Management's Discussion and Analysis of Financial Condition and
Results of Operations
RESULTS OF OPERATIONS
Net income in 1995 was $11.2 million, or $.45 per share, down from $25.1
million, or $.98 per share, in 1994. Net income in 1993 was $27.1 million, or
$1.05 per share. Net income in 1995 includes an extraordinary loss (net of tax
benefit) of $.3 million, or $.01 per share, incurred in connection with the
early call of the Company's 10.63% Senior Notes due September 30, 2001. The
comparative 1993 number 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 1994.
The decline in 1995 earnings was caused primarily by the generally low
level of gas prices and a decline in natural gas production. The decrease in
1994 earnings, as compared to 1993, resulted as lower gas prices and much warmer
weather offset the favorable effect of a year-to-year increase in natural gas
production. Lower gas prices in 1995 and 1994 reflected both the general decline
in spot market prices and the effect of a settlement approved by the Arkansas
Public Service Commission (APSC) to resolve a dispute concerning the Company's
pricing of intersegment sales (the Gas Cost Settlement). The Gas Cost
Settlement, which was effective July 1, 1994, increased the volumes which could
be sold by the Company's exploration and production segment to its gas
distribution segment, but made the sales price equal to a spot market index plus
a premium. The index-based pricing has to date resulted in a lower intersegment
sales price. The Gas Cost Settlement and the increases in recent years in sales
of gas production to unaffiliated purchasers have both caused earnings to become
more sensitive to changes in the market price for natural gas. Revenues and
operating income for the Company's major business segments are shown in the
following table.
1995 1994 1993
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(in thousands)
REVENUES
Exploration and production $ 63,523 $ 80,123 $ 79,374
Gas distribution 119,855 127,060 131,892
Other 336 308 262
Eliminations (30,603) (37,305) (36,684)
- --------------------------------------------------------------------------------
$153,111 $170,186 $174,844
================================================================================
OPERATING INCOME
Exploration and production $ 20,523 $ 38,888 $ 42,608
Gas distribution 11,133 13,386 15,261
Corporate expenses (468) (192) (305)
- --------------------------------------------------------------------------------
$ 31,188 $ 52,082 $ 57,564
================================================================================
EXPLORATION AND PRODUCTION REVENUES
The Company's exploration and production revenues decreased 21% in 1995 and
increased 1% in 1994. The decrease in 1995 was due to lower average gas prices
and a decline in the Company's offshore gas production. The slight increase in
1994 was due to increases in natural gas and oil production, offset by lower
average prices.
Gas production decreased 8% to 34.5 billion cubic feet (Bcf) in 1995 from
37.7 Bcf in 1994. Gas production in 1994 increased by 6% from 35.7 Bcf in 1993.
Sales from the Company's offshore properties were 2.7 Bcf in 1995, compared to
5.6 Bcf in 1994 and 6.3 Bcf in 1993. Sales in 1994 were helped by the start of
production from a new offshore platform which was completed late in 1993. Sales
from the Company's onshore production were 31.8 Bcf in 1995, down slightly from
32.1 Bcf in 1994. Sales from onshore production were 29.4 Bcf in 1993.
Production from producing properties acquired in 1994 and 1995 largely offset
declines in production from the Company's other onshore properties during 1995,
including an unexpected decline from the Earl Chauvin No. 1 well, a 1993
discovery in southeast Louisiana.
1995 1994 1993
- --------------------------------------------------------------------------------
GAS PRODUCTION
Affiliated sales (Bcf) 13.9 13.9 12.8
Unaffiliated sales (Bcf) 20.6 23.8 22.9
- --------------------------------------------------------------------------------
34.5 37.7 35.7
- --------------------------------------------------------------------------------
Average price per Mcf $1.72 $2.04 $2.18
================================================================================
OIL PRODUCTION
Unaffiliated sales (MBbls) 229 200 97
- --------------------------------------------------------------------------------
Average price per Bbl $17.15 $15.89 $17.20
================================================================================
Gas sales to unaffiliated purchasers were 20.6 Bcf in 1995, down from 23.8
Bcf in 1994. Gas sales to unaffiliated purchasers were 22.9 Bcf in 1993. The
decrease in 1995 sales to unaffiliated purchasers was primarily the result of
decreased production from the Company's Gulf Coast properties, as discussed
above. Sales to unaffiliated purchasers are made under contracts which reflect
current short-term prices and which are subject to seasonal price swings. The
Company uses natural 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 gas supply in 1995
and 1994, as compared to 1993. Intersegment sales to Arkansas Western Gas
Company (AWG), the utility subsidiary which operates the Company's northwest
Arkansas utility system, were 8.5 Bcf in 1995, 8.8 Bcf in 1994, and 7.1 Bcf in
1993. The Company's gas production provided approximately 65% of AWG's
requirements in 1995, 64% in 1994, and approximately 57% in 1993. Additionally,
in 1995, 1994, and 1993, the Company sold .6 Bcf, .5 Bcf, and .7 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 pursuant to a long-term contract
entered into in 1978 and which was amended and restated in 1994 as a result of
the Gas Cost Settlement, discussed more fully below under "Regulatory Matters."
Other sales to AWG are made under long-term contracts with flexible pricing
provisions.
The Company's intersegment sales to Associated Natural Gas Company
(Associated), a division of AWG which operates the
10
Company's natural gas distribution systems in northeast Arkansas and parts of
Missouri, were 5.4 Bcf in 1995, 5.1 Bcf in 1994, and 5.7 Bcf in 1993. Deliveries
to Associated increased in 1995 due to colder weather in the heating season and
decreased in 1994 due to warmer weather. Effective October, 1990, one of the
Company's exploration and production subsidiaries entered into a ten-year
contract with Associated to supply its base load system requirements at a price
to be redetermined annually. The sales price under this contract was $1.90 per
thousand cubic feet (Mcf) from inception of the contract through the first nine
months of 1993, $2.385 per Mcf for the contract period ending September 30,
1994, $2.20 per Mcf for the contract period ending September 30, 1995, and is
currently $1.785 per Mcf.
The overall average price received at the wellhead for the Company's gas
production was $1.72 per Mcf in 1995, $2.04 per Mcf in 1994, and $2.18 per Mcf
in 1993. The decline in the average price received since 1993 reflects declines
in average annual spot market prices, an increase in the proportionate share of
the Company's production sold at spot market prices and under long-term
contracts with market-sensitive pricing, and the effect of the Gas Cost
Settlement. Natural gas prices were higher at December 31, 1995, as compared to
the prior year-end, primarily due to colder than normal weather experienced
across the country. The colder weather continued into early 1996 and has had a
positive impact on average prices received to-date in 1996, as compared to 1995.
As described above, a significant portion of the Company's gas pro-duction 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 spot market prices 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 spot market prices. 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 which it receives under the long-term contracts covering
its intersegment sales. Future changes in revenues from sales of the Company's
gas production will be dependent upon changes in the market price for gas,
access to new markets, maintenance of existing markets, and additions of new gas
reserves.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. While the Company experienced a
decline in gas production in 1995, it does expect over the long term to return
to a trend of increasing gas production. However, the Company is unable to
predict changes in the market demand and price for natural gas, including
changes which may be induced by the effects of weather on demand of both
affiliated and unaffiliated customers for the Company's production.
Additionally, the Company holds a large 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.
1995 1994 1993
- --------------------------------------------------------------------------------
GAS DISTRIBUTION SYSTEMS
Throughput (Bcf)
Sales volumes 27.4 26.3 26.8
Transportation volumes
End-use 5.2 4.8 5.6
Off-system 9.8 10.7 11.7
- --------------------------------------------------------------------------------
42.4 41.8 44.1
- --------------------------------------------------------------------------------
Average number of sales customers 164,672 159,897 155,944
- --------------------------------------------------------------------------------
Heating weather--degree days 4,376 4,161 4,929
- --------------------------------------------------------------------------------
Average sales rate per Mcf $4.12 $4.57 $4.65
================================================================================
Gas distribution revenues decreased by 6% in 1995 and by 4% in 1994. The
decrease in 1995 resulted from lower purchased gas costs caused in part by the
Gas Cost Settlement, which more than offset the effects of strong customer
growth and weather which was 5% colder than the prior year. The decrease in 1994
was due to lower purchased gas costs and weather which was 16% warmer than in
1993, partially offset by customer growth.
