Southwestern Energy Company and Subsidiaries
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Southwestern Energy Company is an exempt holding company under the
Public Utility Holding Company Act of 1935 which conducts its primary
activities through four wholly owned subsidiaries. The Company's operating
results and financial condition thus reflect the activities of its
subsidiaries. These subsidiaries are active in the exploration and
production, local distribution and transmission segments of the natural gas
industry. The Company strengthened its financial position in 1993 and
continues to have access to adequate sources of capital to finance its
operations and capital spending.
The consolidated financial statements and the "Financial and Operating
Statistics" should be referred to in conjunction with the following review.
"Selected Financial Data" can be found in the "Financial and Operating
Statistics".
Results of Operations
Net income in 1993 before the cumulative effect of a change in
accounting for income taxes increased by 21% to $27.1 million, or $1.05 per
share, up from $22.3 million, or $.87 per share, in 1992. Net income in 1991
was $20.1 million, or $.78 per share. Operating results for 1993 included an
adjustment of $1.7 million, or $.07 per share, to decrease net income and
record the effect on accumulated deferred income taxes of the increase in the
maximum corporate income tax rate enacted by the Omnibus Budget
Reconciliation Act of 1993 (OBRA). Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes," required that the
entire amount of this adjustment be recorded as a charge to operating results
during the period in which the increased rates were enacted. When
Southwestern adopted the provisions of SFAS No. 109 in the first quarter of
1993, the Company recorded a $10.1 million, or $.39 per share, increase in
net income as the cumulative effect on prior years of adopting the accounting
change. Even though the adjustment resulting from enactment of OBRA was
required to be recorded in the same year as the adoption of the new standard,
SFAS No. 109 does not allow the effects of the two events to be netted
against each other. There were no accounting changes or extraordinary items
recorded in either 1992 or 1991. The Company's reported earnings per share
have been restated to reflect the effect of a three-for-one stock split
distributed in the third quarter of 1993.
The earnings growth in 1993 and 1992 was primarily the result of
increased sales of the Company's gas production. Revenues and operating
income for the Company's major business segments are shown in the following
table.
1993 1992 1991
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(in thousands)
Revenues
Exploration and production $ 79,374 $ 60,554 $ 49,392
Gas distribution 131,892 117,495 121,302
Other 262 256 256
Eliminations (36,684) (34,475) (34,511)
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$174,844 $143,830 $136,439
=============================================================================
Operating Income
Exploration and production $ 42,608 $ 33,071 $ 28,310
Gas distribution 15,261 13,094 14,027
Corporate expenses (305) (177) (195)
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$ 57,564 $ 45,988 $ 42,142
=============================================================================
Exploration and Production Revenues
The Company's exploration and production revenues increased 31% in 1993
and 23% in 1992, due in both years to increased natural gas production.
Production increased by 39% to 35.4 billion cubic feet (Bcf) in 1993 from
25.5 Bcf in 1992. Production in 1992 increased by 28% from 19.9 Bcf in 1991.
The increase in gas production since 1991 is attributable to increased sales
to unaffiliated purchasers.
Gas sales to unaffiliated purchasers increased to 22.6 Bcf in 1993 from
14.1 Bcf in 1992 and 7.0 Bcf in 1991. The increase in sales to unaffiliated
purchasers was the result of higher sales from the Company's properties in
both Arkansas and the Gulf of Mexico. The Company sold 14.8 Bcf of its
Arkansas production to unaffiliated purchasers during 1993, compared to 10.3
Bcf in 1992 and 3.3 Bcf in 1991. The increase in 1993 was the result of the
Company's development drilling program in the Arkoma Basin which made
additional gas available for sale during the late spring and summer months.
The increase in 1992 was the result of the development drilling program and
of production at the Fort Chaffee military reservation which began in August,
1991. Production outside Arkansas, all of which is sold to unaffiliated
purchasers, was 7.8 Bcf in 1993, compared to 3.8 Bcf in 1992 and 3.7 Bcf in
1991. The increase in 1993 was primarily the result of the completion of a
production platform at Brazos Block 397 and the start of production in
November, 1993, from Galveston Block 283. Both of those fields are in the
Gulf of Mexico. Based on current rates of production, these additions should
leave the Company's production from the Gulf of Mexico stable during 1994.
1993 1992 1991
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Gas Production
Affiliated sales (Bcf) 12.8 11.4 12.9
Unaffiliated sales (Bcf) 22.6 14.1 7.0
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35.4 25.5 19.9
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Average price per Mcf $2.18 $2.26 $2.26
=============================================================================
Oil Production
Unaffiliated sales (MBbls) 96 120 176
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Average price per Bbl $17.20 $19.75 $20.67
============================================================================
Sales to unaffiliated purchasers are made under contracts which reflect
current short-term prices and which are subject to seasonal price swings. The
Company curtailed part of its gas production during 1992 and 1991 when sales
prices were deemed below acceptable levels.
Colder weather during the heating season and storage requirements during
the summer months affected the demand of the Company's utility distribution
systems for gas supply in 1993. Gas production sold to Arkansas Western Gas
Company (AWG), which operates the Company's northwest Arkansas utility
system, was 7.1 Bcf in 1993, 7.2 Bcf in 1992 and 7.6 Bcf in 1991. The
decrease in gas sold to AWG in 1993 resulted from the lack of summer
injections by AWG into its gas storage facilities, partially offset by an
increase in sales due to weather related requirements of the utility system
and an increase in sales to a spot market purchasing program available to the
larger business customers of AWG. Injections into AWG's gas storage
facilities were not necessary as physical improvements made by the utility
during 1993 decreased the level of cushion gas necessary to efficiently
operate these facilities. The decrease in sales to AWG in 1992, as compared
to 1991, occurred because a number of AWG's large business customers switched
to a new transportation service offered by the utility. This decrease in
sales to AWG was offset by direct sales of one of the exploration and
production subsidiaries to AWG's large business customers. In 1993, 1992 and
1991, the Company's gas production provided approximately 50% of AWG's
requirements. Additionally, in 1993, 1992 and 1991,
the Company sold .7 Bcf, .4 Bcf and 1.1 Bcf, respectively, of gas to AWG for
the spot market purchasing program described above.
The Company's sales to AWG under the spot market purchasing program are
based upon competitive bids and generally reflect current spot market prices.
Most of the remaining sales to this system are subject to a long-term
contract entered into in 1978, under which the price has been frozen since
the end of 1984. Other sales to the utility are made under newer long-term
contracts which contain provisions for annual price redetermination. In
November, 1993, the Arkansas Public Service Commission (APSC or Commission)
issued an order which found the purchases of AWG under the 1978 contract to
be in violation of an Arkansas statute requiring that gas purchases be made
"from the lowest or most advantageous market." The APSC order is discussed
more fully below under Regulatory Matters.
The Company's deliveries to Associated Natural Gas Company (Associated),
a division of AWG which operates the Company's natural gas distribution
systems in northeast Arkansas and parts of Missouri, were 5.7 Bcf in 1993,
4.3 Bcf in 1992 and 5.3 Bcf in 1991. Deliveries to Associated increased in
1993 primarily due to colder winter heating weather and storage requirements
during the summer months. The decrease in volumes sold to Associated in 1992,
as compared to 1991, was primarily the result of certain industrial customers
switching to transportation service. 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. Deliveries under this contract were made
at $1.90 per thousand cubic feet (Mcf) from inception of the contract through
the first nine months of 1993, and are currently being made at $2.385 per
Mcf.
The average price received at the wellhead for the Company's total gas
production was $2.18 per Mcf in 1993 and $2.26 per Mcf in both 1992 and 1991.
While spot market prices were generally higher in 1993, the Company's
production mix reflected a lower proportion of sales under older, higher
priced contracts. The Company believes that the overall trend of natural gas
pricing in the near future will be favorable, due primarily to rising demand
and the decline of industry drilling activity in recent years. However, for
the next few years the Company expects the average price it receives for its
total production to continue to be either flat or decreasing as any
incremental gas production will likely be sold at current spot market prices
which are generally lower than the average price presently received by the
Company for sales under older long-term contracts. As described above, a
substantial portion of the Company's gas production is sold under long-term
contracts to Southwestern's gas distribution subsidiary. These sales
arrangements help reduce the effects of fluctuations in the spot market price
for natural gas.
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.
