929) (6,038) (6,164)
- ----------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 61,528 44,252 9,136
- ----------------------------------------------------------------------------------------------------------------
Increase in cash 799 346 318
Cash at beginning of year 1,498 1,152 834
- ----------------------------------------------------------------------------------------------------------------
Cash at end of year $ 2,297 $ 1,498 $ 1,152
================================================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1996 1995 1994
- ----------------------------------------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $ 204,632 $ 199,430 $ 180,470
Net income 19,186 11,240 25,124
Cash dividends declared ($.24 per share) (5,929) (6,038) (6,164)
- ----------------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $ 217,889 $ 204,632 $ 199,430
================================================================================================================
The accompanying notes are an integral part of the financial statements.
27
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 1996, 1995 and 1994
(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 70% 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 northwest and northeast Arkansas and parts of
Missouri, and obtains approximately 60% of its gas supply from one of the
Company's exploration and production subsidiaries. The customers of the gas
distribution segment consist of residential, commercial, and industrial users of
natural gas. 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 1996 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Property, Depreciation, Depletion and Amortization
Gas and Oil Properties-The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive) are
capitalized and amortized on an aggregate basis over the estimated lives of the
properties using the units-of-production method. The Company excludes all costs
of unevaluated properties from immediate amortization.
Gas Distribution Systems-Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of the
gas distribution system is provided using the straight-line method with average
annual rates for plant functions ranging from 2.2% to 6.5%. 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 105,000 of these customers are served in
northwest Arkansas and approximately 68,000 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.
28
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 2, 1996, rate schedules for the Company's northwest
Arkansas system 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,
1996 and 1995 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 interest rate and commodity price risks. There were no outstanding
interest rate swap agreements at December 31, 1996 or 1995.
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
Earnings per common share are based on the weighted average number of
common shares outstanding during each year.
During 1996 the Company issued 18,963 treasury shares under a
compensatory plan and for stock awards and returned to treasury 1,428 shares
cancelled from an earlier issue under the compensatory plan. The net weighted
average cost of these transactions was $.2 million.
(2) Long-Term Debt
Long-term debt as of December 31, 1996 and 1995 consisted of the
following:
1996 1995
- -----------------------------------------------------------------------------------------------------------------------
(in thousands)
Senior Notes
6.70% Series due December 1, 2005 $125,000 $125,000
8.69% Series due December 4, 1997 22,500 22,500
8.86% Series due in annual installments of $3.1 million through December 4, 2000 12,285 18,428
9.36% Series due in annual installments of $2.0 million beginning December 4, 2001 22,000 22,000
- -----------------------------------------------------------------------------------------------------------------------
181,785 187,928
Other
Variable rate (5.89% at December 31, 1996) unsecured revolving credit arrangements with two banks 96,500 22,900
- -----------------------------------------------------------------------------------------------------------------------
Total long-term debt 278,285 210,828
Less: Current portion of long-term debt 3,071 3,071
- -----------------------------------------------------------------------------------------------------------------------
$275,214 $207,757
=======================================================================================================================
The 8.69% Senior Notes are classified as long-term at December 31,
1996, because the Company has the intent and ability to refinance these notes on
a long-term basis prior to their due date.
In December, 1995, the Company issued $125.0 million of 6.70% fixed rate
Senior Notes. The notes mature with a single payment due after ten years.
In November, 1995, the Company exercised its prepayment option on its
10.63% Senior Notes due September 30, 2001. Certain costs of the redemption were
expensed in the fourth quarter of 1995 and are classified as an extraordinary
loss, net of related income tax effects, in the accompanying financial
statements.
29
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. These facilities have been temporarily
expanded to $120.0 million to provide additional debt financing to fund the
Company's capital spending program. Borrowings outstanding under these credit
facilities totaled $96.5 million at December 31, 1996, 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 1999 and 2000.
The Company intends to renew or replace the facilities prior to expiration.
The terms of the long-term debt instruments and agreements contain
covenants which impose certain restrictions on the Company, including limitation
of additional indebtedness and restrictions on the payment of cash dividends. At
December 31, 1996, approximately $116.3 million of retained earnings was
available for payment as dividends.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1997 through 2001, are $3.1 million, $3.1 million, $63.1 million,
$62.1 million, and $2.0 million. Total interest payments of $15.6 million, $12.9
million, and $10.2 million were made in 1996, 1995, and 1994, respectively.
