PROSPECTUS SUPPLEMENT
(To Prospectus dated November 20, 1995)
$125,000,000
Southwestern Energy Company
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6.70% SENIOR NOTES DUE 2005
Interest payable June 1 and December 1
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The Notes will not be redeemable prior to maturity and will not
be subject to any sinking fund. The Notes will be represented by
a Registered Global Security registered in the name of The
Depository Trust Company (the "Depository") or its nominee.
Beneficial interests in the Registered Global Security will be
shown on, and transfers thereof will be
effected through, records maintained by the Depository or its
participants. Except as described herein,
Notes in definitive form will not be issued. See "Description of
Notes."
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THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY
STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY
OF THIS PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
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PRICE 99.855% AND ACCRUED INTEREST
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Underwriting Proceeds
Price to Discounts and to the
Public(1) Commissions(2) Company(1)(3)
------------- -------------- -------------
Per Note. . . 99.855% .650% 99.205%
Total . . . . $124,818,750 $812,500 $124,006,250
_____________
(1) Plus accrued interest from December 1, 1995.
(2) The Company has agreed to indemnify the Underwriters against
certain liabilities, including liabilities under the
Securities Act of 1933, as amended. See "Underwriting."
(3) Before deduction of estimated expenses of $370,000 payable by
the Company.
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The Notes are offered, subject to prior sale, when, as and
if accepted by the Underwriters and subject to approval of
certain legal matters by Davis Polk & Wardwell, counsel for the
Underwriters. It is expected that delivery of the Notes will be
made on or about December 5, 1995, through the book-entry
facilities of the Depositary, against payment therefor in
immediately available funds.
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MORGAN STANLEY & CO.
Incorporated
FIRST CHICAGO CAPITAL MARKETS, INC.
NATIONSBANC CAPITAL MARKETS, INC.
November 30, 1995
<PAGE>
No dealer, salesman or other person has been authorized to
give any information or to make any representation not contained
in or incorporated by reference in this Prospectus Supplement and
the accompanying Prospectus and, if given or made, such
information or representation must not be relied upon as having
been authorized by the Company or any underwriter or dealer.
This Prospectus Supplement and the accompanying Prospectus do not
constitute an offer to sell or a solicitation of an offer to buy
any of the securities offered hereby in any jurisdiction to any
person to whom it is unlawful to make such an offer in such
jurisdiction. Neither the delivery of this Prospectus Supplement
and the accompanying Prospectus nor any sale made hereunder
shall, under any circumstances, create any implication that the
information herein is correct as of any time subsequent to the
date hereof or that there has been no change in the affairs of
the Company since such date.
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TABLE OF CONTENTS
Prospectus Supplement
Page
The Company. . . . . . . . . . . . . . . . . . . . . . . . . . S-3
Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . . . S-4
Capitalization . . . . . . . . . . . . . . . . . . . . . . . . S-5
Selected Financial and Operating Data. . . . . . . . . . . . . S-6
Management's Discussion and Analysis
of Financial Condition and Results of Operations . . . . . . S-9
Description of Notes . . . . . . . . . . . . . . . . . . . . . S-20
Underwriting . . . . . . . . . . . . . . . . . . . . . . . . . S-22
Legal Matters. . . . . . . . . . . . . . . . . . . . . . . . . S-22
Prospectus
Available Information. . . . . . . . . . . . . . . . . . . . . 2
Incorporation of Certain Information by Reference. . . . . . . 2
The Company. . . . . . . . . . . . . . . . . . . . . . . . . . 3
Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . . . 3
Ratio of Earnings to Fixed Charges . . . . . . . . . . . . . . 4
Description of Debt Securities . . . . . . . . . . . . . . . . 4
Plan of Distribution . . . . . . . . . . . . . . . . . . . . . 14
Experts. . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
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IN CONNECTION WITH THE OFFERING THE UNDERWRITERS MAY OVER-
ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE
MARKET PRICE OF THE NOTES OFFERED HEREBY AT A LEVEL ABOVE THAT
WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
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<PAGE>
THE COMPANY
Southwestern Energy Company (the "Company") is an integrated
natural gas company. Through its wholly-owned subsidiaries, the
Company is engaged in gas and oil exploration and production,
natural gas gathering and transmission as well as natural gas
distribution. The principal sites for the Company's exploration
and production program are the Arkoma Basin of Arkansas, the Gulf
Coast (both onshore and shallow waters offshore) and the Anadarko
Basin of Oklahoma. The Company's natural gas gathering,
transmission and distribution properties are located in Arkansas
and Missouri. The Company is an exempt holding company under the
Public Utility Holding Company Act of 1935.
Exploration and Production
The Company conducts its exploration and production
activities through two wholly-owned subsidiaries, SEECO, Inc.
("SEECO") and Southwestern Energy Production Company ("SEPCO").
At December 31, 1994, the Company had reserves of approximately
323.5 billion cubic feet equivalent ("Bcfe"), consisting of 316.1
billion cubic feet ("Bcf") of natural gas and 1,231,000 barrels
of oil. The Company's reserve base has increased 46.0% since
1988 from 221.5 Bcfe to 323.5 Bcfe as of December 31, 1994.
Production has increased 199.2% during the same period, from 13.0
Bcfe in 1988 to 38.9 Bcfe in 1994.
SEECO owns the majority of the Company's gas reserves,
virtually all of which are located behind the Company's pipeline
system. SEECO is engaged principally in low risk/low cost
development drilling within the Arkoma Basin of Arkansas. The
nature of the producing sands allows for shallow, low cost
development wells with multiple completion opportunities.
SEPCO conducts exploration and production activities
concentrated primarily on low to moderate risk projects in the
onshore Louisiana and Texas Gulf Coast and Oklahoma. SEPCO holds
approximately 26% of the Company's gas reserves and all of its
oil reserves. In the Gulf Coast areas, it is the policy of the
Company to have a working interest of between 50% and 75%, and
drilling exposure not exceeding $1.0 million, per well.
Recently, SEPCO entered into a joint venture to acquire south
Louisiana seismic data. The seismic program covers 125 square
miles in the gas producing St. Martin's Parish and adjoining
parishes. SEPCO augments its drilling program with selective
producing property acquisitions to minimize total risk. During
1994 and the first nine months of 1995, SEPCO purchased
approximately 37 Bcfe of proved reserves at an average
acquisition cost of $.54 per thousand cubic feet ("Mcf")
equivalent.
Natural Gas Gathering, Transmission and Distribution
The Company conducts natural gas gathering, transmission and
distribution activities through Arkansas Western Gas Company
("Arkansas Western"). Arkansas Western has two operating
divisions, Arkansas Western Gas Company ("AWG"), which operates
the Company's northwest Arkansas utility system, and Associated
Natural Gas Company ("Associated"), which operates the Company's
utility systems in northeast Arkansas and parts of Missouri. The
utility systems serve 164,000 residential, commercial and
industrial customers and obtain a substantial portion of the gas
they consume through AWG's Arkoma Basin gathering system.