New sales contracts entered into under present market conditions may be
either short-term or long-term in nature, but will likely contain some type
of variable pricing mechanism which will be responsive to changes in the
market price for gas. The Company expects access to markets for sales of its
production to continue to improve as a result of the NOARK Pipeline System
(NOARK). NOARK provides additional transportation capacity out of the Arkoma
Basin where most of the Company's present reserves are located. The pipeline
became operational in late 1992 and extends across northern Arkansas,
crossing three major interstate pipelines. The Company, through a subsidiary,
holds a general partnership interest of 47.33% in NOARK and is the pipeline's
operator. The Company completed a pipeline in 1993 to connect NOARK to
Associated's system, tying together the Company's primary gas distribution
systems.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. While the Company expects
over the long term to experience a trend toward increasing volumes of gas
production, it 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 block of undeveloped
leasehold acreage and producing acreage which will continue to be developed
in the future. The Company's exploration programs have been directed almost
exclusively 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.
Gas Distribution Revenues
Gas distribution revenues fluctuate due to the pass-through of cost of
gas increases and decreases and because of 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.
1993 1992 1991
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Gas Distribution Systems
Deliveries (Bcf)
Sales volumes 26.8 23.5 27.1
Transportation volumes
End users 5.6 5.2 1.3
Off-system 11.7 2.5 .2
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44.1 31.2 28.6
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Average number of customers 155,944 151,592 147,629
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Heating weather-degree days 4,929 4,104 4,095
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Average sales rate per Mcf $4.65 $4.75 $4.36
=============================================================================
Gas distribution revenues increased by 12% in 1993 and decreased by 3%
in 1992. The increase in 1993 was primarily due to additional deliveries to
residential and commercial customers resulting from weather which was 20%
colder than in 1992 and from customer growth. Additional revenues related to
the transportation of gas behind AWG's system to NOARK also contributed to
the increase in 1993. The decrease in 1992 was due to the conversion of
certain industrial customers from sales to transportation service. While the
conversion of these customers to transportation service lowered the Company's
gas distribution revenues, there was no resulting impact on operating income
as the rate charged these customers for transportation service was equal to
the rate charged for sales service, exclusive of gas costs. In 1993, AWG sold
17.1 Bcf to its customers at an average rate of $4.40 per Mcf, compared to
15.0 Bcf at $4.62 per Mcf in 1992 and 17.2 Bcf at $4.22 per Mcf in 1991.
Additionally, AWG transported 3.9 Bcf for its customers in 1993, 3.2 Bcf in
1992 and .7 Bcf in 1991 under a transportation program implemented in
October, 1991. Associated sold 9.7 Bcf to its customers in 1993 at an average
rate of $5.08 per Mcf, compared to 8.4 Bcf in 1992 at $4.99 per Mcf and 9.9
Bcf at $4.62 per Mcf in 1991. Associated transported 1.7 Bcf for its
customers in 1993, compared to 2.0 Bcf in 1992 and .6 Bcf in 1991.
Total deliveries to industrial customers of AWG and Associated,
including transportation volumes, increased to 11.7 Bcf in 1993, from 11.3
Bcf in 1992 and 10.8 Bcf in 1991. 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 11.7 Bcf of gas through its gathering system in
1993 for off-system deliveries, primarily to NOARK, compared to 2.5 Bcf in
1992. The average transportation rate was $.13 per Mcf, exclusive of fuel, in
both years.
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 3% to 3.5% annually,
while Associated has experienced customer growth of 1% to 2% annually. Based
on current
economic conditions in the Company's service territories, the Company expects
this trend in customer growth to continue. Rate increase requests which may
be filed in the future will depend upon customer growth, increases in
operating expenses and additional investments in property, plant and
equipment. A rate increase request is not imminent as the strong customer
growth and additional transportation revenues have helped offset the effects
of attrition since the Company's last rate case.
Regulatory Matters
In November, 1993, the APSC issued an order in a three-year-old gas cost
case involving purchases by AWG under a long-term contract with one of the
Company's gas producing subsidiaries. The order found AWG's purchases under
the contract to be in violation of an Arkansas statute requiring that gas
purchases be made "from the lowest or most advantageous market." The order
found that the price paid by AWG was too high, but said that additional
evidence was necessary to enable the Commission to determine a proper price.
A hearing was held in mid-January, 1994, to receive additional evidence. The
long-term contract in question was approved by the APSC in 1979. The gas cost
issues addressed in the order were first raised by the Commission in
December, 1990, in connection with the APSC's approval of an AWG rate
increase. During the rate case, the Commission Staff hired a consultant who
performed an extensive review of the utility's purchasing practices and gas
costs and recommended in filed testimony that all of the Company's gas costs,
including purchases under the contract in question, be accepted without
adjustment. In spite of the testimony filed by its Staff, the Commission
established a proceeding to investigate its concerns. At the January, 1994
hearing, both the Staff of the Commission and the Office of the Attorney
General of the State of Arkansas presented testimony describing
recommendations designed to lower the price received by the Company's
production subsidiary under the contract. The Company presented testimony
which it believes reinforced its position that the contractual arrangements
questioned by the Commission are the most advantageous available to its
utility customers. Legal briefs related to the hearing were filed in late
February, 1994, and the Company expects a Commission order to be forthcoming.
If necessary, the Company intends to continue to defend its gas purchasing
practices through the courts. The Commission has previously stated that AWG's
gas purchasing practices, affiliate transactions, gas costs and gas cost
allocation issues would be considered in the proceeding on a prospective
basis only. The Company does not expect any outcome of the proceeding to have
a material adverse effect on the financial position of the Company. Of the
Company's 35.4 Bcf of gas production during 1993, approximately 6.0 Bcf was
sold under the contract in question.
Another regulatory development which should not have a significant
impact on the Company is the issuance by the Federal Energy Regulatory
Commission (FERC) of its Order No. 636 series, the restructuring rules
covering natural gas service by interstate pipelines. Order No. 636 makes
significant changes to the merchant function historically provided to gas
distributors by interstate pipelines. Since AWG and Associated already obtain
the bulk of their supply at the wellhead directly from producers, the changes
mandated should be insignificant to the Company.
Prior to Order No. 636, Associated purchased gas from interstate
pipelines under contracts with take-or-pay provisions. To date, the Company
has paid approximately $3.2 million for contract reformation costs incurred
by its interstate pipeline suppliers and for contracted quantities of gas not
taken. The Company believes these costs are recoverable from its utility
customers and expects approval from the proper regulatory agencies after the
payments are reviewed in the normal course of business. To date, the Company
has recovered, subject to refund, approximately $1.6 million of these charges
from its customers. 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. The
Company's exposure to take-or-pay liabilities to producers or other suppliers
could increase as a result of the decline in its gas purchase requirements
which has occurred as some of its large business customers participate in a
transportation service offered by AWG and Associated in Arkansas and obtain
their own gas supplies directly from other sources. Associated has offered
such a service to its customers in Missouri for several years and AWG's spot
market purchasing program has provided customers in northwest Arkansas with
many of the benefits of transportation service. 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 20% in 1993 and
by 4% in 1992. The increase in 1993 was due primarily to increased purchased
gas costs related to increased utility deliveries, and increased production
costs and depreciation, depletion and amortization resulting from increased
gas sales in the exploration and production segment. The increase in 1992
resulted from increased operating and general expenses and increased
depreciation, depletion and amortization related to increased gas sales in
the exploration and production segment, partially offset by lower purchased
gas costs caused by the conversion of certain industrial customers of the gas
distribution segment from sales to transportation service. Purchased gas
costs are the largest expense item in each year, typically representing 35%
to 45% 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. As previously
mentioned, increases and decreases in purchased gas costs are passed through
automatically to the Company's utility customers.
Depreciation, depletion and amortization is calculated using the
units-of-production method for the Company's gas and oil properties. The
Company's annual gas and oil production as well as the amount of proved
reserves owned by the Company and the costs associated with adding those
reserves are all components of the amortization calculation. The record level
of natural gas production in each year was the primary reason for the 30%
increase in depreciation, depletion and amortization in 1993 and the 31%
increase in 1992.
Delays inherent in the rate-making process prevent the Company from
obtaining immediate recovery of increased operating costs of its gas
distribution segment. 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. While many of the gas distribution
subsidiary's gas purchase contracts include inflation-based price
escalations, these clauses have generally not been operating as gas market
conditions have led producers to accept prices below the contract maximum
price. Continuing depressed conditions in the gas and oil industry have
resulted in lower costs of drilling and leasehold acquisition. There are some
recent indications, however, that these depressed conditions are abating,
which could cause an increase in such costs in the future.
Other Costs and Expenses
Interest costs decreased in 1993 due to the redemption in late 1992 of
the Company's 12.75% Debentures and 9.38% First Mortgage Bonds, as discussed
below in Financing Requirements, and due to both lower average borrowings and
lower average interest rates on the Company's revolving debt facilities.