(3) Income Taxes
The provision for income taxes included the following components:
1996 1995 1994
- -----------------------------------------------------------------------------------------------
(in thousands)
Federal:
Current $ (5,788) $ (5,436) $ 7,758
Deferred 15,799 11,434 5,588
State:
Current 219 528 1,530
Deferred 1,833 1,046 1,054
Investment tax credit amortization (312) (313) (201)
- -----------------------------------------------------------------------------------------------
Provision for income taxes $ 11,751 $ 7,259 $ 15,729
===============================================================================================
The provision for income taxes was an effective rate of 38.0% in 1996,
38.6% in 1995, and 38.5% in 1994. 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:
1996 1995 1994
- ---------------------------------------------------------------------------------------------------------
(in thousands)
Expected provision at federal statutory rate of 35% $ 10,828 $ 6,578 $ 14,299
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,334 1,023 1,682
Percentage depletion on gas and oil production (140) (70) (96)
Investment tax credit amortization (312) (313) (201)
Other 41 41 45
- ---------------------------------------------------------------------------------------------------------
Provision for income taxes $ 11,751 $ 7,259 $ 15,729
=========================================================================================================
The components of the Company's net deferred tax liability as of
December 31, 1996 and 1995 were as follows:
1996 1995
- ----------------------------------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $116,036 $103,612
Stored gas differences 6,008 5,435
Deferred purchased gas costs 3,907 236
Prepaid pension costs 1,637 1,561
Book over tax basis in partnerships 5,099 4,712
Other 748 971
- ----------------------------------------------------------------------------------------
133,435 116,527
- ----------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 814 681
Alternative minimum tax credit carryforward 2,716 -
Other 437 644
- ----------------------------------------------------------------------------------------
3,967 1,325
- ----------------------------------------------------------------------------------------
Net deferred tax liability $129,468 $115,202
========================================================================================
Total income tax payments of $4.0 million, $.9 million, and $14.6 million
were made in 1996, 1995, and 1994, respectively.
30
(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 1996 and 1995 included an expected long-term rate
of return on plan assets of 9%, a weighted average discount rate of 7.5% in 1996
and 8.5% in 1995 for the net pension cost computation, and a salary progression
rate of 5%. The reconciliation of prepaid pension cost at December 31, 1996
utilizes a discount rate of 7.5% for future settlements.
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1996 and 1995:
1996 1995
- ------------------------------------------------------------------------------------------
(in thousands)
Actuarial present value of benefit obligations:
Vested benefits $ (30,371) $ (25,789)
Nonvested benefits (2,574) (1,860)
- ------------------------------------------------------------------------------------------
Accumulated benefit obligation (32,945) (27,649)
Effect of projected future compensation levels (9,096) (8,623)
- ------------------------------------------------------------------------------------------
Projected benefit obligation (42,041) (36,272)
Plan assets at fair value, primarily common stocks and bonds 56,457 49,570
- ------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 14,416 13,298
Unrecognized net gain (9,962) (8,956)
Unrecognized net asset (769) (952)
Unrecognized prior service cost 354 397
- ------------------------------------------------------------------------------------------
Prepaid pension cost $ 4,039 $ 3,787
==========================================================================================
Net pension cost for 1996, 1995, and 1994 included the following
components:
1996 1995 1994
- -----------------------------------------------------------------------------------------------
(in thousands)
Service costs (benefits earned during the period) $ 1,520 $ 1,101 $ 1,217
Interest cost on projected benefit obligation 2,850 2,316 2,280
Actual return on plan assets (8,332) (15,172) (791)
Net amortization and deferral 3,710 11,699 (2,643)
- -----------------------------------------------------------------------------------------------
Net pension cost (credit) $ (252) $ (56) $ 63
===============================================================================================
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $81,000,
$221,000, and $201,000 in 1996, 1995, and 1994, respectively. At December 31,
1996, the supplemental retirement plan had an accrued pension cost of $172,000.
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.
