Management's Discussion and Analysis of Financial Condition and
Results of Operations
RESULTS OF OPERATIONS
Net income in 1994 decreased by 7% to $25.1 million, or $.98 per share,
down from $27.1 million, or $1.05 per share, in 1993. Net income in 1992 was
$22.3 million, or $.87 per share. The comparison of 1994 to 1993 excludes the
cumulative effect of a change in accounting for income taxes which was recorded
in the first quarter of 1993. Operating results for 1993 also 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 a legislated increase in the
federal corporate income tax rate. There were no accounting changes or
extraordinary items recorded in either 1994 or 1992.
The decline in 1994 earnings resulted as lower gas prices and much warmer
heating weather offset the favorable effect of the Company's seventh consecutive
increase in natural gas production. The low gas prices also magnified the effect
on earnings of a settlement reached to resolve certain gas cost issues before
the Arkansas Public Service Commission (APSC). The settlement, which involved
the price of gas sold under a contract between one of the Company's exploration
and production subsidiaries and its utility subsidiary, is hereafter referred to
as "the gas cost settlement" and is discussed below under Regulatory Matters.
The earnings growth in 1993 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.
1994 1993 1992
-------------------------------------------------------------------------------
(in thousands)
REVENUES
Exploration and production $ 80,123 $ 79,374 $ 60,554
Gas distribution 127,060 131,892 117,495
Other 308 262 256
Eliminations (37,305) (36,684) (34,475)
-------------------------------------------------------------------------------
$170,186 $174,844 $143,830
===============================================================================
OPERATING INCOME
Exploration and production $ 38,883 $ 42,608 $ 33,071
Gas distribution 13,391 15,261 13,094
Corporate expenses (192) (305) (177)
-------------------------------------------------------------------------------
$ 52,082 $ 57,564 $ 45,988
===============================================================================
EXPLORATION AND PRODUCTION REVENUES
The Company's exploration and production revenues increased 1% in 1994 and
31% in 1993. The slight increase in 1994 was due to increases in natural gas and
oil production, offset by lower average product prices. The increase in 1993 was
due to increased natural gas production. Gas production increased by 6% to 37.7
billion cubic feet (Bcf) in 1994 from 35.7 Bcf in 1993. Gas production in 1993
increased by 38% from 25.8 Bcf in 1992. Increased sales to unaffiliated
purchasers have accounted for approximately 80% of the increase in gas
production since 1992.
Gas sales to unaffiliated purchasers increased to 23.8 Bcf in 1994, from
22.9 Bcf in 1993, and 14.4 Bcf in 1992. The increases in sales to unaffiliated
purchasers were primarily the result of higher sales from the Company's
properties in both Arkansas and the Gulf Coast areas of Texas and Louisiana. The
Company sold 15.1 Bcf of its Arkansas production to unaffiliated purchasers
during both 1994 and 1993, compared to 10.6 Bcf in 1992. The increase from the
1992 level 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. Much of this incremental production was sold into interstate
markets as a result of improved access to those markets made possible by the
NOARK Pipeline System (NOARK). NOARK 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 in NOARK of
approximately 48% and is the pipeline's operator. Sales from the Company's Gulf
Coast properties were 6.8 Bcf in 1994, compared to 6.3 Bcf in 1993, and 2.0 Bcf
in 1992. The increase in 1994 was primarily the result of the completion of a
production platform at the Galveston Block 283 gas field late in 1993 and first
production from the Earl Chauvin No. 1 well, a 1993 discovery in southeast
Louisiana. 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.
1994 1993 1992
-------------------------------------------------------------------------------
GAS PRODUCTION
Affiliated sales (Bcf) 13.9 12.8 11.4
Unaffiliated sales (Bcf) 23.8 22.9 14.4
-------------------------------------------------------------------------------
37.7 35.7 25.8
-------------------------------------------------------------------------------
Average price per Mcf $2.04 $2.18 $2.26
===============================================================================
OIL PRODUCTION
Unaffiliated sales (MBbls) 200 97 120
-------------------------------------------------------------------------------
Average price per Bbl $15.89 $17.20 $19.75
===============================================================================
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 when sales prices were
deemed below acceptable levels. The Company also uses gas price hedges on a
limited basis to reduce the Company's exposure to the risk of changing prices.
Deliveries for injection into storage and the gas cost settlement increased
the demand of the Company's utility distribution systems for affiliated gas
supply in 1994. Gas production sold to Arkansas Western Gas Company (AWG), the
utility subsidiary which operates the Company's northwest Arkansas utility
system, was 8.8 Bcf in 1994, up from 7.1 Bcf in 1993, and 7.2 Bcf in 1992. The
increase in gas sold to AWG in 1994 was due largely to increased storage
injections and higher volumes resulting from the gas cost settlement, as
discussed below. 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
14
system and an increase in sales to a spot market purchasing program available to
the larger business customers of AWG. The Company's gas production provided
approximately 64% of AWG's requirements in 1994, and approximately 50% in 1993
and 1992. Additionally, in 1994, 1993, and 1992, the Company sold .5 Bcf, .7
Bcf, and .4 Bcf, respectively, of gas to AWG for its spot market purchasing
program.
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 AWG's system are subject to a long-term contract
entered into in 1978, under which the price had been frozen since the end of
1984. As mentioned above and discussed more fully under Regulatory Matters, this
contract was amended in 1994 as a result of the settlement of certain gas cost
issues with the APSC. The settlement became effective July 1, 1994, and calls
for sales under the contract to take place at a price which is equal to a spot
market index plus an additional premium. The settlement results in a lower
contract price based on current market conditions. That effect is offset in part
by provisions which allow additional volumes to be sold under the contract.
Other sales to AWG are made under long-term contracts with flexible pricing
provisions and under short-term spot arrangements.
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 5.1 Bcf in 1994, 5.7 Bcf in 1993,
and 4.3 Bcf in 1992. Deliveries to Associated decreased in 1994 due to warmer
weather and increased in 1993 due to colder heating weather and storage
requirements during the summer months. 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, increased to $2.385 per Mcf for the contract period ending
September 30, 1994, and are currently being made at $2.20 per Mcf.
The average price received at the wellhead for the Company's total gas
production was $2.04 per Mcf in 1994, $2.18 per Mcf in 1993, and $2.26 per Mcf
in 1992. The decline in the average price received since 1992 reflects the
recent decline in spot market prices, an increase in the proportionate share of
the Company's production sold at spot market prices and under long-term
contracts with market-sensitive pricing, and the effect of the gas cost
settlement. Natural gas prices declined during the last half of 1994, and with
the abnormally warm winter recently experienced across the country, average
prices are generally expected to remain lower in 1995 as compared to 1994. As
described above, a significant portion of the Company's gas production is sold
under long-term contracts to its gas distribution subsidiary. In the past, the
fixed prices received under these sales arrangements helped reduce the effects
of fluctuations in the spot market price for natural gas. Going forward, the
Company expects increased volatility and seasonality in its operating results as
the majority of its gas sales will be tied to a spot market index. In the
future, the Company expects the overall average price it receives for its total
production to be generally higher than average spot market prices due to the
premiums over spot that it receives. Future changes in revenues from sales of
the Company's gas production will be dependent upon changes in the market price
for gas, access to new markets, maintenance of existing markets, and additions
of new gas reserves.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. 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 due to the effects of weather. Because of the
corresponding changes in purchased gas costs, the revenue effect of the pass-
through of gas cost changes has not materially affected net income.