AWG gathers natural gas in the Arkansas River Valley through
405 miles of pipeline. It transports the gas through its own
transmission system to its distribution system. At December 31,
1994, AWG had 744 miles of transmission pipeline and 2,691 miles
of distribution pipeline. AWG's distribution system serves
approximately 97,000 residential, commercial and industrial
customers in northwest Arkansas. Due to the economic growth in
this region, AWG's customer base has grown approximately 3.5% to
4.0% per year over the past several years. AWG purchases the
majority of its gas supply at the wellhead under long-term
contracts. SEECO provided 64% of AWG's gas supply in 1994. AWG
purchases 9.0 Bcf (gross) annually of SEECO's gas production at
the NorAm Index plus an average per Mcf of $.85.
Associated receives its gas from interstate pipelines and
transports it through 602 miles of its own transmission pipeline
for delivery to its distribution systems. Associated's
distribution systems serve approximately 67,000 residential,
commercial and industrial customers, primarily in northeast
Arkansas and southeast Missouri, through 1,555 miles of pipeline.
Associated receives approximately 55% of its gas from a long-term
contract with SEECO at a price to be redetermined annually. The
remainder of its gas supply comes from a mixture of firm
transportation and firm sales arrangements with various
suppliers.
Southwestern Energy Pipeline Company
The Company's subsidiary Southwestern Energy Pipeline
Company has a 47.93% interest in the NOARK Pipeline System,
Limited Partnership ("NOARK"), a 258 mile intrastate gas
transmission system which extends across northern Arkansas.
NOARK aids the Company's system integration by providing access
to the interstate market for sales of the Company's gas
production as well as allowing Associated to acquire a large
portion of its gas supply from the Arkoma Basin.
USE OF PROCEEDS
The Company intends to use substantially all of the net
proceeds from the sale of the Notes to repay certain borrowings
under its revolving credit facilities (bearing interest rates of
6.16% to 6.75%), including the portion of such borrowings
incurred to repay the Company's 10.63% Senior Notes due 2001.
The Company intends to use any remaining net proceeds for general
corporate purposes.
CAPITALIZATION
The following table sets forth the consolidated
capitalization of the Company and its subsidiaries as of
September 30, 1995, and as adjusted to reflect the issuance of
the Notes and the application of the estimated proceeds (without
reduction for the underwriting discount and estimated offering
expenses):
September 30, 1995
------------------
As
Actual Adjusted
------ --------
(unaudited,
in thousands)
Current Portion of Long-Term debt. . . . . . . . . $ 6,071 $ 3,071
======== ========
Long-Term Debt
Senior notes. . . . . . . . . . . . . . . . . . $ 83,929 $ 62,929
% Senior notes offered hereby . . . . . . . . - 125,000
Revolving credit facilities . . . . . . . . . . 92,100 -
-------- --------
Total Long-Term Debt. . . . . . . . . . . . 176,029 187,929
-------- --------
Shareholders' Equity
Common stock. . . . . . . . . . . . . . . . . . 2,774 2,774
Additional paid-in capital. . . . . . . . . . . 21,252 21,252
Retained earnings . . . . . . . . . . . . . . . 201,339 201,339
-------- --------
225,365 225,365
Less:
Unamortized cost of restricted shares
issued under stock incentive plan . . . . . 282 282
Common stock in treasury. . . . . . . . . . . 33,896 33,896
-------- --------
Total Shareholders' Equity . . . . . . . 191,187 191,187
-------- --------
Total Capitalization . . . . . . . . $367,216 $379,116
======== ========
SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth selected consolidated
financial and operating data relating to the Company. The
historical financial data relating to each of the years in the
five-year period ended December 31, 1994 are derived from the
audited consolidated financial statements of the Company and its
subsidiaries. The historical financial data for each of the nine
month periods ended September 30, 1995 and 1994 are derived from
unaudited financial statements of the Company. In the opinion of
Company management, such unaudited financial statements include
all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the financial data for such
periods. The results for the nine months ended September 30,
1995 and 1994 are not necessarily indicative of the results to be
achieved for the full year. The data should be read in
conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the
consolidated financial statements and notes thereto of the
Company incorporated by reference into the Prospectus Supplement
and the accompanying Prospectus.
Nine Months Ended
September 30,
1995 1994
------- --------
Financial Data
($ in thousands)
Income Statement Data:
Revenues:
Exploration and
production......... $ 45,901 $ 61,107
Gas distribution... 82,740 93,627
Other.............. 262 227
Intersegment
revenues.......... (21,056) (27,118)
------- -------
107,847 127,843
------- -------
Operating costs
and expenses:
Purchased gas
costs............. 24,364 27,955
Operating and
general........... 32,243 30,668
Depreciation,
depletion and
amortization...... 27,169 26,098
Taxes, other than
income taxes...... 3,099 2,799
------- -------
86,875 87,520
------- -------
Operating Income..... 20,972 40,323
Interest expense,
net................. 8,040 6,328
Other income
(expense)........... (2,418) (1,547)
------- -------
Income, before
provision for
income taxes........ 10,514 32,448
Provision for
income taxes........ 4,048 12,492
------- -------
Income before
extraordinary item
and cumulative
effect of accounting
change.............. 6,466 19,956
Loss on early
retirement of debt.. - -
Cumulative effect
of change in
accounting for
income taxes........ - -
------- -------
Net income....... $ 6,466 $ 19,956
======= =======
Balance Sheet Data:
(at end of period)
Total Assets......... 521,339 457,572
Long-term Debt,
including current
portion............. 182,100 130,184
Common Shareholders'
Equity.............. 191,187 199,822
Other Financial Data:
Cash flow from
operations.......... $ 48,036 $ 55,355
Capital expenditures. 68,291 54,653
EBITDA(1)............ 45,723 64,874
Ratio of Earnings
to fixed
Charges(2).......... 1.7 3.9
Operating Data:
Exploration and
production:
Natural gas
production (Bcf).. 26.1 27.6
Average gas price
(per Mcf)......... $1.65 $2.13
Oil Production
(MBbls)........... 164 138
Average oil price
(per Bbl)......... $17.25 $15.82
Gas distribution:
Deliveries (Bcf):
Sales volumes.... 18.3 18.7
Transportation
volumes:
End-use........ 3.8 3.5
Off-system..... 8.5 8.8
------- -------
Total
deliveries.. 30.6 31.0
------- -------
Utility customers-
period end........ 161,561 157,451
Heating weather-
% of normal....... 96% 101%
Twelve Months Ended
December 31,
----------------------------------------------------
1994 1993 1992 1991 1990
Financial Data
($ in thousands)