A significant portion of the postretirement benefit cost relates to the
Company's utility operations and has been deferred as a regulatory asset. Net
postretirement benefit cost for 1996 and 1995 included the following components:
1996 1995
- ------------------------------------------------------------------------------------
(in thousands)
Service cost of benefits earned during the year $ 61 $110
Amortization of transition amount 103 103
Amortization of unrecognized gain 4 32
Interest cost on accumulated postretirement benefit obligation (APBO) 161 218
- ------------------------------------------------------------------------------------
Net postretirement benefit cost $329 $463
====================================================================================
The APBO as of December 31, 1996 and 1995 was comprised of the
following:
1996 1995
- -----------------------------------------------------------------------------------
(in thousands)
Retirees $1,037 $1,109
Active participants, fully eligible 326 303
Other participants 926 805
- ------------------------------------------------------------------------------------
Total APBO $2,289 $2,217
====================================================================================
31
In determining the APBO, an assumed weighted average discount rate of
7.5% was used for 1996 and 1995. An increase of 10% in the cost of covered
health care benefits was assumed for 1997. This rate is assumed to decrease
ratably to 6.0% over 8 years and remain at that level thereafter. The effect of
a one percentage point increase in the assumed health care cost trend rate for
each future year would increase the total APBO at year-end 1996 by $262,000 and
the 1996 net postretirement benefit cost by $29,000.
(5) Natural Gas and Oil Producing Activities
All of the Company's gas and oil properties are located in the United
States. The table below sets forth the results of operations from gas and oil
producing activities:
1996 1995 1994
- -----------------------------------------------------------------------------------------------
(in thousands)
Sales $ 86,984 $ 63,205 $ 80,123
Production (lifting) costs (10,607) (7,930) (6,771)
Depreciation, depletion and amortization (35,533) (29,607) (29,738)
- -----------------------------------------------------------------------------------------------
40,844 25,668 43,614
Income tax expense (15,531) (9,831) (16,684)
- -----------------------------------------------------------------------------------------------
Results of operations $ 25,313 $ 15,837 $ 26,930
===============================================================================================
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 1996, 1995,
and 1994:
1996 1995 1994
- -----------------------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $ 60,748 $ 27,715 $ 21,972
Exploration costs 25,436 29,843 12,419
Development costs 23,667 24,429 20,943
- -----------------------------------------------------------------------------------------------
Capitalized costs incurred $ 109,851 $ 81,987 $ 55,334
===============================================================================================
Amortization per Mcf equivalent $.949 $.817 $.759
===============================================================================================
The following table shows the capitalized costs of gas and oil
properties and the related accumulated depreciation, depletion and amortization
at December 31, 1996 and 1995:
1996 1995
- -----------------------------------------------------------------------------------------------
(in thousands)
Proved properties $ 575,458 $ 473,038
Unproved properties 61,642 54,111
- -----------------------------------------------------------------------------------------------
Total capitalized costs 637,100 527,149
Less: Accumulated depreciation, depletion and amortization 241,237 206,148
- -----------------------------------------------------------------------------------------------
Net capitalized costs $ 395,863 $ 321,001
===============================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1996. Included in these costs is
$5.0 million representing leasehold and seismic costs related to the remaining
uneval-uated portion of acreage located on the Fort Chaffee military
reservation. These costs are expected to be evaluated and subjected to
amortization within the next several years as this acreage is further explored
and developed. Included in exploration costs is $15.2 million of 3-D seismic
costs primarily related to the Company's activities 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.
1996 1995 1994 Prior Total
- ----------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $12,084 $ 7,012 $2,269 $6,101 $27,466
Exploration costs 11,032 6,822 1,538 1,228 20,620
Capitalized interest 3,936 982 293 645 5,856
- ----------------------------------------------------------------------------------
$27,052 $14,816 $4,100 $7,974 $53,942
==================================================================================
32
(6) Natural Gas and Oil Reserves (Unaudited)
The following table summarizes the changes in the Company's proved
natural gas and oil reserves for 1996, 1995, and 1994:
1996 1995 1994
- ------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
- ------------------------------------------------------------------------------------------------------
Proved reserves, beginning of year 294,876 2,152 316,098 1,231 318,776 479
Revisions of previous estimates (11,772) 74 (25,970) (199) (16,551) (258)
Extensions, discoveries, and other additions 16,429 61 34,801 498 30,932 189
Production (34,758) (391) (34,515) (229) (37,706) (200)
Acquisition of reserves in place 32,713 6,350 4,462 851 20,647 1,038
Disposition of reserves in place (21) (8) - - - (17)
- -----------------------------------------------------------------------------------------------------
Proved reserves, end of year 297,467 8,238 294,876 2,152 316,098 1,231