In 1995, AWG sold 17.1 Bcf to its customers at an average rate of $3.93 per
Mcf, compared to 16.3 Bcf at $4.25 per Mcf in 1994 and 17.1 Bcf at $4.40 per Mcf
in 1993. Additionally, AWG transported 4.3 Bcf in 1995, 4.0 Bcf in 1994, and 3.9
Bcf in 1993 for its end-use customers. Associated sold 10.3 Bcf to its customers
in 1995 at an average rate of $4.45 per Mcf, compared to 10.0 Bcf in 1994 at
$5.10 per Mcf and 9.7 Bcf at $5.08 per Mcf in 1993. Associated transported .9
Bcf for its end-use customers in 1995, compared to .8 Bcf in 1994 and 1.7 Bcf in
1993. The increase in volumes sold and transported in 1995 for both AWG and
Associated resulted from colder weather and from increases in the average number
of customers. The decrease in the average sales rate since 1993 for AWG and the
decrease in 1995 for Associated reflect the decline in the average cost of gas
purchased for delivery to the Company's customers.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, increased to 13.0 Bcf in 1995, from 12.3 Bcf in 1994 and
11.7 Bcf in 1993. 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 9.8 Bcf of gas through its gatheringsystem in 1995 for
off-system deliveries, all to the NOARK Pipeline System (NOARK), compared to
10.7 Bcf in 1994 and 11.7 Bcf in 1993. The average transportation rate was
approximately $.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
11
Management's Discussion and Analysis of Financial Conditon and
Results of Operations continued
has experienced customer growth of approximately 1% annually. Based on current
economic conditions in the Company's service territories, the Company expects
this trend in customer growth to continue. AWG filed an application with the
APSC on January 30, 1996, for a rate increase of $7.2 million annually. The APSC
has ten months in which to reach a decision on the amount of the rate increase
to be approved. As a result, any increase granted will likely not become
effective until late 1996. The Company anticipates filing a rate increase
request for Associated's operations in late 1996. Rate increase requests which
may be filed in the future will depend on customer growth, increases in
operating expenses, and additional investments in property, plant and equipment.
REGULATORY MATTERS
During 1994, the Company entered into the Gas Cost Settlement with the
Staff of the APSC and the Office of the Attorney General of the State of
Arkansas concerning certain issues that had been outstanding before the APSC for
the previous four years. These gas cost issues were first raised by the APSC in
December, 1990, in connection with its approval of an AWG rate increase. The
issues involved the price of gas sold under a long-term contract between AWG and
one of the Company's gas producing subsidiaries. The terms of the Gas Cost
Settlement became effective as of July 1, 1994, and were approved by the APSC on
January 5, 1995. Under the Gas Cost Settlement, the price paid by AWG is tied to
a monthly spot market index plus a premium. Given current market conditions, the
new pricing provision results in a reduced sales price. That effect is offset in
part by provisions of the Gas Cost Settlement which allow additional volumes to
be sold under the amended 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 pre-mium of $.95 per Mcf, while incremental sales volumes
receive a premium of $.50 per Mcf. In 1995, approximately 7.7 Bcf (net to the
Company's interest) was sold under the contract, compared to approximately 8.1
Bcf and 6.0 Bcf in 1994 and 1993, respectively. Other significant terms of the
Gas Cost Settlement preclude the parties thereto from asking for refunds,
transfer certain of AWG's natural gas storage facilities to another subsidiary
of the Company, and precluded AWG from filing an application for a rate increase
for its northwest Arkansas system before January, 1996.
Associated received an order on July 14, 1995, from the Missouri Public
Service Commission (MPSC) disallowing the recovery of approximately $2.0 million
of gas costs, the result of gas cost audits covering the five-year period ending
August 31, 1993. Of the total disallowed, $1.5 million represented a portion of
the difference between the price paid by Associated under its long-term firm
contract with one of the Company's gas producing subsidiaries (described above
under "Exploration and Production Revenues") and a spot market index price for
gas delivered into an interstate pipeline operating in the Arkoma Basin. The
balance of $.5 million disallowed represented take-or-pay charges passed through
to Associated by its interstate suppliers and allocable to transportation
customers of Associated. These take-or-pay charges resulted from pipeline
deregulation pursuant to Order No. 636 of the Federal Energy Regulatory
Commission, issued in April, 1992, which is a comprehensive set of regulations
designed to encourage compe-tition 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 APSC had previously reviewed the costs charged
to Arkansas ratepayers under this contract and found them to be proper and
allowable for recovery. Associated has appealed the MPSC's decision to the
Circuit Court of Cole County, Missouri, and that court has stayed the MPSC's
order and has directed Associated to pay the money to be refunded under the
MPSC's order into the registry of the court while the appeal is pending. The
MPSC Staff has also recommended the disallowance of an additional $.7 million of
gas costs as a result of an audit for the year ended August, 1994. The MPSC has
not yet issued an order in connection with that recommendation. The Company does
not expect the ultimate outcome of these matters to have a material adverse
impact on the results of operations or the financial position of the Company.
AWG also purchases gas from unaffiliated producers under take-or-pay
contracts. Currently, the Company believes that it does not have a significant
exposure to liabilities resulting from these contracts, although such exposure
has increased in recent years as a result of a decline in its gas purchase
requirements which has occurred as some of its large business customers
converted to a transportation service offered by AWG and began to obtain their
own gas supplies directly from other sources. The Company expects to be able to
continue to satisfactorily manage its exposure to take-or-pay liabilities.
OPERATING COSTS AND EXPENSES
The Company's operating costs and expenses increased by 3% in 1995 and by
1% in 1994. The increase in 1995 was due primarily to increased purchased gas
costs related to increased utility deliveries, increased general and
administrative expenses, and increased production costs. General and
administrative expenses increased due to inflationary increases in payroll and
other costs and from personnel additions in the Company's exploration and
production segment. Increased production costs in the exploration and production
segment are related to workovers of producing wells and higher operating costs
associated with the Company's expansion into areas outside of Arkansas. 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. 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
12
purchased, and the timing of recoveries of deferred purchased gas costs.
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 for the exploration and production segment in 1995 decreased
slightly from 1994 as an increase in the amortization rate per unit was offset
by a decline in total units produced. DD&A increased 15% in 1994 due both to an
increase in units produced and an increase in the amortization rate per unit.
The margin between the Company's full cost ceiling and the financial statement
carrying value of the Company's gas and oil properties was slightly higher at
December 31, 1995, as compared to December 31, 1994, due primarily to a higher
level of market prices for gas at year-end 1995. The margin was eroded
substantially during 1994 as a result of very low average gas prices in effect
at December 31, 1994. Market prices, production rates, levels of reserves, and
the evaluation of costs excluded from amortization all influence the calculation
of the full cost ceiling. A 15% to 20% decline in gas prices from year-end 1995
levels or other factors, without other mitigating circumstances, could cause a
future write-down of capitalized costs 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 up 26% in 1995, as compared to 1994, due to both an
increase in long-term debt and higher average interest rates. The increase in
long-term debt is discussed below in "Liquidity and Capital Resources." Interest
capitalized increased by 54% in 1995 due primarily to higher capital
expenditures in the exploration and production segment where interest is
capitalized on costs excluded from amortization. Interest costs were slightly
lower in 1994, as compared to 1993, due to lower average borrowings on the
Company's revolving credit facilities through most of the year, partially offset
by higher average interest rates.