Income Statement Data:
Revenues:
Exploration and
production........ $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489
Gas distribution.. 127,060 131,892 117,495 121,302 108,911
Other............. 308 262 256 256 256
Intersegment
revenues......... (37,305) (36,684) (34,475) (34,511) (33,586)
------- ------- ------- ------- -------
170,186 174,844 143,830 136,439 117,070
------- ------- ------- ------- -------
Operating costs
and expenses:
Purchased gas
costs............. 36,395 2,962 35,848 40,423 37,678
Operating and
general........... 42,506 40,093 34,970 32,609 28,134
Depreciation,
depletion and
amortization...... 35,546 30,944 23,880 18,248 14,756
Taxes, other than
income taxes..... 3,657 3,281 3,144 3,017 2,885
------- ------- ------- ------- -------
118,104 117,280 97,842 94,297 83,453
------- ------- ------- ------- -------
Operating Income..... 52,082 57,564 45,988 42,142 33,617
Interest expense,
net................. 8,867 9,025 9,983 9,813 10,530
Other income
(expense)........... (2,362) (1,657) (421) (107) (17)
------- ------- ------- ------- -------
Income, before
provision for
income taxes........ 40,853 46,882 35,584 32,222 23,070
Provision for
income taxes........ 15,729 19,832 13,319 12,157 8,562
------- ------- ------- ------- -------
Income before
extraordinary item
and cumulative
effect of accounting
change.............. 25,154 27,050 22,265 20,065 14,508
Loss on early
retirement of debt.. - - - - (433)
Cumulative effect
of change in
accounting for
income taxes........ - 10,126 - - -
------- ------- ------- ------- -------
Net income........... 25,124 37,176 22,265 20,065 14,075
======= ======= ======= ======= =======
Balance Sheet Data:
(at end of period)
Total Assets......... 484,582 445,454 427,175 392,208 366,313
Long-term Debt,
including current
portion............. 142,300 127,000 143,335 134,104 125,535
Common Shareholders'
Equity.............. 203,456 184,530 153,233 136,041 120,709
Other Financial Data:
Cash flow from
operations.......... $ 66,613 $ 70,199 $ 49,730 $ 34,986 $ 36,495
Capital expenditures. 76,854 59,219 44,909 38,888 33,438
EBITDA(1)............ 85,266 86,851 69,447 60,283 48,356
Ratio of Earnings
to fixed
Charges(4).......... 3.6 4.0 3.1 3.6 2.8
Operating Data:
Exploration and
production:
Natural gas
production (Bcf).. 37.7 35.7 25.8 20.3 16.7
Average gas price
(per Mcf)......... $2.04 $2.18 $2.26 $2.25 $2.33
Oil Production
(MBbls)........... 200 97 120 176 112
Average oil price
(per Bbl)......... $15.89 $17.20 $19.75 $20.67 $22.89
Gas distribution:
Deliveries (Bcf):
Sales volumes.... 26.3 26.8 23.5 27.1 26.6
Transportation
volumes:
End-use........ 4.8 5.6 5.2 1.3 0.1
Off-system..... 10.7 11.7 2.5 0.2 0.3
------- ------- ------- ------- -------
Total
deliveries.. 41.8 44.1 31.2 28.6 27.0
------- ------- ------- ------- -------
Utility customers-
period end........ 164,323 160,230 156,071 151,167 148,202
Heating weather-
% of normal....... 95% 113% 92% 93% 90%
- ------------------
(1) EBITDA is earnings before interest, income taxes, depreciation and
amortization. EBITDA is presented here to provide additional
information about the Company's ability to meet its future
requirements for debt service, capital expenditures and working
capital. EBITDA should not be considered as an alternative to net
income as an indicator of operating performance or as an alternative
to cash flows as a measure of liquidity.
(2) In the calculation of the ratio of earnings to fixed charges,
"earnings" consists of income before income taxes, adjusted to add
back fixed charges (excluding capitalized interest relating to oil and
gas properties), the amortization of interest previously capitalized
on oil and gas properties, and the Company's 47.93% ownership share of
the fixed charges of NOARK. "Fixed charges" consists of interest on
borrowings (including capitalized interest), amortization of debt
discount and expense, a portion of rental expense determined to be
representative of the interest factor, and the Company's 60% guaranty
of the fixed charges of NOARK. A statement setting forth the
computation of the unaudited ratio of earnings to fixed charges is
filed as an exhibit to the registration statement of which this
Prospectus Supplement and the accompanying Prospectus are a part.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information set forth below consists of the management's
discussion and analysis contained or incorporated by reference in
the Company's Quarterly Report on Form 10-Q for the quarter ended
September 30, 1995 and the Company's Annual Report on Form 10-K
for the year ended December 31, 1994. Such information is
presented in this Prospectus Supplement for convenience of
reference and has not been updated in any material respect since
the date of each respective document.
Results of Operations - Nine Months Ended September 30, 1995
The Company reported net income of $6.5 million, or $.26 per
share for the nine months ended September 30, 1995, compared to
$20.0 million, or $.78 per share, for the same period in 1994.
The comparative decrease in net income was primarily the result
of lower natural gas prices, reflecting both the general decline
in spot market prices and the effect of the 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 sales price under the contract affected by
the Gas Cost Settlement. The Gas Cost Settlement and the
significant 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 of the exploration and production segment were down
25% for the nine month period ended September 30, 1995, compared
to the same period in 1994. Gas production during the nine
months ended September 30, 1995 was 26.1 Bcf, down 5% from 27.6
Bcf for the same period in 1994. The decrease was primarily the
result of lower sales from the Company's Gulf of Mexico
properties. The Company is in the process of connecting new
production, but due to timing considerations, additions to new
production have fallen somewhat behind the normal decline from
other properties, especially offshore.
Sales from the Company's offshore properties were 2.1 Bcf
for the first nine months of 1995, down from 4.4 Bcf for the same
period in 1994. Sales in the first nine months of 1994 were
helped by the start of production from a new offshore platform
late in 1993. Sales of the Company's onshore gas production were
24.0 Bcf for the nine months ended September 30, 1995, up from
23.2 Bcf for the same period in 1994. Sales of Arkansas
production to unaffiliated purchasers totaled 11.2 Bcf for the
first nine months of 1995, down from 12.0 Bcf for the same period
in 1994.
The Company sold 5.9 Bcf to AWG, which operates its
northwest Arkansas gas distribution system, during the first nine
months of 1995, compared to 5.8 Bcf for the same period in 1994.
Associated, which operates the Company's gas distribution systems
in northeast Arkansas and parts of Missouri, purchased 3.6 Bcf of
the Company's gas production during the first nine months of both
1995 and 1994.