=====================================================================================================
Proved, developed reserves:
Beginning of year 248,714 1,975 261,690 1,116 260,240 469
End of year 255,234 7,804 248,714 1,975 261,690 1,116
=====================================================================================================
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, 1996, 1995, and 1994:
1996 1995 1994
- -----------------------------------------------------------------------------------------------------
(in thousands)
Future cash inflows $1,340,804 $ 751,261 $ 683,438
Future production and development costs (187,825) (106,092) (96,813)
Future income tax expense (398,625) (229,064) (207,359)
- -----------------------------------------------------------------------------------------------------
Future net cash flows 754,354 416,105 379,266
10% annual discount for estimated timing of cash flows (383,410) (212,583) (189,774)
- -----------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 370,944 $ 203,522 $ 189,492
=====================================================================================================
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
1996, 1995, and 1994:
1996 1995 1994
- ----------------------------------------------------------------------------------------------------
(in thousands)
Standardized measure, beginning of year $203,522 $189,492 $227,275
Sales and transfers of gas and oil produced, net of production costs (76,377) (55,275) (73,352)
Net changes in prices and production costs 185,234 39,928 (29,344)
Extensions, discoveries, and other additions,
net of future production and development costs 40,264 49,471 43,458
Acquisition of reserves in place 98,245 7,962 17,934
Revisions of previous quantity estimates (19,839) (29,851) (19,225)
Accretion of discount 31,043 28,733 34,968
Net change in income taxes (80,662) (9,073) 24,564
Changes in production rates (timing) and other (10,486) (17,865) (36,786)
- ----------------------------------------------------------------------------------------------------
Standardized measure, end of year $370,944 $203,522 $189,492
====================================================================================================
(7) Investment in Unconsolidated Partnership
The Company holds a general partnership interest in NOARK of 47.93% and
is the pipeline's operator. NOARK is a 258-mile long intrastate gas transmission
system which extends across northern Arkansas and was placed in service in
September, 1992. The Company's investment in NOARK totaled $6.5 million at
December 31, 1996 and $9.0 million at December 31, 1995. The Company's
investment in NOARK includes advances of $1.3 million made during 1996, $5.0
million during 1995, and $2.3 million during 1994, primarily to provide certain
minimum cash balances to service NOARK's long-term debt. See Note 12 for further
discussion of NOARK's funding requirements and the Company's investment in
NOARK.
33
NOARK's financial position at December 31, 1996 and 1995 is summarized
below:
1996 1995
- --------------------------------------------------------------------------------
(in thousands)
Current assets $ 925 $ 870
Noncurrent assets 95,490 98,048
- --------------------------------------------------------------------------------
$ 96,415 $ 98,918
================================================================================
Current liabilities $ 7,668 $ 6,624
Long-term debt 79,150 76,700
Loans from general partners 13,615 11,505
Partners' capital (deficit) (4,018) 4,089
- --------------------------------------------------------------------------------
$ 96,415 $ 98,918
================================================================================
The Company's share of NOARK's pretax loss, before the effect of
accrued interest expense on general partner loans, was $3.8 million, $.7
million, and $2.8 million for 1996, 1995, and 1994, 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 1996, 1995, and 1994 are summarized
below:
1996 1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Operating revenues $ 5,114 $11,657 $10,111
Pretax loss $(8,106) $(2,167) $(5,917)
================================================================================
(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.
The carrying amounts and estimated fair values of the Company's
financial instruments as of December 31, 1996 and 1995 were as follows:
1996 1995
- ------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------------------------------------------------------
(in thousands)
Cash $ 2,297 $ 2,297 $ 1,498 $ 1,498
Customer deposits $ 4,904 $ 4,904 $ 4,619 $ 4,619
Long-term debt $278,285 $279,692 $210,828 $216,364
Commodity hedges $518 $(1,717) $707 $(1,328)
=====================================================================================
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).
34
At December 31, 1996, the Company had outstanding natural gas price
swaps on total notional volumes of 12.1 Bcf for periods covering January through
October, 1997. Of the total, 11.5 Bcf have fixed price receipts ranging from
$2.11 to $2.82 per MMBtu and the remaining .6 Bcf covering the periods January
through March, 1997, had an average fixed price payment of $3.21 per MMBtu with
the price receipts being variable based on the NYMEX futures market. The Company
held outstanding basis swaps on a notional volume of 5.5 Bcf for periods
covering January through March, 1997. 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. At December 31, 1995, the Company had
outstanding natural gas price swaps on a notional volume of 2.0 Bcf for periods
covering January through March, 1996. There were no basis swaps outstanding at
December 31, 1995. During 1996, the Company recognized losses from price risk
management activities of $3.4 million, which were offset by corresponding
revenue receipts from physical transactions. In 1995 and 1994, the Company
recognized price risk management losses of $.6 million and $.1 million,
respectively.