The change in other income in 1995, as compared to 1994, relates to a
decrease in the Company's share of operating losses incurred by NOARK, partially
offset by accruals for potential liabilities relating to certain regulatory gas
cost issues and other legal matters. The change in other income during 1994, as
compared to 1993, relates primarily to the Company's share of operating losses
incurred by NOARK. The Company, through a subsidiary, holds a 47.93% general
partnership interest in NOARK and is the pipeline's operator (See Note 7 of the
financial statements for additional discussion). NOARK became operational in
late 1992 and extends across northern Arkansas, crossing three major interstate
pipelines. NOARK has been operating below capacity and generating losses since
it was placed in service. The Company's share of the pretax loss from operations
for NOARK included in other income was $.7 million in 1995, $2.8 million in
1994, and $1.8 million in 1993. The 1995 pretax loss included $2.9 million of
income for the Company's share of a $6.0 million settlement of contract issues
with one of NOARK's transporters, as discussed below. Deliveries are currently
being made by NOARK to portions of AWG's distribution system, to Associated, and
to the interstate pipelines with which NOARK interconnects. In 1995, NOARK had
an average daily throughput of 86 million cubic feet of gas per day (MMcfd),
compared to 82 MMcfd in 1994 and 79 MMcfd in 1993. NOARK has a total
transportation capacity of approximately 141 MMcfd. AWG has contracted for 41
MMcfd of firm capacity on NOARK under a ten-year transportation contract, with
seven years remaining on its original term. The contract is renewable
year-to-year until terminated by 180 days' notice. NOARK also had a five-year
transportation contract with Vesta Energy Company (Vesta) covering the
marketer's commitment for 50 MMcfd of firm transportation. The Company's
exploration and production segment was supplying 25 MMcfd of the volumes
transported by Vesta under that agreement. In late 1993, Vesta filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its contract with NOARK. In late
1995, the suit was settled prior to going to trial. In exchange for a $6.0
million payment to NOARK, Vesta was released from its obligations under its firm
transportation agreement and its contract with the Company's affiliates.
The APSC has established a maximum transportation rate of approximately
$.285 per dekatherm for NOARK based on its original construction cost estimate
of approximately $73 million. Due to construction conditions and the addition of
a compressor station, the ultimate cost of the pipeline exceeded the original
estimate by approximately $30 million. NOARK competes primarily with two
interstate pipelines in its gathering area. One of those elected to become an
open access transporter subsequent to NOARK's start of construction. The
increased availability of 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
13
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
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 38.6% in 1995, 38.5% in 1994,
and 42.3% in 1993. The rate was higher 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 1995, 1994, and
1993, net cash provided from operating activities totaled $55.9 million, $66.6
million, and $70.2 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 59% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1995, 92% in 1994, and in excess of 100% in 1993.
Dividends paid to common shareholders in 1995 were $6.0 million, compared
to $6.2 million in 1994 and $5.7 million in 1993. 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.
In February, 1995, the Board of Directors authorized the repurchase of up
to $30.0 million of the Company's common shares. The Company repurchased
1,000,000 shares during 1995 at an average cost of $14.26, using 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 Company does not at present have definite plans to
repurchase additional shares, but may purchase additional shares from time to
time, depending on market conditions.
Changes in the Company's liquidity in future years are expected to be
related primarily to changes in cash flow generated from its operations.
CAPITAL EXPENDITURES
Capital expenditures totaled $101.6 million in 1995, $76.9 million in 1994,
and $59.2 million in 1993. In 1995 and 1994, expenditures for the exploration
and production segment included $6.0 million and $13.9 million, respectively,
for acquisitions of reserves in place.
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
CAPITAL EXPENDITURES
Exploration and production $ 82,237 $55,449 $37,411
Gas distribution 18,523 17,577 19,892
Other 866 3,828 1,916
- --------------------------------------------------------------------------------
$101,626 $76,854 $59,219
================================================================================
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending will be adequate to allow the Company to maintain its
present markets, explore and develop existing gas and oil properties as well as
generate new drilling prospects, and finance improvements necessary due to
normal customer growth in its gas distribution segment.
Capital spending planned for 1996 totals $86.4 million, a decrease of 15%
from 1995, consisting of $71.0 million for gas and oil exploration, $13.5
million for gas distribution system expenditures, and $1.9 million for general
purposes. The gas and oil expenditures consist of $24.5 million for development
drilling, including $14.5 million for the Company's Arkansas program, $20.0
million for producing property acquisitions, and a total of $12.4 million for
exploratory drilling and seismic data acquisition.
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 $22.9 million at the end of 1995 and $52.3
million at the end of 1994.
In November, 1995, the Company filed a shelf registration statement with
the Securities and Exchange Commission for the issuance of up to $250.0 million
of senior unsecured debt securities. Effective December 1, 1995, the Company
issued under the shelf registration statement $125.0 million of 6.70% Senior
Notes due 2005. Proceeds from the issuance of these notes were used primarily to
repay certain borrowings under the Company's revolving credit facilities. The
facilities had been drawn on to prepay the Company's 10.63% Senior Notes, to
repurchase 1,000,000 shares of the Company's common stock, as described above,
and to fund the Company's capital spending program. Additional debt securities
may be issued in the future under the shelf registration statement as
circumstances dictate. The Company's public notes were rated BBB+ by Standard
and Poor's and Baa2 by Moody's Investor Service.
The Company and an affiliate of the other general partner of NOARK are
required to severally guarantee the availability of certain minimum cash
balances to service NOARK's 9.7375% Senior Secured Notes. These notes are held
by a major insurance company which also has a 20% limited partnership interest
in NOARK. The notes had a balance of $56.7 million at December 31, 1995, with
final maturity in 2009. NOARK also has an unsecured long-term revolving credit
agreement with a group of banks which provides the partnership access to $30.0
million of additional funds. Amounts outstanding under this credit arrangement
were $23.2 million at December 31, 1995, and $29.6 million at December 31, 1994.
Amounts borrowed under the long-term revolving credit agreement are severally
guaranteed by the Company and an affiliate of the other general partner. The
Company's share of the several guarantee of the notes and the line of credit is
60%. In 1995, the Company advanced $5.0 million to NOARK to fund its share of
debt service payments. The Company expects to advance $1.0 to $1.5 million to
NOARK during 1996 in connection with its
14
guarantees. The anticipated contributions in 1996 are less than the 1995 amount
due to the receipt by NOARK of the $6.0 million settlement payment from Vesta in
December, 1995, as discussed above. The cash received was used by NOARK to pay
down its revolving credit facility. The credit facility will be used in 1996 to
help fund NOARK's long-term debt service payments before additional partner
advances are called for.
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 1995, the
capital structure consisted of 51.6% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
48.4% equity, with a ratio of earnings to fixed charges of 1.9.
The percentage of debt in the Company's capital structure may in the near
term increase from the current level as the Company funds expenditures which
will not generate cash flow until future periods, such as the acquisition of
seismic data. Over the longer term, the Company expects to lower the debt
portion of its capital structure through its policy of adjusting its routine
capital spending. The Company will 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.
WORKING CAPITAL
The Company maintains access to funds which may be needed to meet seasonal
requirements through the revolving lines of credit explained above. The Company
had net working capital of $18.5 million at the end of 1995, and $8.9 million at
the end of 1994. Current assets increased by 29% to $63.9 million in 1995, while
current liabilities increased 12% to $45.4 million. The increase in current
assets at December 31, 1995, was due primarily to increases in income taxes
receivable, inventories, and accounts receivable. The increase in accounts
receivable was due to higher weather-related sales at year-end 1995. The
increase in income taxes receivable relates to the carryback of a 1995 tax net
operating loss which resulted from lower operating income and higher intangible
drilling costs. Intangible drilling costs are deductible currently for tax
purposes, but are capitalized and amortized over future periods for financial
reporting purposes. The increase in inventories since December 31, 1994, is the
result of injections of purchased gas into the Company' s unregulated
underground storage facility. The Company has been withdrawing and selling this
gas during the first quarter of 1996. The increase in current liabilities
resulted primarily from an increase in accounts payable, an increase in taxes
(other than income) payable, and an increase in over-recovered purchased gas
costs, offset by a decrease in the current portion of long-term debt. The
increase in accounts payable resulted primarily from increased amounts due for
gas purchases which resulted from the higher weather-related sales in the gas
distribution segment, a higher level of exploration and production capital
expenditures, and from the timing of payments. Over-recovered purchased gas
costs will be refunded to the Company's utility customers over future periods
through the automatic cost of gas adjustment clauses in the Company's filed rate
tariffs.
This discussion and analysis of financial condition and results of
operations includes forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. The Company believes that its expectations are based on reasonable
assumptions. No assurances, however, can be given that its goals will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward-looking statements herein include (1) the timing and
extent of changes in commodity prices for gas and oil, (2) the extent of the
Company's success in discovering, developing, and producing reserves, (3) the
effects of weather and regulation on the Company's gas distribution segment, and
(4) conditions in capital markets, availability of oil field services, drilling
rigs, and other equipment, as well as other competitive factors during the
periods covered by the forward-looking statements.
15
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, 1995 and
1994, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1995.