The Company's average sales price for its gas production was
$1.65 per Mcf for the first nine months of 1995, down 23% from
$2.13 per Mcf for the same period of 1994.
The Company's oil production increased to 164,022 barrels for the
nine months ended September 30, 1995, up from 137,691 barrels for
the same period in 1994. The increase was due primarily to
additional production from properties acquired in Oklahoma and
the Gulf Coast area during the last half of 1994 and the first
half of 1995.
Operating revenues of the gas distribution segment decreased
12% in the nine months ended September 30, 1995, compared to the
same period in 1994. The decrease was due both to a decrease in
the average utility rate and lower volumes due to warmer weather.
Growth of 3% in 1995 in the average number of utility customers
substantially offset the effect of weather which was 4% warmer
than normal during the first nine months of 1995 and 5% warmer
than in the same period in 1994. Deliveries by the Company's gas
distribution systems to sales and end-use transportation
customers were 22.1 Bcf for the nine months ended September 30,
1995, compared to 22.2 Bcf for the same period in 1994. AWG
delivered a total of 14.7 Bcf to its sales and end-use
transportation customers during the first nine months of 1995, up
from 14.5 Bcf for the same period in 1994. AWG also transported
8.5 Bcf for delivery off its system during the first nine months
of 1995, down from 8.8 Bcf for the same period in 1994.
Associated delivered a total of 7.4 Bcf to its customers during
the first nine months of 1995, down from 7.7 Bcf for the same
period in 1994.
The Company's average rate for its utility sales decreased
to $4.24 per Mcf during the first nine months of 1995, down from
$4.73 per Mcf for the same period in 1994. The decrease
reflected lower prices paid for purchases of natural gas which
are passed through to customers under automatic adjustment
clauses.
Operating costs and expenses decreased $.6 million, or .7%,
for the nine months ended September 30, 1995, compared to the
same period in 1994. The decrease in operating costs and
expenses was due primarily to lower purchased gas costs related
to lower prices paid for gas supplies, partially offset by
increases in both operating and general expenses and
depreciation, depletion and amortization expense.
Total interest expense for the nine months ended September
30, 1995, was up 27%, compared to the same period in 1994. The
increase was due to both higher average borrowings and higher
average interest rates on the Company's revolving credit
facilities.
The Company's share of NOARK's pre-tax loss included in
other income was $2.6 million for the nine months ended September
30, 1995, compared to $1.8 million for the same period in 1994.
The increase in NOARK's pre-tax loss resulted primarily from a
decrease in firm demand revenues and from an increase in interest
expense. The Company, through a subsidiary, holds a 47.93%
general partnership interest in NOARK and is the pipeline's
operator.
The changes in the provisions for current and deferred
income taxes recorded in the nine month period ended September
30, 1995, compared to the same period in 1994, resulted primarily
from the level of taxable income and from the deduction for tax
purposes of intangible drilling costs incurred, netted against
the turnaround of intangible drilling costs deducted for tax
purposes in prior years. Intangible drilling costs are
capitalized and amortized over future years for financial
reporting purposes under the full cost method of accounting.
Changes In Financial Condition
Changes in the Company's financial condition at September
30, 1995, compared to December 31, 1994, primarily reflect the
seasonal nature of the gas distribution segment of the Company's
business and changes in prices received for gas production of the
Company's exploration and production segment.
Routine capital expenditures, cash dividends and scheduled
debt retirements are predominately funded through cash provided
by operations. For the first nine months of 1995, operating
activities provided net cash flows of $48.0 million, a $7.4
million decrease from the $55.4 million provided in the first
nine months of 1994. The decrease was primarily due to lower net
income and the timing of both cash receipts and expenditures.
The Company expects its outstanding borrowings to increase during
the fourth quarter of 1995 as cash generated from operations will
be less than the requirements for capital expenditures and cash
dividends.
The Company's capital expenditures for the first nine months
of 1995 were $68.3 million, compared to $54.7 million for the
same period in 1994. The comparative increase was the result of
additional oil and gas exploration expenditures, primarily on the
onshore Louisiana and Texas Gulf Coast combined with expenditures
of $9.2 million to purchase oil and gas producing properties in
the same area. The Company originally budgeted $55.2 million in
1995 for the exploration and production segment, approximately
level with the total spent in 1994, but currently expects total
spending for this segment to be approximately $70.0 to $75.0
million based on current projections of activity through the end
of 1995. Total capital spending for the exploration and
production segment could be affected by oil and gas property
acquisitions which might be identified later in 1995.
The Company maintains two floating rate revolving credit
facilities that provide up to $80.0 million of medium to long-
term capital at current market lending rates. These facilities
have been temporarily expanded to $140.0 million to provide
additional debt financing and to provide for the prepayment of
the outstanding balance on the Company's 10.63% Senior Notes.
The Company has given notice of its intention to repay the
outstanding balance of its 10.63% Senior Notes on November 17,
1995. A total of $92.1 million was outstanding under the
revolving credit facilities at September 30, 1995, all of which
was classified as long-term debt. The Company also had available
short-term lines of credit totaling $3.5 million, none of which
was outstanding at September 30, 1995. During the first nine
months of 1995, the Company's revolving long-term debt increased
by $39.8 million. The increase was a result of both higher
capital expenditures and repurchases of 1,000,000 shares of the
Company's Common Stock under a program authorized by its Board of
Directors in the first quarter of 1995. As a result of the
increased borrowings, long-term debt at September 30, 1995,
accounted for 49% of the Company's capitalization, up from 41% at
December 31, 1994.
The Company has filed a shelf registration statement with
the Securities and Exchange Commission for the issuance of up to
$250 million of senior unsecured debt securities and under which
the Notes are offered. The Company intends to use substantially
all of the net proceeds from the sale of the Notes to repay
certain borrowings under its revolving credit facilities (bearing
interest rates of 6.16% to 6.75%), including the portion of such
borrowings used to repay the Company's 10.63% Senior Notes due
2001. The Company intends to use any remaining net proceeds for
general corporate purposes. Additional debt securities may be
issued in the future under the shelf registration statement as
circumstances dictate.
Accounts receivable have declined since December 31, 1994,
due to both seasonally lower deliveries of the gas distribution
segment and a decrease in amounts due from unaffiliated
purchasers of gas production in the exploration and production
segment caused by lower average gas prices and the timing of cash
receipts. The increase in income taxes receivable since December
31, 1994, is primarily due to the lower level of taxable income
in 1995, resulting from lower operating income and higher
intangible drilling costs. The increase in inventories since
December 31, 1994, is the result of injections of purchased gas
into the Company's unregulated underground gas storage facility.