1994 1993 1992
-------------------------------------------------------------------------------
GAS DISTRIBUTION SYSTEMS
Deliveries (Bcf)
Sales volumes 26.3 26.8 23.5
Transportation volumes
End-use 4.8 5.6 5.2
Off-system 10.7 11.7 2.5
-------------------------------------------------------------------------------
41.8 44.1 31.2
-------------------------------------------------------------------------------
Average number of sales customers 159,897 155,944 151,592
-------------------------------------------------------------------------------
Heating weather--degree days 4,161 4,929 4,104
-------------------------------------------------------------------------------
Average sales rate per Mcf $4.57 $4.65 $4.75
===============================================================================
Gas distribution revenues decreased by 4% in 1994 and increased by 12% in
1993. The decrease in 1994 reflected the net effects of strong customer growth,
weather which was 16% warmer than the prior year, and lower purchased gas costs
caused in part by the gas cost settlement. 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.
15
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
In 1994, AWG sold 16.3 Bcf to its customers at an average rate of $4.25 per
Mcf, compared to 17.1 Bcf at $4.40 per Mcf in 1993, and 15.0 Bcf at $4.62 per
Mcf in 1992. Additionally, AWG transported 4.0 Bcf for its end-use customers in
1994, 3.9 Bcf in 1993, and 3.2 Bcf in 1992. Associated sold 10.0 Bcf to its
customers in 1994 at an average rate of $5.10 per Mcf, compared to 9.7 Bcf in
1993 at $5.08 per Mcf, and 8.4 Bcf at $4.99 per Mcf in 1992. The increase in
1994 was due to the conversion of an industrial customer from transportation to
sales service. While the conversion of this customer to sales service raised the
Company's gas distribution revenues, there was no resulting impact on operating
income as the rate charged this customer for transportation service was equal to
the rate charged for sales service, exclusive of gas costs. Associated
transported .8 Bcf for its end-use customers in 1994, compared to 1.7 Bcf in
1993, and 2.0 Bcf in 1992.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, increased to 12.3 Bcf in 1994, from 11.7 Bcf in 1993,
and 11.3 Bcf in 1992. 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 10.7 Bcf of gas through its gathering system in 1994
for off-system deliveries, all through NOARK, compared to 11.7 Bcf in 1993, and
2.5 Bcf in 1992. The average transportation rate was $.13 per Mcf, exclusive of
fuel, in all 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 approximately 3.5% to 4.0% 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.
AWG is precluded from filing an application for a rate increase with the APSC
prior to January 1, 1996, as a result of the gas cost settlement. The Company
anticipates filing a rate increase request for AWG in early 1996 and will
continue to monitor the status of returns on the systems operated by Associated
and file rate cases as the need arises.
REGULATORY MATTERS
During 1994, the Company reached a settlement with the Staff of the APSC
and the Office of the Attorney General of the State of Arkansas concerning
certain gas cost issues which had been outstanding before the APSC for the past
four years. The gas cost issues were first raised by the APSC in December, 1990,
in connection with its approval of an AWG rate increase. The issues in question
involved the price of gas sold under a long-term contract between AWG and one of
the Company's gas producing subsidiaries. The terms of the settlement became
effective as of July 1, 1994, and were approved by the APSC on January 5, 1995.
Under the settlement, the price paid by AWG is tied to a monthly spot market
index plus an additional premium. Given current market conditions, the new
pricing provision results in a reduced sales price. That effect is offset in
part by provisions which allow additional volumes to be sold under the contract.
The amended contract provides for volumes equal to the historical level of sales
under the contract to be sold at the spot market index plus a premium of $.95
per Mcf, while any incremental sales volumes will receive a premium of $.50 per
Mcf. In 1994, approximately 8.1 Bcf (net to the Company's interest) was sold
under the contract, compared to approximately 6.0 Bcf in 1993. Other significant
terms of the settlement prevent any of the parties thereto from asking for
refunds, transfers certain of AWG's natural gas storage facilities to another
subsidiary of the Company, and prohibits AWG from filing a rate case for its
northwest Arkansas system before January, 1996, as mentioned above.
As discussed earlier, Associated also purchases a portion of its gas supply
at the wellhead from one of the Company's gas producing subsidiaries under a
long-term firm contract entered into in October, 1990. As a result of recent gas
cost audits for the two-year period ended August 31, 1992, the Staff of the
Missouri Public Service Commission (Staff) recommended the disallowance of
approximately $3.1 million in gas costs. This amount represents the difference
between the price paid by Associated and a spot market index price for gas
delivered into an interstate pipeline operating in the Arkoma Basin. The price
paid by Associated under the contract was $1.90 per Mcf during the period in
question. In making its recommendation, the Staff acknowledged that Associated
had lowered its gas cost and saved its ratepayers money by purchasing gas from
its affiliate. The Staff also acknowledged that the appropriate price for
purchases made under this long-term firm contract should include a premium over
the spot market price. However, a Staff consultant testified that there was
insufficient data upon which to determine an appropriate premium over a spot
market index for pricing purchases under this contract and that he was unable to
determine what the appropriate premium should be. A hearing was held on January
31, 1995. The Company presented testimony to demonstrate that the price paid
under the contract was at or below the market price for contracts with similar
terms during the period in which the purchases were made. The APSC previously
reviewed the costs charged to Arkansas rate-payers under this contract and found
them to be proper and allowable for recovery. The Missouri Public Service
Commission (Missouri Commission) has not yet issued an order in this proceeding.
The Staff has also audited Associated's gas purchases for the period from
September, 1992, through August, 1993, and recommended no changes to the gas
costs for that period. The Company does not expect any outcome of the proceeding
to have a material adverse effect on the results of operations or the financial
position of the Company.
In April, 1992, the Federal Energy Regulatory Commission issued Order No.
636, a comprehensive set of regulations designed to encourage competition and
continue the significant restructuring of the interstate natural gas pipeline
industry. Prior to Order No. 636, Associated purchased portions of its gas
supply from interstate pipelines under firm long-term supply contracts. The
Company has paid approximately $3.2 million in contract reformation costs and
16
take-or-pay costs and $1.9 million in transition costs which these interstate
pipelines incurred and were allowed to recover. The Company anticipates full
recovery of the $1.9 million in transition costs incurred. Additionally, the
Company has recovered, subject to refund, approximately $1.6 million of the
contract reformation costs and take-or-pay costs from its utility sales
customers in the state of Missouri. Of the unrecovered $1.6 million related to
contract reformation costs and take-or-pay costs, $.7 million is applicable to
Associated's transportation customers in the state of Missouri and $.9 million
is applicable to all customers in the state of Arkansas. The Staff of the
Missouri Commission has reviewed these payments and made a recommendation that
the unrecovered $.7 million related to Associated's transportation customers
should be disallowed on the grounds of retroactive rate-making. The Company
disagreed with this recommendation and a hearing was held on January 31, 1995.
The Company is awaiting the Missouri Commission's order.
AWG also purchases gas from unaffiliated producers under take-or-pay
contracts. Currently, the Company believes that it does not have a significant
exposure to liabilities resulting from these contracts, although the Company's
exposure to take-or-pay liabilities to producers or other suppliers has
increased in recent years as a result of a decline in its gas purchase
requirements which has occurred as some of its large business customers
converted to a transportation service offered by AWG and Associated in Arkansas
and began to 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 1% in 1994 and by
20% in 1993. The slight increase in 1994 resulted from increased depreciation,
depletion and amortization expense (DD&A) primarily related to the Company's
exploration and production segment and increased utility operating expenses,
offset by lower purchased gas costs related to lower prices paid for gas
supplies. The increase in 1993 was due primarily to increased purchased gas
costs related to increased utility deliveries, and increased production costs
and DD&A resulting from increased gas sales in the exploration and production
segment. Purchased gas costs are one of the largest expense items in each year,
typically representing 30% to 40% of the Company's total operating costs and
expenses. Purchased gas costs are influenced primarily by changes in
requirements for gas sales of the gas distribution segment, the price and mix of
gas purchased, and the timing of recoveries of deferred purchased gas costs. As
previously mentioned, increases and decreases in purchased gas costs are
automatically passed through to the Company's utility customers.