Interest costs increased slightly in 1992, as compared to 1991, due primarily
to the Company's issuance of $66.0 million of fixed rate debt in December,
1991, which was issued to refinance lower cost variable rate bank debt.
The change in other income during 1993 and 1992 relates primarily to the
Company's share of operating losses incurred by NOARK. The Company accounts
for its 47.33% interest in the NOARK partnership under the equity method of
accounting (see Note 7 to the financial statements for additional
discussion). The Company's share of the pre-tax loss for NOARK included in
other income was $1.8 million in 1993 and $.6 million in 1992. Deliveries are
currently being made by NOARK to portions of AWG's distribution systems, to
Associated and to the interstate pipelines with which NOARK interconnects.
NOARK completed its first full year of operation in 1993 and had an average
daily throughput
during the year of 79 million cubic feet of gas per day (MMcfd). NOARK has a
total transportation capacity of 141 MMcfd. AWG has contracted for 41 MMcfd
of firm capacity on NOARK under a ten-year transportation contract. NOARK
also has 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 supplies 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. The complaint seeks rescission of the transportation contract and
a contract to purchase gas from the Company's affiliates, along with actual
and punitive damages. The Company and NOARK both believe the suit is without
merit and have filed counterclaims seeking enforcement of the contracts and
damages. The Company is currently making its own sales arrangements and
transporting the 25 MMcfd of production through NOARK which was previously
purchased by Vesta.
The APSC has established a maximum transportation rate of approximately
$.285 per dekatherm for NOARK based on its original construction cost
estimate of approximately $73.0 million. NOARK's actual cost of construction
was approximately $103.0 million, due primarily to unanticipated construction
conditions which were encountered along certain segments of the pipeline's
route. 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. 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. That
pipeline does not offer firm transportation, but the increased availability
of interruptible transportation services intensified the competitive
environment within which NOARK operates. The Company believes that the FERC's
Order No. 636 restructuring rules implemented in the latter part of 1993 will
have a positive impact on NOARK. The unbundling of gas sales, gathering,
transmission and storage services required by Order No. 636 should provide
NOARK with expanded options for accessing gas supply and for transporting gas
to downstream customers. The Company believes it will realize its investment
in NOARK over the life of the system.
The Company's effective income tax rate was 42.3% in 1993, 37.4% in 1992
and 37.7% in 1991. The rate increased in 1993 because the Company's deferred
tax provision included $1.7 million of expense for the increase in the
maximum corporate tax rate legislated by OBRA.
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
1993, 1992 and 1991, net cash provided from operating activities totaled
$70.2 million, $49.7 million and $35.0 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 in excess of 100% of the Company's
capital requirements for routine capital expenditures, cash dividends and
scheduled debt retirements in 1993, 94% in 1992 and 75% in 1991.
In July, 1993, the Board of Directors increased the quarterly dividend
on the Company's common stock by 20% to $.06 per share from $.05 per share.
On an annual basis, the new rate is equivalent to $.24 per share, compared to
a dividend rate of $.20 per share paid in 1992 and a dividend rate of $.19
per share paid in 1991. The dividend rates reflect the effect of a
three-for-one stock split distributed in 1993. Total dividends paid to common
shareholders in 1993 were $5.7 million compared to $5.1 million in 1992 and
$4.8 million in 1991.
Changes in the Company's liquidity in future years are expected to be
related primarily to changes in cash flow generated from its operations.
Factors affecting operating results were discussed under Results of
Operations.
Capital Expenditures
Routine capital expenditures were $59.2 million in 1993, $44.9 million
in 1992 and $38.9 million in 1991. In 1992, the Company also made a $7.6
million equity contribution to the partnership formed to construct NOARK.
1993 1992 1991
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(in thousands)
Capital Expenditures
Exploration and production $37,411 $30,823 $30,339
Gas distribution 19,892 12,188 7,856
Other 1,916 1,898 693
- -----------------------------------------------------------------------------
$59,219 $44,909 $38,888
=============================================================================
The Company generally intends to limit its routine capital expenditures
to internally generated cash or less. This level of spending should be
adequate to allow the Company to maintain its present markets, finance
improvements necessary due to normal customer growth in its gas distribution
segment and to explore and develop existing gas and oil properties as well as
generate new drilling prospects.
Routine capital expenditures expected to be incurred in 1994 are $67.3
million, consisting of $50.0 million for gas and oil exploration, $13.3
million for gas distribution system expenditures and $4.0 million for general
purposes. The Company's capital expenditure plans also include approximately
$6.7 million of non-routine spending, including $5.5 million to extend gas
service to new communities along NOARK's route and $1.2 million to construct
a transmission loop in Associated's system. The majority of the 1994 budgeted
expenditure to extend gas service to new communities along NOARK is a
carryover from the 1993 capital expenditures budget. The gas and oil
expenditures include $12.5 million for exploratory drilling, $4.3 million for
additional drilling and development of properties on the Fort Chaffee
military reservation and $14.0 million to continue the development of the
Company's proved acreage in the Arkoma Basin. The Company may use its
existing revolving credit facilities to meet seasonal or short-term
requirements related to these expenditures. Additionally, the Company
recently formed a group to focus solely on the acquisition of producing
properties and expects that effort to supplement its exploration and
development drilling programs.
The Company plans to manage the debt portion of its capital structure
over time through its policy of generally limiting its routine capital
spending to internally generated cash or less, but expects to continue to use
additional debt to address extraordinary needs or opportunities, such as
attractive acquisitions of gas and oil properties.
Financing Requirements
Two floating rate revolving credit facilities provided the Company
access to $60.0 million of variable rate long-term capital at December 31,
1993. Borrowings outstanding under these credit facilities totaled $31.0
million at the end of 1993. The Company also had available short-term lines
of credit totaling $3.5 million at the end of 1993. The Company is currently
in the process of renegotiating the terms and increasing the capacity of its
variable rate facilities.
In the fourth quarter of 1992, the Company redeemed its 12.75%
Debentures and its 9.38% First Mortgage Bonds which were due in 1993. The
redemptions were funded by the Company's variable rate credit facilities.
The Company and an affiliate of the other major general partner of NOARK
are required to severally guarantee the availability of certain minimum cash
balances to service a $63.0 million issue of 9.7375% Senior Secured Notes.
The notes, which have a remaining term of approximately 16 years, are held by
a major insurance company which also has a 20% limited partnership interest
in NOARK. The Company's share of the several guarantee of available cash
balances
is 60%. Also in 1993, NOARK entered into an unsecured long-term revolving
credit agreement with a group of banks which provides the partnership access
to $30.0 million of additional funds. At December 31, 1993, $25.2 million was
outstanding under this credit arrangement. This facility replaced a $20.0
million short-term line of credit, all of which was outstanding at December
31, 1992. Amounts borrowed under the long-term revolving credit agreement are
severally guaranteed by the Company and an affiliate of the other major
general partner. The Company's share of the several guarantee is also 60%.
NOARK has borrowed approximately 84% of its total construction costs under
these financing arrangements. The remainder of NOARK's capital was provided
by equity contributions of the partners during 1992. The Company expects to
fund approximately $1.7 million during 1994, in the form of equity
contributions or loans to the partnership, in connection with its guarantees.
In July, 1992, in view of interest rates obtainable at the time, the
Company entered into a two-year reverse interest rate swap agreement with a
notional amount of $30.0 million. Under the terms of the swap, the Company
receives interest semiannually at a fixed rate of 5.11% and pays interest
semiannually at the London Interbank Offered Rate (LIBOR). The LIBOR rate is
determined at the end of each six-month period.
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 1.50 or higher. At the end of 1993,
the capital structure consisted of 40.19% debt (excluding the current portion
of long-term debt) and 59.81% equity, with a ratio of earnings to fixed
charges of 3.98.
Working Capital
The Company maintains access to funds which may be needed to meet
seasonal requirements through the revolving and short-term lines of credit
explained above. The Company had net working capital of $8.1 million at the
end of 1993 and $14.2 million at the end of 1992. Current assets increased by
4% to $46.8 million in 1993, while current liabilities increased 25% to $38.7
million. The increase in current assets was due primarily to an increase in
the current portion of gas stored underground, reflecting the value of stored
gas expected to be utilized on an annual basis. The increase in current
liabilities resulted primarily from an increase in the current portion of
long-term debt and an increase in accounts payable and taxes payable. The
increases in accounts payable and taxes payable resulted primarily from the
timing of payments of amounts due. Additionally, a portion of the increase in
taxes payable in 1993 was due to the increase in taxable income.