The Company expects to withdraw and sell this gas during the
upcoming heating season and has hedged the projected sales to
protect against price declines. Accounts payable have declined
since December 31, 1994, due primarily to seasonally lower gas
purchases of the gas distribution segment. Other changes in
current assets and current liabilities between periods resulted
primarily from the timing of expenditures.
The Company had over-recovered $6.7 million of purchased gas
costs at September 30, 1995, which will be refunded to its
utility customers through automatic cost of gas adjustment
clauses included in its filed rate tariffs. At December 31,
1994, the Company had over-recovered purchased gas costs in the
amount of $3.6 million. These amounts are classified as current
liabilities.
Regulatory Matters
Associated purchases a portion of its gas supply at the
wellhead from one of the Company's gas producing subsidiaries
under a long-term firm contract entered into in October, 1990.
As a result of recent gas cost audits in Missouri for the five-
year period ended August 31, 1993, Associated received an order
on July 14, 1995, from the Missouri Public Service Commission
(the "MPSC") disallowing the recovery of $2.2 million of gas
costs incurred under this contract. Of the total disallowed,
$1.5 million represented a portion of the difference between the
price paid by Associated under this contract and a spot market
index price for gas delivered into an interstate pipeline
operating in the Arkoma Basin. The balance of $.7 million in
recovery 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 competition and continue the significant
restructuring of the interstate natural gas pipeline industry.
Prior to Order No. 636, Associated purchased portions of its gas
supply from interstate pipelines under firm long-term supply
contracts. The 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
Company does not expect the ultimate outcome of this matter to
have a material adverse impact on the results of operations or
the financial position of the Company.
AWG also purchases gas from unaffiliated suppliers 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 Associated in Arkansas and began to obtain their own gas
supplies directly from other sources. Associated has offered
such a service to its customers in Missouri for several years and
AWG's spot market purchasing program has provided customers in
northwest Arkansas with many of the benefits of transportation
service. The Company expects to be able to continue to
satisfactorily manage its exposure to take-or-pay liabilities.
Results of Operations - Year Ended December 31, 1994
Net income in 1994 decreased by 7% to $25.1 million, or $.98
per share, down from $27.1 million, or $1.05 per share, in 1993.
The comparison of 1994 to 1993 excludes the cumulative effect of
a change in accounting for income taxes which was recorded in the
first quarter of 1993. Operating results for 1993 also included
an adjustment of $1.7 million, or $.07 per share, to decrease net
income and record the effect on accumulated deferred income taxes
of a legislated increase in the federal corporate income tax
rate. There were no accounting changes or extraordinary items
recorded in 1994.
The decline in 1994 earnings resulted as lower gas prices
and much warmer heating weather offset the favorable effect of
the Company's seventh consecutive increase in natural gas
production. The low gas prices also magnified the effect on
earnings of the Gas Cost Settlement.
Exploration and Production Revenues
The Company's exploration and production revenues increased
1% in 1994. The slight increase was due to increases in natural
gas and oil production, offset by lower average product prices.
Gas production increased by 6% to 37.7 Bcf in 1994 from 35.7 Bcf
in 1993.
Gas sales to unaffiliated purchasers increased to 23.8 Bcf
in 1994, from 22.9 Bcf in 1993. The increases in sales to
unaffiliated purchasers were primarily the result of higher sales
from the Company's properties in both Arkansas and the Gulf Coast
areas of Texas and Louisiana. The Company sold 15.1 Bcf of its
Arkansas production to unaffiliated purchasers during both 1994
and 1993. Sales from the Company's Gulf Coast properties were
6.8 Bcf in 1994, compared to 6.3 Bcf in 1993. The increase in
1994 was primarily the result of the completion of a production
platform at the Galveston Block 283 gas field late in 1993 and
first production from the Earl Chauvin No. 1 well, a 1993
discovery in southeast Louisiana.
Sales to unaffiliated purchasers are made under contracts
that reflect current short-term prices and are subject to
seasonal price swings. The Company also uses gas price hedges on
a limited basis to reduce the Company's exposure to the risk of
changing prices.
Deliveries for injection into storage and the Gas Cost
Settlement, discussed below, increased the demand of the
Company's utility distribution systems for affiliated gas supply
in 1994. Gas production sold to AWG was 8.8 Bcf in 1994, up from
7.1 Bcf in 1993. The Company's gas production provided
approximately 64% of AWG's requirements in 1994, and
approximately 50% in 1993. Additionally, in 1994 and 1993, the
Company sold .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
(the "AWG Contract"), under which the price had been frozen since
the end of 1984. The AWG Contract was amended in 1994 as a
result of the Gas Cost Settlement with the APSC. The settlement
became effective July 1, 1994, and calls for sales under the AWG
Contract to take place at a price which is equal to a spot market
index plus a premium. The Gas Cost Settlement results in a lower
contract price based on current market conditions. That effect
is offset in part by provisions of the Gas Cost Settlement which
allow additional volumes to be sold under the AWG Contract. See
"--Regulatory Matters". Other sales to AWG are made under long-
term contracts with flexible pricing provisions and under short-
term spot arrangements.
The Company's deliveries to Associated for distribution in
northeast Arkansas and parts of Missouri were 5.1 Bcf in 1994
and 5.7 Bcf in 1993. Deliveries to Associated decreased in 1994
due to warmer weather in the heating season. Effective October,
1990, one of the Company's exploration and production
subsidiaries entered into a ten-year contract with Associated to
supply its base load system requirements at a price to be
redetermined annually. Deliveries under this contract were made
at $1.90 per Mcf from inception of the contract through the first
nine months of 1993, then increased to $2.385 per Mcf through
September 30, 1994 and decreased to $2.20 per Mcf through September
30, 1995. The price effective from October 1, 1995 through
September 30, 1996 has recently been redetermined at $1.785.
The average price received at the wellhead for the Company's
total gas production was $2.04 per Mcf in 1994 and $2.18 per Mcf
in 1993. The decline in the average price received reflects the
recent decline in spot market prices, an increase in
proportionate share of the Company's production sold at spot
market prices and under long-term contracts with market-sensitive
pricing, and the effect of the Gas Cost Settlement. Natural gas
prices declined during the last half of 1994, and with the
abnormally warm winter recently experienced across the country,
average prices are generally expected to remain lower in 1995 as
compared to 1994. As described above, a significant portion of
the Company's gas production is sold under long-term contracts to
AWG, its gas distribution subsidiary. In the past, the fixed
prices received under these sales arrangements helped reduce the
effects of fluctuations in the spot market price for natural gas.
Going forward, the Company expects increased volatility and
seasonality in its operating results as the majority of its gas
sales will be tied to a spot market index. In the future, the
Company expects the overall average price it receives for its
total production to be generally higher than average spot market
prices due to the premiums over spot that it receives. Future
changes in revenues from sales of the Company's gas production
will be dependent upon changes in the market price for gas,
access to new markets, maintenance of existing markets, and
additions of new gas reserves.