The Company follows the full-cost method of accounting for the exploration,
development, and acquisition of oil and gas properties. DD&A is calculated using
the units-of-production method. The Company's annual gas and oil production, as
well as the amount of proved reserves owned by the Company and the costs
associated with adding those reserves, are all components of the amortization
calculation. DD&A increased 15% in 1994 due both to an increase in gas and oil
production and an increase in the amortization rate. The 30% increase in DD&A in
1993 was primarily due to increased levels of natural gas production. The margin
between the Company's full cost ceiling and the financial statement carrying
value of the Company's gas and oil properties was eroded substantially during
1994 as a result of very low average gas prices in effect at December 31, 1994.
Product prices, production rates, levels of reserves, and the evaluation of
unamortized costs all influence the calculation of the ceiling. A significant
decline in gas prices from year-end 1994, without other mitigating factors,
could cause a future write-down and a noncash charge against earnings.
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 some 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.
OTHER COSTS AND EXPENSES
Interest costs were down slightly in 1994, as compared to 1993, due to
lower average borrowings on the Company's revolving credit facilities throughout
most of the year, partially offset by higher average interest rates. Borrowings
under these facilities were higher at year-end 1994, as compared to 1993,
primarily as a result of increased capital spending activity during the fourth
quarter of 1994. 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, and due
to both lower average borrowings and lower average interest rates on the
Company's revolving credit facilities.
The change in other income during 1994 and 1993 relates primarily to the
Company's share of operating losses incurred by NOARK. The Company accounts for
its 47.93% interest in the NOARK partnership under the equity method of
accounting (see Note 7 to the financial statements for additional discussion).
NOARK has been operating below capacity and generating losses since it was
placed in service. The Company's share of the pretax loss for NOARK included in
other income was $2.8 million in 1994, $1.8 million in 1993, and $.6 million in
1992. Deliveries are currently being made by NOARK to portions of AWG's
distribution system, to Associated, and to the interstate pipelines with which
NOARK interconnects. In 1994, NOARK had
17
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
an average daily throughput of 82 million cubic feet of gas per day (MMcfd),
compared to 79 MMcfd in 1993, its first full year of operation. 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 was supplying 25 MMcfd of the volumes
transported by Vesta under that agreement. In late 1993, Vesta filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its contract with NOARK. The
complaint and subsequent filings seek rescission of both the transportation
contract and a contract to purchase gas from the Company's affiliates, along
with actual and punitive damages. The Company and NOARK believe the suit is
without merit and have filed counterclaims seeking enforcement of the contracts
and damages.
The APSC has established a maximum transportation rate of approximately
$.285 per dekatherm for NOARK based on its original construction cost estimate
of approximately $73 million. Due to construction conditions and the addition of
a compressor station, the ultimate cost of the pipeline exceeded the original
estimate by approximately $30 million. NOARK competes primarily with two
interstate pipelines in its gathering area. One of those elected to become an
open access transporter subsequent to NOARK's start of construction. That
pipeline, which was recently sold, has not offered firm transportation, but the
increased availability of interruptible transportation service has intensified
the competitive environment within which NOARK operates. The Company expects
further losses from its equity investment in NOARK until the pipeline is able to
increase its level of throughput and until improvement occurs in the competitive
conditions which determine the transportation rates NOARK can charge. The
Company and the other partners of NOARK are currently investigating several
options which would improve NOARK's future financial prospects. However, the
Company believes that no write-down of its investment in NOARK is appropriate at
this time and that it will realize its investment in NOARK over the life of the
system.
The Company's effective income tax rate was 38.5% in 1994, 42.3% in 1993,
and 37.4% in 1992. The rate increased in 1993 because the Company's deferred tax
provision included $1.7 million of expense for the legislated increase in the
maximum federal corporate income tax rate.
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 1994, 1993, and
1992, net cash provided from operating activities totaled $66.6 million, $70.2
million, and $49.7 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 92% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1994, in excess of 100% in 1993, and 94% in 1992.
Dividends paid to common shareholders in 1994 were $6.2 million, compared
to $5.7 million in 1993, and $5.1 million in 1992. 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 rate is
equivalent to $.24 per share, compared to an annual dividend rate of $.20 per
share paid in 1992. The dividend rates reflect the effect of a three-for-one
stock split distributed in 1993.
On February 22, 1995, the Board of Directors authorized the repurchase of
up to $30 million of the Company's common shares. The shares will be purchased
from time to time, depending on market conditions, in the open market or in
private negotiated transactions. The Company plans to utilize available capacity
of its revolving credit facilities to fund the share repurchase. Shares
repurchased will be held in treasury and may be used for general corporate
purposes, including issuance under option plans. The repurchase program will
continue until terminated by the Company's Board of Directors.
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
Capital expenditures totaled $76.9 million in 1994, $59.2 million in 1993,
and $44.9 million in 1992. In 1994, expenditures for the exploration and
production segment included $13.9 million for acquisitions of reserves in place.
In 1992, the Company also made a $7.6 million equity contribution to the
partnership formed to construct NOARK.
1994 1993 1992
-------------------------------------------------------------------------------
(in thousands)
CAPITAL EXPENDITURES
Exploration and production $55,449 $37,411 $30,823
Gas distribution 17,577 19,892 12,188
Other 3,828 1,916 1,898
-------------------------------------------------------------------------------
$76,854 $59,219 $44,909
===============================================================================
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending will be adequate to allow the Company to maintain its
present markets, finance improvements necessary due to normal customer growth in
its gas distribution segment, and explore and develop existing gas and oil
properties as well as generate new drilling prospects.
Routine capital expenditures expected to be incurred in 1995 are
18
$71.7 million, consisting of $55.2 million for gas and oil exploration, $14.1
million for gas distribution system expenditures, and $2.4 million for general
purposes. The Company's capital expenditure plans also include approximately
$6.7 million of nonroutine spending, including $3.3 million for the construction
and renovation of office and operations facilities in the utility division and
$3.4 million for improvements to the utility's gas storage facilities. The gas
and oil expenditures include $12.0 million for exploratory drilling and $18.2
million to continue the development of the Company's acreage in the Arkoma
Basin.
During 1994, the Company increased its emphasis on acquisitions of
producing properties and expects that effort to continue as a supplement to its
exploration and development drilling programs. Such acquisitions may require
capital spending beyond that planned for routine purposes. The Company plans to
manage the debt portion of its capital structure over time through its policy of
adjusting its routine capital spending, but expects to continue to use
additional debt to address extraordinary needs or opportunities, such as
attractive acquisitions of gas and oil properties. Additionally, the Company may
use its existing revolving credit facilities to meet seasonal or short-term
requirements related to its capital expenditures.
FINANCING REQUIREMENTS
Two floating rate revolving credit facilities provide the Company access to
$80.0 million of variable rate long-term capital. Borrowings outstanding under
these credit facilities totaled $52.3 million at the end of 1994 and $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 1994 and 1993. The Company plans to
evaluate options for converting a significant portion of the amount outstanding
on its floating rate revolving credit facilities to another form of long-term
debt during 1995.