Report of Independent Auditors
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, 1993
and 1992, and the related consolidated statements of income, retained
earnings and cash flows for each of the three years in the period ended
December 31, 1993. 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, 1993 and 1992, and the
results of its operations and its cash flows for each of the three years in
the period ended December 31, 1993, in conformity with generally accepted
accounting principles.
As discussed in Notes 3 and 4 to the consolidated financial statements,
effective January 1, 1993, the Company changed its methods of accounting for
income taxes and for postretirement benefits other than pensions.
ARTHUR ANDERSEN & CO.
Tulsa, Oklahoma
February 7, 1994
Southwestern Energy Company and Subsidiaries
STATEMENTS OF INCOME
For the Years Ended December 31 1993 1992 1991
- -----------------------------------------------------------------------------
($ in thousands, except per share amounts)
Operating Revenues
Gas sales $165,597 $135,274 $129,196
Oil sales 1,659 2,377 3,639
Gas transportation 5,177 3,597 857
Other 2,411 2,582 2,747
- -----------------------------------------------------------------------------
174,844 143,830 136,439
- -----------------------------------------------------------------------------
Operating Costs and Expenses
Purchased gas costs 42,962 35,848 40,423
Operating and general 40,093 34,970 32,609
Depreciation, depletion and
amortization 30,944 23,880 18,248
Taxes, other than income taxes 3,281 3,144 3,017
- -----------------------------------------------------------------------------
117,280 97,842 94,297
- -----------------------------------------------------------------------------
Operating Income 57,564 45,988 42,142
- -----------------------------------------------------------------------------
Interest Expense
Interest on long-term debt 10,090 10,932 10,464
Other interest charges 483 547 776
Interest capitalized (1,548) (1,496) (1,427)
- -----------------------------------------------------------------------------
9,025 9,983 9,813
- -----------------------------------------------------------------------------
Other Income (Expense) (1,657) (421) (107)
- -----------------------------------------------------------------------------
Income Before Provision for
Income Taxes and Cumulative Effect
of Accounting Change 46,882 35,584 32,222
- -----------------------------------------------------------------------------
Provision for Income Taxes
Current 13,704 7,403 7,158
Deferred (includes $1.7 million in
1993 related to legislated
increase in tax rates) 6,128 5,916 4,999
- -----------------------------------------------------------------------------
19,832 13,319 12,157
- -----------------------------------------------------------------------------
Income Before Cumulative Effect of
Accounting Change 27,050 22,265 20,065
Cumulative Effect of Change in
Accounting for Income Taxes 10,126 - -
- -----------------------------------------------------------------------------
Net Income $ 37,176 $ 22,265 $ 20,065
=============================================================================
Earnings Per Share
Income Before Cumulative Effect of
Accounting Change $1.05 $.87 $.78
Cumulative Effect of Change in
Accounting for Income Taxes .39 - -
- -----------------------------------------------------------------------------
Net Income $1.44 $.87 $.78
=============================================================================
Weighted Average Common Shares
Outstanding 25,684,110 25,683,963 25,678,011
=============================================================================
The accompanying notes are an integral part of the financial statements.
Southwestern Energy Company and Subsidiaries
BALANCE SHEETS
December 31 1993 1992
- -----------------------------------------------------------------------------
(in thousands)
ASSETS
Current Assets
Cash $ 834 $ 1,122
Accounts receivable 34,866 34,30
5
Inventories, at average cost 9,580 8,036
Other 1,525 1,639
- -----------------------------------------------------------------------------
Total current assets 46,805 45,102
- -----------------------------------------------------------------------------
Investments 5,661 7,523
- -----------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method,
including $16,769,000 in 1993 and $20,633,000
in 1992 excluded from amortization 375,281 338,062
Gas distribution systems 165,443 146,837
Gas in underground storage 37,171 46,290
Other 14,684 13,040
- -----------------------------------------------------------------------------
592,579 544,229
Less: Accumulated depreciation, depletion and
amortization 205,949 174,949
- -----------------------------------------------------------------------------
386,630 369,280
- -----------------------------------------------------------------------------
Other Assets 6,358 5,270
- -----------------------------------------------------------------------------
$445,454 $427,175
=============================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt $ 3,000 $ 133
Accounts payable 16,052 13,816
Taxes payable 6,449 3,338
Interest payable 1,445 1,472
Customer deposits 3,927 3,510
Current portion of deferred income taxes 1,426 2,536
Over-recovered purchased gas costs, net 4,187 4,473
Other 2,211 1,669
- -----------------------------------------------------------------------------
Total current liabilities 38,697 30,947
- -----------------------------------------------------------------------------
Long-Term Debt, less current portion above 124,000 143,202
- -----------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 93,593 95,203
Deferred investment tax credits 2,617 2,786
Other 2,017 1,804
- -----------------------------------------------------------------------------
98,227 99,793
- -----------------------------------------------------------------------------
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 21,231 21,231
Retained earnings, per accompanying statements 180,470 148,945
- -----------------------------------------------------------------------------
204,475 172,950
Less: Unamortized cost of 17,447 restricted
shares issued under stock incentive plan 228 -
Common stock in treasury, at cost,
2,053,974 shares 19,717 19,717
- -----------------------------------------------------------------------------
184,530 153,233
- -----------------------------------------------------------------------------
$445,454 $427,175
=============================================================================
The accompanying notes are an integral part of the financial statements.
Southwestern Energy Company and Subsidiaries
STATEMENTS OF CASH FLOWS
For the Years Ended December 31 1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating
Activities
Net income $ 37,176 $ 22,265 $ 20,065
Adjustments to reconcile
net income to net
cash provided by
operating activities:
Depreciation, depletion and
amortization 31,223 24,160 18,528
Deferred income taxes 6,128 5,916 4,999
Equity in loss of partnership 1,788 531 -
Cumulative effect of change in
accounting for income taxes (10,126) - -
Change in assets
and liabilities:
Increase in accounts
receivable (561) (5,002) (4,163)
(Increase) decrease in
inventories (1,544) 440 (1,910)
Increase (decrease) in
accounts payable 2,236 876 (2,162)
Increase (decrease) in
taxes payable 3,111 1,848 (1,294)
Increase (decrease) in
interest payable (27) (240) 133
Increase in customer deposits 417 347 150
Increase (decrease) in
over-recovered
purchased gas costs (286) (1,335) 171
Net change in other
current assets
and liabilities 656 (76) 469
- -----------------------------------------------------------------------------
Net cash provided by
operating activities 70,191 49,730 34,986
- -----------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (59,219) (44,909) (38,888)
Investment in partnership - (7,573) 544
(Increase) decrease in gas stored
underground 9,119 (4,432) 435
Other items 1,607 1,997 163
- -----------------------------------------------------------------------------
Net cash used in investing
activities (48,493) (54,917) (37,746)
- -----------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving
long-term debt (15,500) 22,000 (54,500)
Proceeds from issuance of other
long-term debt - - 66,000
Payments on other long-term debt (835) (12,769) (2,931)
Dividends paid (5,651) (5,137) (4,793)
- -----------------------------------------------------------------------------
Net cash provided (used) by
financing activities (21,986) 4,094 3,776
- -----------------------------------------------------------------------------
Increase (decrease) in cash (288) (1,093) 1,016
Cash at beginning of year 1,122 2,215 1,199
- -----------------------------------------------------------------------------
Cash at end of year $ 834 $ 1,122 $ 2,215
=============================================================================
Southwestern Energy Company and Subsidiaries
STATEMENTS OF RETAINED EARNINGS
For the Years Ended December 31 1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning
of year $148,945 $131,817 $116,545
Net income 37,176 22,265 20,065
Cash dividends declared ($.22 per
share in 1993, $.20 per share
in 1992 and $.19 per share
in 1991) (5,651) (5,137) (4,793)
- -----------------------------------------------------------------------------
Retained Earnings, end of year $180,470 $148,945 $131,817
=============================================================================
The accompanying notes are an integral part of the financial statements.
NOTES TO FINANCIAL STATEMENTS
December 31, 1993, 1992 and 1991
(1) Summary of Significant Accounting Policies
Consolidation
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 Pipeline Company, Arkansas Western Pipeline Company and
A.W. Realty Company. All significant intercompany accounts and transactions
have been eliminated. The Company accounts for a general partnership interest
of 47.33% 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
1993 presentation.
Property, Depreciation, Depletion and Amortization
Gas and Oil Properties - The Company follows the full cost method of
accounting for the cost of exploration and development 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 6.7%. 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 93,000 of these customers are served in
northwest Arkansas and approximately 67,000 are served in northeast Arkansas
and Missouri.
