<PAGE> 1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Fiscal Year Ended December 31, 1995
Commission File Number 1-3751
NORAM ENERGY CORP.
(Exact name of registrant as specified in its charter)
Delaware
(State or jurisdiction of incorporation or organization)
EMPLOYER IDENTIFICATION
(I.R.S. No. 72-0120530)
1600 SMITH, 32nd FLOOR, HOUSTON, TEXAS 77002
(Address of principal executive office)
(713) 654-5699
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of Each Exchange on Which Registered
Common Stock, $.625 par value New York Stock Exchange
Convertible Exchangeable Preferred New York Stock Exchange
Stock, Series A, Cumulative, $0.10 par value
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such report), and (2) has been subject to such
filing requirements for the past 90 days.
Yes x No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained
herein, and will not be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K.
-----
The aggregate market value of the voting stock held by non-affiliates:
$1,116,001,584 Common Stock, $.625 par value, based upon the closing sales
price on March 15, 1996 as reported on the New York Stock Exchange, using
beneficial ownership of stock rules adopted pursuant to Section 13 of the
Securities Exchange Act of 1934 and excluding stock owned by affiliates.
Indicate the number of shares outstanding of each of the issuer's classes of
Common Stock, as of the latest practicable date: 125,180,609 shares of
Common Stock, $.625 par value, as of March 15, 1996.
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of the NorAm Energy Corp. Annual Report to Stockholders for the
fiscal year ended December 31, 1995, are incorporated by reference in Parts I,
II and IV herein.
2. NorAm Energy Corp. definitive Proxy Statement respecting the Annual Meeting
of Stockholders to be held on May 14, 1996, to be filed pursuant to Regulation
14A under the Securities Exchange Act of 1934 (to the extent set forth in Items
10, 11, 12 and 13 of Part III of this report) is incorporated by reference.
The Exhibits included in this report are indexed on pages 30 through 32.
<PAGE> 2
NORAM ENERGY CORP. AND SUBSIDIARIES
PART I
ITEM 1. BUSINESS.
NorAm Energy Corp. (the "Company") was incorporated in 1928 under the
laws of the State of Delaware and is principally engaged in the distribution
and transmission of natural gas including gathering, marketing and storage of
natural gas. The revenue, operating profit and identifiable assets of the
Company's natural gas segment exceed 90% of the respective totals for the
Company. Accordingly, the Company is not required to report on a "segment"
basis, although the Company is organized into, and the following business
description focuses on, the five operating units described below. Previously,
the Company segregated its business activities into "Natural Gas Distribution"
and "Natural Gas Pipeline" when reporting results of operations. In
recognition of changes within the natural gas industry and the manner in which
the Company manages its portfolio of businesses, the Company has further broken
down its results of operations into (1) Natural Gas Distribution; (2)
Interstate Pipelines; (3) Wholesale Energy Marketing; (4) Retail Energy
Marketing; and (5) Natural Gas Gathering. The business units now referred to
as Interstate Pipelines, Wholesale Energy Marketing and Natural Gas Gathering
have also been referred to from time to time as the NorAm Trading and
Transportation Group or the Trading and Transportation Group. The business
unit referred to herein as Retail Energy Marketing includes a number of
activities previously conducted as part of Natural Gas Distribution. Set forth
below is the Operating Income (Loss) by the five Business Units described above
as well as Corporate. Following that table is a reconciliation of operating
income reported in accordance with the current organizational breakdown with
operating income reported in accordance with the previous organizational
breakdown.
<PAGE> 3
OPERATING INCOME (LOSS) BY BUSINESS UNIT(1)
<TABLE>
<CAPTION>
(MILLIONS OF DOLLARS) 1995 1994 1993
--------------------- ------- ------- -------
<S> <C> <C> <C>
Natural Gas Distribution $ 158.0 $ 145.5 $ 160.1
Interstate Pipelines 103.8 105.4 100.6
Wholesale Energy Marketing 4.2 (3.0) (22.4)
Natural Gas Gathering 8.7 5.6 - (2)
Retail Energy Marketing 22.2 18.4 15.1
Corporate and Other(3) (9.6) (7.0) (16.9)
------- ------- -------
Subtotal 287.3 264.9 236.5
Louisiana Intrastate Gas Corp.(4) - - 5.6
Contract Termination Charge(5) - - (34.2)
-----------------------------------------------
Consolidated $ 287.3 $ 264.9 $ 207.9
===============================================
</TABLE>
(1) To the extent practicable, prior year results of operations have been
reclassified to conform to the current business unit presentation,
although such results are not necessarily indicative of the results
which would have been achieved had the revised business unit structure
been in effect during those periods. In general, transactions among
business units are recorded at market prices and material affiliate
transactions within business units have been eliminated.
(2) Included with "Interstate Pipelines" in 1993.
(3) Includes amortization of goodwill, see Note 1 of Notes to Consolidated
Financial Statements included in the Company's 1995 Annual Report to
Stockholders.
(4) See "Interstate Pipelines" following.
(5) In December 1993, the Company completed a comprehensive settlement
agreement ("the Settlement") with certain subsidiaries of Samson
Investment Company, terminating or modifying a number of outstanding
contractual arrangements. The Settlement resulted in a $34.2 million
pre-tax charge to earnings, set forth in the Company's Statement of
Consolidated Income for 1993 as "Contract Termination Charge".
-2-
<PAGE> 4
OPERATING INCOME (LOSS) BY BUSINESS UNIT
RECONCILIATION TO PREVIOUS FORMAT
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
Natural Wholesale Natural Retail
Gas Interstate Energy Gas Energy Corporate
1995 Distribution Pipelines Marketing Gathering Marketing & Other
---- ------------ --------- --------- --------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
PREVIOUS FORMAT $ 178.0 $ 116.6 - - - $ (7.3)
Distribution (21.5) - - - $ 21.5 -
Pipeline - (12.8) $ 4.2 $ 8.7 - (0.1)
Corporate & Other 1.5 - - - 0.7 (2.2)
------- ------- ------ ------ -------- --------
CURRENT REPORTING $ 158.0 $ 103.8 $ 4.2 $ 8.7 $ 22.2 $ (9.6)
======= ======= ====== ====== ======== ========
Consolidated $ 287.3
========
1994
----
PREVIOUS FORMAT $ 163.2 $ 108.1 - - - $ (5.3)
Distribution (17.5) - - - $ 17.5 -
Pipeline - (2.7) $ (3.0) $ 5.6 - 0.1
Corporate & Other (0.2) - - - 0.9 (1.8)
------- ------- ------ ------ -------- --------
CURRENT REPORTING $ 145.5 $ 105.4 $ (3.0) $ 5.6 $ 18.4 $ (7.0)
======= ======= ====== ====== ======== ========
Consolidated $ 264.9
========
1993
----
PREVIOUS FORMAT $ 174.8 $ 78.2 - - $ (17.4)
Distribution (15.3) - - $ 15.3 -
Pipeline - 22.4 $(22.4) - -
Corporate & Other 0.6 - - (0.2) 0.5
------- ------- ------ ------- --------
CURRENT REPORTING $ 160.1 $ 100.6 $(22.4) $ 15.1 $ (16.9)
======= ======= ====== ======== ========
$ 236.5
Contract Termination Charge (34.2)
Louisiana Intrastate Gas Corporation 5.6
Consolidated --------
$ 207.9
========
</TABLE>
See the separate discussions for each Business Unit for operating revenue and
throughput information.
The Company also is evaluating opportunities for international
investment, and the Company's efforts thus far have focused on opportunities
emerging in Latin America due to privatization initiatives currently underway
in a number of countries, as well as broad-based efforts to encourage
international investment.
Since the Company's December 31, 1992 sale of its oil and gas
exploration and production business, the Company's operations principally have
been rate regulated. The operations of the Natural Gas Distribution and
Interstate Pipelines business units are subject to rate regulation, while the
operations of Wholesale Energy Marketing, Retail Energy Marketing and Natural
Gas Gathering are not generally subject to direct regulation as to the rates
which may be charged.
-3-
<PAGE> 5
NATURAL GAS DISTRIBUTION.
The Company's natural gas distribution business is conducted through
its three divisions, Arkla, Entex and Minnegasco, and their affiliates.
Historically, the Company's Natural Gas Distribution business included
substantially all the activities conducted by these three divisions. In
recognition of the fact that certain of these activities are not subject to
traditional cost-of-service rate regulation and, as such, have different risk
profiles and return potentials, and in order to concentrate its
similarly-targeted marketing efforts in a single business unit, certain
large-volume marketing activities, including the provision of services to a
number of customers previously reported with "Natural Gas Distribution", have
been aggregated and separately reported as "Retail Energy Marketing". Thus,
Natural Gas Distribution, as presently constituted consists principally of
natural gas sales to and natural gas transportation for residential, commercial
and a limited number of industrial customers, substantially all of which are
located behind the "city gate" and subject to traditional cost-of-service rate
regulation.
Arkla provides service in approximately 613 communities in the states
of Arkansas, Louisiana, Oklahoma and Texas. The largest communities served by
Arkla are the metropolitan areas of Little Rock, Arkansas, and Shreveport,
Louisiana. In 1995, approximately 73% of Arkla's total throughput was composed
of sales of gas at retail and approximately 27% was attributable to
transportation services. For the same period, in excess of 95% of Arkla's
supplies were obtained from NorAm Gas Transmission Company ("NGT") and
Mississippi River Transmission Corporation ("MRT"), or through transportation
agreements with NorAm Energy Services, Inc. ("NES"). In September of 1994,
Arkla and NGT, respectively, completed the sale of its Kansas distribution
properties and certain related pipeline assets of NGT, located in Kansas, to
UtiliCorp United Inc. ("UtiliCorp", an affiliate of Peoples Natural Gas) for
approximately $23 million in cash. This sale terminated the Company's
distribution operations in Kansas.
Entex provides service in approximately 502 communities in the states
of Texas, Louisiana and Mississippi. The largest community served by Entex is
the metropolitan area of Houston, Texas. In 1995, approximately 95% of Entex's
total throughput was composed of sales of gas at retail and approximately 5%
was attributable to transportation services. For the same period, Entex's
principal suppliers of gas were Enron Capital & Trade Resources, MidCon Texas
Pipeline Co., Koch Gateway Pipeline Company, and certain affiliates of each
such company. No other supplier accounted for more than 10% of Entex's
purchases.
During 1995, Minnegasco provided service in approximately 243
communities in Minnesota. The largest community served by Minnegasco is
Minneapolis, Minnesota and its suburbs. In 1995, approximately 92% of
Minnegasco's total throughput was composed of sales of gas at retail and
approximately 8% was attributable to transportation services. For the same
period, Minnegasco's principal pipeline service providers were Northern Natural
Gas Company, Viking Gas Transmission Company, Minnesota Intrastate Pipeline and
Natural Gas Pipeline Company of America. For the same period, Minnegasco's
principal suppliers of gas were Pan Alberta Gas, NES, Coastal Gas Marketing and
Western Gas Marketing. No other supplier of natural gas accounted for more
than 10% of Minnegasco's purchases. In February 1993, Minnegasco completed the
sale of its Nebraska distribution system to UtiliCorp for
-4-
<PAGE> 6
$75.3 million in cash plus an additional payment of $17.8 million for net
working capital transferred. In August of 1993, Minnegasco completed the
exchange of its South Dakota distribution properties plus $38 million in cash
for the Minnesota distribution properties of Midwest Gas, a division of Midwest
Power System Inc. ("Midwest"). The UtiliCorp and Midwest transactions
terminated Minnegasco's distribution operations outside of Minnesota.