The Company and an affiliate of the other general partner of NOARK are
required to severally guarantee the availability of certain minimum cash
balances to service NOARK's 9.7375% Senior Secured Notes. These notes are held
by a major insurance company which also has a 20% limited partnership interest
in NOARK. The notes had a balance of $59.9 million at December 31, 1994, with
final maturity in 2009. The Company's share of the several guarantee of
available cash balances is 60%. NOARK also has an unsecured long-term revolving
credit agreement with a group of banks which provides the partnership access to
$30.0 million of additional funds. Amounts outstanding under this credit
arrangement were $29.6 million at December 31, 1994, and $25.2 million at
December 31, 1993. Amounts borrowed under the long-term revolving credit
agreement are severally guaranteed by the Company and an affiliate of the other
general partner. The Company's share of this several guarantee is also 60%. In
1994, the Company advanced $2.3 million to NOARK to fund its share of debt
service payments and to make the final payment of construction retainage to the
pipeline's main line contractor. The Company expects to advance funds to NOARK
totaling $4.5 million to $5.0 million during 1995 in connection with its
guarantees.
In July, 1992, 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, which expired in 1994, the Company received interest semiannually at a
fixed rate of 5.11% and paid interest semiannually at the London Interbank
Offered Rate. Over the two-year period the swap was in effect, the Company
received $.7 million in excess of its required payments. This amount was
recorded as a net reduction of interest expense.
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 1994, the
capital structure consisted of 40.1% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
59.9% equity, with a ratio of earnings to fixed charges of 3.3.
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 $8.9 million at the end of 1994,
and $8.1 million at the end of 1993. Current assets increased by 3% to $48.0
million in 1994, while current liabilities increased 1% to $39.1 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, offset by a decrease in accounts receivable
due to lower weather related sales at year-end 1994. The increase in current
liabilities resulted primarily from an increase in the current portion of long-
term debt and an increase in accounts payable, offset by a decrease in taxes
payable. The increase in accounts payable resulted primarily from the timing of
payments of amounts due. The decrease in taxes payable was due primarily to
lower taxable income and increased deductions for intangible drilling costs.
Intangible drilling costs are deductible currently for tax purposes, but are
capitalized and amortized over future periods for financial reporting purposes.
19
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, 1994 and
1993, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1994.
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, 1994 and 1993, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1994, 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 LLP
Tulsa, Oklahoma
February 7, 1995
20
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992
-----------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
OPERATING REVENUES
Gas sales $ 160,463 $ 166,164 $ 135,765
Oil sales 3,178 1,662 2,379
Gas transportation 4,721 5,177 3,597
Other 1,824 1,841 2,089
-----------------------------------------------------------------------------------------------------------------------
170,186 174,844 143,830
-----------------------------------------------------------------------------------------------------------------------
OPERATING COSTS AND EXPENSES
Purchased gas costs 36,395 42,962 35,848
Operating and general 42,506 40,093 34,970
Depreciation, depletion and amortization 35,546 30,944 23,880
Taxes, other than income taxes 3,657 3,281 3,144
-----------------------------------------------------------------------------------------------------------------------
118,104 117,280 97,842
-----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 52,082 57,564 45,988
-----------------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE
Interest on long-term debt 9,962 10,090 10,932
Other interest charges 504 483 547
Interest capitalized (1,599) (1,548) (1,496)
-----------------------------------------------------------------------------------------------------------------------
8,867 9,025 9,983
-----------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE) (2,362) (1,657) (421)
-----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 40,853 46,882 35,584
-----------------------------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES
Current 9,288 13,704 7,403
Deferred 6,441 6,128 5,916
-----------------------------------------------------------------------------------------------------------------------
15,729 19,832 13,319
-----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 25,124 27,050 22,265
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- 10,126 --
-----------------------------------------------------------------------------------------------------------------------
NET INCOME $ 25,124 $ 37,176 $ 22,265
=======================================================================================================================
EARNINGS PER SHARE
Income Before Cumulative Effect of Accounting Change $.98 $1.05 $.87
Cumulative Effect of Change in Accounting for Income Taxes -- .39 --
-----------------------------------------------------------------------------------------------------------------------
NET INCOME $.98 $1.44 $.87
=======================================================================================================================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 25,684,110 25,684,110 25,683,963
=======================================================================================================================
The accompanying notes are an integral part of the financial statements.
21
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31 1994 1993
-------------------------------------------------------------------------------------------------------------------
(in thousands)
ASSETS
CURRENT ASSETS
Cash $ 1,152 $ 834
Accounts receivable 32,325 34,894
Inventories, at average cost 12,199 9,580
Other 2,353 1,489
-------------------------------------------------------------------------------------------------------------------
Total current assets 48,029 46,797
-------------------------------------------------------------------------------------------------------------------
Investments 4,877 5,661
-------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $20,751,000 in 1994 and
$16,769,000 in 1993 excluded from amortization 435,570 375,281
Gas distribution systems 176,728 165,443
Gas in underground storage 36,629 37,171
Other 18,541 14,684
-------------------------------------------------------------------------------------------------------------------
667,468 592,579
Less: Accumulated depreciation, depletion and amortization 242,008 205,949
-------------------------------------------------------------------------------------------------------------------
425,460 386,630
-------------------------------------------------------------------------------------------------------------------
Other Assets 6,216 6,366
-------------------------------------------------------------------------------------------------------------------
$484,582 $445,454
===================================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt $ 6,071 $ 3,000
Accounts payable 18,670 16,114
Taxes payable 716 6,449
Customer deposits 4,232 3,927
Current portion of deferred income taxes 1,482 1,426
Over-recovered purchased gas costs, net 3,627 4,187
Other 4,345 3,594
-------------------------------------------------------------------------------------------------------------------
Total current liabilities 39,143 38,697
-------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 136,229 124,000
-------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 100,288 93,593
Deferred investment tax credits 2,416 2,617
Other 3,050 2,017
-------------------------------------------------------------------------------------------------------------------
105,754 98,227
-------------------------------------------------------------------------------------------------------------------
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 199,430 180,470
-------------------------------------------------------------------------------------------------------------------
223,435 204,475
Less: Unamortized cost of restricted shares issued under stock incentive plan,
21,499 shares in 1994 and 17,447 shares in 1993 262 228
Common stock in treasury, at cost, 2,053,974 shares 19,717 19,717
-------------------------------------------------------------------------------------------------------------------
203,456 184,530
-------------------------------------------------------------------------------------------------------------------
$484,582 $445,454
===================================================================================================================
The accompanying notes are an integral part of the financial statements.
22
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income $ 25,124 $ 37,176 $ 22,265
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 35,825 31,223 24,160
Deferred income taxes 6,441 6,128 5,916
Equity in loss of partnership 2,818 1,788 531
Cumulative effect of change in accounting for income taxes -- (10,126) --
Change in assets and liabilities:
(Increase) decrease in accounts receivable 2,569 (589) (5,002)
(Increase) decrease in inventories (2,619) (1,544) 440
Increase in accounts payable 2,556 2,298 876
Increase (decrease) in taxes payable (5,733) 3,111 1,848
Increase in customer deposits 305 417 347
Decrease in over-recovered purchased gas costs (560) (286) (1,335)
Net change in other current assets and liabilities (113) 603 (316)
--------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 66,613 70,199 49,730
--------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (76,854) (59,219) (44,909)
Investment in partnership (2,319) -- (7,573)
(Increase) decrease in gas stored underground 542 9,119 (4,432)
Other items 3,200 1,599 1,997
--------------------------------------------------------------------------------------------------------
Net cash used in investing activities (75,431) (48,501) (54,917)
--------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt 21,300 (15,500) 22,000
Payments on other long-term debt (6,000) (835) (12,769)
Dividends paid (6,164) (5,651) (5,137)
--------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 9,136 (21,986) 4,094
--------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 318 (288) (1,093)
Cash at beginning of year 834 1,122 2,215
--------------------------------------------------------------------------------------------------------
Cash at end of year $ 1,152 $ 834 $ 1,122
========================================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $180,470 $148,945 $131,817
Net income 25,124 37,176 22,265
Cash dividends declared ($.24 per share in 1994, $.22
per share in 1993 and $.20 per share in 1992) (6,164) (5,651) (5,137)
--------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $199,430 $180,470 $148,945
========================================================================================================
The accompanying notes are an integral part of the financial statements.