The Company records gas distribution revenues on an accrual basis, as
gas volumes are used, in order to provide a proper matching of revenues with
expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual costs of purchased gas above or below
the levels included in the base rates are permitted to be billed or are
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.
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 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, 1993 and 1992 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.
Investment Tax Credits
Investment tax credits have been deferred for financial reporting
purposes and are being amortized over the estimated useful lives of the
related properties.
Interest Rate Swap Agreements
Interest rate swap agreements involve the exchange of fixed rate and
floating rate interest payments without the exchange of the underlying
principal amounts. The differential to be paid or received is recognized as
an adjustment to interest expense.
Earnings Per Share and Shareholders' Equity
Earnings per common share are based on the weighted average number of
common shares outstanding during each year. All share and per share
information for 1992 and 1991 has been restated to reflect the effects of a
three-for-one stock split distributed on August 5, 1993. The common stock
and additional paid-in capital accounts at December 31, 1992 have been
restated to reflect the stock split and the effect of a reduction in the par
value of common stock from $2.50 per share to $.10 per share on June 9, 1993.
(2) Long-Term Debt
Long-term debt as of December 31, 1993 and 1992, consisted of the
following:
1993 1992
- -----------------------------------------------------------------------------
(in thousands)
Senior Notes
8.69% Series due December 4, 1997 $ 22,500 $ 22,500
8.86% Series due in annual installments of
$3.1 million beginning December 4, 1995 21,500 21,500
9.36% Series due in annual installments of
$2.0 million beginning December 4, 2001 22,000 22,000
10.63% Series due in annual installments of
$3.0 million beginning September 30, 1994 30,000 30,000
- -----------------------------------------------------------------------------
96,000 96,000
- -----------------------------------------------------------------------------
Other
Variable rate (3.80% at December 31, 1993)
unsecured revolving credit arrangements with
two banks, each convertible at the Company's
option to a term loan repayable in six
semi-annual installments beginning no later
than June, 1994 31,000 46,500
Other notes payable - 835
- -----------------------------------------------------------------------------
31,000 47,335
- -----------------------------------------------------------------------------
Total long-term debt 127,000 143,335
Less: Current portion of long-term debt 3,000 133
- -----------------------------------------------------------------------------
$124,000 $143,202
=============================================================================
The Company has several prepayment options under the terms 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.
At December 31, 1993, the Company had two variable rate facilities which
make available $60.0 million of long-term revolving credit, of which $31.0
million was outstanding. 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. As of February 7, 1994, the Company was in the
process of renegotiating the terms and increasing the capacity of its
variable rate facilities.
At December 31, 1993, the Company had available other lines of credit
totaling $3.5 million. These lines either expire within one year or are
cancellable by the banks involved at any time. All bear interest at or below
the banks' prime rates. There were no outstanding borrowings under these
lines at December 31, 1993.
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, 1993, approximately $102.8 million of retained
earnings was available for payment as dividends.
At December 31, 1993 and 1992, the Company had an interest rate swap
agreement outstanding with a notional amount of $30.0 million. The notional
amount is used to measure the volume of the agreement and does not represent
exposure to credit loss. In the event of default by the counterparty, the
risk of this transaction is the cost of replacing the swap agreement at
current market rates. Management believes the risk of incurring a loss due to
a default by the counterparty is remote, and that if incurred, such loss
would be immaterial.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1994 through 1998, are $3.0 million, $6.1 million, $6.1 million,
$59.6 million and $6.1 million. Total interest payments of $10.3 million,
$11.7 million and $10.4 million were made in 1993, 1992 and 1991, respectively.
(3) Income Taxes
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes." The liability method specified by SFAS No. 109 requires
the calculation of accumulated deferred income taxes by application of the
tax rate expected to be in effect when the taxes will actually be paid or
refunds will be received. Under the liability method, the effect on deferred
taxes of a change in tax rates is recognized in income in the period of
enactment of the rate change. Under generally accepted accounting principles
previously in effect, deferred income taxes were not adjusted to reflect
changes in tax rates. The recognition of the cumulative effect, through
December 31, 1992, of this change in accounting increased net income in the
first quarter of 1993 by $10.1 million, or $.39 per share. SFAS No. 109 also
required an adjustment in the third quarter of 1993 to record the effects of
a legislated increase in tax rates. This adjustment decreased income before
the cumulative effect of the accounting change by $1.7 million, or $.07 per
share.
The provision for income taxes included the following components:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Federal:
Current $11,514 $ 6,190 $ 5,584
Deferred 3,827 5,096 4,598
Deferred tax adjustment for tax
rate increase 1,743 - -
State:
Current 2,190 1,213 1,574
Deferred 752 1,004 577
Investment tax credit amortization (194) (184) (176)
- -----------------------------------------------------------------------------
Provision for income taxes $19,832 $13,319 $12,157
=============================================================================
The provision for income taxes was an effective rate of 42.3% in 1993,
37.4% in 1992 and 37.7% in 1991. 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:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Expected provision at federal statutory
rate of 35% in 1993 and 34% in 1992
and 1991 $16,409 $12,098 $10,956
Increase (decrease) resulting from:
State income taxes, net of federal
income tax benefit 1,914 1,463 1,419
Percentage depletion on gas and
oil production (117) (106) (49)
Adjustment to deferred taxes for tax
rate increase 1,743 - -
Investment tax credit amortization (194) (184) (176)
Other 77 48 7
- -----------------------------------------------------------------------------
Provision for income taxes $19,832 $13,319 $12,157
=============================================================================
The components of the Company's net deferred tax liability as of December
31, 1993 were as follows (in thousands):
- -----------------------------------------------------------------------------
Deferred tax liabilities:
Differences between book and tax basis of property $83,875
Stored gas differences 5,132
Deferred purchased gas costs 1,232
Prepaid pension costs 1,731
Book over tax basis in partnerships 2,675
Gas imbalances 644
Other 876
- -----------------------------------------------------------------------------
96,165
- -----------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 770
Other 376
- -----------------------------------------------------------------------------
1,146
- -----------------------------------------------------------------------------
Net deferred tax liability $95,019
=============================================================================
Prior to the change in accounting for income taxes, the sources of
deferred tax items and the corresponding tax effects during 1992 and 1991
were as follows:
1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Intangible and other exploration and development costs $1,581 $1,952
Investment tax credits amortized (184) (176)
Stored gas differences 972 170
Excess of tax over book depreciation 1,987 1,419
Deferred purchased gas costs 355 950
Excess of tax over book partnership loss 953 -
Other 252 684
- -----------------------------------------------------------------------------
Deferred provision for income taxes $5,916 $4,999
=============================================================================
Total income tax payments of $10.2 million, $6.4 million and $8.3 million
were made in 1993, 1992 and 1991, respectively.
(4) Pension Plans and Other Postretirement Benefits
Substantially all employees are covered by the Company's defined benefit
pension plans. 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
plans with sufficient assets to meet future benefit payment requirements and
which are tax deductible.
Plan assumptions for 1993 and 1992 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 8.5% for the
net pension cost computation and a salary progression rate of 5%. The
reconciliation of prepaid pension cost at December 31, 1993 utilizes a
discount rate of 7.5% for future settlements.
The following table sets forth the plans' funded status and amounts
recognized in the Company's balance sheets at December 31, 1993 and 1992:
1993 1992
- -----------------------------------------------------------------------------
(in thousands)
Actuarial present value of benefit obligations:
Vested benefits $(20,746) $(16,623)
Nonvested benefits (1,685) (1,297)
- -----------------------------------------------------------------------------
Accumulated benefit obligation (22,431) (17,920)
Effect of projected future compensation levels (7,463) (5,098)
- -----------------------------------------------------------------------------
Projected benefit obligation (29,894) (23,018)
Plan assets at fair value, primarily common stocks
and bonds 36,601 34,327
- -----------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 6,707 11,309
Unrecognized net gain (1,869) (6,904)
Unrecognized net asset (1,318) (1,509)
Unrecognized prior service cost 274 301
- -----------------------------------------------------------------------------
Prepaid pension cost $ 3,794 $ 3,197
=============================================================================
Net pension cost for 1993, 1992 and 1991 included the following
components:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Service costs (benefits earned during
the period) $ 897 $ 805 $ 692
Interest cost on projected benefit
obligation 1,999 1,768 1,527
Actual return on plan assets (2,819) (4,914) (6,947)
Net amortization and deferral (673) 1,860 4,558
- -----------------------------------------------------------------------------
Net pension cost (credit) $ (596) $ (481) $ (170)
=============================================================================
The Company also has a supplemental retirement plan which provides
for certain pension benefits. Net pension cost recorded for this plan was
$628,000 and $241,000 in 1993 and 1992, respectively. In 1993, this plan was
funded with $1.2 million, resulting in an addition to prepaid pension cost of
$331,000 at December 31, 1993.