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, 1995 and 1994, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1995, 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 5, 1996
16
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
OPERATING REVENUES
Gas sales $142,455 $160,463 $166,164
Oil sales 3,924 3,178 1,662
Gas transportation 4,964 4,721 5,177
Other 1,768 1,824 1,841
- -----------------------------------------------------------------------------------------------------------------------------
153,111 170,186 174,844
- -----------------------------------------------------------------------------------------------------------------------------
OPERATING COSTS AND EXPENSES
Purchased gas costs 37,133 36,395 42,962
Operating and general 44,436 42,506 40,093
Depreciation, depletion and amortization 35,992 35,546 30,944
Taxes, other than income taxes 4,362 3,657 3,281
- -----------------------------------------------------------------------------------------------------------------------------
121,923 118,104 117,280
- -----------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 31,188 52,082 57,564
- -----------------------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE
Interest on long-term debt 12,984 9,962 10,090
Other interest charges 639 504 483
Interest capitalized (2,456) (1,599) (1,548)
- -----------------------------------------------------------------------------------------------------------------------------
11,167 8,867 9,025
- -----------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE) (1,227) (2,362) (1,657)
- -----------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE 18,794 40,853 46,882
- -----------------------------------------------------------------------------------------------------------------------------
INCOME TAXES
Current (4,908) 9,288 13,704
Deferred 12,167 6,441 6,128
- -----------------------------------------------------------------------------------------------------------------------------
7,259 15,729 19,832
- -----------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 11,535 25,124 27,050
EXTRAORDINARY LOSS DUE TO EARLY RETIREMENT OF DEBT (NET OF $185 TAX BENEFIT) (295) -- --
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- -- 10,126
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 11,240 $ 25,124 $ 37,176
=============================================================================================================================
EARNINGS PER SHARE
Income before extraordinary item and cumulative effect of accounting change $.46 $.98 $1.05
Extraordinary loss due to early retirement of debt (net of $185 tax benefit) (.01) -- --
Cumulative effect of change in accounting for income taxes -- -- .39
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME $.45 $.98 $1.44
=============================================================================================================================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 25,130,781 25,684,110 25,684,110
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
17
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
ASSETS
Current Assets
Cash $ 1,498 $ 1,152
Accounts receivable 35,541 32,325
Income taxes receivable 8,221 1,492
Inventories, at average cost 15,448 12,199
Other 3,188 2,353
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 63,896 49,521
- -----------------------------------------------------------------------------------------------------------------------------
Investments 9,114 4,877
- -----------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $51,337,000 in 1995 and
$20,751,000 in 1994 excluded from amortization 517,979 435,570
Gas distribution systems 193,258 176,728
Gas in underground storage 32,616 36,629
Other 19,717 18,541
- -----------------------------------------------------------------------------------------------------------------------------
763,570 667,468
Less: Accumulated depreciation, depletion and amortization 277,751 242,008
- -----------------------------------------------------------------------------------------------------------------------------
485,819 425,460
- -----------------------------------------------------------------------------------------------------------------------------
Other Assets 10,264 6,216
- -----------------------------------------------------------------------------------------------------------------------------
$569,093 $486,074
=============================================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt $ 3,071 $ 6,071
Accounts payable 23,989 18,670
Taxes payable 2,422 2,208
Customer deposits 4,619 4,232
Over-recovered purchased gas costs, net 7,327 3,627
Other 3,982 5,827
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 45,410 40,635
- -----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 207,757 136,229
- -----------------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 115,461 100,288
Deferred investment tax credits 2,103 2,416
Other 3,858 3,050
- -----------------------------------------------------------------------------------------------------------------------------
121,422 105,754
- -----------------------------------------------------------------------------------------------------------------------------
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 21,272 21,231
Retained earnings, per accompanying statements 204,632 199,430
- -----------------------------------------------------------------------------------------------------------------------------
228,678 223,435
Less: Common stock in treasury, at cost, 3,036,735 shares in 1995 and
2,053,974 shares in 1994 33,795 19,717
Unamortized cost of restricted shares issued under stock incentive plan,
34,807 shares in 1995 and 21,499 shares in 1994 379 262
- -----------------------------------------------------------------------------------------------------------------------------
194,504 203,456
- -----------------------------------------------------------------------------------------------------------------------------
$569,093 $486,074
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
18
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income $ 11,240 $ 25,124 $ 37,176
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 36,272 35,825 31,223
Deferred income taxes 12,167 6,441 6,128
Equity in loss of partnership 696 2,818 1,788
Cumulative effect of change in accounting for income taxes -- -- (10,126)
Change in assets and liabilities:
(Increase) decrease in accounts receivable (3,216) 2,569 (589)
(Increase) decrease in income taxes receivable (6,729) (5,354) 3,090
Increase in inventories (3,249) (2,619) (1,544)
Increase in accounts payable 5,319 2,556 2,298
Increase (decrease) in taxes payable 214 (379) 21
Increase in customer deposits 387 305 417
Increase (decrease) in over-recovered purchased gas costs 3,700 (560) (286)
Net change in other current assets and liabilities (940) (113) 603
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 55,861 66,613 70,199
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (101,626) (76,854) (59,219)
Investment in partnership (4,968) (2,319) --
Decrease in gas stored underground 4,013 542 9,119
Other items 2,814 3,200 1,599
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (99,767) (75,431) (48,501)
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net proceeds from issuance of Senior Notes 121,978 -- --
Net increase (decrease) in revolving long-term debt (29,400) 21,300 (15,500)
Retirement of 10.63% Senior Notes and prepayment premium (24,958) -- --
Payments on other long-term debt (3,071) (6,000) (835)
Purchase of treasury stock (14,259) -- --
Dividends paid (6,038) (6,164) (5,651)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 44,252 9,136 (21,986)
- -----------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 346 318 (288)
Cash at beginning of year 1,152 834 1,122
- -----------------------------------------------------------------------------------------------------------------------------
Cash at end of year $ 1,498 $ 1,152 $ 834
=============================================================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $199,430 $180,470 $148,945
Net income 11,240 25,124 37,176
Cash dividends declared ($.24 per share in 1995 and 1994, and $.22 per share in 1993) (6,038) (6,164) (5,651)
- -----------------------------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $204,632 $199,430 $180,470
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
19
Notes to Financial Statements
December 31, 1995, 1994 and 1993
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS AND CONSOLIDATION
Southwestern Energy Company is a diversified natural gas company which
operates principally in the exploration and production segment and the gas
distribution segment of the natural gas industry. Approximately 75% of the
Company's business is derived from the exploration and production segment based
on operating income. The primary areas of operations for the exploration and
production segment are the Arkoma Basin of Arkansas, the Gulf Coast areas of
Louisiana and Texas, the Anadarko Basin of Oklahoma, and the Delaware Basin of
New Mexico. The gas distribution segment operates in northwest and northeast
Arkansas and parts of Missouri, and obtains approximately 60% of its gas supply
from one of the Company's exploration and production subsidiaries. The customers
of the gas distribution segment consist of residential, commercial, and
industrial users of natural gas.
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 its general partnership interest in the NOARK Pipeline
System, Limited Partnership (NOARK) using the equity method of accounting. In
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the Company
recognizes profit on intercompany sales of gas delivered to storage by its
utility subsidiary. Certain reclassifications have been made to the prior years'
financial statements to conform with the 1995 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
Gas and Oil Properties-The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive) are
capitalized and amortized on an aggregate basis over the estimated lives of the
properties using the units-of-production method. The Company excludes all costs
of unevaluated properties from immediate amortization.
Gas Distribution Systems-Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of the
gas distribution system is provided using the straight-line method with average
annual rates for plant functions ranging from 2.2% to 6.7%. Gas in underground
storage is stated at average cost.
Other property, plant and equipment is depreciated using the straight-line
method over estimated useful lives ranging from 5 to 40 years.
The Company charges to maintenance or operations the cost of labor,
materials, and other expenses incurred in maintaining the operating efficiency
of its properties. Betterments are added to property accounts at cost.
Retirements are credited to property, plant and equipment at cost and charged to
accumulated depreciation, depletion and amortization with no gain or loss
recognized, except for abnormal retirements.
Capitalized Interest-Interest is capitalized on the costs of unevaluated
gas and oil properties excluded from amortization. In accor-dance 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 101,000 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, to provide a proper matching of revenues with expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual cost of purchased gas above or below the
level included in the base rates is permitted to be billed or is required to be
credited to customers. Each month, the difference between actual costs of
purchased gas and gas costs recovered from customers is deferred. The deferred
differences are billed or credited, as appropriate, to customers in subsequent
months.