The Company uses options to fix a floor or both a floor and ceiling (a
"collar") for prices on its production volumes. At December 31, 1996, the
Company had a fixed-priced collar agreement for a notional volume of 5.6 Bcf
covering April through October, 1997, which provides a floor price of $2.00 and
sets a ceiling price of $2.80 per MMBtu. The Company has also purchased a crude
oil price floor of $18.00 per barrel on total notional volumes of 1,450,000
barrels covering production during calendar years 1998 through 2001. At December
31, 1995, there were no similar options outstanding.
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) Segment Information
Intersegment sales by the exploration and production segment to the gas
distribution segment are priced in accordance with terms of existing gas
contracts and current market conditions. Following is industry segment data for
the years ended December 31, 1996, 1995, and 1994:
1996 1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Revenues
Exploration and production $ 87,017 $ 63,603 $ 80,123
Gas distribution 143,141 119,855 127,060
Other 256 256 308
Eliminations (41,188) (30,603) (37,305)
- --------------------------------------------------------------------------------
$189,226 $153,111 $170,186
================================================================================
Intersegment Revenues
Exploration and production $ 40,416 $ 29,811 $ 36,465
Gas distribution 516 536 584
Other 256 256 256
- --------------------------------------------------------------------------------
$ 41,188 $ 30,603 $ 37,305
================================================================================
Operating Income
Exploration and production $ 33,777 $ 20,315 $ 38,888
Gas distribution 14,425 11,013 13,386
Corporate expenses (206) (140) (192)
- --------------------------------------------------------------------------------
$ 47,996 $ 31,188 $ 52,082
================================================================================
Identifiable Assets
Exploration and production $427,303 $347,716 $288,175
Gas distribution 197,880 183,410 171,471
Other 35,007 37,967 26,428
- --------------------------------------------------------------------------------
$660,190 $569,093 $486,074
================================================================================
Depreciation, Depletion and Amortization
Exploration and production $ 35,540 $ 29,607 $ 29,738
Gas distribution 5,792 5,338 4,981
Other 1,062 1,047 827
- --------------------------------------------------------------------------------
$ 42,394 $ 35,992 $ 35,546
================================================================================
Capital Additions
Exploration and production $110,352 $ 82,237 $ 55,449
Gas distribution 12,752 18,523 17,577
Other 1,809 866 3,828
- --------------------------------------------------------------------------------
$124,913 $101,626 $ 76,854
================================================================================
35
(10) Stock Options
The Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan)
provides for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan provides for grants of options, shares of
restricted stock, and stock bonuses that in the aggregate do not exceed
1,275,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock, and cash awards, the shares related to which in the
aggregate do not exceed 1,275,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The types of incentives which may
be awarded are comprehensive and are intended to enable the Board of Directors
to structure the most appropriate incentives and to address changes in income
tax laws which may be enacted over the term of the plan.
The Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors provides for annual stock option grants of 12,000 shares (with 12,000
limited SARs) to each non-employee director. Options may be awarded under the
plan on no more than 240,000 shares. The Company's 1985 Nonqualified Stock
Option Plan, expired in 1992, except with respect to awards then outstanding.
The following table summarizes stock option activity for the years 1996,
1995 and 1994:
1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------
Exercise Exercise Exercise
Shares Price Range Shares Price Range Shares Price Range
- --------------------------------------------------------------------------------------------------------------------
Options outstanding at January 1 1,552,558 $5.58-$17.50 1,411,558 $5.58-$17.50 579,854 $5.58-$17.50
Granted 129,000 $14.75-$15.13 186,000 $12.63-$13.38 831,704 $14.63-$14.75
Exercised 6,000 $12.81 - - - -
Canceled 173,917 $12.81-$17.50 45,000 $14.75-$17.50 - -
- ---------------------------------------------------------------------------------------------------------------------
Options outstanding at December 31 1,501,641 $5.58-$17.50 1,552,558 $5.58-$17.50 1,411,558 $5.58-$17.50
=====================================================================================================================
All options are issued at fair market value at the date of grant and
expire ten years from the date of grant. Options were exercisable with respect
to 588,695 shares at December 31, 1996. Options generally vest to employees and
directors over a three to four year period from the date of grant. Of the total
options outstanding, 670,000 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.