23
Notes to Financial Statements
December 31, 1994, 1993 and 1992
(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 approximately 48% 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 1994 presentation.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
Gas and Oil Properties-The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive) are
capitalized and amortized on an aggregate basis over the estimated lives of the
properties using the units-of-production method. The Company excludes all costs
of unevaluated properties from immediate amortization.
Gas Distribution Systems-Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of
the gas distribution system is provided using the straight-line method with
average annual rates for plant functions ranging from 2.2% to 6.9%. 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 97,000 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, 1994 and 1993 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.
24
DERIVATIVES
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. They are used to
manage defined interest rate and commodity price risks.
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. See Note 2 for a discussion of the Company's interest rate
swap agreement which expired in 1994. The Company had no outstanding interest
rate swap agreements at December 31, 1994.
The Company uses natural gas swap agreements on a limited basis to hedge
sales of natural gas. Under the natural gas swap agreements, the Company
makes payments or receives the differential between a specified price and the
actual selling price of natural gas. Gains and losses resulting from hedging
activities have not had a material impact on the Company's results of
operations. The Company had no outstanding natural gas swap agreements at
December 31, 1994.
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 has been restated to reflect the effects of a three-for-one stock split
distributed on August 5, 1993.
(2) LONG-TERM DEBT
Long-term debt as of December 31, 1994 and 1993 consisted of the following:
1994 1993
---------------------------------------------------------------------------------------------------------------------------------
(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 through September 30, 2002 24,000 30,000
---------------------------------------------------------------------------------------------------------------------------------
90,000 96,000
OTHER
Variable rate (6.62% at December 31, 1994) unsecured revolving credit arrangements with two banks 52,300 31,000
---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt 142,300 127,000
Less: Current portion of long-term debt 6,071 3,000
---------------------------------------------------------------------------------------------------------------------------------
$136,229 $124,000
=================================================================================================================================
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, 1994, the Company had two variable rate facilities which
make available $80.0 million of long-term revolving credit, of which $52.3
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. The revolving credit facilities expire in 1998. The
Company intends to renew or replace the facilities prior to expiration.
At December 31, 1994, 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, 1994.
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, 1994, approximately $121.8 million of retained earnings was
available for payment as dividends.
In 1992, the Company entered into a two-year interest rate swap agreement
with a notional amount of $30.0 million to take advantage of low variable
rates in relation to existing fixed rates on the Company's long-term debt.
This interest rate swap agreement expired in 1994.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1995 through 1999, are $6.1 million, $6.1 million, $28.6 million,
$58.4 million, and $6.1 million. Total interest payments of $10.2 million, $10.3
million, and $11.7 million were made in 1994, 1993, and 1992, respectively.
25
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(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:
1994 1993 1992
----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Federal:
Current $ 7,758 $11,514 $ 6,190
Deferred 5,588 3,827 5,096
Deferred tax adjustment for tax rate increase -- 1,743 --
State:
Current 1,530 2,190 1,213
Deferred 1,054 752 1,004
Investment tax credit amortization (201) (194) (184)
----------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes $15,729 $19,832 $13,319
==================================================================================================================================
The provision for income taxes was an effective rate of 38.5% in 1994,
42.3% in 1993, and 37.4% in 1992. 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:
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Expected provision at federal statutory rate of 35% in 1994 and 1993 and 34% in 1992 $14,299 $16,409 $12,098
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,682 1,914 1,463
Percentage depletion on gas and oil production (96) (117) (106)
Adjustment to deferred taxes for tax rate increase -- 1,743 --
Investment tax credit amortization (201) (194) (184)
Other 45 77 48
---------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes $15,729 $19,832 $13,319
=================================================================================================================================
The components of the Company's net deferred tax liability as of December
31, 1994 and 1993 were as follows:
1994 1993
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $ 89,289 $83,875
Stored gas differences 5,736 5,132
Deferred purchased gas costs 1,557 1,232
Prepaid pension costs 1,628 1,731
Book over tax basis in partnerships 3,535 2,675
Gas imbalances 410 644
Other 685 876
---------------------------------------------------------------------------------------------------------------------------------
102,840 96,165
---------------------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 700 770
Other 370 376
---------------------------------------------------------------------------------------------------------------------------------
1,070 1,146
---------------------------------------------------------------------------------------------------------------------------------
Net deferred tax liability $101,770 $95,019
=================================================================================================================================
26
Prior to the change in accounting for income taxes, the sources of deferred
tax items, and the corresponding tax effects during 1992 were as follows (in
thousands):
------------------------------------------------------------------------------
Intangible and other exploration and development costs $1,581
Investment tax credits amortized (184)
Stored gas differences 972
Excess of tax over book depreciation 1,987
Deferred purchased gas costs 355
Excess of tax over book partnership loss 953
Other 252
------------------------------------------------------------------------------
Deferred provision for income taxes $5,916
==============================================================================
Total income tax payments of $14.6 million, $10.2 million, and $6.4 million
were made in 1994, 1993, and 1992, respectively.
(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
Substantially all employees are covered by the Company's defined benefit
pension plan. Benefits are based on years of benefit service and the
employee's "average compensation," as defined. The Company's funding policy
is to contribute amounts which are actuarially determined to provide the plan
with sufficient assets to meet future benefit payment requirements and which
are tax deductible.
Plan assumptions for 1994 and 1993 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 7.5% in 1994
and 8.5% in 1993 for the net pension cost computation, and a salary
progression rate of 5%. The reconciliation of prepaid pension cost at
December 31, 1994 utilizes a discount rate of 8.5% for future settlements.
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1994 and 1993:
1994 1993
-----------------------------------------------------------------------------------------------
(in thousands)
Actuarial present value of benefit obligations:
Vested benefits $(20,643) $(20,746)
Nonvested benefits (1,635) (1,685)
-----------------------------------------------------------------------------------------------
Accumulated benefit obligation (22,278) (22,431)
Effect of projected future compensation levels (6,368) (7,463)
-----------------------------------------------------------------------------------------------
Projected benefit obligation (28,646) (29,894)
Plan assets at fair value, primarily common stocks and bonds 36,675 36,601
-----------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 8,029 6,707
Unrecognized net gain (3,617) (1,869)
Unrecognized net asset (1,135) (1,318)
Unrecognized prior service cost 454 274
-----------------------------------------------------------------------------------------------
Prepaid pension cost $ 3,731 $ 3,794
===============================================================================================
Net pension cost for 1994, 1993 and 1992 included the following components:
1994 1993 1992
-----------------------------------------------------------------------------------------------
(in thousands)
Service costs (benefits earned during the period) $ 1,217 $ 897 $ 805
Interest cost on projected benefit obligation 2,280 1,999 1,768
Actual return on plan assets (791) (2,819) (4,914)
Net amortization and deferral (2,643) (673) 1,860
-----------------------------------------------------------------------------------------------
Net pension cost (credit) $ 63 $ (596) $ (481)
===============================================================================================
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $201,000,
$628,000, and $241,000 in 1994, 1993, and 1992, respectively. In 1993, this plan
was funded with $1.2 million. At December 31, 1994, the supplemental retirement
plan had a prepaid pension cost of $130,000.