GAS PRODUCTION IMBALANCES
The exploration and production subsidiaries record gas sales using the
entitlement method. The entitlement method requires revenue recognition of the
Company's revenue interest share of gas production from properties in which gas
sales are disproportionately allocated to owners because of marketing or other
contractual arrangements. The Company's net imbalance position at December 31,
1995 and 1994 was not significant.
20
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.
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. There were no outstanding
interest rate swap agreements at December 31, 1995 or 1994.
The Company uses natural gas swap agreements to hedge sales of natural gas.
Under the natural gas swap agreements, the Company makes or receives payments
based on the differential between a specified price and the indicated market
price of natural gas. Gains and losses resulting from hedging activities are
recognized when the related physical natural gas transactions are recognized.
Gains or losses from natural gas swap agreements that do not qualify for
accounting treatment as hedges are recognized currently as other income or
expense. Gains and losses resulting from natural gas swap agreements and hedging
activities have not had a material impact on the Company's results of
operations.
EARNINGS PER SHARE AND SHAREHOLDERS' EQUITY
Earnings per common share are based on the weighted average number of
common shares outstanding during each year.
During 1995 the Company repurchased 1,000,000 shares of its common stock
for $14.3 million, and issued under a compensatory plan and for stock awards
17,239 treasury shares with a weighted average cost of $.2 million.
(2) LONG-TERM DEBT
Long-term debt as of December 31, 1995 and 1994 consisted of the following:
1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
SENIOR NOTES
6.70% Series due December 1, 2005 $125,000 $ --
8.69% Series due December 4, 1997 22,500 22,500
8.86% Series due in annual installments of $3.1 million through December 4, 2001 18,428 21,500
9.36% Series due in annual installments of $2.0 million beginning December 4, 2001 22,000 22,000
10.63% Series -- 24,000
- --------------------------------------------------------------------------------------------------------------------------
187,928 90,000
OTHER
Variable rate (6.33% at December 31, 1995)unsecured revolving credit arrangements with two banks 22,900 52,300
- --------------------------------------------------------------------------------------------------------------------------
Total long-term debt 210,828 142,300
Less: Current portion of long-term debt 3,071 6,071
- --------------------------------------------------------------------------------------------------------------------------
$207,757 $136,229
==========================================================================================================================
In December, 1995, the Company issued $125.0 million of 6.70% fixed rate
Senior Notes. The notes mature with a single payment due after ten years. The
proceeds were used to repay certain borrowings of the Company. The Company
incurred $3.0 million of costs associated with the issuance of this debt. This
amount has been capitalized and will be amortized over the life of the notes.
In November, 1995, the Company exercised its prepayment option on its
10.63% Senior Notes due September 30, 2001. Certain costsof the redemption were
expensed in the fourth quarter of 1995 and are classified as an extraordinary
loss, net of related income tax effects, in the accompanying financial
statements.
The Company has several prepayment options under the terms of its other
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, 1995, the Company had two variable rate facilities which
make available $80.0 million of long-term revolving credit, of which $22.9
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 and 1999.
The Company intends to renew or replace the facilities prior to expiration.
The terms of the long-term debt instruments and agreements contain
covenants which impose certain restrictions on the Company, including limitation
of additional indebtedness and restrictions on the payment of cash dividends. At
December 31, 1995, approximately $103.0 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.
21
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
Aggregate maturities of long-term debt for each of the years ending
December 31, 1996 through 2000, are $3.1 million, $25.6 million, $16.1 million,
$13.0 million, and $3.1 million. Total interest payments of $12.9 million, $10.2
million, and $10.3 million were made in 1995, 1994, and 1993, respectively.
(3) INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes." The liability method specified by SFAS No. 109 requires the
calculation of accumulated deferred income taxes by application of the tax rate
expected to be in effect when the taxes will actually be paid or refunds will be
received. 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:
1995 1994 1993
- ----------------------------------------------------------------------------------------------------
(in thousands)
Federal:
Current $(5,436) $ 7,758 $11,514
Deferred 11,434 5,588 3,827
Deferred tax adjustment for tax rate increase -- -- 1,743
State:
Current 528 1,530 2,190
Deferred 1,046 1,054 752
Investment tax credit amortization (313) (201) (194)
- ----------------------------------------------------------------------------------------------------
Provision for income taxes $ 7,259 $15,729 $19,832
====================================================================================================
The provision for income taxes was an effective rate of 38.6% in 1995,
38.5% in 1994, and 42.3% in 1993. 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:
1995 1994 1993
- --------------------------------------------------------------------------------------------------------------
(in thousands)
Expected provision at federal statutory rate of 35% $6,578 $14,299 $16,409
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,023 1,682 1,914
Percentage depletion on gas and oil production (70) (96) (117)
Adjustment to deferred taxes for tax rate increase -- -- 1,743
Investment tax credit amortization (313) (201) (194)
Other 41 45 77
- --------------------------------------------------------------------------------------------------------------
Provision for income taxes $7,259 $15,729 $19,832
==============================================================================================================
The components of the Company's net deferred tax liability as of December
31, 1995 and 1994 were as follows:
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $103,612 $ 89,289
Stored gas differences 5,435 5,736
Deferred purchased gas costs 236 1,557
Prepaid pension costs 1,561 1,628
Book over tax basis in partnerships 4,712 3,535
Other 971 1,095
- --------------------------------------------------------------------------------
116,527 102,840
- --------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 681 700
Other 644 370
- --------------------------------------------------------------------------------
1,325 1,070
- --------------------------------------------------------------------------------
Net deferred tax liability $115,202 $101,770
================================================================================
Total income tax payments of $.9 million, $14.6 million, and $10.2 million
were made in 1995, 1994, and 1993, respectively.
22
(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 1995 and 1994 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 8.5% in 1995
and 7.5% in 1994 for the net pension cost computation, and a salary progression
rate of 5%. The reconciliation of prepaid pension cost at December 31, 1995
utilizes a discount rate of 7.5% for future settlements.
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1995 and 1994:
1995 1994
- ------------------------------------------------------------------------------------------
(in thousands)
Actuarial present value of benefit obligations:
Vested benefits $(25,789) $(20,643)
Nonvested benefits (1,860) (1,635)
- ------------------------------------------------------------------------------------------
Accumulated benefit obligation (27,649) (22,278)
Effect of projected future compensation levels (8,623) (6,368)
- ------------------------------------------------------------------------------------------
Projected benefit obligation (36,272) (28,646)
Plan assets at fair value, primarily common stocks and bonds 49,570 36,675
- ------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 13,298 8,029
Unrecognized net gain (8,956) (3,617)
Unrecognized net asset (952) (1,135)
Unrecognized prior service cost 397 454
- ------------------------------------------------------------------------------------------
Prepaid pension cost $ 3,787 $ 3,731
==========================================================================================
Net pension cost for 1995, 1994, and 1993 included the following
components:
1995 1994 1993
- ----------------------------------------------------------------------------------------------------
(in thousands)
Service costs (benefits earned during the period) $ 1,101 $ 1,217 $ 897
Interest cost on projected benefit obligation 2,316 2,280 1,999
Actual return on plan assets (15,172) (791) (2,819)
Net amortization and deferral 11,699 (2,643) (673)
- ----------------------------------------------------------------------------------------------------
Net pension cost (credit) $ (56) $ 63 $ (596)
====================================================================================================
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $221,000,
$201,000, and $628,000 in 1995, 1994, and 1993, respectively. In 1993, this plan
was funded with $1.2 million. At December 31, 1995, the supplemental retirement
plan had an accrued pension cost of $91,000.
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.
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 1995 and 1994 included the following components:
1995 1994
- ----------------------------------------------------------------------------------------------------
(in thousands)
Service cost of benefits earned during the year $110 $ 79
Amortization of transition amount 103 178
Amortization of unrecognized gain 32 17
Interest cost on accumulated postretirement benefit obligation (APBO) 218 164
- ----------------------------------------------------------------------------------------------------
Net postretirement benefit cost $463 $438
====================================================================================================
23
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
The APBO as of December 31, 1995 and 1994 was comprised of the following:
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Retirees $1,109 $ 766
Active participants, fully eligible 303 442
Other participants 805 804
- --------------------------------------------------------------------------------
Total APBO $2,217 $2,012
================================================================================
In determining the APBO, assumed weighted average discount rates of 7.5%
and 8.5% were used for 1995 and 1994, respectively. An increase of 10% in the
cost of covered health care benefits was assumed for 1996. This rate is assumed
to decrease ratably to 6.0% over 8 years and remain at that level thereafter.