The following table summarizes by state the number of communities and
the estimated number of customers served by the Company as of December 31,
1995:
SERVICE AREA COMMUNITIES NUMBER OF
LOCATIONS SERVED CUSTOMERS
------------ ----------- ---------
Texas 365 1,203,712
Minnesota 243 626,556
Arkansas 383 425,423
Louisiana 179 262,480
Mississippi 91 118,520
Oklahoma 97 114,794
----- ---------
1,358 2,751,485
===== =========
-5-
<PAGE> 7
The following table summarizes the estimated number of customers
served by each of the divisions as of December 31, 1995 and 1994:
DECEMBER 31,
------------
CUSTOMERS BY DIVISION 1995 1994
--------------------- --------- ---------
Entex 1,394,292 1,375,393
Arkla 730,637 721,185
Minnegasco 626,556 612,254
--------- ---------
Total 2,751,485 2,708,832
========= =========
The Company's approximately 54,982 linear miles of gas distribution
mains vary in size from one-half inch to 24 inches. Generally, in each of the
cities, towns and rural areas it serves, the Company owns the underground gas
mains and service lines, metering and regulating equipment located on
customers' premises, and the district regulating equipment necessary for
pressure maintenance. With a few exceptions, the measuring stations at which
the Company receives gas from its suppliers are owned, operated and maintained
by others, and the distribution facilities of the Company begin at the
outlet of the measuring equipment. These facilities include odorizing
equipment usually located on the land owned by suppliers and district regulator
installations, in most cases located on small parcels of land which are leased
or owned by the Company.
-6-
<PAGE> 8
Consolidated revenue, throughput and customer data of the distribution
divisions are as follows:
NATURAL GAS DISTRIBUTION
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
(IN MILLIONS OF DOLLARS)
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
OPERATING REVENUES
------------------
Sales $ 1,678.6 $ 1,769.9 $ 1,865.7
Transportation 19.1 17.6 18.7
Other 21.7 23.1 22.6
--------- --------- ---------
Total $ 1,719.4 $ 1,810.6 $ 1,907.0
========= ========= =========
YEAR ENDED DECEMBER 31,
------------------------------
(IN BILLIONS OF CUBIC FEET)
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
THROUGHPUT
----------
Sales
Residential 183.3 180.0 193.6
Commercial 123.3 119.1 126.7
Industrial 52.4 53.4 49.7
Transportation 49.4 44.9 52.2
----- ----- -----
Total 408.4 397.4 422.2
===== ===== =====
YEAR ENDED DECEMBER 31,
------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
AVERAGE NUMBER OF CUSTOMERS
---------------------------
Residential 2,495,022 2,458,520 2,433,598
Commercial 224,946 222,193 222,523
Industrial 2,338 2,462 2,509
--------- --------- ---------
Total 2,722,306 2,683,175 2,658,630
========= ========= =========
</TABLE>
-7-
<PAGE> 9
In almost all of the communities in which it provides service, the
city or other relevant governmental body has granted the Company a franchise to
serve, and its service is subject to the terms and conditions of the franchise.
In most instances the Company's franchise is not exclusive. The rates at which
the Company provides service at retail to its residential and commercial
customers are, in all instances, subject to regulation by the relevant state
public service commissions and, in Texas, also by municipalities. The services
provided by the Company to its industrial customers are largely unregulated in
Texas and Louisiana, and are subject to regulatory supervision of differing
degrees in each of the other states. See "Regulation."
INTERSTATE PIPELINES.
The Company's interstate natural gas pipeline business (collectively
referred to as "Pipeline") is conducted principally through NGT and MRT, two
wholly-owned subsidiaries of the Company together with certain subsidiaries and
affiliates. The Company's natural gas gathering activities subsequent to 1993
and wholesale energy marketing activities for all periods, previously included
with Pipeline, are now separately discussed, see "Wholesale Energy Marketing"
and "Natural Gas Gathering" elsewhere herein.
In March 1993, the Company transferred assets, liabilities and service
obligations of Arkla Energy Resources, formerly a division of the Company, into
a then newly-formed wholly-owned subsidiary of the Company, now called NGT,
pursuant to an order from the Federal Energy Regulatory Commission ("FERC")
approving the transfer. As a result of this transfer of assets, liabilities and
service obligations, the FERC now has sole jurisdiction over NGT's interstate
pipeline business, including transportation services and certain of NGT's
transactions with affiliates of the Company, which historically were subject to
both FERC and state regulatory oversight. See "Regulation."
On June 30, 1993, the Company completed the sale of its intrastate
pipeline business as conducted by Louisiana Intrastate Gas Corporation and its
subsidiaries, LIG Chemical Company, LIG Liquids Corporation and Tuscaloosa
Pipeline (the "LIG Group"), to a subsidiary of Equitable Resources, Inc.
("Equitable") for $191 million in cash. The Company agreed to indemnify
Equitable against certain exposures, for which the Company has established
reserves equal to anticipated claims under the indemnity. The Company acquired
the LIG Group in July of 1989. The LIG Group operated a natural gas pipeline
system located wholly within Louisiana.
In February 1996, Pipeline announced a reorganization plan which
resulted in the elimination of a total of approximately 275 positions at NGT
and MRT. The reorganization plan is intended to allow Pipeline to operate more
efficiently, improving its ability to compete in its market areas. The Company
expects to record a first-quarter 1996 charge of less than $20 million
associated with the reorganization plan, which amount is expected to be
substantially offset by the associated cost savings during 1996.
-8-
<PAGE> 10
NGT owns and operates a natural gas pipeline system located in
portions of Arkansas, Louisiana, Mississippi, Missouri, Kansas, Oklahoma,
Tennessee and Texas. As described above under "Natural Gas Distribution",
effective September 30, 1994, NGT sold to UtiliCorp certain of its pipeline
assets in Kansas. At December 31, 1995 the NGT system consisted of
approximately 6,400 miles of transmission lines. The NGT pipeline system
extends generally in an easterly direction from the Anadarko Basin area of the
Texas Panhandle and western Oklahoma through the Arkoma Basin area of eastern
Oklahoma and Arkansas to the Mississippi River. Additional pipelines extend
from east Texas to north Louisiana and central Arkansas, and from the mainline
system in Oklahoma and Arkansas to south central Kansas and southwest Missouri.
In its system, NGT operates various compressor facilities related to its gas
transmission business. NGT's peak day gas handled during the 1995/96 heating
season was approximately 2.40 billion cubic feet ("Bcf"). NGT , on behalf of
various shippers, transports and delivers gas to distributors for resale for
ultimate public consumption, to industrial customers for their own use and
consumption, and to third party pipeline interconnects located in the states of
Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and
Texas. In 1995 NGT's throughput totaled 630.1 million MMBtu. Approximately
17% of the total throughput was attributable to services provided to Arkla,
and 17% was attributable to gas marketed by NES to other parties. No other
customer or supplier accounted for more than 10% of NGT's throughput.
The MRT system consists of approximately 2,200 miles of pipeline
serving principally the greater St. Louis area in Missouri and Illinois. This
pipeline system includes the "Main Line System," the "East Line," and the "West
Line." The Main Line System includes three transmission lines extending
approximately 435 miles from Perryville, Louisiana, to the greater St. Louis
area. The East Line, also a main transmission line, extends approximately 94
miles from southwestern Illinois to St. Louis. The West Line extends
approximately 140 miles from east Texas to Perryville, Louisiana. The system
also incudes various other branch, lateral, transmission and gathering lines
and compressor stations. During 1995, MRT's throughput totaled 395.1 million
MMBtu. Approximately half of MRT's total 1995 volumes were delivered to its
traditional markets along its system in Missouri, Illinois and Arkansas with
the remaining volumes delivered to off-system customers. MRT's peak day
deliveries during the 1995/96 heating season to its traditional market area
customers were approximately one million MMBtu. MRT's largest customer is
Laclede Gas Company, which serves metropolitan St. Louis and to which MRT
provides service under several long-term firm transportation and storage
agreements and an agency agreement. The FERC has jurisdiction over MRT with
regard to its interstate pipeline business. See "Regulation."
The Company owns and operates seven gas storage fields. Four storage
fields are associated with NGT's pipeline and have a combined maximum
deliverability of approximately 665 million cubic feet ("mmcf") per day and a
working gas capacity of approximately 22.8 Bcf. NGT also owns a 1/12 interest
in Koch Gateway Pipeline Company's Bistineau storage field which provides an
additional 100 mmcf per day of deliverability and additional working gas
capacity of 8 Bcf. The two largest NGT storage fields are located in Oklahoma:
the Ada field - capable of delivering approximately 330 mmcf per day, and the
Chiles Dome field - capable of delivering 265 mmcf per day. The other NGT
storage fields, Ruston and Collinson, are located near Ruston, La. and
Winfield, Kansas. However, the Collinson storage field is scheduled for
abandonment in 1996. Three storage fields are associated with MRT's pipeline
and have a maximum aggregate deliverability of approximately 580 mmcf per
-9-
<PAGE> 11
day and a working gas capacity of approximately 31 Bcf. Most of MRT's storage
capacity is located in two fields in north central Louisiana, near Ruston.
MRT's other storage field is located at St. Jacob, Illinois off of MRT's East
Line. During 1995, all of MRT's storage capacity was subscribed on a firm
basis by its customers, who had contracted for the capacity as a result of
MRT's FERC Order 636 restructuring proceeding.
As stated above, the Company sold the LIG Group to a subsidiary of
Equitable Resources in June, 1993. As a result, LIG's results of operations
have been excluded from the following data, although this disposition did not
qualify for presentation as "discontinued operations" in the Company's
Consolidated Financial Statements. LIG's operating income was $5.6 million for
the six months ended June 30, 1993 and total throughput for the same period was
103.4 million MMBtu.
Consolidated throughput and revenue data for Pipeline is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
THROUGHPUT (million MMBtu)
Sales 79.5 63.2 115.1
Transportation 974.3 831.8 780.1
FERC Order 636 (1) Elimination (77.5) (59.9) (24.2)
------ ------ ------
Total 976.3 835.1 871.0
====== ====== ======
REVENUES (in millions of dollars)
Sales $100.8 $162.4 $451.3
Transportation 245.9 238.2 151.4
------ ------ ------
Total $346.7 $400.6 $602.7
====== ====== ======
</TABLE>
(1) When sold volumes are also transported by Pipeline, the throughput
statistics will include the same physical volumes in both the sales
and transportation categories, requiring an elimination to prevent the
overstatement of actual total throughput. No elimination is made for
volumes of 196.6 million MMBtu, 145.8 million MMBtu and 158.2 million
MMBtu in 1995, 1994 and 1993, respectively, which were transported on
both the NGT and MRT systems.
During the 1980s, the Company, as most other pipelines, was compelled
to resolve a number of significant disputes with its suppliers under contracts
which allegedly required the Company to take or, if not taken pay for,
quantities of gas in excess of its available sales markets and/or at prices
generally above the levels required by such markets. These disputes, generally
referred to as "take-or-pay" claims, have been resolved in a number of ways,
including both buy-out/buy-downs and payments for gas in advance of its
delivery. In the third quarter of 1989, the Company recorded a pre-tax Special
Charge of $269 million related
-10-
<PAGE> 12
to these claims. The amount shown as "Gas Purchased in Advance of Delivery" in
the Company's Consolidated Balance Sheet and the component of "Investments and
Other Assets" bearing the same caption (See Note 1 of Notes to Consolidated
Financial Statements included in the Company's 1995 Annual Report to
Stockholders) represents, in substantial part, amounts paid to suppliers in
conjunction with the above referenced settlements. These prepayments for gas
were made at varying prices but have been reduced to their estimated net
realizable value (which approximates fair value) and, to the extent that the
Company is unable to realize at least this amount through sale of the gas as
delivered over the life of these agreements, its earnings will be adversely
affected, although such impact is not expected to be material.
In addition, the Company's Consolidated Balance Sheet includes an
accrual representing its estimate of the amount it will be required to pay in
settlement of all remaining claims, including those not yet asserted. While
the vast majority of such claims have been settled, the Company is committed,
under certain of these settlements, to make additional payments, expects that
other such claims may be asserted and that amounts may be expended in
settlement of such claims. The Company currently expects that the amount of
such settlements if any, in excess of existing reserves will not be material.