The Company expects future increases in its gas production
to come primarily from sales to unaffiliated purchasers. While
the Company expects over the long term to experience a trend
toward increasing volumes of gas production, it is unable to
predict changes in the market demand and price for natural gas,
including changes which may be induced by the effects of weather
on demand of both affiliated and unaffiliated customers for the
Company's production. Additionally, the Company holds a large
block of undeveloped leasehold acreage and producing acreage
which will continue to be developed in the future. The Company's
exploration programs have been directed almost exclusively toward
natural gas in recent years. The Company will continue to
concentrate on developing and acquiring gas reserves, but will
also selectively seek opportunities to participate in projects
oriented toward oil production.
Gas Distribution Revenues
Gas distribution revenues fluctuate due to the pass-through
of cost of gas increases and decreases, and due to the effects of
weather. Because of the corresponding changes in purchased gas
costs, the revenue effect of the pass-through of gas cost changes
has not materially affected net income.
Gas distribution revenues decreased by 4% in 1994. The
decrease reflected the net effects of strong customer growth
offset by weather which was 16% warmer than the prior year, and
lower purchased gas costs caused in part by the Gas Cost
Settlement.
In 1994, AWG sold 16.3 Bcf to its customers at an average
rate of $4.25 per Mcf, compared to 17.1 Bcf at $4.40 per Mcf in
1993. Additionally, AWG transported 4.0 Bcf for its end-use
customers in 1994 and 3.9 Bcf in 1993. Associated sold 10.0 Bcf
to its customers in 1994 at an average rate of $5.10 per Mcf,
compared to 9.7 Bcf in 1993 at $5.08 per Mcf. Associated's
increase in 1994 was due to the conversion of an industrial
customer from transportation to sales service. While the
conversion of this customer to sales service raised the Company's
gas distribution revenues, there was no resulting impact on
operating income as the rate charged this customer for
transportation service was equal to the rate charged for sales
service, exclusive of gas costs. Associated transported .8 Bcf
for its end-use customers in 1994, compared to 1.7 Bcf in 1993.
Total deliveries to industrial customers of AWG and
Associated, including end-use transportation volumes, increased
to 12.3 Bcf in 1994, from 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 10.7 Bcf of gas through its gathering
system in 1994 for off-system deliveries, all through NOARK,
compared to 11.7 Bcf in 1993. The average transportation rate
was $.13 per Mcf, exclusive of fuel, in both years.
Gas distribution revenues in future years will be impacted
by both customer growth and rate increases allowed by regulatory
commissions. In recent years, AWG has experienced customer
growth of approximately 3.5% to 4.0% annually, while Associated
has experienced customer growth of approximately 1% to 2% annually.
Based on current economic conditions in the Company's service
territories, the Company expects this trend in customer growth to
continue. Rate increase requests which may be filed in the future
will depend upon customer growth, increases in operating expenses,
and additional investments in property, plant and equipment. AWG is
precluded from filing an application for a rate increase with the
APSC prior to January 1, 1996, as a result of the Gas Cost
Settlement. The Company anticipates filing a rate increase
request for AWG in early 1996 and will continue to monitor the
status of returns on the systems operated by Associated and file
rate cases as the need arises.
Regulatory Matters
During 1994, the Company 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-related issues were first raised by
the APSC in December, 1990, in connection with its approval of an
AWG rate increase. The issues in question involved the price of
gas sold under the AWG Contract, 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
that allow additional volumes to be sold under the amended AWG
Contract. The amended AWG Contract provides for volumes equal to
the historical level of sales under the contract to be sold at
the spot index plus a premium of $.95 per Mcf, while any
incremental sales volumes will receive a premium of $.50 per Mcf.
In 1994, approximately 8.1 Bcf (net to the Company's interest)
was sold under the AWG Contract, compared to approximately 6.0
Bcf in 1993. Under other significant terms of the Gas Cost
Settlement, the parties thereto may not ask for refunds, certain
of AWG's natural gas storage facilities were transferred to
another subsidiary of the Company, and as noted above, AWG may
not file a rate case for its northwest Arkansas system before
January, 1996.
Operating Costs and Expenses
The Company's operating costs and expenses increased by 1%
in 1994. 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
purchased, and the timing of recoveries of deferred purchased gas
costs. As previously mentioned, increases and decreases in
purchased gas costs are automatically passed through to the
Company's utility customers.
The Company follows the full-cost method of accounting for
the exploration, development, and acquisition of oil and gas
properties. DD&A is calculated using the units-of-production
method. The Company's annual gas and oil production, as well as
the amount of proved reserves owned by the Company and the costs
associated with adding those reserves, are all components of the
amortization calculation. DD&A increased 15% in 1994 due both to
an increase in gas and oil production and an increase in the
amortization rate. The margin between the Company's full cost
ceiling and the financial statement carrying value of the
Company's gas and oil properties was eroded substantially during
1994 as a result of very low average gas prices in effect at
December 31, 1994. Product prices, production rates, levels of
reserves, and the evaluation of unamortized costs all influence
the calculation of the ceiling. A significant decline in gas
prices from September 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 down slightly in 1994, as compared to
1993, due to lower average borrowings on the Company's revolving
credit facilities throughout most of the year, partially offset
by higher average interest rates. Borrowings under these
facilities were higher at year-end 1994, as compared to 1993,
primarily as a result of increased capital spending activity
during the fourth quarter of 1994.
The change in other income during 1994 and 1993 relates
primarily to the Company's share of operating losses incurred by
NOARK. The Company accounts for its 47.93% interest in the NOARK
partnership under the equity method of accounting. NOARK has
been operating below capacity and generating losses since it was
placed in service. The Company's share of the pre-tax loss for
NOARK included in other income was $2.8 million in 1994 and $1.8
million in 1993. Deliveries are currently being made by NOARK to
portions of AWG's distribution system, to Associated, and to the
interstate pipelines with which NOARK interconnects. In 1994,
NOARK had an average daily throughput of 82 million cubic feet of
gas per day ("MMcfd"), compared to 79 MMcfd in 1993, its first
full year of operation. NOARK has a total transportation
capacity of 141 MMcfd. AWG has contracted for 41 MMcfd of firm
capacity on NOARK under a ten-year transportation contract.
NOARK also has a five-year transportation contract with Vesta
Energy Company ("Vesta"), an independent marketer, to transport
50 MMcfd on a firm basis. The Company's exploration and
production segment was supplying 25 MMcfd of the volumes
transported by Vesta under that agreement. In late 1993, Vesta
filed suit against NOARK, the Company, and certain of its
affiliates, and, effective January 1, 1994, ceased transporting
gas under its contract with NOARK. The complaint and subsequent
filings seek rescission of both the transportation contract and a
contract to purchase gas from the Company's affiliates, along
with actual and punitive damages. The Company and NOARK believe
the suit is without merit and have filed counterclaims seeking
enforcement of the contracts and damages. The Company is
currently making its own sales arrangements and transporting
production through NOARK which previously had been purchased by
the marketer.