The effect of a one percentage point increase in the assumed health care cost
trend rate for each future year would increase the total APBO at year-end 1995
by $253,000 and the 1995 net postretirement benefit cost by $29,000.
(5) NATURAL GAS AND OIL PRODUCING ACTIVITIES
All of the Company's gas and oil properties are located in the United
States. The table below sets forth the results of operations from gas and oil
producing activities:
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
Sales $ 63,205 $ 80,123 $ 79,374
Production (lifting) costs (7,930) (6,771) (6,341)
Depreciation, depletion and amortization (29,607) (29,738) (25,686)
- --------------------------------------------------------------------------------
25,668 43,614 47,347
Income tax expense (9,831) (16,684) (18,081)
- --------------------------------------------------------------------------------
Results of operations $ 15,837 $ 26,930 $ 29,266
================================================================================
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 1995, 1994,
and 1993:
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $27,715 $21,972 $ 5,920
Exploration costs 29,843 12,419 11,695
Development costs 24,429 20,943 19,722
- --------------------------------------------------------------------------------
Capitalized costs incurred $81,987 $55,334 $37,337
================================================================================
Amortization per Mcf equivalent $.817 $.759 $.710
================================================================================
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 1995 and 1994:
1995 1994
- ----------------------------------------------------------------------------------------------------
(in thousands)
Proved properties $463,868 $405,081
Unproved properties 54,111 30,489
- ----------------------------------------------------------------------------------------------------
Total capitalized costs 517,979 435,570
Less: Accumulated depreciation, depletion and amortization 206,148 176,764
- ----------------------------------------------------------------------------------------------------
Net capitalized costs $311,831 $258,806
====================================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1995. Included in these costs is
$6.6 million representing leasehold and seismic costs related to the remaining
unevaluated portion of acreage located on the Fort Chaffee military reservation.
These costs are expected to be evaluated and subjected to amortization within
the next several years as this acreage is further explored and developed.
Included in exploration costs is $4.7 million of seismic costs related to the
Company's 50% interest in a joint venture seismic program in the Atchafalaya
Basin in Louisiana. These costs and subsequent costs to be incurred will be
evaluated over several years as the seismic data is interpreted and the acreage
is explored. The remaining costs excluded from
24
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.
1995 1994 1993 Prior Total
- --------------------------------------------------------------------------------
(in thousands)
Property acquisition costs $14,207 $3,667 $1,084 $6,595 $25,553
Exploration costs 17,322 3,202 1,204 347 22,075
Capitalized interest 2,379 535 255 540 3,709
- --------------------------------------------------------------------------------
$33,908 $7,404 $2,543 $7,482 $51,337
================================================================================
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1995, 1994, and 1993:
1995 1994 1993
- -----------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
- -----------------------------------------------------------------------------------------------------------
Proved reserves, beginning of year 316,098 1,231 318,776 479 312,291 359
Revisions of previous estimates (25,970) (199) (16,551) (258) (4,110) (25)
Extensions, discoveries, and other additions 34,801 498 30,932 189 46,069 250
Production (34,515) (229) (37,706) (200) (35,693) (97)
Acquisition of reserves in place 4,462 851 20,647 1,038 222 --
Disposition of reserves in place -- -- -- (17) (3) (8)
- -----------------------------------------------------------------------------------------------------------
Proved reserves, end of year 294,876 2,152 316,098 1,231 318,776 479
===========================================================================================================
Proved, developed reserves:
Beginning of year 261,690 1,116 260,240 469 246,904 337
End of year 248,714 1,975 261,690 1,116 260,240 469
===========================================================================================================
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, 1995, 1994, and 1993:
1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
(in thousands)
Future cash inflows $ 751,261 $ 683,438 $ 745,967
Future production and development costs (106,092) (96,813) (85,609)
Future income tax expense (229,064) (207,359) (236,170)
- ---------------------------------------------------------------------------------------------------------
Future net cash flows 416,105 379,266 424,188
10% annual discount for estimated
timing of cash flows (212,583) (189,774) (196,913)
- ---------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 203,522 $ 189,492 $ 227,275
=========================================================================================================
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.
25
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
Following is an analysis of changes in the standardized measure during
1995, 1994, and 1993:
1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
Standardized measure, beginning of year $189,492 $227,275 $209,970
Sales and transfers of gas and oil produced, net of production costs (55,275) (73,352) (73,017)
Net changes in prices and production costs 39,928 (29,344) 22,392
Extensions, discoveries, and other additions, net of future production and development costs 49,471 43,458 74,511
Revisions of previous quantity estimates (29,851) (19,225) (5,217)
Accretion of discount 28,733 34,968 31,885
Net change in income taxes (9,073) 24,564 (13,524)
Changes in production rates (timing)and other (9,903) (18,852) (19,725)
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $203,522 $189,492 $227,275
===================================================================================================================================
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company holds a general partnership interest in NOARK of 47.93% and is
the pipeline's operator. NOARK is a 258 mile long intrastate gas transmission
system which extends across northern Arkansas and was placed in service in
September, 1992. The Company's investment in NOARK totaled $9.0 million at
December 31, 1995 and $4.8 million at December 31, 1994. The Company's
investment in NOARK includes advances of $5.0 million made during 1995 and $2.3
million during 1994, primarily to provide certain minimum cash balances to
service NOARK's long-term debt. See Note 12 for further discussion of NOARK's
funding requirements and the Company's investment in NOARK.
NOARK's financial position at December 31, 1995 and 1994 is summarized
below:
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
Current assets $ 870 $ 1,078
Noncurrent assets 98,048 100,662
- --------------------------------------------------------------------------------
$98,918 $101,740
================================================================================
Current liabilities $ 6,624 $ 6,009
Long-term debt 76,700 86,250
Loans from general partners 11,505 3,225
Partners' capital 4,089 6,256
- --------------------------------------------------------------------------------
$98,918 $101,740
================================================================================
The Company's share of NOARK's pretax loss, before the effect of accrued
interest expense on general partner loans, was $.7 million, $2.8 million, and
$1.8 million for 1995, 1994, and 1993, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
income. The 1995 pretax loss included $2.9 million of income for the Company's
share of a $6.0 million settlement of contract issues with one of NOARK's
transporters.
NOARK's results of operations for 1995, 1994, and 1993 are summarized
below:
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
Operating revenues $11,657 $10,111 $ 8,301
Pretax loss $(2,167) $(5,917) $(3,778)
================================================================================
(8) DISCLOSURES ABOUT THE FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
the value:
Cash and Customer Deposits - The carrying amount is a reasonable estimate
of fair value.
Long-Term Debt - The fair value of the Company's long-term debt is
estimated based on the expected current rates which would be offered to the
Company for debt of the same maturities.
26
The estimated fair values of the Company's financial instruments as of
December 31, 1995 and 1994 were as follows:
1995 1994
-------------------- ---------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
(in thousands)
Cash $1,498 $1,498 $1,152 $1,152
Customer deposits $4,619 $4,619 $4,232 $4,232
Long-term debt $210,828 $216,364 $142,300 $144,245
================================================================================
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.