Under the 1993 Plan, 55,177 shares of restricted stock have been granted to
employees through 1996. Of this total, 14,055 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 has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS No. 123"). Accordingly, no compensation cost has been
recognized for the stock option plans. Had compensation cost for the Company's
stock options 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:
1996 1995
- --------------------------------------------------------------------------------
Net Income:
As Reported $19,186 $11,240
Pro Forma $19,055 $11,226
Earnings Per Share
As Reported $.78 $.45
Pro Forma $.77 $.45
================================================================================
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 1.6% to 1.9%; expected volatility of 24.9% to
26.2%; risk-free interest rate of 5.71% to 7.38%; and expected lives of 6 years.
(11) Common Stock Purchase Rights
One common share purchase right is attached to each outstanding share of
the Company's common stock. Each right entitles the holder to purchase one share
of common stock at an exercise price of $25.00, subject to adjustment. These
rights will become exercisable in the event that a person or group acquires or
commences a tender offer for 20% or more of the Company's outstanding shares or
the Board determines that a holder of 10% or more of the Company's outstanding
shares presents a threat to the best interests of the Company. At no time will
these rights have any voting power.
If any person or entity actually acquires 20% of the common stock (10% or
more if the Board determines such acquiror is adverse), rightholders (other than
the 20% or 10% stockholder) will be entitled to buy, at the right's then current
exercise price, the Company's common stock with a market value of twice the
exercise price. Similarly, if the Company is acquired in a merger or other
business 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.
36
The rights may be redeemed by the Board for $.003 per right prior to the
time that they become exercisable. In the event, however, that redemption of the
rights is considered in connection with a proposed acquisition of the Company,
the Board may redeem the rights only on the recommendation of its independent
directors (nonmanagement directors who are not affiliated with the proposed
acquiror). These rights expire in 1999.
(12) Contingencies and Commitments
The Company and the other general partner of NOARK are required to
severally guarantee the availability of certain minimum cash balances to service
the 9.7375% Senior Secured Notes used to finance a portion of NOARK's total
construction cost. At December 31, 1996, the Senior Secured Notes had a
remaining balance of $53.6 million and a remaining term of 13 years. At December
31, 1996, NOARK also had an unsecured long-term revolving credit agreement in
the amount of $30.0 million with a group of banks, of which $28.7 million was
outstanding. Amounts borrowed under the long-term revolving credit facility are
severally guaranteed by the Company and an affiliate of the other general
partner. The Company's share of the several guarantee of the notes and the line
of credit is 60%. Additionally, the Company's gas distribution subsidiary has a
transportation contract with an original term of ten years with NOARK for firm
capacity of 41 MMcfd. The remaining term of that contract is six years and is
renewable year-to-year until terminated by 180 days' notice.
In late 1993, a transporter of gas on NOARK's pipeline system filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its firm transportation agreement
with NOARK. In December, 1995, the parties to the lawsuit settled prior to going
to trial. In exchange for a $6.0 million payment to NOARK, the transporter was
released from its obligations under its firm transportation agreement. The
Company will be required to fund its share of any cash flow deficiencies to the
extent they are not funded by the available line of credit. Management of the
Company and the NOARK partners continue to investigate options available to
NOARK. However, management believes that no write-down of its investment in
NOARK is appropriate at this time and that it will realize its investment in
NOARK over the life of the system. Therefore, no provision for any loss has been
made in the accompanying financial statements.