The APSC has established a maximum transportation rate of
approximately $.285 per dekatherm for NOARK based on its original
construction cost estimate of approximately $73 million. Due to
construction conditions and the addition of a compressor station,
the ultimate cost of the pipeline exceeded the original estimate
by approximately $30 million. NOARK competes primarily with two
interstate pipelines in its gathering area. One of those elected
to become an open access transporter subsequent to NOARK's start
of construction. That pipeline, which was recently sold, has not
offered firm transportation, but the increased availability of
interruptible transportation service has intensified the
competitive environment within which NOARK operates. As a result
of these developments, NOARK is currently incurring losses and
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 that determine the transportation rates NOARK can
charge. The Company and the other partners of NOARK are
currently investigating several options that could improve
NOARK's future financial prospects. However, the Company
believes that no writedown of its investment in NOARK is
appropriate at this time and that it will realize its investment
in NOARK over the life of the system.
The Company's effective income tax rate was 38.5% in 1994
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
1994 and 1993, net cash provided from operating activities
totaled $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 92% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt
retirements in 1994 and in excess of 100% in 1993.
Dividends paid to common shareholders in 1994 were $6.2
million, compared to $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. On an annual basis, the rate is equivalent to $.24 per
share. The dividend rates reflect the effect of a three-for-one
stock split distributed in 1993.
On February 22, 1995, the Board of Directors authorized the
repurchase of up to $30 million of the Company's common shares.
The Company repurchased 1,000,000 shares during the first nine
months of 1995, 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.
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 $76.9 million in 1994 and $59.2
million in 1993. In 1994, expenditures for the exploration and
production segment included $13.9 million for acquisitions of
reserves in place.
1994 1993
_______ _______
(in thousands)
Capital Expenditures
Exploration and production . . . . . . . . . . $55,449 $37,411
Gas distribution . . . . . . . . . . . . . . . 17,577 19,892
Other. . . . . . . . . . . . . . . . . . . . . 3,828 1,916
------- -------
Total . . . . . . . . . . . . . . . . . . . $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, finance improvements necessary due to normal
customer growth in its gas distribution segment, and explore and
develop existing gas and oil properties as well as generate new
drilling prospects.
Routine capital expenditures expected to be incurred in 1995
are approximately $75 million, consisting of $61 million for gas
and oil exploration, $13 million for gas distribution system
expenditures, and $1 million for general purposes. The
Company's 1995 capital expenditures are also expected to include
approximately $19 million of nonroutine spending, consisting of
$9 million for acquisitions of reserves in place (including
$3 million related to a producing property purchased in
connection with an exploration prospect), $5 million of seismic
expenditures under a joint venture program in south Louisiana,
$3 million for the construction and renovation of office and
operations facilities in the utility division and $2 million
for improvements to the utility's gas storage facilities. The
gas and oil expenditures include approximately $15 million for
exploratory drilling and approximately $18 million to continue
the development of the Company's acreage in the Arkoma Basin.
During 1994, the Company increased its emphasis on
acquisitions of producing properties and expects that effort to
continue as a supplement to its exploration and development
drilling programs. Such acquisitions may require capital
spending beyond that planned for routine purposes. The Company
plans to manage the debt portion of its capital structure over
time through its policy of adjusting its routine capital
spending, but expects to continue to use additional debt to
address extraordinary needs or opportunities, such as attractive
acquisitions of gas and oil properties. Additionally, the
Company may use its existing revolving credit facilities to meet
seasonal or short-term requirements related to its capital
expenditures.
Financing Requirements
Two floating rate revolving credit facilities provide the
Company access to $80.0 million of variable rate long-term
capital. Borrowings outstanding under these credit facilities
totaled $52.3 million at the end of 1994 and $31.0 million at the
end of 1993. The Company also had available short-term lines of
credit totaling $3.5 million at the end of 1994 and 1993.
The Company and an affiliate of the other general partner of
NOARK are required to severally guarantee the availability of
certain minimum cash balances to service NOARK's 9.7375% Senior
Secured Notes. These notes are held by a major insurance company
which also has a 20% limited partnership interest in NOARK. The
notes had a balance of $59.9 million at December 31, 1994, with
final maturity in 2009. The Company's share of the several
guarantee of available cash balances is 60%. NOARK also has an
unsecured long-term revolving credit agreement with a group of
banks which provides the partnership access to $30.0 million of
additional funds. Amounts outstanding under this credit
arrangement were $29.6 million at December 31, 1994, and $25.2
million at December 31, 1993. Amounts borrowed under the long-
term revolving credit agreement are severally guaranteed by the
Company and an affiliate of the other general partner. The
Company's share of this several guarantee is also 60%. In 1994,
the Company advanced $2.3 million to NOARK to fund its share of
debt service payments and to make the final payment of
construction retainage to the pipeline's main line contractor.
The Company expects to advance funds to NOARK totaling $4.5
million to $5.0 million during 1995 in connection with its
guarantees.
Under its existing debt agreements, the Company may not
issue long-term debt in excess of 65% of its total capital and
may not issue total debt in excess of 70% of its total capital.
To issue additional long-term debt, the Company must also have,
after giving effect to the debt to be issued, a ratio of earnings
to fixed charges of at least 1.50 or higher. At the end of 1994,
the capital structure consisted of 40.1% debt (excluding the
current portion of long-term debt and the Company's several
guarantee of NOARK's obligations) and 59.9% equity, with a ratio
of earnings to fixed charges of 3.6.
Working Capital
The Company maintains access to funds which may be needed to
meet seasonal requirements through the revolving and short-term
lines of credit described above. The Company had net working
capital of $8.9 million at the end of 1994, and $8.1 million at
the end of 1993. Current assets increased by 3% to $48.0 million
in 1994, while current liabilities increased 1% to $39.1 million.
The increase in current assets was due primarily to an increase
in the current portion of gas stored underground, reflecting the
value of stored gas expected to be utilized on an annual basis,
offset by a decrease in accounts receivable due to lower weather
related sales at year-end 1994. The increase in current
liabilities resulted primarily from an increase in the current
portion of long-term debt and an increase in accounts payable,
offset by a decrease in taxes payable. The increase in accounts
payable resulted primarily from the timing of payments of amounts
due. The decrease in taxes payable was due primarily to lower
taxable income and increased deductions for intangible drilling
costs. Intangible drilling costs are deductible currently for
tax purposes, but are capitalized and amortized over future
periods for financial reporting purposes.