(9) SEGMENT INFORMATION
Intersegment sales by the exploration and production segment to the gas
distribution segment are priced in accordance with terms of existing gas
contracts and current market conditions. Following is industry segment data for
the years ended December 31, 1995, 1994, and 1993:
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
REVENUES
Exploration and production $ 63,523 $ 80,123 $ 79,374
Gas distribution 119,855 127,060 131,892
Other 336 308 262
Eliminations (30,603) (37,305) (36,684)
- --------------------------------------------------------------------------------
$153,111 $170,186 $174,844
- --------------------------------------------------------------------------------
INTERSEGMENT REVENUES
Exploration and production $ 29,811 $ 36,465 $ 36,091
Gas distribution 536 584 337
Other 256 256 256
- --------------------------------------------------------------------------------
$ 30,603 $ 37,305 $ 36,684
- --------------------------------------------------------------------------------
OPERATING INCOME
Exploration and production $ 20,523 $ 38,888 $ 42,608
Gas distribution 11,133 13,386 15,261
Corporate expenses (468) (192) (305)
- --------------------------------------------------------------------------------
$ 31,188 $ 52,082 $ 57,564
- --------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Exploration and production $346,514 $288,175 $236,968
Gas distribution 183,410 171,471 186,704
Other 39,169 26,428 21,782
- --------------------------------------------------------------------------------
$569,093 $486,074 $445,454
- --------------------------------------------------------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION
Exploration and production $ 29,607 $ 29,738 $ 25,686
Gas distribution 5,338 4,981 4,564
Other 1,047 827 694
- --------------------------------------------------------------------------------
$ 35,992 $ 35,546 $ 30,944
- --------------------------------------------------------------------------------
CAPITAL ADDITIONS
Exploration and production $ 82,237 $ 55,449 $ 37,411
Gas distribution 18,523 17,577 19,892
Other 866 3,828 1,916
- --------------------------------------------------------------------------------
$101,626 $ 76,854 $ 59,219
================================================================================
27
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(10) STOCK OPTIONS
The Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan)
provides for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan provides for grants of options, shares of
restricted stock, and stock bonuses that in the aggregate do not exceed
1,275,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock, and cash awards, the shares related to which in the
aggregate do not exceed 1,275,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The types of incentives which may
be awarded are comprehensive and are intended to enable the Board of Directors
to structure the most appropriate incentives and to address changes in income
tax laws which may be enacted over the term of the plan.
At December 31, 1995, there were options for 1,024,108 shares outstanding
under the 1993 Plan at option prices ranging from $13 3/8 to $17 1/8,
representing the fair market value at the dates of grant. Of the total, 780,000
performance accelerated options were granted in 1994 at an option price of $14
5/8. These options vest over a four-year period beginning six years from the
date of grant or earlier if certain corporate performance criteria are achieved.
The remaining options, granted in 1993, 1994, and 1995, vest to employees over a
three-year period from the date of grant. Options for 28,774 shares were
exercisable at December 31, 1995. All options expire ten years from the date of
grant. Additionally, 38,965 shares of restricted stock have been granted to
employees during the period 1993 through 1995. Of this total, 6,855 shares
issued in 1995 vest over a three-year period and the remaining shares vest over
a five-year period. The related compensation expense is being amortized over the
vesting periods.
Under the Company's 1985 Nonqualified Stock Option Plan, there were options
for 427,050 shares and 84,900 SARs outstanding at December 31, 1995 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 Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors provides for annual stock option grants of 12,000 shares (with 12,000
limited SARs) to each non-employee director. Options may be awarded under the
plan on no more than 240,000 shares. 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, 1995, there
were options for 99,000 shares outstanding at option prices ranging from $12 7/8
to $17 1/2. Options for 21,000 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. 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 combi-nation, 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, 1995, the Senior Secured Notes had a
remaining balance of $56.7 million and a remaining term of 14 years. At December
31, 1995, NOARK also had an unsecured long-term revolving credit agreement in
the amount of $30.0 million with a group of banks, of which $23.2 million was
outstanding. Amounts borrowed under the long-term revolving credit facility are
severally guaranteed by the Company and an affiliate of the other general
partner. The Company's share of the several guarantee of the notes and the line
of credit is 60%. Additionally, the Company's gas distribution subsidiary has a
transportation contract with an original term of ten years with NOARK for firm
capacity of 41 MMcfd. The remaining term of that contract is seven years and is
renewable year-to-year until terminated by 180 days' notice.
In late 1993, a transporter of gas on NOARK's pipeline system filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its firm transportation agreement
with NOARK. In December, 1995, the parties
28
to the lawsuit settled prior to going to trial. In exchange for a $6.0 million
payment to NOARK, the transporter was released from its obligations under its
firm transportation agreement. The Company will be required to fund its share of
any cash flow deficiencies to the extent they are not funded by the available
line of credit. Management of the Company and the NOARK partners continue to
investigate options available to NOARK. However, management believes that no
write-down of its investment in NOARK is appropriate at this time and that it
will realize its investment in NOARK over the life of the system. Therefore, no
provision for any loss has been made in the accompanying financial statements.
The Company has been advised of a potential claim against it involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties and related matters. The Company has begun discussions with the
claimant and has engaged special counsel to assist it in a preliminary
investigation of the claim's merits. The Company is unable to predict at this
time whether litigation will be commenced in respect of this claim or how the
claim will ultimately be resolved. While the amount of the potential claim is
significant in the aggregate, management believes, based on its preliminary
investigation, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial condition or reported results of operations
of the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1995 and 1994:
Quarter Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
1995
----
Operating revenues $51,751 $30,642 $25,454 $45,264
Operating income $15,090 $ 3,927 $ 1,955 $10,216
Income (loss) before extraordinary item $ 7,102 $ 445 $(1,081) $ 5,069
Net income (loss) $ 7,102 $ 445 $(1,081) $ 4,774
Earnings (loss) per share before extraordinary item $.28 $.02 $(.04) $.20
Earnings (loss) per share $.28 $.02 $(.04) $.19
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
==========================================================================================================================
29
Financial and Operating Statistics
1995 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------------------------
FINANCIAL REVIEW (in thousands)
Operating revenues:
Exploration and production $ 63,523 $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489
Gas distribution 119,855 127,060 131,892 117,495 121,302 108,911
Other 336 308 262 256 256 256
Intersegment revenues (30,603) (37,305) (36,684) (34,475) (34,511) (33,586)
- ------------------------------------------------------------------------------------------------------------------------------
153,111 170,186 174,844 143,830 136,439 117,070
- ------------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 37,133 36,395 42,962 35,848 40,423 37,678
Operating and general 44,436 42,506 40,093 34,970 32,609 28,134
Depreciation, depletion and amortization 35,992 35,546 30,944 23,880 18,248 14,756
Taxes, other than income taxes 4,362 3,657 3,281 3,144 3,017 2,885
- ------------------------------------------------------------------------------------------------------------------------------
121,923 118,104 117,280 97,842 94,297 83,453
- ------------------------------------------------------------------------------------------------------------------------------
Operating income 31,188 52,082 57,564 45,988 42,142 33,617
Interest expense, net (11,167) (8,867) (9,025) (9,983) (9,813) (10,530)
Other income (expense) (1,227) (2,362) (1,657) (421) (107) (17)
- ------------------------------------------------------------------------------------------------------------------------------
Income before income taxes, extraordinary items and the
cumulative effect of accounting change 18,794 40,853 46,882 35,584 32,222 23,070
- ------------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current (4,908) 9,288 13,704 7,403 7,158 4,994
Deferred 12,167 6,441 6,128 5,916 4,999 3,568
- ------------------------------------------------------------------------------------------------------------------------------
7,259 15,729 19,832 13,319 12,157 8,562
- ------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative effect of
accounting change 11,535 25,124 27,050 22,265 20,065 14,508
Extraordinary loss due to early retirement of debt
(net of $185 tax benefit) (295) -- -- -- -- --
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 $ 11,240 $ 25,124 $ 37,176 $ 22,265 $ 20,065 $ 14,075
==============================================================================================================================
Cash flow from operations (in thousands) $ 55,861 $ 66,613 $ 70,199 $ 49,730 $ 34,986 $ 36,495
Return on equity 5.78% 12.35% 14.66%/(1)/ 14.53% 14.75% 11.66%
Gross profit margin 20.37% 30.60% 32.92% 31.97% 30.89% 28.72%
Net profit margin 7.34% 14.76% 15.47%/(1)/ 15.48% 14.71% 12.02%
==============================================================================================================================
COMMON STOCK STATISTICS/(2)/
Earnings per share before extraordinary item and
cumulative effect of accounting change $.46 $.98 $1.05 $.87 $.78 $.57
Earnings per share $.45 $.98 $1.44 $.87 $.78 $.56
Cash dividends declared and paid per share $.24 $.24 $.22 $.20 $.19 $.19
Book value per share $7.87 $7.92 $7.18 $5.97 $5.30 $4.70
Market price at year-end $12.75 $14.88 $18.00 $12.96 $10.50 $10.42
Number of shareholders of record at year-end 2,759 2,875 3,005 2,930 2,989 3,136
Average shares outstanding 25,130,781 25,684,110 25,684,110 25,683,963 25,678,011 25,270,674
==============================================================================================================================
CAPITALIZATION (in thousands)
Long-term debt, including current portion $210,828 $142,300 $127,000 $143,335 $134,104 $125,535
Common shareholders' equity 194,504 203,456 184,530 153,233 136,041 120,709
- ------------------------------------------------------------------------------------------------------------------------------
Total capitalization $405,332 $345,756 $311,530 $296,568 $270,145 $246,244
- ------------------------------------------------------------------------------------------------------------------------------
Total assets $569,093 $486,074 $445,454 $427,175 $392,208 $366,313
- ------------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 51.65% 40.10% 40.19% 48.31% 49.08% 50.39%
Equity 48.35% 59.90% 59.81% 51.69% 50.92% 49.61%
==============================================================================================================================
CAPITAL EXPENDITURES (in millions)
Exploration and production $82.2 $55.4 $37.4 $30.8 $30.3 $23.4
Gas distribution 18.5 17.6 19.9 12.2 7.9 9.3
Other .9 3.9 1.9 1.9 .7 .7
- ------------------------------------------------------------------------------------------------------------------------------
$101.6 $76.9 $59.2 $44.9 $38.9 $33.4
==============================================================================================================================
/(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.