The Company is committed under certain agreements to purchase certain
quantities of gas in the future. At December 31, 1995, the Company had the
following gas take commitments under its agreements which are not variable-
market-based priced:
<TABLE>
<CAPTION>
VOLUME VALUE
(MILLIONS OF ($ IN PRICE
MMBTU) MILLIONS) ($/MMBTU)
------------ --------- ---------
<S> <C> <C> <C>
1996 17.8 $40.5 $2.27
1997 15.6 35.4 2.27
1998 12.0 26.4 2.19
1999 6.2 14.4 2.33
Beyond 1999 1.0 $ 3.6 $3.47
</TABLE>
-11-
<PAGE> 13
At December 31, 1995, the Company had the following gas take
commitments under its agreements which are variable-market-based priced, valued
using an average spot price over the delivery period of approximately
$2.13/MMBtu:
<TABLE>
<CAPTION>
VOLUME VALUE AVERAGE
(MILLIONS OF ($ IN PRICE
MMBTU) MILLIONS) ($/MMBTU)
------------ --------- --------
<S> <C> <C> <C>
1996 157.2* $350.6 $2.23
1997 9.4 19.5 2.07
1998 5.0 10.1 2.04
1999 4.3 9.1 2.11
Beyond 1999 3.7 $ 8.0 $2.18
</TABLE>
* Includes approximately 45.4 million MMBtu of gas subject to
3 - 6 month term purchase agreements at NES which, in general,
are matched with sale agreements with similar terms.
In order to mitigate the risk from market fluctuations in the price of
natural gas and transportation during the terms of these commitments, the
Company enters into futures contracts, swaps and options, (see Notes 1 and 8 of
Notes to Consolidated Financial Statements included in the Company's 1995
Annual Report to Stockholders). In no case are these derivatives held for
trading purposes. To the extent that the Company expects that these
commitments will result in losses over the contract term, the Company has
established reserves equal to such expected losses.
WHOLESALE ENERGY MARKETING.
The Company's marketing of natural gas and risk management services to
natural gas resellers and certain large volume industrial consumers is
principally conducted by NES, together with certain affiliates. NES,
previously reported as a part of Pipeline, historically has operated primarily
in those states served by the NGT and MRT systems but recently has had
significant sales in various other states as it seeks to extend its activities
throughout North America. In addition, in recent periods, NES has begun to
market electricity in wholesale markets.
NES markets gas under daily, baseload and term agreements which
include either market sensitive or fixed pricing provisions. Fixed priced
sales or purchase contracts are hedged using gas futures contracts or other
derivative financial instruments. See Notes 1 and 8 of Notes to the Company's
Consolidated Financial Statements included in the Company's 1995 Annual Report
to Stockholders. NES gas supplies are purchased from others on both a daily
and term basis. Most gas supplies are purchased based on market sensitive
pricing. Gas sales for 1995 were approximately 513 million MMBtu of which
approximately 85.2% was to unaffiliated parties. Customers are located both on
the NGT system and other pipelines. Gas is transported to customers using both
firm and interruptible transportation. Sales and services provided by NES are
generally not subject to any form of rate regulation.
-12-
<PAGE> 14
RETAIL ENERGY MARKETING.
The Company's marketing of natural gas and related services to those
industrial and commercial customers located behind the "city gate" of local gas
distribution companies but not utilizing traditional "bundled" utility service,
as well as certain industrial customers served by third-party pipelines on
which the Company holds capacity, is principally carried out by NorAm Energy
Management, Inc., together with certain affiliates (collectively, "NEM").
Certain of NEM's activities, while not subject to traditional cost-of-service
rate determination, are subject to the jurisdiction of various regulatory
bodies as to the allocation of joint costs between such activities and certain
of the company's regulated activities. This recently-formed business unit
includes a number of activities previously included with Distribution (see
"Natural Gas Distribution" elsewhere herein) and will execute the Company's
plan for serving these markets more coherently and effectively. NEM had sales
to five chemical facilities, operated by its largest customer and owned by a
total of five customers, which collectively represented approximately 38.3 Bcf
(22.6%), 11.9 Bcf (10.2%) and 7.0 Bcf(8.6%) of NEM's total gas sales volumes of
169.7 Bcf, 116.6 Bcf and 81.7 Bcf in 1995, 1994 and 1993, respectively.
NATURAL GAS GATHERING.
On February 1, 1995, pursuant to a "spindown" order from the FERC, the
Company transferred the natural gas gathering assets of NGT into the Company's
wholly-owned subsidiary, NorAm Field Services Corp. ("NFS"). These assets
consist principally of approximately 3,500 miles of gathering pipelines which
collect gas from more than 200 separate systems located in major producing
fields in Oklahoma, Louisiana, Arkansas and Texas. NFS is not generally
subject to cost-of-service regulation, although the spindown order
required that it offer to continue any pre-existing gathering services
generally under the terms of NGT's tariff, including the applicable stated
maximum gathering rate of $0.1417 per MMBtu for a two-year period (the "Default
Contract"), except to the extent that separate terms and conditions have been
negotiated. While various parties, including NFS, have appealed certain of the
FERC's findings and the case is pending before the D.C. Circuit Court of
Appeals, if the Default Contract provisions are not reversed in the interim,
NFS will be unable to realize the full market value for certain of its services
until February 1, 1997. The Company expects that efforts will be made in
certain states to enact legislation to regulate gathering rates and services
but the Company currently expects that any such efforts will be successful only
to the extent of providing for complaint-type proceedings alleging undue
discrimination or similar "light-handed" regulatory approaches. Natural Gas
Gathering also includes Arkla Chemical Company which performs gas processing,
liquids extraction and marketing activities, generally in conjunction with
certain of NFS's gathering activities. In the future, the majority of NFS's
gas processing activities will
-13-
<PAGE> 15
be conducted by Waskom Gas Processing Company, a joint venture of NFS and NGC
Corp. (an affiliate of Natural Gas Clearinghouse).
MARKET FACTORS.
The Company's business is generally affected by a number of market
factors, including competition, seasonality and the general economic climate.
Increasingly, the activities of the Company's Interstate Pipelines, Wholesale
Energy Marketing and Retail Energy Marketing units are most significantly
affected by national trends in these areas. On the other hand, the results of
the Company's Natural Gas Distribution units continue to be influenced most
significantly by local trends in these factors.
Historically, competition in the sale and transportation of natural
gas was limited due to the pervasive nature of the regulation of the industry
and the long-term nature of the service obligations assumed by its
participants. As a result, the Company's results of operations were largely
affected by local factors, including the effects of local regulation. Over the
past few years, however, regulatory and economic developments have
significantly reduced the influence of such factors, particularly with respect
to the Company's Interstate Pipelines, Wholesale Energy Marketing and Retail
Energy Marketing operations. At the federal level, regulations governing
natural gas transmission and marketing have been redesigned in order to promote
intense competition between natural gas transporters and marketers. From an
economic perspective, in recent years the energy industry, including the
natural gas industry, has been characterized by a surplus of product
deliverability (and, in the case of natural gas transportation in certain
locations during certain seasons, a surplus of capacity), which also has
increased the level of competition.
Currently, the Company generally faces competition in all aspects of
its operations, both from other companies engaged in the natural gas business
and from companies providing other energy products. This has an effect both on
the quantity of the services sold by the Company and the prices it receives.
At all levels of the industry in which the Company is engaged, competition
generally occurs on the basis of price, the ability to meet individual customer
requirements, access to supplies and markets and reliability. In the current
environment, the ability of the Company to respond to this competition is tied
directly to its ability to maintain operational flexibility, achieve low
operating costs and maintain continued access to reliable sources of
competitively priced gas and a broad range of gas markets.
These developments have had the effect of increasing the number of
competitors and competitive options faced by the Company. As a consequence,
changes in the market for natural gas and gas transportation services at the
national level increasingly influence the demand and prices paid for the
natural gas and gas transportation services offered by the Company.
Additionally, to the extent that the customers served by those units are
relatively large volume customers using gas to meet industrial or electric
power generation requirements, the Company faces significant competition from
fuel oil, waste products used as a source of fuel for the generation of process
heat or steam, energy conservation products, and, with respect to electric
generation customers, low cost energy available to such customers from other
electric generators.
-14-
<PAGE> 16
Largely as a result of increasing competition, the Company
discontinued the application of Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation"
("SFAS 71") to NGT's transactions and balances in 1992, see Note 1 of
Notes to Consolidated Financial Statements included in the Company's
1995 Annual Report to Stockholders. These trends in competition are
expected to continue, although not necessarily at the same rate as in the past.
The Company's distribution units also face competition. As with
customers served by the Company's transmission and marketing units, over the
last few years the Company's small industrial and large commercial customers
served through its distribution units increasingly have been the target of
other companies engaged in the natural gas business seeking to sell gas
directly or transport third-party gas to customers currently served through the
Company's distribution units. In some cases, these other companies seek to
provide such service through newly constructed facilities, thereby bypassing
the facilities installed by the Company to serve such customers. The Company
has met such competition by adopting new programs which, in some instances,
have provided its competitors with access to its sales customers, but through
the use of the Company's facilities. The Company also faces competition with
respect to such customers from fuel oil, electricity, energy conservation
products, and in certain instances, liquified petroleum gas.
While with certain limited exceptions, the Company currently is not in
direct competition with any other distributors of natural gas with respect to
its existing small commercial and residential customers, the Company
nevertheless faces significant competition for such customers from electric
utilities and providers of energy conservation products. Moreover, while the
Company currently holds franchises in almost all of the communities which it
serves, such franchises generally are not by their terms exclusive and
competition has been experienced in certain instances as the Company has sought
to extend service from existing service areas to geographically adjacent areas.
In addition to competition, the Company's business is also affected at
all levels by the seasonality of weather and general economic conditions.
Because one of the significant markets for natural gas is use in space heating,
demand for natural gas and gas transportation services is generally seasonal in
nature. The Company has obtained rate design changes in its regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to changes in natural gas consumption prompted by seasonal weather
patterns. Additionally, in recent years, the Company's transmission and
marketing units have increased the volume of their off-season sales by
expanding their markets to include additional industrial users of gas,
gas-fired electric generators, and customers seeking gas in the summer to fill
storage. Even with increased summer demand, however, the price of natural gas
and gas transportation services continues to be seasonal in nature, with prices
generally significantly lower in the summer than in winter. While the
Company's distribution units also have sought to increase the level of their
off-season sales, the opportunity to do so within their historic service areas
is limited.
General economic conditions also significantly influence the demand
for gas. The national demand for gas has increased in recent years and
currently is expected to continue to increase in future years. This, in turn,
at certain times and in certain market segments has influenced the price for
natural gas and gas transportation services. However, this increased
-15-
<PAGE> 17
demand for gas is somewhat tied to the overall state of economic activity and
there can be no assurance that current levels of demand will continue or that,
if they continue, they will necessarily have a significant effect on the price
of or demand for the Company's products or services. From the perspective of
the Company's local distribution units, the economic conditions prevailing in
the Company's historic service areas continue to have a significant effect on
the results of their operations. Unlike the Company's transmission and
marketing units, the local distribution units are not readily able to redirect
their activities to other markets when the demand for gas in their local
service areas declines. In recent years, the level of economic activity in the
areas served by these units has remained relatively stable.
REGULATION.
The Company's business operations are significantly affected by
regulation. This regulation occurs at all levels -- federal, state and local
- -- and has the effect, among other things, of: (i) requiring that the Company
seek and obtain certain approvals before it may undertake certain acts, (ii)
regulating the level of rates which the Company may charge for certain of its
services and products, and (iii) imposing certain conditions on the Company's
conduct of its business.
The Company is significantly affected by the regulations of the FERC.
FERC Order 636 is currently the subject of an appeal to the U.S. Court of
Appeals, D.C. Circuit. Until such time as this appeal is resolved, there will
continue to be some uncertainty in the natural gas industry respecting the full
effect of FERC Order 636.