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.
27
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
The Company provides postretirement health care and life insurance benefits
to eligible employees. Employees become eligible for these benefits if they meet
age and service requirements. Generally, the benefits paid are a stated
percentage of medical expenses reduced by deductibles and other coverages.
A significant portion of the postretirement benefit cost relates to the
Company's utility operations and has been deferred as a regulatory asset. Net
postretirement benefit cost for 1994 and 1993 included the following
components:
1994 1993
-------------------------------------------------------------------------------------------------------
(in thousands)
Service cost of benefits earned during the year $ 79 $ 61
Amortization of transition amount 178 103
Amortization of unrecognized gain 17 --
Interest cost on accumulated postretirement benefit obligation (APBO) 164 158
-------------------------------------------------------------------------------------------------------
Net postretirement benefit cost $438 $322
=======================================================================================================
The APBO as of December 31, 1994 and 1993 was comprised of the following:
1994 1993
-------------------------------------------------------------------------------------------------------
(in thousands)
Retirees $ 766 $ 655
Active participants, fully eligible 442 543
Other participants 804 835
-------------------------------------------------------------------------------------------------------
Total APBO $2,012 $2,033
=======================================================================================================
In determining the APBO, assumed weighted average discount rates of 8.5%
and 7.5% were used for 1994 and 1993, respectively. An increase of 8.0% in the
cost of covered health care benefits was assumed for 1995. This rate is assumed
to decrease ratably to 6.0% over 7 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 1994
by $254,000 and the 1994 net postretirement benefit cost by $31,000.
(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:
1994 1993 1992
-------------------------------------------------------------------------------------------------------
(in thousands)
Sales $ 80,123 $ 79,374 $ 60,554
Production (lifting) costs (6,771) (6,341) (4,271)
Depreciation, depletion and amortization (29,743) (25,686) (19,128)
-------------------------------------------------------------------------------------------------------
43,609 47,347 37,155
Income tax expense (16,684) (18,081) (13,787)
-------------------------------------------------------------------------------------------------------
Results of operations $ 26,925 $ 29,266 $ 23,368
=======================================================================================================
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 1994, 1993
and 1992:
1994 1993 1992
-------------------------------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $21,972 $ 5,920 $ 4,768
Exploration costs 12,419 11,695 6,441
Development costs 20,943 19,722 19,563
-------------------------------------------------------------------------------------------------------
Capitalized costs incurred $55,334 $37,337 $30,772
=======================================================================================================
Amortization per Mcf equivalent $.759 $.710 $.723
=======================================================================================================
28
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at
December 31, 1994 and 1993:
1994 1993
---------------------------------------------------------------------------------------------
(in thousands)
Proved properties $405,081 $350,854
Unproved properties 30,489 24,427
---------------------------------------------------------------------------------------------
Total capitalized costs 435,570 375,281
Less: Accumulated depreciation, depletion and amortization 176,764 146,471
---------------------------------------------------------------------------------------------
Net capitalized costs $258,806 $228,810
=============================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1994. Included in property
acquisition costs is $7.3 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.
1994 1993 1992 Prior Total
------------------------------------------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $3,655 $1,441 $286 $7,199 $12,581
Exploration costs 3,230 1,200 128 579 5,137
Capitalized interest 1,178 452 71 1,332 3,033
------------------------------------------------------------------------------------------------------------------
$8,063 $3,093 $485 $9,110 $20,751
==================================================================================================================
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1994, 1993 and 1992:
1994 1993 1992
----------------------------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
----------------------------------------------------------------------------------------------------------------------------
Proved reserves, beginning of year 318,776 479 312,291 359 307,484 505
Revisions of previous estimates (16,551) (258) (4,110) (25) 704 (30)
Extensions, discoveries and other additions 30,932 189 46,069 250 29,627 4
Production (37,706) (200) (35,693) (97) (25,755) (120)
Acquisition of reserves in place 20,647 1,038 222 -- 231 --
Disposition of reserves in place -- (17) (3) (8) -- --
----------------------------------------------------------------------------------------------------------------------------
Proved reserves, end of year 316,098 1,231 318,776 479 312,291 359
============================================================================================================================
Proved, developed reserves:
Beginning of year 260,240 469 246,904 337 226,767 467
End of year 261,690 1,116 260,240 469 246,904 337
============================================================================================================================
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, 1994, 1993 and 1992:
1994 1993 1992
---------------------------------------------------------------------------------------------------------
(in thousands)
Future cash inflows $ 683,438 $ 745,967 $ 681,033
Future production and development costs (96,813) (85,609) (84,483)
Future income tax expense (207,359) (236,170) (207,249)
---------------------------------------------------------------------------------------------------------
Future net cash flows 379,266 424,188 389,301
10% annual discount for estimated timing of cash flows (189,774) (196,913) (179,331)
---------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 189,492 $ 227,275 $ 209,970
=========================================================================================================
29
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
Under the standardized measure, future cash inflows were estimated by
applying year-end prices, adjusted for known contractual changes, to the
estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pretax cash inflows. Future income taxes were
computed by applying the year-end statutory rate, after consideration of
permanent differences and enacted tax legislation, to the excess of pretax
cash inflows over the Company's tax basis in the associated proved gas and
oil properties. Future net cash inflows after income taxes were discounted
using a 10% annual discount rate to arrive at the standardized measure.
Following is an analysis of changes in the standardized measure during
1994, 1993 and 1992:
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Standardized measure, beginning of year $227,275 $209,970 $198,274
Sales and transfers of gas and oil produced, net of production costs (73,352) (73,017) (56,283)
Net changes in prices and production costs (29,344) 22,392 9,446
Extensions, discoveries, and other additions, net of future production and development costs 43,458 74,511 52,917
Revisions of previous quantity estimates (19,225) (5,217) 318
Accretion of discount 34,968 31,885 30,253
Net change in income taxes 24,564 (13,524) (4,623)
Changes in production rates (timing) and other (18,852) (19,725) (20,332)
---------------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $189,492 $227,275 $209,970
=================================================================================================================================
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company held a general partnership interest in NOARK of 47.93% at
December 31, 1994 and 47.33% at December 31, 1993, and is the pipeline's
operator. NOARK is a 258 mile long intrastate gas transmission system which
extends across northern Arkansas and was placed in service in September,
1992. 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. NOARK's transportation capacity is 141
million cubic feet of gas per day (MMcfd).
The Company's investment in NOARK totaled $4.8 million at December 31, 1994
and $5.3 million at December 31, 1993. The Company's investment in NOARK
includes advances of $2.3 million made during 1994 to make the final payment of
construction retainage and to provide certain minimum cash balances to service
NOARK's long-term debt. Subsequent to December 31, 1994, the Company advanced an
additional $1.1 million to NOARK. See Note 12 for further discussion of NOARK's
funding requirements and the Company's investment in NOARK.
NOARK's financial position at December 31, 1994 and 1993 is summarized
below:
1994 1993
-----------------------------------------------------------------------------------------
(in thousands)
Current assets $ 1,078 $ 1,551
Noncurrent assets 100,662 102,322
-----------------------------------------------------------------------------------------
$101,740 $103,873
=========================================================================================
Current liabilities $ 6,009 $ 7,290
Long-term debt 86,250 85,050
Loans from general partners 3,225 --
Partners' capital 6,256 11,533
-----------------------------------------------------------------------------------------
$101,740 $103,873
=========================================================================================
The Company's share of NOARK's 1994, 1993 and 1992 pretax loss included in
other income (expense) on the statements of income was $2.8 million, $1.8
million, and $.6 million, respectively.