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 purported 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, 1996 and 1995:
Quarter Ended March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
1996
- ----------------------------------------------------------------------------------------------------------------
Operating revenues $63,862 $34,304 $30,252 $60,808
Operating income $19,518 $8,073 $4,260 $16,145
Net income $9,334 $2,791 $212 $6,849
Earnings per share $.38 $.11 $.01 $.28
1995
- -----------------------------------------------------------------------------------------------------------------
Operating revenues $51,751 $30,642 $25,454 $45,264
Operating income $15,090 $3,927 $1,955 $10,216
Net income (loss) $7,102 $445 $(1,081) $4,774
Earnings (loss) per share $.28 $.02 $(.04) $.19
=================================================================================================================
37
Financial and Operating Statistics
Southwestern Energy Company and Subsidiaries
1996 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
Financial Review (in thousands)
Operating revenues:
Exploration and production $ 87,017 $ 63,603 $ 80,123 $ 79,374 $ 60,554 $ 49,392
Gas distribution 143,141 119,855 127,060 131,892 117,495 121,302
Other 256 256 308 262 256 256
Intersegment revenues (41,188) (30,603) (37,305) (36,684) (34,475) (34,511)
- ------------------------------------------------------------------------------------------------------------------------------------
189,226 153,111 170,186 174,844 143,830 136,439
- ------------------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 42,851 37,133 36,395 42,962 35,848 40,423
Operating and general 50,509 44,436 42,506 40,093 34,970 32,609
Depreciation, depletion and amortization 42,394 35,992 35,546 30,944 23,880 18,248
Taxes, other than income taxes 5,476 4,362 3,657 3,281 3,144 3,017
- ------------------------------------------------------------------------------------------------------------------------------------
141,230 121,923 118,104 117,280 97,842 94,297
- ------------------------------------------------------------------------------------------------------------------------------------
Operating income 47,996 31,188 52,082 57,564 45,988 42,142
Interest expense, net (13,044) (11,167) (8,867) (9,025) (9,983) (9,813)
Other income (expense) (4,015) (1,227) (2,362) (1,657) (421) (107)
- ------------------------------------------------------------------------------------------------------------------------------------
Income before income taxes, extraordinary item
and the cumulative effect of accounting change 30,937 18,794 40,853 46,882 35,584 32,222
- ------------------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current (5,569) (4,908) 9,288 13,704 7,403 7,158
Deferred 17,320 12,167 6,441 6,128 5,916 4,999
- ------------------------------------------------------------------------------------------------------------------------------------
11,751 7,259 15,729 19,832 13,319 12,157
- ------------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative
effect of accounting change 19,186 11,535 25,124 27,050 22,265 20,065
Extraordinary loss due to early retirement of debt
(net of $185 tax benefit) - (295) - - - -
Cumulative effect of change in accounting for
income taxes - - - 10,126 - -
- ------------------------------------------------------------------------------------------------------------------------------------
Net income $ 19,186 $ 11,240 $ 25,124 $ 37,176 $ 22,265 $ 20,065
====================================================================================================================================
Cash flow from operations (in thousands) $ 67,585 $ 55,861 $ 66,613 $ 70,199 $ 49,730 $ 34,986
Return on equity 9.23% 5.78% 12.35% 14.66%(1) 14.53% 14.75%
Gross profit margin 25.36% 20.37% 30.60% 32.92% 31.97% 30.89%
Net profit margin 10.14% 7.34% 14.76% 15.47%(1) 15.48% 14.71%
====================================================================================================================================
Common Stock Statistics(2)
Earnings per share before extraordinary item and
cumulative effect of accounting change $.78 $.46 $.98 $1.05 $.87 $.78
Earnings per share $.78 $.45 $.98 $1.44 $.87 $.78
Cash dividends declared and paid per share $.24 $.24 $.24 $.22 $.20 $.19
Book value per share $8.41 $7.87 $7.92 $7.18 $5.97 $5.30
Market price at year-end $15.13 $12.75 $14.88 $18.00 $12.96 $10.50
Number of shareholders of record at year-end 2,572 2,759 2,875 3,005 2,930 2,989
Average shares outstanding 24,705,256 25,130,781 25,684,110 25,684,110 25,683,963 25,678,011
====================================================================================================================================
(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.