The changes to the industry brought about by FERC Order 636 also have
affected and will continue to affect the business environment in which the
Company's local distribution units operate in those geographical areas where
gas supplies are delivered on interstate pipelines. The impact is less
pronounced in the case of Entex, where a significant portion of supplies are
delivered on intrastate pipelines. FERC Order 636 has increased, and in some
cases likely will continue to increase, the number and diversity of potential
suppliers and products available to meet the supply needs of each unit. In
addition, the requirement that pipelines "unbundle" their services permits the
Company's distribution units to avoid the purchase -- and, thus, the cost -- of
services which they do not require. On the other hand, the elimination of the
right of local distribution companies to require service from interstate
pipelines in the absence of a contract will expose local distributors to an
increased risk of supply disruption and the potential for increased review from
some state regulatory agencies. In addition, the ability of holders of firm
transportation capacity entitlements to assign their capacity rights to other
parties, coupled with the ability of those holders to change the points at
which that capacity is used, likely will increase the competitive pressures
faced by local distributors. This is because such provisions will expand the
incentives for and capabilities of third parties to build new facilities from
nearby pipelines which bypass the existing facilities of the incumbent local
distributors.
Under FERC Order 636, the Company's distribution units have incurred
increased costs as a result of the recovery by their pipeline suppliers through
their rates of those pipelines' FERC Order 636-related "transition costs". In
some cases, the recovery of
-16-
<PAGE> 18
transition costs remains unresolved. In addition, the ratemaking provisions of
FERC Order 636 have increased the fixed costs incurred by distribution
companies in reserving firm transportation capacity on their pipeline
suppliers. While the Company's distribution units generally expect to be able
to recover all of these increased costs in their retail rates, the resulting
increases may adversely affect their competitive posture relative to alternate
fuels and suppliers.
As described below, the Company is involved in several significant
proceedings before the FERC.
In one such set of proceedings, NGT and MRT appealed the FERC's
approval of NGT's and MRT's proposal to sell approximately 250 MMcf per day of
capacity in certain NGT and MRT facilities to ANR Pipeline Company ("ANR").
The FERC had approved the parties' agreements (the "Agreement") but had also
imposed conditions inconsistent with the Agreement. In 1995, the parties
renegotiated and resolved their outstanding issues. The Federal Trade
Commission, which also had to approve the sale, modified its Consent Decree on
April 5, 1995, to delete the requirement that NorAm, through NGT and MRT,
divest certain facilities by sale to ANR. In accordance with a March 1, 1995
Supplemental Agreement between the parties, effective June 1, 1995, all prior
agreements between the parties were superseded or terminated except for
amendment of and continuation of certain existing transportation arrangements
between the parties. NGT and MRT subsequently dismissed their appeals and
withdrew their FERC application to consummate the transaction.
As circumstances warrant, both NGT and MRT regularly seek
authorization from the FERC for changes in their rates. In August 1994, NGT
filed at the FERC for a $42.5 million annual rate increase, which case was
subsequently accepted for filing with rates that became effective in February
1995 subject to refund. On January 22, 1996, the FERC affirmed a settlement of
this proceeding making the settlement rates effective February, 1995. The
settlement did not result in any refund in excess of amounts previously
reserved.
In February, 1995, MRT filed an application with the FERC to install
new compressors at its Biggers and Tuckerman Compressor Stations, and to
abandon a segment of its Main Line No. 1. These changes will help modernize
MRT's facilities, and will help MRT meet future, and increasingly stricter, air
emission standards. MRT received FERC approval for the installation and
abandonment in September, 1995.
At the state and local level, the primary effect of regulation of the
Company relates to the rates charged by the Company's various distribution
units for the services they provide to their customers. These services
generally include both gas transportation and gas sale services. During 1995
Minnegasco and Arkla obtained increases in their local rates from the
appropriate Minnesota and Arkansas regulatory agencies. Entex engaged in no
major rate initiatives during 1995, although it was granted a total of
approximately $2.3 million in annual rate increases from three of the larger
cities it serves and received increases in several other jurisdictions pursuant
to annual cost-of-service adjustment filings.
On October 24, 1994 the Minnesota Public Utilities Commission ("MPUC")
issued its order in the rate case filed by Minnegasco in November 1993. The
order allowed Minnegasco a rate increase of $7.1 million, compared to $22.7
million requested, and $14.6 million allowed
-17-
<PAGE> 19
in interim rates. In addition, Minnegasco was allowed to reduce its interim
rate refund for unrecovered conservation improvement program ("CIP") costs and
$.3 million of unrecovered prior rate case costs. To the extent certain
unrecovered CIP costs are used to reduce the interim rate refund, the allowed
revenue may be reduced. Minnegasco asked for reconsideration on certain issues
in the MPUC's decision. On April 4, 1995, the MPUC issued an order upholding
its original decision. In July 1995, Minnegasco issued an interim rate refund
for the amount of interim rates collected in excess of the final rate increase
of $7.1 million, including interest. Currently Minnegasco has an appeal
pending before the Minnesota Supreme Court of certain portions of the MPUC's
order in its 1993 rate case as well as prior MPUC decisions (1) providing that
a portion of the cost of responding to certain gas leak calls not be allowed in
rates and (2) that Minnegasco's non-regulated appliance sales and service
operations must pay the regulated operations an amount for the use of
Minnegasco's name, image and reputation.
On August 11, 1995, Minnegasco filed for a $24.3 million annual rate
increase in Minnesota. In October 1995, the MPUC accepted the filing and
issued an order allowing Minnegasco to collect $17.8 million in interim rates.
Hearings were held before an Administrative Law Judge in January 1996; the
Judge's recommended decision is expected in April. The MPUC is expected to
issue its final decision in June 1996.
Also in August 1995, Minnegasco filed a performance-based or incentive
regulation plan for its procurement of natural gas. The costs of natural gas
have historically been flowed through to customers on a dollar-for-dollar
basis. Under Minnegasco's plan, it would be able to receive a reward or
penalty of up to $7 million annually based on its performance in procuring
natural gas. In January 1996, Minnegasco entered into a settlement with two
state agencies which recommends approval of the plan. The plan is currently
pending review by the MPUC, which is expected to render its decision in the
second quarter of 1996.
In March 1995, an order was issued by the Arkansas Public Service
Commission (the "APSC") approving a settlement among Arkla, the APSC and
certain of Arkla's customers which provided for (1) an annual rate increase of
approximately $7 million and (2) an agreement by Arkla not to file another rate
application in Arkansas before June 1996. In December 1995, an APSC order was
issued authorizing implementation of a Weather Normalization Adjustment (the
"WNA") to be effective for a two-year pilot period beginning January 1, 1996.
The WNA provides that, from November to April of each year, Arkla's Arkansas
customer bills will be adjusted by 75% of any variation from normal weather.
Also during 1995, Arkla received annual increases totaling $0.9 million
pursuant to annual cost of service adjustment filings in other jurisdictions.
In addition to regulation of the Company's distribution rates, state
and local regulatory bodies also issue the franchises and certificates of
public convenience and necessity which govern most services provided by the
Company at retail.
Regulations at both the federal and state levels also have other
effects on the competitive environment in which the Company operates.
Historically, the regulatory regimes applicable at both the federal and state
level restricted the amount of facilities which could be installed to serve a
given customer. Customarily, these regulations did not allow for the
construction of "duplicate" facilities by a second supplier to a given customer
if the customer
-18-
<PAGE> 20
already was being adequately served by its existing supplier. Since the
mid-1980's, however, these regulatory restrictions gradually have been eroded
and other companies competing for the sale or transportation of gas to
customers presently served or capable of being served through facilities owned
by the Company have been permitted to use existing facilities owned by others
or to construct new facilities, thereby entirely bypassing the Company's
facilities. In certain instances, these proposals require the advance approval
of various regulatory bodies before they may be implemented. In the past,
certain such proposals have been approved and, when approved and implemented,
have resulted in reductions in the level of services provided by the Company to
its customers. In other situations, proposals to bypass facilities owned by
the Company have not been approved. The Company is not able at present to
predict either the outcome of any current or future proceedings or the effect,
if any, which they ultimately may have on the Company.
Certain business activities of the Company in the United States are
subject to existing federal, state and local laws and regulations governing
environmental quality and pollution control.
On October 24, 1994, the United States Environmental Protection Agency
advised the Company that MRT and a number of other companies have been named
under federal law as potentially responsible parties for a landfill site in
West Memphis, Arkansas and may be required to share in the cost of remediation
of this site. However, considering the information currently known about the
site and the involvement of MRT, the Company does not believe that this matter
will have a material adverse effect on the financial position, results of
operations or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental
Quality advised the Company, that the Company, through one of its subsidiaries,
and together with several other unaffiliated entities, have been named under
state law as potentially responsible parties with respect to a hazardous
substance site in Shreveport, Louisiana and may be required to share in the
remediation costs, if any, of the site. However, considering the information
currently known about the site and the involvement of the Company and its
subsidiaries with respect to the site, the Company does not believe that the
matter will have a material adverse effect on the financial position, results
of operations or cash flows of the Company.
With the acquisition of Diversified Energies, Inc. ("DEI") in
November 1990, the Company acquired Minnegasco, a natural gas distribution
company headquartered in Minneapolis, Minnesota, which owns or is otherwise
associated with a number of sites where manufactured gas plants ("MGPs") were
previously operated.
From the late 1800s to 1960, Minnegasco and its predecessors
manufactured gas at a site in Minnesota, located in Minneapolis near the
Mississippi River (the "Minneapolis Site"), which site is on Minnesota's
Permanent List of Environmental Priorities. Minnegasco
-19-
<PAGE> 21
is working with the Minnesota Pollution Control Agency to implement an
appropriate response action. There are six other former MGP sites in Minnesota
in the service territory in which Minnegasco operated at December 31, 1995. Of
these six sites, Minnegasco believes that two were neither owned nor operated
by Minnegasco, two were owned at one time by Minnegasco but were operated by
others and are currently owned by others, one is presently owned by Minnegasco
but was operated by others and one was operated by Minnegasco for a short
period and is now owned by others. Minnegasco believes it has no liability
with respect to the sites neither owned nor operated by Minnegasco.
At December 31, 1995, the Company has estimated a range of $20 million
to $177 million for possible remediation of the Minnesota sites. The low end
of the range was determined using only those sites presently owned or known to
have been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned
by the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the Minneapolis Site are based on
studies of that site. The remediation costs for other sites are based on
industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites remediated, the
participation of other potentially responsible parties, if any, and the
remediation methods used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to
recover amortization of previously deferred and ongoing clean-up costs. Any
amounts in excess of $2.1 million annually were deferred for future recovery.
In its 1995 rate case, Minnegasco asked that the annual allowed recovery be
increased to approximately $7 million and that such costs be subject to a
true-up mechanism whereby any over or under recovered amounts, net of certain
insurance recoveries, be deferred until the next rate case. Such accounting
was implemented effective October 1, 1995 pending final approval in the
existing rate case. At December 31, 1995 and 1994, the Company had net
deferred expenses of $2.3 million and $0.2 million respectively. At December
31, 1995 and 1994, the Company had recorded a liability of $45.2 million and
$40.1 million, respectively, to cover the cost of remediation. The Company
expects that the majority of its accrual as of December 31, 1995 will be
expended within the next five years. In accordance with the provisions of SFAS
71, a regulatory asset has been recorded equal to the liability accrued. The
Company believes the difference between any cash expenditure for these costs
and the amounts recovered in rates during any year will not be material to the
Company's overall cash requirements. The Company is pursuing recovery of its
costs from insurers.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites
in the service territories of the distribution divisions. At the present time,
the Company is aware of some plant sites in addition to the Minnesota sites and
is investigating certain other locations. While the Company's evaluation of
these other MGP sites is in its preliminary stages, it is likely that some
compliance costs will be identified and become subject to reasonable
quantification. To the extent that such potential costs are quantified, as
with the Minnesota remediation costs for MGP described herein, the Company
expects to provide an appropriate accrual and seek recovery for such
remediation costs through all appropriate means, including regulatory relief.