DESCRIPTION OF NOTES
The Notes, which are a series of Debt Securities described
in the accompanying Prospectus, will be limited to $125,000,000
aggregate principal amount and will mature on December 1, 2005.
The following description of the particular terms of the Notes
supplements, and to the extent inconsistent therewith replaces,
the description of the general terms and provision of the Debt
Securities set forth in the accompanying Prospectus. Reference
should be made to the accompanying Prospectus for a detailed
summary of additional provisions of the Notes and of the
Indenture of the Company to The First National Bank of Chicago,
dated as of December 1, 1995 (the "Indenture"), under which the
Notes are issued. Whenever a defined term is referred to and not
herein defined, the definition thereof is contained in the
accompanying Prospectus or in the Indenture referred to therein.
Interest
Except as otherwise provided in the Indenture, the Notes
will bear interest from December 1, 1995 at the annual rate set
forth on the cover page of this Prospectus Supplement, payable
semi-annually on December 1 and June 1 of each year, beginning
June 1, 1996, to the persons in whose names the Notes are
registered at the close of business on the immediately preceding
November 15 and May 15, respectively.
Redemption
The Notes will not be redeemable prior to maturity and will
not be entitled to the benefits of any sinking fund.
Trustee
The Trustee for the Notes is The First National Bank of
Chicago.
Defeasance and Covenant Defeasance
The Company may elect under certain circumstances either (i)
to defease and be discharged from any and all obligations with
respect to the Notes or (ii) to be released from its obligations
with respect to certain covenants applicable to the Notes. See
"Description of Debt Securities -- Defeasance" in the
accompanying Prospectus.
Book-Entry System
The Notes initially will be represented by one or more
global securities (the "Global Securities") deposited with The
Depository Trust Company ("DTC") and registered in the name of a
nominee of DTC. Except as set forth below, the Notes will be
available for purchase in denominations of $1,000 and integral
multiples thereof in book-entry form only. The term "Depository"
refers to DTC or any successor depository.
DTC has advised the Company and Morgan Stanley & Co.
Incorporated, First Chicago Capital Markets, Inc., NationsBanc
Capital Markets, Inc. and Llama Company (the "Underwriters") as
follows: DTC is a limited-purpose trust company organized under
the laws of the State of New York, a "banking organization"
within the meaning of the New York Banking Law, a member of the
Federal Reserve System, a "clearing corporation" within the
meaning of the New York Uniform Commercial Code and a "clearing
agency" registered pursuant to the provisions of Section 17A of
the Exchange Act. DTC was created to hold securities of its
participating organizations ("DTC Participants") and to
facilitate the clearance and settlement of securities
transactions between DTC Participants through electronic book-
entry changes in accounts of the Participants, thereby
eliminating the need for physical movement of certificates. DTC
Participants include securities brokers and dealers (including
the Underwriters), brokers, banks, trust companies and clearing
corporations and may include certain other organizations.
Indirect access to the DTC system is also available to others,
such as banks, brokers, dealers and trust companies that clear
through or maintain a custodial relationship with a DTC
Participant, either directly or indirectly ("Indirect DTC
Participants").
Unless and until the Global Securities are exchanged in
whole or in part for individual certificates evidencing the Notes
represented thereby, such Global Securities may not be
transferred except as a whole by the Depository for such Global
Securities to a nominee of such Depository or by a nominee of
such Depository to such Depository or another nominee of such
Depository or by the Depository or any nominee of such Depository
to a successor Depository or any nominee of such successor
Depository.
Neither the Company, the Trustee, any paying agent nor the
registrar for the Notes will have any responsibility or liability
for any aspect of the records relating to or payments made on
account of beneficial ownership interests in the Notes
represented by such Global Securities or for maintaining,
supervising or reviewing any records relating to such beneficial
ownership interests.
Settlement for the Notes will be made by the Underwriters in
immediately available or same-day funds. Secondary trading on
long-term notes of corporate issuers is generally settled in
clearinghouse or next-day funds. In contrast, the Notes will
trade in the Depositary's Same-Day Funds Settlement System until
maturity, and secondary market trading activity in the Notes will
therefore be required by the Depositary to settle in same-day
funds. No assurance can be given as to the effect, if any, of
settlement in same-day funds on trading activity in the Notes.
UNDERWRITING
Subject to the terms and conditions contained in an
Underwriting Agreement dated the date hereof, the Company has
agreed to sell to each of the Underwriters named below,
severally, and each of the Underwriters has severally agreed to
purchase, the respective principal amount of Notes set forth
below.
Principal
Amount of
Name Notes
---- ---------
Morgan Stanley & Co. Incorporated . . . . . . . . . $ 40,000,000
First Chicago Capital Markets, Inc. . . . . . . . . 40,000,000
NationsBanc Capital Markets, Inc. . . . . . . . . . 40,000,000
Llama Company . . . . . . . . . . . . . . . . . . . 5,000,000
------------
Total. . . . . . . . . . . . . . . . . . . . . $125,000,000
============
The Underwriting Agreement provides that the obligations of
the several Underwriters to pay for and accept delivery of the
Notes are subject to the approval of certain legal matters by
their counsel and to certain other conditions. The Underwriters
are committed to take and pay for all the Notes if any are taken.
The Underwriters initially propose to offer the Notes
directly to the public at the public offering price set forth on
the cover page of this Prospectus Supplement and to certain
dealers at such price less a concession not in excess of .40% of
the principal amount of the Notes. The Underwriters may allow,
and such dealers may reallow, a concession not in excess of .25%
of the principal amount of the Notes to certain other dealers.
After the initial public offering, the public offering price and
such concessions may be changed by the Underwriters.
The Company does not intend to apply for listing of the
Notes on a national securities exchange. The Underwriters
presently intend to make a market in the Notes in the secondary
trading market. However, the Underwriters are not obligated to
make a market in the Notes and any such market making may be
discontinued at any time at the sole discretion of the
Underwriters. No assurance can be given as to the liquidity of,
or the trading markets for, the Notes.
The Company has agreed to indemnify the Underwriters against
certain liabilities, including liabilities under the Securities
Act of 1933, as amended.
The Underwriters and certain of their affiliates have from
time to time performed various investment banking and commercial
banking services for the Company and its subsidiaries, for which
compensation has been received. Affiliates of First Chicago Capital
Markets, Inc. and NationsBanc Capital Markets, Inc. are lenders
under the Company's revolving credit facilities. See "Use of
Proceeds".
LEGAL MATTERS
The validity of the Notes will be passed upon for the
Company by Cleary, Gottlieb, Steen & Hamilton, New York, New York
and for the Underwriters by Davis Polk & Wardwell, New York, New
York. Both of such firms will rely on the opinion of Jeffrey L.
Dangeau, Assistant Secretary of the Company, as to certain
matters of Arkansas law.