NOARK's results of operations for 1994, 1993 and 1992 are summarized below:
1994 1993 1992
---------------------------------------------------------------------------
(in thousands)
Operating revenues $10,111 $ 8,301 $ 1,466
Pretax loss $(5,917) $(3,778) $(1,348)
===========================================================================
(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.
30
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, 1994 and 1993 were as follows:
1994 1993
-------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------------------------------------------------------------------------------------
(in thousands)
Cash $1,152 $1,152 $834 $834
Customer deposits $4,232 $4,232 $3,927 $3,927
Long-term debt $142,300 $144,245 $127,000 $134,661
========================================================================================
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, 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, 1994, 1993 and 1992:
1994 1993 1992
------------------------------------------------------------------------------
(in thousands)
REVENUES
Exploration and production $ 80,123 $ 79,374 $ 60,554
Gas distribution 127,060 131,892 117,495
Other 308 262 256
Eliminations (37,305) (36,684) (34,475)
------------------------------------------------------------------------------
$170,186 $174,844 $143,830
------------------------------------------------------------------------------
INTERSEGMENT REVENUES
Exploration and production $ 36,465 $ 36,091 $ 33,994
Gas distribution 584 337 225
Other 256 256 256
------------------------------------------------------------------------------
$ 37,305 $ 36,684 $ 34,475
------------------------------------------------------------------------------
OPERATING INCOME
Exploration and production $ 38,883 $ 42,608 $ 33,071
Gas distribution 13,391 15,261 13,094
Corporate expenses (192) (305) (177)
------------------------------------------------------------------------------
$ 52,082 $ 57,564 $ 45,988
------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Exploration and production $286,887 $236,968 $224,302
Gas distribution 171,470 186,704 179,998
Other 26,225 21,782 22,875
------------------------------------------------------------------------------
$484,582 $445,454 $427,175
------------------------------------------------------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION
Exploration and production $ 29,743 $ 25,686 $ 19,128
Gas distribution 4,976 4,564 4,213
Other 827 694 539
------------------------------------------------------------------------------
$ 35,546 $ 30,944 $ 23,880
------------------------------------------------------------------------------
CAPITAL ADDITIONS
Exploration and production $ 55,449 $ 37,411 $ 30,823
Gas distribution 17,577 19,892 12,188
Other 3,828 1,916 1,898
------------------------------------------------------------------------------
$ 76,854 $ 59,219 $ 44,909
==============================================================================
31
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(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 then 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, 1994, there were options for 886,108 shares outstanding
under the 1993 Plan at option prices of $14 5/8 and $17 1/8, representing the
fair market values at the dates of grant. Of the total, 783,704 performance
accelerated options were granted in 1994 at an option price of $14 5/8. These
options vest over a four-year period beginning six years from the date of grant
or earlier if certain corporate performance criteria are achieved. The remaining
options, granted in 1993, vest to employees over a three-year period from the
date of grant. Options for 14,387 shares are currently exercisable. All options
expire ten years from the date of grant. Additionally, 5,573 shares in 1994 and
17,447 shares in 1993 of restricted stock have been 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, 1994, at prices ranging from $5.58 to $12.81. All
options are currently exercisable. 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, 1994, there were options for 96,000 shares outstanding at option
prices of $14 3/4 and $17 1/2. Options for 12,000 shares are currently
exercisable.
(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 general partner of NOARK are required to
severally guarantee the availability of certain minimum cash balances to service
the 9.7375% Senior Secured Notes used to finance a portion of NOARK's total
construction cost. At December 31, 1994, the Senior Secured Notes had a
remaining balance of $59.9 million. The notes have a remaining term of 15 years
and the Company's share of the several guarantee is 60%. At December 31, 1994,
NOARK also had an unsecured long-term revolving credit agreement in the amount
of $30.0 million with a group of banks, of which $29.6 million was outstanding.
Amounts borrowed under the long-term revolving credit facility are severally
guaranteed by the Company and an affiliate of the other general partner. The
Company's share of the several guarantee of the 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.
32
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 and NOARK believe the suit is without merit and
have filed counterclaims 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 of the Company and the NOARK partners are currently
investigating several options available to NOARK. However, management
believes that no write-down of its investment in NOARK is appropriate at this
time and that it will realize its investment in NOARK over the life of the
system. Therefore, no provision for any loss has been made in the
accompanying financial statements.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial condition or reported results of operations
of the Company.
The Company is subject to other litigation that has arisen in the ordinary
course of business. In the opinion of management, the results of such
litigation will not have a material effect on the results of operations or
the financial position of the Company.
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1994 and 1993:
Quarter Ended March 31 June 30 September 30 December 31
---------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
1994
----
Operating revenues $65,430 $34,605 $27,808 $42,343
Operating income $23,525 $10,471 $6,327 $11,759
Net income $12,994 $4,834 $2,128 $5,168
Earnings per share $.51 $.18 $.09 $.20
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
===============================================================================================================
33
Financial and Operating Statistics
1994 1993 1992 1991 1990 1989
----------------------------------------------------------------------------------------------------------------------------------
FINANCIAL REVIEW (in thousands)
Operating revenues:
Exploration and production $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489 $ 40,499
Gas distribution 127,060 131,892 117,495 121,302 108,911 117,514
Other 308 262 256 256 256 256
Intersegment revenues (37,305) (36,684) (34,475) (34,511) (33,586) (33,670)
----------------------------------------------------------------------------------------------------------------------------------
170,186 174,844 143,830 136,439 117,070 124,599
----------------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 36,395 42,962 35,848 40,423 37,678 46,850
Operating and general 42,506 40,093 34,970 32,609 28,134 26,132
Depreciation, depletion and amortization 35,546 30,944 23,880 18,248 14,756 16,055
Taxes, other than income taxes 3,657 3,281 3,144 3,017 2,885 2,844
----------------------------------------------------------------------------------------------------------------------------------
118,104 117,280 97,842 94,297 83,453 91,881
----------------------------------------------------------------------------------------------------------------------------------
Operating income 52,082 57,564 45,988 42,142 33,617 32,718
Interest expense, net (8,867) (9,025) (9,983) (9,813) (10,530) (10,662)
Other income (expense) (2,362) (1,657) (421) (107) (17) 180
----------------------------------------------------------------------------------------------------------------------------------
Income before provision for income taxes 40,853 46,882 35,584 32,222 23,070 22,236
----------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes:
Current 9,288 13,704 7,403 7,158 4,994 6,671
Deferred 6,441 6,128 5,916 4,999 3,568 1,586
----------------------------------------------------------------------------------------------------------------------------------
15,729 19,832 13,319 12,157 8,562 8,257
----------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative
effect of accounting change 25,124 27,050 22,265 20,065 14,508 13,979
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 $ 25,124 $ 37,176 $ 22,265 $ 20,065 $ 14,075 $ 13,979
==================================================================================================================================
Cash flow from operations (in thousands) $66,613 $70,191 $49,730 $34,986 $36,495 $29,306
Return on equity 12.35% 14.66%/(1)/ 14.53% 14.75% 11.66% 13.51%
Gross profit margin 30.60% 32.92% 31.97% 30.89% 28.72% 26.26%
Net profit margin 14.76% 15.47%/(1)/ 15.48% 14.71% 12.02% 11.22%
==================================================================================================================================
COMMON STOCK STATISTICS/(2)/
Earnings per share before extraordinary item and
cumulative effect of accounting change $.98 $1.05 $.87 $.78 $.57 $.56
Earnings per share $.98 $1.44 $.87 $.78 $.56 $.56
Cash dividends declared and paid per share $.24 $.22 $.20 $.19 $.19 $.19
Book value per share $7.92 $7.18 $5.97 $5.30 $4.70 $4.15
Market price at year end $14.88 $18.00 $12.96 $10.50 $10.42 $10.75
Number of shareholders of record at year end 2,875 3,005 2,930 2,989 3,136 3,298
Average shares outstanding 25,684,110 25,684,110 25,683,963 25,678,011 25,270,674 24,940,488
==================================================================================================================================
CAPITALIZATION (in thousands)
Long-term debt, including current portion $142,300 $127,000 $143,335 $134,104 $125,535 $128,449
Common shareholders' equity 203,456 184,530 153,233 136,041 120,709 103,455
----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $345,756 $311,530 $296,568 $270,145 $246,244 $231,904
----------------------------------------------------------------------------------------------------------------------------------
Total assets $484,582 $445,454 $427,175 $392,208 $366,313 $347,212
----------------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 40.10% 40.19% 48.31% 49.08% 50.39% 54.82%
Equity 59.90% 59.81% 51.69% 50.92% 49.61% 45.18%
==================================================================================================================================
CAPITAL EXPENDITURES (in millions)
Exploration and production $55.4 $37.4 $30.8 $30.3 $23.4 $26.6
Gas distribution 17.6 19.9 12.2 7.9 9.3 8.9
Other 3.9 1.9 1.9 .7 .7 3.5
----------------------------------------------------------------------------------------------------------------------------------
$76.9 $59.2 $44.9 $38.9 $33.4 $39.0
==================================================================================================================================
/(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.