-20-
<PAGE> 22
In addition, the Company, as well as other similar firms in the
industry, is investigating the possibility that it may elect or be required to
perform remediation of various sites where meters containing mercury were
disposed of improperly, or where mercury from such meters may have leaked or
been disposed of improperly. While the Company's evaluation of this issue is
in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
To the extent that potential environmental compliance costs are
quantified within a range, the Company establishes reserves equal to the most
likely level of costs within the range and adjusts such accruals as better
information becomes available. If justified by circumstances within the
Company's businesses subject to SFAS 71, corresponding regulatory assets are
set up in anticipation of recovery through the ratemaking process. At December
31, 1995 and 1994, the Company had recorded a liability of $3.3 million (with a
maximum estimated exposure of approximately $18 million) for environmental
matters in addition to those described above with an offsetting regulatory
asset.
While the nature of environmental contingencies makes complete
evaluation impracticable, the Company currently is aware of no other
environmental matter which could reasonably be expected to have a material
impact on the results of operations, financial position or cash flows of the
Company.
Other legislative proposals affecting the industry have been and may
be introduced before the Congress and state legislatures, and the FERC and
various state agencies currently have under consideration various policies and
proposals, in addition to those discussed above, that may affect the natural
gas industry. It is not possible to predict what actions, if any, the
Congress, the FERC or the states will take on these matters, or the effect any
such legislation, policies, or proposals may have on the activities of the
Company.
MERGERS, ACQUISITIONS AND DISPOSITIONS.
All levels of the natural gas industry -- transmission and marketing,
distribution, and exploration and production -- have undergone a number of
acquisitions, divestitures and combinations in recent years, and the Company
has been a party to several such transactions, including, as previously
described, the sale of Arkla's Kansas distribution properties and certain of
NGT's Kansas pipeline assets in September 1994, the exchange of Minnegasco's
South Dakota distribution properties in August of 1993, the sale of the LIG
Group in June of 1993 and the sale of Minnegasco's Nebraska distribution
properties in February 1993, and as described more fully below, the sale of the
Company's exploration and production business in December 1992, the sale of
Dyco Petroleum and the acquisition of The Hunter Company in 1991, its merger
with DEI, the parent company of Minnegasco in 1990, its acquisition of the LIG
Group in 1989 and its merger with Entex in 1988. The Company reviews possible
transactions from time to time and may engage in other business combinations in
the future that are not specifically described herein.
On December 31, 1992, the Company completed the sale of the stock of
Arkla Exploration Company ("AEC") to Seagull for approximately $397 million in
cash (including
-21-
<PAGE> 23
$7.3 million removed from AEC just prior to closing). This sale terminated the
Company's activities in the exploration and production business and,
accordingly in 1992, the Company reclassified the results of operations of AEC
to discontinued operations.
The Company previously conducted operations in the radio
communications business through E. F. Johnson and the energy measurement
business through EnScan, Inc. ("EnScan") which were acquired in conjunction
with the merger with DEI. In early 1992, EnScan merged with Itron, Inc.
("Itron") of Spokane, Washington, of which, the Company owned at March 1, 1996,
common stock representing ownership of approximately 12.3% of the combined
enterprise, which is managed by Itron. In December 1994 and January 1995 the
Company sold a total of 480,000 shares of Itron common stock in a public
offering, resulting in the reduction of the Company's stock ownership
percentage of Itron common stock from 18.5% to the current 12.3%. Based on
price quotations on the NASDAQ, the market value of the Company's interest at
December 31, 1995 was approximately $50.7 million and had increased to
approximately $65.4 million at March 1, 1996. While there are other ways in
which the Company can monetize its investment in the Itron shares, in general,
the market for the Itron shares on the NASDAQ is not sufficiently liquid to
allow the company to dispose of a significant portion of its investment in a
single transaction without accepting a significant discount from the quoted
price. It is currently the Company's intention to dispose of its investment in
the combined enterprise over the next several years at times to be determined
principally by economic factors in the markets available for the sale or
exchange of such interests. In July 1992, the Company sold the stock of
Johnson for total consideration of approximately $40 million, receiving cash
proceeds of approximately $15 million at closing and retaining an investment
currently valued at approximately $5 million.
In addition to the EnScan and Johnson transactions described above,
during recent years, the Company has disposed of substantially all of its
non-gas related businesses, including, in late 1992 the sale of the principal
assets of Arkla Products Company, which was originally sold as a part of the
1984 sale of Arkla Industries and conducted operations for the Company in the
gas grill manufacturing business after it was reacquired by the Company due to
Preway Inc.'s default on certain revenue bonds for which the Company was
secondarily liable. Prior to its merger with the Company in 1988, Entex
similarly disposed of substantially all of its non-gas related assets. For a
further discussion of certain of these matters, see Note 1 of Notes to
Consolidated Financial Statements included in the Company's 1995 Annual Report
to Stockholders incorporated herein by reference.
EMPLOYEES.
The Company employs approximately 6,703 persons and has retirement
plans for the majority of its employees and maintains contributory group life,
medical, dental and disability insurance plans for its employees as well as
certain other benefit plans for its retirees.
-22-
<PAGE> 24
ITEM 2. PROPERTIES.
The Company is of the opinion that it has generally satisfactory title
to the properties owned and used in its businesses, subject to the liens for
current taxes, liens incident to minor encumbrances, and easements and
restrictions which do not materially detract from the value of such property or
the interests therein or the use of such properties in its businesses. See
"Natural Gas Distribution" and Natural Gas Pipeline".
ITEM 3. LEGAL PROCEEDINGS.
On August 6, 1993, the Company, its former subsidiary, Arkla
Exploration Company ("AEC") and Arkoma Production Company, a subsidiary of AEC,
were named as defendants in a lawsuit filed in the Circuit Court of
Independence County, Arkansas. On September 20, 1994, the Circuit Court
entered an order granting the Company's motion to dismiss. On October 23,
1995, the Supreme Court of Arkansas affirmed the Circuit Court's order granting
the Company's motion to dismiss.
On October 24, 1994, the United States Environmental Protection Agency
advised the Company that MRT and a number of other companies have been named
under federal law as potentially responsible parties for a landfill site in
West Memphis, Arkansas and may be required to share in the cost of remediation
of this site. However, considering the information currently known about the
site and the involvement of MRT, the Company does not believe that this matter
will have a material adverse effect on the financial position, results of
operations or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company, that the Company, through one of its subsidiaries, along
with several other unaffiliated entities have been named under state law as
potentially responsible parties with respect to a hazardous substance site in
Shreveport, Louisiana and may be required to share in the remediation cost of
the site, if any are incurred. However, considering the information currently
known about the site and the involvement of the Company and its subsidiaries
with respect to the site, the Company does not believe that the matter will
have a material adverse effect on the financial position, results of operations
or cash flows of the Company.
REGULATION S-K, ITEM 401(b). EXECUTIVE OFFICERS OF THE COMPANY
The following table sets forth certain information concerning the
"executive officers" of the Company (as defined by the Securities and Exchange
Commission) as of March 15, 1996:
-23-
<PAGE> 25
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE DURING
NAME AGE PAST 5 YEARS
---- --- ------------
<S> <C> <C>
Rollie B. Bohall 49 Senior Vice President and Chief
Operating Officer of NorAm Energy
Management, Inc., 3/95 to present,
Chairman of the Board and President of
Entex Gas Marketing Company,
subsidiary of NorAm Energy Corp.
Michael B. Bracy 54 Executive Vice President and Principal
Financial Officer of the Company,
10/91 to present,
Chief Executive Officer, Arkla
Pipeline Group and Executive Vice
President of the Company from at least
1/90 to 10/91
Michael A. Creel 42 Vice President and Treasurer of the
Company from 10/23/95 to present,
Assistant Treasurer of Corporate
Finance of Enron
Dale C. Earwood 40 President of NorAm Field Services
Corp., 10/93 to present,
Vice President of Arkla Energy
Resources Company, 4/94 to 1/95,
Senior Vice President & General
Counsel, Arkla Pipeline Group, from at
least 1/90 to 4/94
W. Craig Elias 47 President and Chief Operating Officer
of NorAm Energy Services, Inc., 4/95
to present, Executive Vice President
of Marketing and Gas Supply at Coastal
Gas Marketing
Jack W. Ellis, II 42 Vice President and Controller of the
Company, 12/89 to present
</TABLE>
-24-
<PAGE> 26
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE DURING
NAME AGE PAST 5 YEARS
---- --- ------------
<S> <C> <C>
Hubert Gentry, Jr. 64 Senior Vice President and General
Counsel of the Company, 8/90 to
present
Secretary of the Company, 7/92 to
present
Executive Vice President and General
Counsel - Entex from at least 1/90 to
8/90
T. Milton Honea 63 President of the Company, 10/93 to
present,
Chairman of the Board and Chief
Executive Officer of the Company,
12/92 to present,
Vice Chairman of the Board, 7/92 to
12/92,
Executive Vice President of the
Company, 10/91 to 7/92,
President and Chief Operating Officer-
Arkansas Louisiana Gas Company from at
least 1/90 to 10/91
Robert N. Jones 43 President and Chief Operating Officer
of Entex, 1/95 to present
Executive Vice President of Entex,
4/94 to 1/95
Vice President & Manager of Houston
Division, 3/92 to 4/94
Vice President & Manager of
Mississippi Division, from at least
1/90 to 3/92
William A. Kellstrom 54 Senior Vice President, Corporate
Business Development, 7/95 to present,
President of NorAm Energy Services,
Inc., 9/92 to 7/95
President of Tenaska Marketing
Ventures from at least 1/90 to 9/92
</TABLE>
-25-
<PAGE> 27
<TABLE>
<CAPTION>
NAME AGE BUSINESS EXPERIENCE DURING
---- ---
PAST 5 YEARS
------------
<S> <C> <C>
Michael H. Means 47 President and Chief Operating
Officer, Arkansas Louisiana Gas
Company, 10/91 to present, Vice
President Arkansas Division, Arkansas
Louisiana Gas Company from at least
1/90 to 10/91
Charles M. Oglesby 43 President of NorAm Trading and
Transportation Group, Inc., 3/95 to
present, Vice President of Coastal
Corporation and President and chief
Executive Officer of Coastal Gas
Services Company
Gary N. Petersen 43 President and Chief Operating Officer
of Minnegasco 9/91 to present,
Executive Vice President and Chief
Operating Officer of Minnegasco,
Senior Vice President of DEI and
Executive Vice President and Chief
Operating Officer of Minnegasco, Inc.,
Vice President, Gas Supply and
Regulatory Administration - Minnegasco
from at least 1/90 to 9/91
Rick L. Spurlock 50 Senior Vice President, Human Resources
and Administrative Services of the
Company, 12/90 to present
Vice President, Corporate Human
Resources of the Company from at least
1/90 to 12/90
</TABLE>
-26-
<PAGE> 28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The information required hereunder applicable to market, number of
security holders and dividend history is shown on page 53 of the 1995 Annual
Report to Stockholders, which information is incorporated herein by reference.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data required hereunder is included on page 34
of the 1995 Annual Report to Stockholders, which data is incorporated herein by
reference. For information, if any, concerning accounting changes, business
combinations or dispositions of business operations that materially affect the
comparability of the information reflected in selected financial data, see
Notes to Consolidated Financial Statements on pages 58 through 70 of the
1995 Annual Report to Stockholders, which information is incorporated herein by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The required information is included on pages 34 through 53 of the
1995 Annual Report to Stockholders, which pages are incorporated herein by
reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements of the Company and
auditor's reports are set forth on pages 54 through 71 of the 1995 Annual
Report to Stockholders, which pages are incorporated herein by reference.
Statement of Consolidated Income for the years ended December 31,
1995, 1994, and 1993.
Consolidated Balance Sheet as of December 31, 1995 and 1994.
Statement of Consolidated Stockholders' Equity for the years ended
December 31, 1995, 1994 and 1993.
Statement of Consolidated Cash Flows for the years ended December 31,
1995, 1994 and 1993.
-27-
<PAGE> 29
Notes to Consolidated Financial Statements.
Report of Independent Accountants.