Effective January 1, 1993, the Company adopted SFAS No. 106
"Employers' Accounting for Postretirement Benefits Other Than Pensions."
Under SFAS No. 106, the cost of those benefits is accrued over the period the
employee provides services to the Company. Prior to 1993, postretirement
benefit expenses were recognized on a pay-as-you-go basis and were not
material. The Company currently funds postretirement benefits as claims are
incurred.
The Company provides postretirement health care and life insurance
benefits to eligible employees under two different plans. Employees become
eligible for these benefits if they meet age and service requirements.
Generally, the plans pay 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 1993 included the following components
(in thousands):
Service cost of benefits earned during the year $ 61
Amortization of transition amount 103
Interest cost on accumulated postretirement benefit obligation (APBO) 158
- -----------------------------------------------------------------------------
Net postretirement benefit cost $322
=============================================================================
The APBO as of December 31, 1993 was comprised of the following (in
thousands):
Retirees $ 655
Active participants, fully eligible 543
Other participants 835
- -----------------------------------------------------------------------------
Total APBO $2,033
=============================================================================
In determining the APBO, an assumed weighted average discount rate of
7.5% was used. An increase of 9.0% in the cost of covered health care
benefits was assumed for 1994. This rate is assumed to decrease ratably to
7.0% 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 1993 by $263,000 and
the 1993 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:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Sales $ 79,374 $ 60,554 $ 49,392
Production (lifting) costs (6,341) (4,271) (4,077)
Depreciation, depletion and amortization (25,686) (19,128) (13,843)
- -----------------------------------------------------------------------------
47,347 37,155 31,472
Income tax expense (18,081) (13,787) (11,819)
- -----------------------------------------------------------------------------
Results of operations $ 29,266 $ 23,368 $ 19,653
=============================================================================
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 1993,
1992 and 1991:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Property acquisition costs $ 5,920 $ 4,768 $ 5,385
Exploration costs 11,695 6,441 8,790
Development costs 19,722 19,563 16,134
- -----------------------------------------------------------------------------
Capitalized costs incurred $37,337 $30,772 $30,309
=============================================================================
Amortization per Mcf equivalent $.710 $.723 $.653
=============================================================================
The following table shows the capitalized costs of gas and oil
properties and the related accumulated depreciation, depletion and
amortization at December 31, 1993 and 1992:
1993 1992
- -----------------------------------------------------------------------------
(in thousands)
Proved properties $350,854 $314,194
Unproved properties 24,427 23,868
- -----------------------------------------------------------------------------
Total capitalized costs 375,281 338,062
Less: Accumulated depreciation, depletion and
amortization 146,471 120,842
- -----------------------------------------------------------------------------
Net capitalized costs $228,810 $217,220
=============================================================================
The table below sets forth the composition of net unevaluated
costs excluded from amortization as of December 31, 1993. Included in
property acquisition costs is $6.4 million representing leasehold and seismic
costs related to the remaining unevaluated portion of acreage located on the
Fort Chaffee military reservation. These costs are expected to be evaluated
and subjected to amortization within the next five years as this acreage is
further explored and developed. 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.
1993 1992 1991 Prior Total
- -----------------------------------------------------------------------------
(in thousands)
Property acquisition costs $2,544 $612 $1,049 $7,424 $11,629
Exploration costs 1,253 153 193 277 1,876
Capitalized interest 918 185 300 1,861 3,264
- -----------------------------------------------------------------------------
$4,715 $950 $1,542 $9,562 $16,769
=============================================================================
(6) Natural Gas and Oil Reserves (Unaudited)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1993, 1992 and 1991:
1993 1992 1991
- -----------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls)(MMcf) (MBbls) (MMcf)(MBbls)
- -----------------------------------------------------------------------------
Proved reserves,
beginning of year 312,291 359 307,484 505 304,511 773
Revisions of previous
estimates (4,385) (26) 479 (30) (6,707) (123)
Extensions, discoveries
and other additions 46,069 250 29,627 4 29,563 33
Production (35,418) (96) (25,530)(120) (19,924) (176)
Acquisition of reserves
in place 222 - 231 - 129 -
Disposition of reserves
in place (3) (8) - - (88) (2)
- -----------------------------------------------------------------------------
Proved reserves,
end of year 318,776 479 312,291 359 307,484 505
=============================================================================
Proved, developed reserves:
Beginning of year 246,904 337 226,767 467 234,001 763
End of year 260,240 469 246,904 337 226,767 467
=============================================================================
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 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, 1993, 1992 and 1991:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Future cash inflows $ 745,967 $ 681,033 $ 643,157
Future production and development costs (85,609) (84,483) (82,811)
Future income tax expense (236,170) (207,249) (196,811)
- -----------------------------------------------------------------------------
Future net cash flows 424,188 389,301 363,535
10% annual discount for estimated
timing of cash flows (196,913) (179,331) (165,261)
- -----------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows $ 227,275 $ 209,970 $ 198,274
=============================================================================
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 pre-tax cash inflows.
Future income taxes were computed by applying the year end statutory rate,
after consideration of permanent differences and enacted tax legislation, to
the excess of pre-tax 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 1993, 1992 and 1991:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Standardized measure, beginning of year $209,970 $198,274 $196,354
Sales and transfers of gas and oil
produced, net of production costs (73,017) (56,283) (45,315)
Net changes in prices and production costs 22,392 9,446 (45,655)
Extensions, discoveries and other
additions, net of future production
and development costs 74,511 52,917 29,322
Revisions of previous quantity estimates (5,217) 318 (6,405)
Accretion of discount 31,885 30,253 30,033
Net change in income taxes (13,524) (4,623) (279)
Changes in production rates (timing)
and other (19,725) (20,332) 40,219
- -----------------------------------------------------------------------------
Standardized measure, end of year $227,275 $209,970 $198,274
=============================================================================
(7) Investment in Unconsolidated Partnership
The Company holds a 47.33% general partnership interest in NOARK
and is the pipeline's operator. NOARK is a 258 mile long intrastate gas
transmission system which extends across northern Arkansas. NOARK's
transportation capacity is 141 million cubic feet of gas per day (MMcfd).
NOARK's main line was completed and placed in service in September, 1992. A
lateral line of NOARK that allows the Company to augment its gas supply for
existing markets as well as supply new markets was completed and placed in
service in November, 1992. The Company's equity investment in NOARK totaled
$5.3 million at December 31, 1993 and $7.0 million at December 31, 1992. The
Company's share of NOARK's 1993 and 1992 pre-tax loss included in other
income (expense) on the statements of income was $1.8 million and $.6
million, respectively. NOARK's financial position at December 31, 1993 and
1992 and its results of operations for the years then ended are summarized
below:
1993 1992
- -----------------------------------------------------------------------------
(in thousands)
Current assets $ 1,551 $ 1,503
Noncurrent assets 102,322 102,902
- -----------------------------------------------------------------------------
$103,873 $104,405
=============================================================================
Current liabilities $ 7,290 $ 5,406
Long-term debt 85,050 84,200
Partners' capital 11,533 14,799
- -----------------------------------------------------------------------------
$103,873 $104,405
=============================================================================
Operating revenues $ 8,301 $ 1,466
Pre-tax loss $ (3,778) $ (1,348)
=============================================================================
NOARK's total construction cost was approximately $103.0 million,
with $16.0 million provided by equity contributions of the partners and the
remainder provided by long-term debt. See Note 12 for an explanation of
NOARK's long-term debt and certain obligations related thereto.
(8) Disclosures About the 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.
The estimated fair values of the Company's financial instruments
as of December 31, 1993 and 1992, were as follows:
1993 1992
------------------ -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------
(in thousands)
Cash $834 $834 $1,122 $1,122
Customer deposits $3,927 $3,927 $3,510 $3,510
Long-term debt $127,000 $134,661 $143,335 $148,474
=============================================================================
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 in fact 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.
At December 31, 1993 and 1992 the Company also had an interest
rate swap with a notional amount of $30.0 million, as discussed in Note 2,
with terms that approximate fair market value.
(9) Segment Information
The Company operates principally in the exploration and
production segment and the gas distribution segment of the natural gas
industry. Exploration and production activities consist of ownership of
mineral interests in productive and undeveloped leases located entirely in
the United States. The gas distribution activities consist of the operation
of integrated natural gas transmission and distribution utility systems in
the states of Arkansas and Missouri.