30
1995 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------------------------------------------
Natural Gas and Oil Wells Completed
Producers:
Gross 70.0 78.0 57.0 69.0 25.0 25.0
Net 43.8 50.2 40.7 54.6 11.8 9.1
Dry holes:
Gross 39.0 30.0 28.0 29.0 12.0 10.0
Net 26.5 16.5 14.5 19.5 4.1 2.1
- --------------------------------------------------------------------------------------------------------------------------------
Total:
Gross 109.0 108.0 85.0 98.0 37.0 35.0
Net 70.3 66.7 55.2 74.1 15.9 11.2
At the end of 1995, the Company was a participant in 17.0 (12.4 net) wells in process.
================================================================================================================================
Natural Gas and Oil Produced
Natural gas:
Production, Bcf 34.5 37.7 35.7 25.8 20.3 16.7
Average price per Mcf $1.72 $2.04 $2.18 $2.26 $2.25 $2.33
Oil:
Production, MBbls 229 200 97 120 176 112
Average price per barrel $17.15 $15.89 $17.20 $19.75 $20.67 $22.89
Average production (lifting) cost per Mcf equivalent $.22 $.17 $.18 $.16 $.19 $.16
Proved reserves at year-end:
Natural gas, Bcf 294.9 316.1 318.8 312.3 307.5 304.5
Oil, MBbls 2,152 1,231 479 359 505 773
================================================================================================================================
Utility Operating Data
Sales volumes, Bcf:
Residential 12.1 11.6 12.9 10.8 10.9 10.1
Commercial 7.6 7.2 7.8 6.6 6.7 6.3
Industrial 7.7 7.5 6.1 6.1 9.5 10.2
Transportation volumes, Bcf:
End-use 5.2 4.8 5.6 5.2 1.3 .1
Off-system 9.8 10.7 11.7 2.5 .2 .3
- --------------------------------------------------------------------------------------------------------------------------------
42.4 41.8 44.1 31.2 28.6 27.0
- --------------------------------------------------------------------------------------------------------------------------------
Average sales customers:
Residential 144,828 140,684 137,087 133,103 129,379 127,142
Commercial 19,502 18,872 18,511 18,141 17,880 17,680
Industrial 342 341 346 348 370 366
- --------------------------------------------------------------------------------------------------------------------------------
164,672 159,897 155,944 151,592 147,629 145,188
- --------------------------------------------------------------------------------------------------------------------------------
Sales and transportation revenues (in thousands):
Residential $ 59,523 $ 62,565 $ 67,502 $ 59,747 $ 58,372 $ 48,407
Commercial 31,018 32,252 35,311 31,425 30,718 27,535
Industrial 22,466 25,191 21,757 20,502 29,187 30,463
Transportation 4,964 4,721 5,177 3,597 857 179
- --------------------------------------------------------------------------------------------------------------------------------
$117,971 $124,729 $129,747 $115,271 $119,134 $106,584
- --------------------------------------------------------------------------------------------------------------------------------
Miles of pipe:
Gathering 434 405 398 383 375 371
Transmission 1,348 1,346 1,335 1,328 1,326 1,326
Distribution 4,451 4,246 4,160 4,090 4,002 3,931
- --------------------------------------------------------------------------------------------------------------------------------
6,233 5,997 5,893 5,801 5,703 5,628
- --------------------------------------------------------------------------------------------------------------------------------
Degree days 4,376 4,161 4,929 4,104 4,095 3,972
Percent of normal 99% 95% 113% 92% 93% 90%
================================================================================================================================
31
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 Monday, May
13, 1996, 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 1995 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
----------------------------- -------------------
1995 1994 1995 1994
- -----------------------------------------------------------------------------------------
High Low High Low
March 31 $15.13 $11.75 $18.88 $15.13 $.06 $.06
June 30 $15.50 $13.63 $17.75 $15.50 $.06 $.06
September 30 $14.25 $12.00 $17.88 $15.50 $.06 $.06
December 31 $14.25 $12.25 $17.75 $14.00 $.06 $.06
=========================================================================================
Market prices represent transactions on the New York Stock Exchange.
32
Southwestern Energy Company and Subsidiaries
APPENDIX to 1995 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in four
areas; the Arkoma Basin, the Anadarko Basin, the Gulf Coast, and the Delaware
Basin of New Mexico. The Arkoma Basin is located in the central section of
western Arkansas and the central section of eastern Oklahoma. Southwestern's
activities are concentrated in the historically productive Arkansas section of
the Arkoma Basin. The Anadarko Basin covers most of the western part of Oklahoma
and extends to the northwest into the northern panhandle of Texas and the
panhandle area of Oklahoma. Southwestern's Gulf Coast operations include both
onshore and offshore activity along both the Texas and Louisiana coasts. The
Delaware Basin is located in the southeast corner of New Mexico and extends to
the south into western Texas.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where it also provides distribution
service to communities in that area, including the towns of Ozark and
Clarksville. AWG's transmission and distribution lines extend north and supply
communities in the northwest part of the state, including the towns of
Fayetteville, Springdale, and Rogers. AWG's service area also extends east to
the Harrison and Mountain Home areas. This eastern section of the AWG system
receives a portion of its gas supply from a lateral line off of the NOARK
Pipeline System (NOARK) as discussed below. Through its division, Associated
Natural Gas Company (Associated), AWG provides distribution of natural gas to
communities in northeast Arkansas and parts of Missouri. Major communities
served in northeast Arkansas include Blytheville, Piggott, and Osceola. The
Associated distribution system also serves the "bootheel" area in southeast
Missouri, including the communities of Sikeston, New Madrid, and Caruthersville
and extends north to the Jackson area. In addition, Associated provides service
to Butler, Missouri, near the state's western border and Kirksville, Missouri,
near the state's northern border through connections off of interstate pipelines
in those areas.
Description of NOARK Pipeline System Operating Area:
Southwestern Energy Pipeline Company owns a 47.93% general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Claimant's gathering and
transmission pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Forth Smith, at
the Fort Chaffee military reservation, and extends east through the Arkoma Basin
and across northern Arkansas. A lateral from NOARK extends north and connects to
AWG's distribution line in the Mountain Home area. NOARK crosses three
interstate pipelines in northeast Arkansas and ends at an interconnection with
Arkansas Western Pipeline Company's 8-mile interstate pipeline at the
Arkansas/Missouri border. This pipeline transports gas from NOARK to
Associated's distribution system.
Operating Properties:
ACREAGE AND PRODUCING WELLS
Undeveloped Developed Wells
Gross Net Gross Net Gross Net
- -----------------------------------------------------------------------------------------------------------
Arkansas 175,335 84,566 298,523 138,425 761 395.3
Louisiana 37,485 21,880 12,890 4,060 34 19.6
Oklahoma 21,799 15,601 51,551 27,494 471 245.5
Texas 31,517 15,416 48,687 11,887 39 8.2
New Mexico 17,200 8,967 1,000 161 5 1.6
Other areas 10,154 8,564 4,018 964 11 3.0
- -----------------------------------------------------------------------------------------------------------
293,490 154,994 416,669 182,991 1,321 673.2
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GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
- -----------------------------------------------------------------------------------------------------------
Gathering 434 -- 434
Transmission 745 603 1,348
Distribution 2,867 1,584 4,451
- -----------------------------------------------------------------------------------------------------------
4,046 2,187 6,233
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