The required supplementary data concerning quarterly results of
operations is set forth on page 72 of the 1995 Annual Report to Stockholders,
which page is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT
The information appearing under the caption "Election of Directors And
Beneficial Ownership of Common Stock For Officers and Directors" set forth in
the Company's definitive proxy statement, for the Annual Meeting of
Stockholders to be held on May 14, 1996, to be filed pursuant to Regulation 14A
under the Securities Exchange Act of 1934 (the "1934 Act") is incorporated
herein by reference. See also "Regulation S-K, Item 401(b)" appearing in Part
I of this Annual Report.
ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the caption "Executive Compensation"
set forth in the Company's definitive proxy statement for the Annual Meeting of
Stockholders to be held on May 14, 1996, to be filed pursuant to Regulation 14A
under the 1934 Act is incorporated herein by reference.
-28-
<PAGE> 30
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information appearing under the captions "Voting" and "Election of
Directors And Beneficial Ownership of Common Stock For Officers and Directors"
set forth in the Company's definitive proxy statement for the Annual Meeting of
Stockholders to be held on May 14, 1996 to be filed pursuant to Regulation 14A
under the 1934 Act is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information appearing under the captions "Compensation Committee
Interlocks and Insider Participation" and "Executive Compensation" set forth in
the Company's definitive proxy statement for the Annual Meeting of Stockholders
to be held on May 14, 1996 to be filed pursuant to Regulation 14A under the
1934 Act is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) FINANCIAL STATEMENTS
Included under Item 8 are the following financial statements:
Statement of Consolidated Income for the years ended December 31, 1995, 1994
and 1993.
Consolidated Balance Sheet as of December 31, 1995 and 1994.
Statement of Consolidated Stockholders' Equity for the years ended December 31,
1995, 1994 and 1993.
Statement of Consolidated Cash Flows for the years ended December 31, 1995,
1994 and 1993.
Notes to Consolidated Financial Statements.
Report of Independent Accountants.
-29-
<PAGE> 31
(a)(2) FINANCIAL STATEMENT SCHEDULES Page
----
Report of Independent Accountants 33
Schedule II - Valuation and Qualifying
Accounts 34
All other schedules for which provision is made in applicable regulations of
the Securities and Exchange Commission have been omitted because the
information is disclosed in the Consolidated Financial Statements or because
such schedules are not required or are not applicable.
(b)(3) EXHIBITS
* (Asterisk indicates exhibits incorporated by reference herein).
Pursuant to Item 601(b)(4)(iii), the Company agrees to furnish to the
Commission upon request a copy of any instrument with respect to long-term debt
not exceeding 10 percent of the total assets of the Company and its
subsidiaries on a consolidated basis.
<TABLE>
<S> <C>
*3.1 Restated Certificate of NorAm Energy Corp., dated May 11, 1994 as amended, incorporated herein by
reference to Exhibit 4.1 to the Company's Registration Statement on Form S-3 (33-52853).
*3.2 By-Laws of NorAm Energy Corp., dated May 11, 1994, incorporated herein by reference to Exhibit 4.2 to
the Company's Registration Statement on Form S-8 (33-54241).
*4.1 Indenture, dated as of December 1, 1986, between the Company and Citibank, N.A., as Trustee,
incorporated herein by reference to Exhibit 4.14 to the Company's Annual Report on Form 10-K for the
year 1986.
*4.2 Indenture, dated as of March 1, 1987, between the Company and The Chase Manhattan Bank, N.A., as
Trustee, authorizing 6% Convertible Subordinated Debentures Due 2012, incorporated herein by reference
to Exhibit 4.20 to the Company's Registration Statement on Form S-3 (Registration No. 33-14586).
*4.3 Indenture, dated as of April 15, 1990, between the Company and Citibank, N.A., as Trustee, incorporated
herein by reference to Exhibit 4.1 of the Company's Registration Statement on Form S-3 filed on May 1,
1990 (Registration No. 33-23375)
*10.1 Copy of Deferred Compensation Agreement incorporated herein by reference to Exhibit 10.2 to the
Company's Annual Report on Form 10-K for the year 1988.
</TABLE>
-30-
<PAGE> 32
<TABLE>
<S> <C>
*10.2 Copy of Deferred Stock Appreciation Agreement incorporated herein by reference to Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year 1988.
*10.3 Executive Supplemental Medical Plan (Page 13 of Proxy Statement, Annual Meeting of Stockholders, May
12, 1987, and incorporated herein by reference).
*10.4 1982 Nonqualified Stock Option Plan with Appreciation Rights (Form S-8, Registration No. 2-84830, dated
July 1, 1983, and incorporated herein by reference).
*10.5 Nonqualified Executive Disability Income Plan incorporated herein by reference to Exhibit 10.6 to the
Company's Annual Report on Form 10-K for the year 1988.
*10.6 Nonqualified Unfunded Executive Supplemental Income Retirement Plan incorporated herein by reference to
the Company's Annual Report on Form 10-K for the year 1988.
*10.7 Unfunded Nonqualified Retirement Income Plan incorporated herein by reference to Exhibit 10.10 to the
Company's Form 10-K for the year 1985.
*10.8 Annual Incentive Award Plan incorporated herein by reference as maintained in the files of the
Commission, File No. 1-3751.
*10.9 Long-Term Incentive Compensation Plan (Form S-8, Registration No. 33-10806, dated December 12, 1986,
and incorporated herein by reference).
*10.10 Service Agreement, by and between Mississippi River Transmission Corporation and Laclede Gas Company,
dated August 22, 1989 incorporated herein by reference to Exhibit 10.20 to the Company's Annual Report
on Form 10-K for the year 1989.
*10.11 Agreement and Plan of Merger, dated as of July 30, 1990, between NorAm Energy Corp., Diversified
Energies, Inc. and Minnegasco, Inc., incorporated by reference to Exhibit A to the Company's
Registration Statement on Form S-4 (Reg. No. 33-27428).
*10.14 Incentive Equity Plan, incorporated herein by reference to Appendix B of Proxy Statement, Annual
Meeting of Stockholders May 10, 1994.
*10.15 Non-Employee Director Restricted Stock Plan, incorporated here by reference to Appendix D of Proxy
Statement, Annual meeting of Stockholders May 10, 1994.
12 Computation of Ratio of Earnings to Fixed Charges.
</TABLE>
-31-
<PAGE> 33
<TABLE>
<S> <C>
13 The portions of the Annual Report to Stockholders for the year ended December 31, 1995 incorporated by
reference into this Form 10-K.
21 Subsidiaries of the Company.
23 Consent of Coopers & Lybrand L.L.P.
24 Powers of Attorney from each Director of NorAm Energy Corp. whose signature is affixed to this Form
10-K.
27 Financial Data Schedule
</TABLE>
(b) REPORTS ON FORM 8-K FILED DURING THE LAST QUARTER OF THE PERIOD COVERED BY
THIS REPORT
Report on Form 8-K, dated November 2, 1995 - Third Quarter Earnings Release
-32-
<PAGE> 34
REPORT OF INDEPENDENT ACCOUNTANTS
Board of Directors and Stockholders
NorAm Energy Corp.:
Our report on the consolidated financial statements of NorAm Energy Corp. and
Subsidiaries has been incorporated by reference in this Form 10-K from page 71
of the 1995 Annual Report to Stockholders of NorAm Energy Corp. and
Subsidiaries. In connection with our audits of such consolidated financial
statements, we have also audited the related financial statement schedule
listed in the index on page 30 of this Form 10-K.
In our opinion, the financial statement schedule referred to above, when
considered in relation to the basic financial statements taken as a whole,
presents fairly, in all material respects, the information required to be
included therein.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 25, 1996
-33-
<PAGE> 35
NORAM ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(In thousands of dollars)
<TABLE>
<CAPTION>
==========================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------------------------------
Additions
----------------------
Balances at Charged to Charged to Balance at
Beginning Costs and Other End
Description of Period Expenses Accounts Deductions of Period
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves which are deducted in the balance
sheet from assets to which they apply:
(a) Allowance for Doubtful Accounts
Receivable
Year ended December 31, 1995 . . . . . . . $12,604 $10,315 $ (470) $11,332 $11,117
Year ended December 31, 1994 . . . . . . . $11,296 $11,957 $ 1,771 $12,420 $12,604
Year ended December 31, 1993 . . . . . . . $12,003 $10,393 $ 744 $11,844 $11,296
(b) Deferred Tax Asset Valuation Allowance
Year ended December 31, 1995 . . . . . . . $ 5,974 $ 214 - - $ 6,188
Year ended December 31, 1994 . . . . . . . $10,023 $ - - $ 4,049 $ 5,974
Year ended December 31, 1993 . . . . . . . $ 9,997 $ 26 - $ - $10,023
</TABLE>
-34-
<PAGE> 36
SIGNATURES
Pursuant to the requirements of Section 13 and 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
NORAM ENERGY CORP.
(Registrant)
By /s/ T. Milton Honea
-----------------------------------
(T. Milton Honea)
Chairman of the Board, President
and Chief Executive Officer
By /s/ Michael B. Bracy
-----------------------------------
(Michael B. Bracy)
Executive Vice President
(Principal Financial Officer)
By /s/ Jack W. Ellis, II
--------------------------------------
(Jack W. Ellis, II)
Vice President and
Corporate Controller
(Principal Accounting Officer)
Date: March 29, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ T. MILTON HONEA Director March 29, 1996
- -------------------------
(T. Milton Honea)
/s/ MICHAEL B. BRACY Director
- -------------------------
(Michael B. Bracy)
</TABLE>
-35-
<PAGE> 37
<TABLE>
<S> <C> <C>
JOE E. CHENOWETH* Director
- -------------------------
(Joe E. Chenoweth)
O. HOLCOMBE CROSSWELL* Director
- -------------------------
(O. Holcombe Crosswell)
WALTER A. DeROECK* Director
- -------------------------
(Walter A. DeRoeck)
MICKEY P. FORET* Director
- -------------------------
(Mickey P. Foret)
JOHN P. GOVER* Director
- -------------------------
(John P. Gover)
JOSEPH M. GRANT* Director
- -------------------------
(Joseph M. Grant)
ROBERT C. HANNA* Director
- -------------------------
(Robert C. Hanna)
W. JEFFREY HART* Director
- -------------------------
(W. Jeffrey Hart)
MYRA JONES* Director
- -------------------------
(Myra Jones)
LARRY C. WALLACE* Director
- -------------------------
(Larry C. Wallace)
*By /s/ T. MILTON HONEA March 29, 1996
------------------------
(T. Milton Honea
Attorney-in-Fact)
</TABLE>
-36-
<PAGE> 38
EXHIBIT INDEX
12 Computation of Ratio of Earnings to Fixed Charges.
13 The portions of the Annual Report to Stockholders for the year ended
December 31, 1995 incorporated by reference into this Form 10-K.
21 Subsidiaries of the Company.
23 Consent of Coopers & Lybrand L.L.P.
24 Powers of Attorney from each Director of NorAm Energy Corp. whose
signature is affixed to this Form 10-K.