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, 1993, 1992 and 1991:
1993 1992 1991
- -----------------------------------------------------------------------------
(in thousands)
Revenues
Exploration and production $ 79,374 $ 60,554 $ 49,392
Gas distribution 131,892 117,495 121,302
Other 262 256 256
Eliminations (36,684) (34,475) (34,511)
- -----------------------------------------------------------------------------
$174,844 $143,830 $136,439
- -----------------------------------------------------------------------------
Intersegment Revenues
Exploration and production $ 36,091 $ 33,994 $ 34,098
Gas distribution 337 225 157
Other 256 256 256
- -----------------------------------------------------------------------------
$ 36,684 $ 34,475 $ 34,511
- -----------------------------------------------------------------------------
Operating Income
Exploration and production $ 42,608 $ 33,071 $ 28,310
Gas distribution 15,261 13,094 14,027
Corporate expenses (305) (177) (195)
- -----------------------------------------------------------------------------
$ 57,564 $ 45,988 $ 42,142
- -----------------------------------------------------------------------------
Identifiable Assets
Exploration and production $236,968 $224,302 $210,593
Gas distribution 186,704 179,998 168,047
Other 21,782 22,875 13,568
- -----------------------------------------------------------------------------
$445,454 $427,175 $392,208
- -----------------------------------------------------------------------------
Depreciation, Depletion and Amortization
Exploration and production $ 25,686 $ 19,128 $ 13,843
Gas distribution 4,564 4,213 3,978
Other 694 539 427
- -----------------------------------------------------------------------------
$ 30,944 $ 23,880 $ 18,248
- -----------------------------------------------------------------------------
Capital Additions
Exploration and production $ 37,411 $ 30,823 $ 30,339
Gas distribution 19,892 12,188 7,856
Other 1,916 1,898 693
- -----------------------------------------------------------------------------
$ 59,219 $ 44,909 $ 38,888
=============================================================================
(10) Stock Options
In 1993, the Board of Directors adopted, and the shareholders
approved, the Southwestern Energy Company 1993 Stock Incentive Plan (1993
Plan) for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan replaced both the Company's 1985
Non-Qualified Stock Option Plan (1985 Plan) and the long-term component of
the Company's existing cash-based incentive compensation plan. 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 ten-year term of the plan.
At December 31, 1993, there were options for 102,404 shares
outstanding under the 1993 Plan at an option price of $17 1/8, representing
the fair market value at the date of grant. The options vest to employees
over a three-year period and expire ten years from the date of grant.
Additionally,
there were 17,447 shares of restricted stock granted which vest to employees
over a five-year period. The related compensation expense is being amortized
over the vesting period.
Under the 1985 Plan, there were options for 427,050 shares and
84,900 SARs outstanding at December 31, 1993, at prices ranging from $5.58 to
$12.81. All options are currently exercisable. Options and SARs totaling
103,350 shares were exercised or canceled during 1993 at prices ranging from
$5.58 to $10.60. All options expire ten years from the date of grant. The
number of options, SARs and option prices have been restated to reflect the
effect of a three-for-one stock split distributed in 1993.
In 1993, the Company also adopted, and the shareholders approved,
the Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors. The directors' plan 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. Options
are issued at fair market value on the date of grant and become exercisable
in installments at a rate of 25% per year for each twelve months' service as
a director. At December 31, 1993, there were options for 48,000 shares
outstanding at an option price of $17 1/2.
(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. The exercise price and the number of rights outstanding have been
adjusted to reflect the effects of the stock split distributed in 1993. These
rights will become exercisable in the event that a person or group acquires
or commences a tender offer for 20% or more of the Company's outstanding
shares or the Board determines that a holder of 10% or more of the Company's
outstanding shares presents a threat to the best interests of the Company. At
no time will these rights have any voting power.
If any person or entity actually acquires 20% of the common stock
(10% or more if the Board determines such acquiror is adverse), rightholders
(other than the 20% or 10% stockholder) will be entitled to buy, at the
right's then current exercise price, the Company's common stock with a market
value of twice the exercise price. Similarly, if the Company is acquired in a
merger or other business combination, each right will entitle its holder to
purchase, at the right's then current exercise price, a number of the
surviving company's common shares having a market value at that time of twice
the right's exercise price.
The rights may be redeemed by the Board for $.003 per right prior
to the time that they become exercisable. In the event, however, that
redemption of the rights is considered in connection with a proposed
acquisition of the Company, the Board may redeem the rights only on the
recommendation of its independent directors (nonmanagement directors who are
not affiliated with the proposed acquiror). These rights expire in 1999.
(12) Contingencies and Commitments
The Company and the other major general partner of NOARK are
required to severally guarantee the availability of certain minimum cash
balances to service $63.0 million of 9.7375% Senior Secured Notes used to
finance a portion of NOARK's total construction cost. The notes have a
remaining term of 16 years and the Company's share of the several guarantee
is 60%. In 1993, NOARK also entered into an unsecured long-term revolving
credit agreement in the amount of $30.0 million with a group of banks. At
December 31, 1993, $25.2 million was outstanding under this credit
arrangement. Amounts borrowed under the long-term revolving credit facility
are severally guaranteed by the Company and an affiliate of the other major
general partner. The Company's share of the several guarantee of the line of
credit is also 60%. Additionally, the Company's gas distribution subsidiary
has a ten-year transportation contract with NOARK for firm capacity of 41
MMcfd.
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. The complaint seeks rescission of the transportation
contract and rescission of a separate contract to purchase gas from two of
the Company's affiliates, as well as actual and punitive damages in excess of
$1.0 million. The Company believes the suit is without merit and filed a
counterclaim in February, 1994, seeking enforcement of the contracts and
damages. Until enforcement occurs or replacement transportation contracts
are arranged, 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 believes any funding which may be required for NOARK will
not have a material effect on the financial condition or reported results of
operations of the Company.
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.
(13) Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations
for the years ended December 31, 1993 and 1992:
Quarter Ended March 31 June 30 September 30 December 31
- -----------------------------------------------------------------------------
(in thousands, except per share amounts)
1993
-----
Operating revenues $59,208 $33,990 $28,466 $53,180
Operating income $21,259 $8,738 $7,789 $19,778
Income before cumulative
effect of accounting change $11,372 $3,696 $1,439 $10,543
Net income $21,498 $3,696 $1,439 $10,543
Earnings per share before
cumulative effect of
accounting change $.44 $.15 $.05 $.41
Earnings per share $.83 $.15 $.05 $.41
1992
-----
Operating revenues $48,874 $25,125 $20,992 $48,839
Operating income $16,609 $5,228 $5,354 $18,797
Net income $8,795 $1,820 $1,769 $9,881
Earnings per share $.35 $.07 $.07 $.38
=============================================================================
FINANCIAL AND OPERATING STATISTICS
1993 1992 1991 1990 1989 1988
- ---------------------------------------------------------------------------------------------------------
Financial Review
(in thousands)
Operating revenues:
Exploration and production $ 79,374 $ 60,554 $ 49,392 $ 41,489 $ 40,499 $ 34,345
Gas distribution 131,892 117,495 121,302 108,911 117,514 89,277
Other 262 256 256 256 256 256
Intersegment revenues (36,684) (34,475) (34,511) (33,586) (33,670) (27,670)
- ---------------------------------------------------------------------------------------------------------
174,844 143,830 136,439 117,070 124,599 96,208
- ---------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 42,962 35,848 40,423 37,678 46,850 34,055
Operating and general 40,093 34,970 32,609 28,134 26,132 21,466
Depreciation, depletion and
amortization 30,944 23,880 18,248 14,756 16,055 12,168
Taxes, other than income
taxes 3,281 3,144 3,017 2,885 2,844 2,350
- ---------------------------------------------------------------------------------------------------------
117,280 97,842 94,297 83,453 91,881 70,039
- ---------------------------------------------------------------------------------------------------------
Operating income 57,564 45,988 42,142 33,617 32,718 26,169
Interest expense, net (9,025) (9,983) (9,813) (10,530) (10,662) (8,049)
Other income (expense) (1,657) (421) (107) (17) 180 46