34
1994 1993 1992 1991 1990 1989
-----------------------------------------------------------------------------------------------------------------------------------
NATURAL GAS AND OIL WELLS COMPLETED
Producers:
Gross 78.0 57.0 69.0 25.0 25.0 38.0
Net 50.2 40.7 54.6 11.8 9.1 16.4
Dry holes:
Gross 30.0 28.0 29.0 12.0 10.0 22.0
Net 16.5 14.5 19.5 4.1 2.1 7.3
-----------------------------------------------------------------------------------------------------------------------------------
Total:
Gross 108.0 85.0 98.0 37.0 35.0 60.0
Net 66.7 55.2 74.1 15.9 11.2 23.7
At the end of 1994, the Company was a participant in 8.0 (2.1 net) wells in process.
===================================================================================================================================
NATURAL GAS AND OIL PRODUCED
Natural gas:
Production, Bcf 37.7 35.7 25.8 20.3 16.7 15.6
Average price per Mcf $2.04 $2.18 $2.26 $2.25 $2.33 $2.43
Oil:
Production, MBbls 200 97 120 176 112 149
Average price per barrel $15.89 $17.20 $19.75 $20.67 $22.89 $17.89
Average production (lifting) cost per Mcf equivalent $.17 $.18 $.16 $.19 $.16 $.14
Proved reserves at year end:
Natural gas, Bcf 316.1 318.8 312.3 307.5 304.5 252.9
Oil, MBbls 1,231 479 359 505 773 745
===================================================================================================================================
UTILITY OPERATING DATA
Sales volumes, Bcf:
Residential 11.6 12.9 10.8 10.9 10.1 11.6
Commercial 7.2 7.8 6.6 6.7 6.3 7.1
Industrial 7.5 6.1 6.1 9.5 10.2 9.8
Transportation volumes, Bcf
End-use 4.8 5.6 5.2 1.3 .1 .5
Off-system 10.7 11.7 2.5 .2 .3 .1
-----------------------------------------------------------------------------------------------------------------------------------
41.8 44.1 31.2 28.6 27.0 29.1
-----------------------------------------------------------------------------------------------------------------------------------
Average sales customers:
Residential 140,684 137,087 133,103 129,379 127,142 125,581
Commercial 18,872 18,511 18,141 17,880 17,680 17,437
Industrial 341 346 348 370 366 372
-----------------------------------------------------------------------------------------------------------------------------------
159,897 155,944 151,592 147,629 145,188 143,390
-----------------------------------------------------------------------------------------------------------------------------------
Sales and transportation revenues (in thousands):
Residential $ 62,565 $ 67,502 $ 59,747 $ 58,372 $ 48,407 $ 54,181
Commercial 32,252 35,311 31,425 30,718 27,535 30,522
Industrial 25,191 21,757 20,502 29,187 30,463 29,982
Transportation 4,721 5,177 3,597 857 179 368
-----------------------------------------------------------------------------------------------------------------------------------
$124,729 $129,747 $115,271 $119,134 $106,584 $115,053
-----------------------------------------------------------------------------------------------------------------------------------
Miles of pipe:
Gathering 405 398 383 375 371 364
Transmission 1,346 1,335 1,328 1,326 1,326 1,309
Distribution 4,246 4,160 4,090 4,002 3,931 3,859
-----------------------------------------------------------------------------------------------------------------------------------
5,997 5,893 5,801 5,703 5,628 5,532
-----------------------------------------------------------------------------------------------------------------------------------
Degree days 4,161 4,929 4,104 4,095 3,972 4,961
Percent of normal 95% 113% 92% 93% 90% 112%
===================================================================================================================================
35
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 31, 1995, 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 LLP
6450 South Lewis
Suite 300
Tulsa, Oklahoma 74136-1068
FINANCIAL INFORMATION
Financial analysts and investors who need additional information should
contact Stanley D. Green, Executive Vice President--Finance and Corporate
Development, at corporate headquarters, 501-521-1141.
TRANSFER AGENT AND REGISTRAR
First Chicago Trust Company of New York
525 Washington Blvd.
Jersey City, NJ 07310
Phone 1-800-446-2617
DIVIDEND REINVESTMENT PLAN
Southwestern Energy Company offers holders of record of its common stock the
opportunity to purchase additional shares through its Dividend Reinvestment
Plan. Dividends and/or optional cash investments of up to $1,000 monthly may
be used to purchase additional shares of the Company's stock for nominal
service and broker's fees. Information about the Plan is available from the
administrator:
First Chicago Trust Company of New York
P.O. Box 2598
Jersey City, NJ 07303-2598
Phone 1-800-446-2617
ANNUAL REPORT
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 1994 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
------------------------------------------------ -------------------
1994 1993 1994 1993
---------------------------------------------------------------------------------------------
HIGH LOW High Low
March 31 $18.88 $15.13 $15.25 $12.13 $.06 $.05
June 30 $17.75 $15.50 $16.83 $14.13 $.06 $.05
September 30 $17.88 $15.50 $21.75 $16.04 $.06 $.06
December 31 $17.75 $14.00 $21.88 $15.13 $.06 $.06
============================================================================================
Market prices represent transactions on the New York Stock Exchange.
36
Southwestern Energy Company and Subsidiaries
APPENDIX TO 1994 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 47.93% 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
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Arkansas 184,008 95,486 289,387 138,269 736 380.6
Louisiana 15,874 8,938 10,748 3,214 10 5.2
Oklahoma 23,746 15,946 69,835 36,214 465 241.6
Texas 25,121 13,292 51,024 11,247 29 6.7
Other areas 8,361 7,992 5,490 1,313 14 3.8
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257,110 141,654 426,484 190,257 1,254 637.9
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GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
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Gathering 405 -- 405
Transmission 744 602 1,346
Distribution 2,691 1,555 4,246
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3,840 2,157 5,997
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