27 Financial Data Schedule
<PAGE> 1
EXHIBIT 12
NORMAN ENERGY CORP. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(in thousands of dollars)
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991 1990
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Income from continuing operations
as set forth in Consolidated
Statement of Income $ 65,529 $ 51,291 $ 39,935 $ 6,227 $ 16,515 $100,826
Add back:
Provision for income taxes 55,379 34,372 46,481 12,516 18,418 52,643
Less:
Non-utility interest capitalized 0 0 0 0 0 0
-------- -------- -------- -------- -------- --------
120,908 85,663 86,416 18,743 34,933 153,469
-------- -------- -------- -------- -------- --------
Fixed charges (from continuing
operations):
Interest 155,584 167,384 169,857 182,453 174,044 150,593
Amortization of debt discount
and expense 3,483 3,312 3,421 4,450 3,290 2,191
Portion of rents considered to
represent an interest factor 16,215 11,292 10,402 7,704 6,514 5,534
-------- -------- -------- -------- -------- --------
Total fixed charges 175,282 181,988 183,680 194,607 183,848 158,318
-------- -------- -------- -------- -------- --------
Earnings $296,190 $267,651 $270,096 $213,350 $218,781 $311,787
======== ======== ======== ======== ======== ========
Ratio of earnings to fixed charges 1.69 1.47 1.47 1.10 1.19 1.97
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE> 1
EXHIBIT 13
FINANCIAL CONTENTS
<TABLE>
<S> <C>
SELECTED FINANCIAL DATA 34
MANAGEMENT ANALYSIS
Organization and Accounting Policies 34
Material Changes in the Results of Continuing Operations
General 34
Regulatory Matters 35
Change in Estimated Service Lives of Certain Assets 36
Operating Income (Loss) by Business Unit
Summary Table 36
Natural Gas Distribution 36
Interstate Pipelines 38
Wholesale Energy Marketing 40
Natural Gas Gathering 42
Retail Energy Marketing 43
Corporate and Other 44
Non-Operating Income and Expense 44
Discontinued Operations 45
Liquidity and Capital Resources 45
Commitments and Contingencies 49
Accounting Changes 53
Ratio of Earnings to Fixed Charges 53
Debt Retirement Schedule 53
Common Stock Prices and Dividends 53
FINANCIAL STATEMENTS & RELATED INFORMATION
Statement of Consolidated Income 54
Consolidated Balance Sheet 55
Statement of Consolidated Stockholders' Equity 56
Statement of Consolidated Cash Flows 57
Notes to Consolidated Financial Statements 58
Report of Independent Accountants 71
Management's Responsibility for Financial Statements 71
Quarterly Information 72
</TABLE>
N O R A M 33
<PAGE> 2
SELECTED FINANCIAL DATA
The following data should be read in conjunction with the Company's
consolidated financial statements and accompanying notes and "Management
Analysis" elsewhere herein. The results of operations of Louisiana Intrastate
Gas Corporation are included until its sale at June 30, 1993, see "Interstate
Pipelines" under "Management Analysis" elsewhere herein. Results of operations
for 1993, 1992 and 1991 include significant non-recurring charges, see
"Interstate Pipelines", "Wholesale Energy Marketing" and "Regulatory Matters"
under "Management Analysis" elsewhere herein. Results of operations for 1993
also include significant gains from sales of property, see Note 1 of Notes to
Consolidated Financial Statements.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
(millions of dollars, except per share amounts) 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $2,964.7 $2,857.9 $2,988.3 $2,782.2 $2,759.2
- ------------------------------------------------------------------------------------------------------------------------------------
Income from continuing operations $ 65.5 $ 51.3 $ 39.9 $ 6.2 $ 16.5
- ------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations per common share (1) $ 0.47 $ 0.36 $ 0.26 $ (0.01) $ 0.08
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $3,666.0 $3,561.5 $3,727.8 $4,059.0 $4,806.9
- ------------------------------------------------------------------------------------------------------------------------------------
Long-term obligations $1,474.9 $1,414.4 $1,629.4 $1,783.1 $1,551.5
- ------------------------------------------------------------------------------------------------------------------------------------
Dividends per common share $ 0.28 $ 0.28 $ 0.28 $ 0.48 $ 1.08
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Computed after reduction for the preferred dividend requirement of $7.8
million in each year.
MANAGEMENT ANALYSIS
ORGANIZATION AND ACCOUNTING POLICIES
NorAm Energy Corp., referred to herein together with its consolidated
subsidiaries and divisions (all of which are wholly owned) as "NorAm" or "the
Company", principally conducts activities in the natural gas industry,
including gathering, transmission, marketing, storage and distribution which,
collectively, account for in excess of 90% of the Company's total revenues,
income or loss and identifiable assets. The Company also makes certain
non-energy sales and provides certain non-energy services, principally to
certain of its retail natural gas distribution customers, see "Retail Energy
Marketing" under "Material Changes in the Results of Continuing Operations"
elsewhere herein. The Company's activities historically have been limited to
the 48 contiguous states, principally Texas, Louisiana, Mississippi, Arkansas,
Oklahoma, Missouri and Minnesota, although the Company is evaluating
opportunities for international investment as discussed following. A
significant portion of the Company's activities are subject to rate regulation,
see "Regulatory Matters" elsewhere herein. The Company previously conducted
operations in the oil and gas exploration and production and radio
communications businesses which were discontinued in 1992 and 1991,
respectively. In recent years, the Company has engaged in several transactions
with respect to its distribution properties and completed the sale of Louisiana
Intrastate Gas Corporation on June 30, 1993. For additional information on
these matters, see the discussions by business unit under "Material Changes in
the Results of Continuing Operations" and "Discontinued Operations" following.
The Company changed its method of accounting for postemployment
benefits and postretirement benefits as of January 1, 1992 and 1993,
respectively, see "Accounting Changes" elsewhere herein. The Company expects
that it will adopt the "disclosure only" option of Statement of Financial
Accounting Standards No. 123, "Accounting for Stock-Based Compensation", see
Note 6 of Notes to Consolidated Financial Statements. The Company recorded an
impairment of certain assets in conjunction with its discontinuance of the
application of specialized regulatory accounting principles to its NorAm Gas
Transmission Company subsidiary ("NGT") at December 31, 1992, see "Interstate
Pipelines" under "Material Changes in the Results of Continuing Operations"
elsewhere herein. The Company currently does not expect to record further
impairments as a result of its initial adoption of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), which is
effective for fiscal years beginning after December 15, 1995, although SFAS 121
requires that assets be evaluated for impairment on an ongoing basis (as
indications of possible impairment are noted) and, therefore, changing
circumstances could result in impairments at some future date. The reader is
directed to Note 1 of Notes to Consolidated Financial Statements for a
discussion of the Company's other significant accounting policies.
MATERIAL CHANGES IN THE RESULTS
OF CONTINUING OPERATIONS
GENERAL
The Company previously has segregated its business activities into
"Distribution" and "Pipeline" when reporting its results of operations. In
recognition of changes within the natural gas industry and the manner in which
the Company manages its portfolio of businesses, and in order to facilitate a
more detailed understanding of the various activi-
34 N O R A M
<PAGE> 3
ties in which the Company engages, the Company has further broken down its
results of operations into (1) Natural Gas Distribution, (2) Interstate
Pipelines, (3) Wholesale Energy Marketing, (4) Natural Gas Gathering, and (5)
Retail Energy Marketing and is evaluating opportunities for international
investment as discussed following. The Company's results of operations are
seasonal due to weather-related fluctuations in the demand for and price of
natural gas although, as discussed following and elsewhere herein, (1) the
Company has obtained rate design changes in its rate-regulated businesses which
generally have reduced the sensitivity of the Company's earnings to seasonal
weather patterns and further such changes are anticipated and (2) the Company
is seeking to derive a larger portion of its earnings from businesses which
exhibit less earnings seasonality.
Since the Company's December 1992 sale of its oil and gas exploration
and production business, the Company's operations principally have been rate
regulated. While these businesses have been subjected to varying levels of
competition through changes in the form of regulation (and further such changes
are anticipated), in general, they continue to be regulated on a
cost-of-service basis and the potential for growth in earnings and increased
rates of return is limited. The Company seeks to improve its returns from these
businesses through increased efficiency, aggressive marketing and by rate
initiatives which allow these businesses to compete more effectively and retain
more of the value added through improved operations and expanded services.
The Company believes that its greatest potential for significant
increases in overall profitability lies in those businesses which are, in some
instances, subject to regulation as to the nature of services offered, the
manner in which services are provided or the allocation of joint costs between
cost-of-service regulated and other operations, but are not generally subject
to direct regulation as to the rates which may be charged. Such operations are
sometimes referred to herein for convenience as "unregulated". The Company has
undertaken to separate its strategically significant unregulated activities
into discrete management units and to formulate plans for increasing the future
financial contribution from these businesses. The Company expects to (1) expand
both the range of products and services offered by these businesses and the
geographic areas served and (2) increase the percentage of the Company's
overall earnings derived from these activities.
In addition, the Company is investigating opportunities for
international investment. To date, the Company's efforts have focused on
opportunities emerging in Latin America due to privatization initiatives
currently underway in a number of countries, as well as broad-based efforts to
encourage international investment. While such investments involve increased
risks such as political, economic or regulatory instability and foreign
currency exchange rate fluctuations, the Company believes that, together with
carefully selected partners (both within the target countries and otherwise),
it can effectively apply its natural gas industry expertise to selected
projects in Latin America, thereby increasing its overall returns on invested
capital while keeping the increased risk within acceptable limits. In general,
the international investment is expected to build up gradually over a period of
years as the Company (1) identifies and creates working relationships with
strategic business partners, (2) selects projects which meet its risk/return
requirements, (3) develops specific country experience and (4) in some cases,
increases its investment in specific projects as facilities are constructed,
see "Capital Expenditures - Continuing Operations" under "Net Cash Flow from
Investing Activities" elsewhere herein.
REGULATORY MATTERS
In general, the Company's interstate pipelines are subject to
regulation by the Federal Energy Regulatory Commission ("the FERC"), while its
distribution operations are subject to regulation at the state or municipal
level. Historically, all of the Company's rate-regulated businesses have
followed the accounting guidance contained in Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
("SFAS 71"). The Company discontinued application of SFAS 71 to NGT effective
with year-end 1992 reporting, see "Interstate Pipelines" elsewhere herein. As a
result of the continued application of SFAS 71 to Mississippi River
Transmission Corporation ("MRT") and the Company's distribution operations, the
Company's consolidated financial statements contain certain assets and
liabilities which would not be recognized by unregulated entities. In addition
to regulatory assets related to postretirement benefits other than pensions,
the Company's only other significant regulatory asset is related to anticipated
environmental remediation costs, see Note 5 of Notes to Consolidated Financial
Statements and "Commitments and Contingencies" elsewhere herein. Following are
recent significant regulatory actions and developments.
In August 1994, NGT filed at the FERC for a $42.5 million annual rate
increase, with increased rates becoming effective in February 1995, subject to
refund. During the second and third quarters of 1995, NGT conducted several
conferences with the relevant parties. These conferences led to a settlement of
the rate case, which settlement was filed at the FERC in September and approved
by a FERC order ("the Order") in January 1996. The Order terminated the rate
proceeding and retroactively established rate levels for NGT's services as of
February 1995. NGT received an increase of approximately $22 million, 52% of
the filed request, and the resulting refunds were not in excess of amounts
previously accrued. The Order also included a moratorium on certain rate design
changes (zone rates) until January 1998, and NGT has no obligation to file
another rate case.
During 1995, MRT made various filings to recover approximately $12.9
million of gas supply realignment ("GSR") costs. Pursuant to the terms of a
FERC settlement, MRT expects to recover approximately $11.5 million of such GSR
costs. The recovery period for these costs ends on June 30, 1996.
N O R A M 35
<PAGE> 4
Effective June 1, 1995, Minnegasco implemented final rates resulting from
Minnegasco's 1993 Minnesota rate case filing. Minnegasco received an annual
rate increase of $7.1 million in comparison to the previously granted interim
increase of $14.6 million, which difference had been substantially reserved.
Minnegasco has appealed, to the Minnesota Supreme Court, the Minnesota Public
Utilities Commission's decisions that (1) Minnegasco's unregulated appliance
sales and service operations pay the regulated distribution operations a fee for
the use of Minnegasco's name, image and reputation and (2) a portion of the cost
of responding to certain gas leak calls not be allowed in regulated rates. The
Supreme Court's decision is expected during 1996. In August 1995, Minnegasco
filed a rate case in Minnesota including requests for (1) a $24.3 million (4.2%)
annual rate increase and (2) certain changes to the recovery and accounting for
environmental costs, see "Environmental Matters" under "Commitments and
Contingencies" elsewhere herein. Interim rates of $17.8 million were put into
effect in October 1995 subject to refund. A decision in this rate case is
expected in mid-1996.