- ---------------------------------------------------------------------------------------------------------
Income before provision for
income taxes 46,882 35,584 32,222 23,070 22,236 18,166
- ---------------------------------------------------------------------------------------------------------
Provision for income taxes:
Current 13,704 7,403 7,158 4,994 6,671 4,380
Deferred 6,128 5,916 4,999 3,568 1,586 2,254
- ---------------------------------------------------------------------------------------------------------
19,832 13,319 12,157 8,562 8,257 6,634
- ---------------------------------------------------------------------------------------------------------
Income before extraordinary
item and cumulative effect
of accounting change 27,050 22,265 20,065 14,508 13,979 11,532
Extraordinary loss due to
redemption of convertible
debentures (net of $257
tax benefit) - - - (433) - -
Cumulative effect of change in
accounting for income taxes 10,126 - - - - -
- ---------------------------------------------------------------------------------------------------------
Net income $ 37,176 $ 22,265 $ 20,065 $ 14,075 $ 13,979 $ 11,532
=========================================================================================================
Cash flow from operations
(in thousands) $ 70,191 $ 49,730 $ 34,986 $ 36,495 $ 29,306 $ 20,030
Return on equity(1) 15.51% 14.53% 14.75% 11.66% 13.51% 12.25%
Gross profit margin 32.92% 31.97% 30.89% 28.72% 26.26% 27.20%
Net profit margin(1) 15.47% 15.48% 14.71% 12.02% 11.22% 11.99%
=========================================================================================================
Common Stock Statistics(2)
Earnings per share before
extraordinary item and
cumulative effect of
accounting change $1.05 $.87 $.78 $.57 $.56 $.46
Earnings per share $1.44 $.87 $.78 $.56 $.56 $.46
Cash dividends declared
and paid per share $.22 $.20 $.19 $.19 $.19 $.19
Book value per share $7.18 $5.97 $5.30 $4.70 $4.15 $3.77
Market price at year end $18.00 $12.96 $10.50 $10.42 $10.75 $6.00
Number of shareholders of
record at year end 3,005 2,930 2,989 3,136 3,298 3,426
Average shares outstanding 25,684,110 25,683,963 25,678,011 25,270,674 24,940,488 24,940,488
=========================================================================================================
Capitalization (in thousands)
Long-term debt, including
current portion $127,000 $143,335 $134,104 $125,535 $128,449 $107,082
Common shareholders' equity 184,530 153,233 136,041 120,709 103,455 94,115
- ---------------------------------------------------------------------------------------------------------
Total capitalization $311,530 $296,568 $270,145 $246,244 $231,904 $201,197
- ---------------------------------------------------------------------------------------------------------
Total assets $445,454 $427,175 $392,208 $366,313 $347,212 $311,632
- ---------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding
current portion) 40.19% 48.31% 49.08% 50.39% 54.82% 52.58%
Equity 59.81% 51.69% 50.92% 49.61% 45.18% 47.42%
=========================================================================================================
Capital Expenditures (in millions)
Exploration and production $37.4 $30.8 $30.3 $23.4 $26.6 $14.0
Gas distribution 19.9 12.2 7.9 9.3 8.9 6.8
Other 1.9 1.9 .7 .7 3.5 .6
- ---------------------------------------------------------------------------------------------------------
$59.2 $44.9 $38.9 $33.4 $39.0 $21.4
=========================================================================================================
<FN>
(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.
1993 1992 1991 1990 1989 1988
- ---------------------------------------------------------------------------------------------------------
Natural Gas and Oil Wells
Completed
Producers:
Gross 57.0 69.0 25.0 25.0 38.0 48.0
Net 40.7 54.6 11.8 9.1 16.4 19.1
Dry holes:
Gross 28.0 29.0 12.0 10.0 22.0 25.0
Net 14.5 19.5 4.1 2.1 7.3 3.1
- ---------------------------------------------------------------------------------------------------------
Total:
Gross 85.0 98.0 37.0 35.0 60.0 73.0
Net 55.2 74.1 15.9 11.2 23.7 22.2
At the end of 1993, the
Company was a participant
in 5.0 (1.1 net) wells
in process.
=========================================================================================================
Natural Gas and Oil Produced
Natural gas:
Production, Bcf 35.4 25.5 19.9 16.4 15.3 12.0
Average price per Mcf $2.18 $2.26 $2.26 $2.33 $2.43 $2.61
Oil:
Production, MBbls 96 120 176 112 148 160
Average price per barrel $17.20 $19.75 $20.67 $22.89 $17.89 $14.58
Average production (lifting) cost
per Mcf equivalent $.18 $.16 $.19 $.16 $.14 $.25
Proved reserves at year end:
Natural gas, Bcf 318.8 312.3 307.5 304.5 252.9 216.0
Oil, MBbls 479 359 505 773 745 911
=========================================================================================================
Utility Operating Data(1)
Sales volumes, Bcf:
Residential 12.9 10.8 10.9 10.1 11.6 8.4
Commercial 7.8 6.6 6.7 6.3 7.1 5.4
Industrial 6.1 6.1 9.5 10.2 9.8 7.9
Transportation volumes, Bcf
End users 5.6 5.2 1.3 .1 .5 .5
Off-system 11.7 2.5 .2 .3 .1 1.5
- ---------------------------------------------------------------------------------------------------------
44.1 31.2 28.6 27.0 29.1 23.7
- ---------------------------------------------------------------------------------------------------------
Average sales customers:
Residential 137,087 133,103 129,379 127,142 125,581 100,846
Commercial 18,511 18,141 17,880 17,680 17,437 14,060
Industrial 346 348 370 366 372 330
- ---------------------------------------------------------------------------------------------------------
155,944 151,592 147,629 145,188 143,390 115,236
- ---------------------------------------------------------------------------------------------------------
Sales and transportation
revenues (in thousands):
Residential $ 67,502 $ 59,747 $ 58,372 $ 48,407 $ 54,181 $38,790
Commercial 35,311 31,425 30,718 27,535 30,522 22,742
Industrial 21,757 20,502 29,187 30,463 29,982 24,646
Transportation 5,177 3,597 857 179 368 349
- ---------------------------------------------------------------------------------------------------------
$129,747 $115,271 $119,134 $106,584 $115,053 $86,527
- ---------------------------------------------------------------------------------------------------------
Miles of pipe:
Gathering 398 383 375 371 364 360
Transmission 1,335 1,321 1,326 1,326 1,309 1,296
Distribution 4,160 4,090 4,002 3,931 3,859 3,794
- ---------------------------------------------------------------------------------------------------------
5,893 5,794 5,703 5,628 5,532 5,450
- ---------------------------------------------------------------------------------------------------------
Degree days 4,929 4,104 4,095 3,972 4,961 4,697
Percent of normal 113% 92% 93% 90% 112% 106%
=========================================================================================================
<FN>
(1)Includes operating data of Associated since acquisition in June, 1988.
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 Wednesday, May
25, 1994, 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 Auditors
Arthur Andersen & Co.
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
This annual report and the statements contained herein are submitted for the
general information of shareholders of the Company and are not intended to
induce any sale or purchase of securities or to be used in connection therewith.
The 1993 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
------------------------------------- --------------------
1993 1992 1993 1992
- ------------------------------------------------------------------------------
High Low High Low
March 31 $15.25 $12.13 $11.17 $9.38 $.05 $.05
June 30 $16.83 $14.13 $11.04 $9.25 $.05 $.05
September 30 $21.75 $16.04 $12.42 $10.04 $.06 $.05
December 31 $21.88 $15.13 $13.96 $11.92 $.06 $.05
==============================================================================
Market prices represent transactions on the New York Stock Exchange.
Southwestern Energy Company and Subsidiaries
APPENDIX TO 1993 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in three
areas; the Arkoma Basin, the Anadarko Basin and the Gulf Coast. 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. Southwestern's Gulf Coast
operations include both onshore and offshore activity along both the Texas and
Louisiana coasts.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where they also provide
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 47.33% general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Claimant's distribution
and gathering pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Fort 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.
Operating Properties:
ACREAGE AND PRODUCING WELLS
Undeveloped Developed Wells
Gross Net Gross Net Gross Net
- ---------------------------------------------------------------------------
Arkansas 164,750 88,030 282,336 138,799 632 338.3
Louisiana 15,428 7,783 10,217 2,842 7 3.1
Oklahoma 23,133 17,992 28,726 11,437 122 24.7
Texas 21,539 7,591 50,185 11,192 27 5.7
Other areas 9,316 6,984 5,417 1,385 19 5.2
- ---------------------------------------------------------------------------
234,166 128,380 376,881 165,655 807 377.0
===========================================================================
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
- ---------------------------------------------------------------------------
Gathering 398 -- 398
Transmission 739 596 1,335
Distribution 2,625 1,535 4,160
- ---------------------------------------------------------------------------
3,762 2,131 5,893
===========================================================================