38
1996 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands)
Long-term debt, including current portion $278,285 $210,828 $142,300 $127,000 $143,335 $134,104
Common shareholders' equity 207,941 194,504 203,456 184,530 153,233 136,041
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $486,226 $405,332 $345,756 $311,530 $296,568 $270,145
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $660,190 $569,093 $486,074 $445,454 $427,175 $392,208
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 56.96% 51.65% 40.10% 40.19% 48.31% 49.08%
Equity 43.04% 48.35% 59.90% 59.81% 51.69% 50.92%
====================================================================================================================================
Capital Expenditures (in millions)
Exploration and production $110.3 $ 82.2 $55.4 $37.4 $30.8 $30.3
Gas distribution 12.8 18.5 17.6 19.9 12.2 7.9
Other 1.8 .9 3.9 1.9 1.9 .7
- ------------------------------------------------------------------------------------------------------------------------------------
$124.9 $101.6 $76.9 $59.2 $44.9 $38.9
====================================================================================================================================
Exploration and Production
Natural gas:
Production, Bcf 34.8 34.5 37.7 35.7 25.8 20.3
Average price per Mcf $2.26 $1.72 $2.04 $2.18 $2.26 $2.25
Oil:
Production, MBbls 391 229 200 97 120 176
Average price per barrel $21.21 $17.15 $15.89 $17.20 $19.75 $20.67
Average production (lifting) cost per Mcf equivalent $.29 $.22 $.17 $.18 $.16 $.19
Proved reserves at year-end:
Natural gas, Bcf 297.5 294.9 316.1 318.8 312.3 307.5
Oil, MBbls 8,238 2,152 1,231 479 359 505
Total Reserves, Bcf equivalent 346.9 307.8 323.5 321.7 314.5 310.5
====================================================================================================================================
Gas Distribution
Sales and transportation volumes, Bcf:
Residential 13.4 12.1 11.6 12.9 10.8 10.9
Commercial 8.8 7.6 7.2 7.8 6.6 6.7
Industrial 7.7 7.7 7.5 6.1 6.1 9.5
End-use transportation 5.5 5.2 4.8 5.6 5.2 1.3
- ------------------------------------------------------------------------------------------------------------------------------------
35.4 32.6 31.1 32.4 28.7 28.4
Off-system transportation 3.6 9.8 10.7 11.7 2.5 .2
- ------------------------------------------------------------------------------------------------------------------------------------
39.0 42.4 41.8 44.1 31.2 28.6
- ------------------------------------------------------------------------------------------------------------------------------------
Customers - year-end
Residential 151,880 147,267 144,486 140,761 136,895 132,304
Commercial 20,845 20,109 19,489 19,121 18,819 18,500
Industrial 326 340 348 348 357 363
- ------------------------------------------------------------------------------------------------------------------------------------
173,051 167,716 164,323 160,230 156,071 151,167
- ------------------------------------------------------------------------------------------------------------------------------------
Degree days 4,627 4,376 4,161 4,929 4,104 4,095
Percent of normal 105% 99% 95% 113% 92% 93%
====================================================================================================================================
39
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
22, 1997, 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 1996 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
- --------------------------------------------------------------------------------
1996 1995 1996 1995
- --------------------------------------------------------------------------------
March 31 $13.25 $10.63 $15.13 $11.75 $.06 $.06
June 30 $14.75 $11.88 $15.50 $13.63 $.06 $.06
September 30 $16.13 $13.63 $14.25 $12.00 $.06 $.06
December 31 $17.38 $14.25 $14.25 $12.25 $.06 $.06
================================================================================
Market prices represent transactions on the New York Stock Exchange.
41
Southwestern Energy Company and Subsidiaries
APPENDIX to 1996 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in five
areas; the Arkoma Basin, the Anadarko Basin, the Midland Basin, the Gulf Coast,
and the Delaware Basin of New Mexico. The Arkoma Basin is located in the central
section of western Arkansas and the central section of eastern Oklahoma.
Southwestern's activities are concentrated in the historically productive
Arkansas section of the Arkoma Basin. The Anadarko Basin covers most of the
western part of Oklahoma and extends to the northwest into the northern
panhandle of Texas and the panhandle area of Oklahoma. The Midland Basin is
located in west Texas, just east of New Mexico. Southwestern's Gulf Coast
operations include both onshore and offshore activity along both the Texas and
Louisiana coasts. The Delaware Basin is located in the southeast corner of New
Mexico and extends to the south into western Texas.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where it also provides distribution
service to communities in that area, including the towns of Ozark and
Clarksville. AWG's transmission and distribution lines extend north and supply
communities in the northwest part of the state, including the towns of
Fayetteville, Springdale, and Rogers. AWG's service area also extends east to
the Harrison and Mountain Home areas. This eastern section of the AWG system
receives a portion of its gas supply from a lateral line off of the NOARK
Pipeline System (NOARK) as discussed below. Through its division, Associated
Natural Gas Company (Associated), AWG provides distribution of natural gas to
communities in northeast Arkansas and parts of Missouri. Major communities
served in northeast Arkansas include Blytheville, Piggott, and Osceola. The
Associated distribution system also serves the "bootheel" area in southeast
Missouri, including the communities of Sikeston, New Madrid, and Caruthersville
and extends north to the Jackson area. In addition, Associated provides service
to Butler, Missouri, near the state's western border and Kirksville, Missouri,
near the state's northern border through connections off of interstate pipelines
in those areas.
Description of NOARK Pipeline System Operating Area:
Southwestern Energy Pipeline Company owns a 47.93% general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the 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
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Gathering 442 -- 442
Transmission 745 606 1,351
Distribution 2,936 1,599 4,535
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4,123 2,205 6,328
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