Entex engaged in no major rate initiatives during 1995, although it was
granted a total of approximately $2.3 million in annual rate increases from
three of the larger cities it serves and received increases in several other
jurisdictions pursuant to annual cost-of-service adjustment filings.
In March 1995, an order was issued by the Arkansas Public Service
Commission ("the APSC") approving a settlement among Arkla, the APSC and certain
of Arkla's customers which provided for (1) an annual rate increase of
approximately $7 million and (2) an agreement by Arkla not to file another rate
application in Arkansas before June 1996. In November 1995, an APSC order was
issued authorizing implementation of a Weather Normalization Adjustment ("the
WNA") to be effective for a two-year pilot period beginning January 1, 1996. The
WNA provides that, from November to April of each year, Arkla's Arkansas
customer bills will be adjusted by 75% of any variation from normal weather.
Also during 1995, Arkla received annual increases totaling $0.9 million pursuant
to annual cost-of-service adjustment filings in other jurisdictions.
Pursuant to a settlement with the APSC in June 1991, the Company was
required to issue credits of $8.25 million to certain of its customers over a
12-month period and pay certain related costs. Expense of $15 million associated
with this settlement is included in the Company's 1991 results of continuing
operations.
CHANGE IN ESTIMATED SERVICE LIVES OF CERTAIN ASSETS
Pursuant to an updated study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas pipeline and gathering assets, see "Interstate Pipelines" and
"Natural Gas Gathering" elsewhere herein. This change had the effect of
increasing the Company's 1995 income before extraordinary item by approximately
$3.2 million ($0.03 per share) and represents an annualized increase of
approximately $6.5 million ($0.05 per share).
OPERATING INCOME (LOSS) BY BUSINESS UNIT(1)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(millions of dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Distribution $ 158.0 $ 145.5 $ 160.1
Interstate Pipelines 103.8 105.4 100.6
Wholesale Energy Marketing 4.2 (3.0) (22.4)
Natural Gas Gathering 8.7 5.6 - (2)
Retail Energy Marketing 22.2 18.4 15.1
Corporate and Other(3) (9.6) (7.0) (16.9)
- --------------------------------------------------------------------------------
Subtotal 287.3 264.9 236.5
Louisiana Intrastate
Gas Corporation(4) - - 5.6
Contract Termination Charge(5) - - (34.2)
- --------------------------------------------------------------------------------
Consolidated $ 287.3 $ 264.9 $ 207.9
================================================================================
</TABLE>
(1) To the extent practicable, prior year results of operations have been
reclassified to conform to the current business unit presentation, although
such results are not necessarily indicative of the results which would have
been achieved had the revised business unit structure been in effect during
those periods. In general, transactions among business units are recorded
at market prices and material affiliate transactions within business units
have been eliminated.
(2) Included with "Interstate Pipelines" in 1993, see "Natural Gas Gathering"
following.
(3) Includes amortization of goodwill, see Note 1 of Notes to Consolidated
Financial Statements.
(4) See "Interstate Pipelines" following.
(5) See "Wholesale Energy Marketing" following.
NATURAL GAS DISTRIBUTION
The Company's natural gas distribution business is conducted by the Entex,
Minnegasco and Arkla divisions of NorAm Energy Corp. and, historically, the
Company's "Distribution" business unit has included substantially all the
activities conducted by these three divisions. In recognition of the fact that
certain of these activities are not subject to traditional cost-of-service rate
regulation and, as such, have different risk profiles and return potentials,
and in order to concentrate its similarly-targeted marketing efforts in a
single business unit, certain large-volume marketing activities, including the
provision of services to a number of customers previously reported with
Distribution, have been aggregated and separately reported as "Retail Energy
Marketing". Thus, Distribution, as presently constituted (see "Significant
Distribution Property Transactions" following), consists principally of
natural gas sales to and natural gas transportation for residential, commercial
and a limited number of industrial customers, substantially all of which are
located behind the "city gate" and subject to traditional cost-of-service rate
regulation, see "Regulatory Matters" and "Retail Energy Marketing" elsewhere
herein.
36 N O R A M
<PAGE> 5
SIGNIFICANT DISTRIBUTION PROPERTY TRANSACTIONS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------
(dollars in millions)
Acquired
(Surrendered) Cash
--------------------- Received Pre-tax
Date Transaction Communities/Customers (Paid)(1) Gain
- --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Sept. 1993 Exchange with Midwest Gas:
Midwest - Minnesota 41 82,000
Minnegasco - South Dakota (18) (45,000) $(38.0) -(2)
Feb. 1993 Sale of Nebraska properties (63) (124,000) 93.1 $23.9(3)
Sept. 1994 Sale of Kansas properties (14) (23,000) $ 23.0 N/M(4)
- --------------------------------------------------------------------------------------------------
</TABLE>
(1) In general, cash proceeds were used to retire a portion of the
Company's short-term borrowings.
(2) The acquired Midwest Gas Minnesota properties were recorded at the
historical cost of the Minnegasco South Dakota properties surrendered
plus the cash paid; a gas plant acquisition adjustment of $14 million
was recorded, for which the Company is seeking recovery through the
regulatory process.
(3) Included in the accompanying Statement of Consolidated Income under the
caption "Other, net". The associated tax expense was $8.7 million.
(4) Indicates that the item is not material.
DISTRIBUTION - FINANCIAL RESULTS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(millions of dollars) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $ 1,678.6 $ 1,769.9 $ 1,865.7
Transportation revenue 19.1 17.6 18.7
Other revenue 21.7 23.1 22.6
- -----------------------------------------------------------------------------
Total operating revenues 1,719.4 1,810.6 1,907.0
- -----------------------------------------------------------------------------
Purchased gas cost
Unaffiliated 777.3 855.0 909.9
Affiliated 237.9 273.7 315.6
Operations and maintenance 372.0 366.6 356.7
Depreciation and amortization 90.4 86.9 81.5
Other operating expenses 83.8 82.9 83.2
- -----------------------------------------------------------------------------
Operating income $ 158.0 $ 145.5 $ 160.1
=============================================================================
Average invested capital $ 940.7 $ 902.2 $ 907.1
=============================================================================
</TABLE>
DISTRIBUTION - OPERATING STATISTICS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------
(billions of cubic feet) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Residential sales 183.3 180.0 193.6
Commercial sales 123.3 119.1 126.7
Industrial sales 52.4 53.4 49.7
Transportation 49.4 44.9 52.2
- -----------------------------------------------------------------------------
Total throughput 408.4 397.4 422.2
=============================================================================
Arkla actual degree days 2,830 2,806 3,314
Arkla normal degree days 2,999 3,038 3,063
- -----------------------------------------------------------------------------
Entex actual degree days 1,331 1,348 1,632
Entex normal degree days 1,531 1,554 1,582
- -----------------------------------------------------------------------------
Minnegasco actual degree days 7,836 7,617 8,057
Minnegasco normal degree days 7,821 7,786 7,865
- -----------------------------------------------------------------------------
Avg. number of customers 2,722,306 2,683,175 2,658,630
- -----------------------------------------------------------------------------
Number of employees 5,538 5,617 5,638
- -----------------------------------------------------------------------------
Average sales price ($/Mcf)
Residential $ 5.53 $ 5.99 $ 5.77
- -----------------------------------------------------------------------------
Commercial $ 4.18 $ 4.66 $ 4.65
- -----------------------------------------------------------------------------
Industrial $ 2.65 $ 3.00 $ 3.21
- -----------------------------------------------------------------------------
Annual revenues per
residential customer $ 406.29 $ 438.61 $ 458.82
- -----------------------------------------------------------------------------
Annual residential use
per customer (Mcf) 73.46 73.20 79.53
- -----------------------------------------------------------------------------
</TABLE>
1995 vs. 1994
Distribution operating income for 1995 was $158.0 million, an increase of $12.5
million (8.6%) over the $145.5 million earned in 1994. This increase reflects
both decreased operating revenues and decreased operating expenses as discussed
following.
Operating revenues decreased from $1,810.6 million in 1994 to $1,719.4
million in 1995, a decrease of $91.2 million (5.0%), principally due to a
decline in the average cost of purchased gas, a component of the overall sales
rate, from approximately $3.20/Mcf in 1994 to approximately $2.83/Mcf in 1995,
a decrease of approximately $0.37/Mcf (11.6%). This unfavorable revenue impact
was partially offset by (1) increases of 6.5 Bcf (1.8%) and 4.5 Bcf (10.0%) from
1994 to 1995 in total sales volumes and transported volumes, respectively, and
(2) rate increases obtained in certain jurisdictions, see "Regulatory Matters"
elsewhere herein.
"Purchased gas cost" decreased from $1,128.7 million in 1994 to $1,015.2
million in 1995, a decrease of $113.5 million (10.1%), principally due to the
11.6% decrease in the average cost of gas in 1995 as discussed preceding,
partially offset by the 6.5 Bcf increase in 1995 sales volumes. Gross margin
("Natural gas sales" minus the cost of purchased gas) increased from $641.2
million in 1994 to $663.4 million in 1995, an increase of $22.2 million (3.5%),
principally due to the rate increases and increased sales volumes as discussed
preceding.
Operating expenses, exclusive of purchased gas cost, increased from $536.4
million in 1994 to $546.2 million in 1995, an increase of $9.8 million (1.8%),
principally due to (1) increased operations and maintenance expense due to
increased costs for labor and related benefits and (2) increased depreciation
expense due to increased investment, including the transfer to Distribution of
certain Corporate assets during 1995.
1994 vs. 1993
Distribution operating income for 1994 was $145.5 million, a decrease of $14.6
million (9.1%) from the $160.1 million earned in 1993. This decrease reflects
both reduced operating revenues and reduced operating expenses as discussed
following.
Operating revenues decreased from $1,907.0 million in 1993 to $1,810.6
million in 1994, a decrease of $96.4 million (5.1%), principally due to (1)
warmer 1994 weather, 11,771 total degree days in 1994 vs. 13,003 degree days
in 1993, which was largely responsible for a 21.2 Bcf (6.6%) decline in
residential and commercial sales volumes and (2) a decrease in the average
cost of gas of approximately $0.11/Mcf (3.3%) from $3.31/Mcf in 1993 to
$3.20/Mcf in 1994 (the cost of gas is a component of the sales rate).
Partially offsetting these unfavorable revenue impacts were annual rate
increases implemented at various points during 1994 in Oklahoma, Arkansas and
Minnesota, as well as annual cost-of-service adjustments granted in 1994 in
other jurisdictions.
"Purchased gas cost" declined by $96.8 million (7.9%) from 1993 to 1994
due to the combined effects of decreased sales volumes and the
N O R A M 37
<PAGE> 6
decline in the average cost of gas as described preceding. The gross margin
("Natural gas sales" minus the cost of purchased gas) increased by
approximately $1 million from 1993 to 1994, despite the decrease in sales
volume, largely due to the rate increases described preceding.
Operating expenses, exclusive of purchased gas cost, increased by
$15.0 million (2.9%) from 1993 to 1994 principally due to (1) increased
1994 operations and maintenance expense due to increased costs for labor
and related benefits and (2) increased depreciation expense due to
increased investment.
INTERSTATE PIPELINES
The Company's interstate pipeline business is conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), together with certain subsidiaries and affiliates (collectively,
"Pipeline"). NGT owns and operates an interstate natural gas pipeline system
consisting of approximately 6,400 miles of transmission lines located in
portions of Arkansas, Louisiana, Mississippi, Missouri, Kansas, Oklahoma,
Tennessee and Texas, and which includes three natural gas storage facilities.
MRT owns and operates an interstate pipeline system consisting of approximately
2,200 miles of transmission lines serving principally the greater St. Louis
area in Missouri and Illinois, and which includes three natural gas storage
facilities. The Company's natural gas gathering activities subsequent to 1993
and wholesale energy marketing activities for all periods, previously included
with Pipeline, are now separately reported, see "General", "Wholesale Energy
Marketing" and "Natural Gas Gathering" ("NFS") elsewhere herein. The Company
has an agreement with ANR Pipeline Company for the lease of certain
transmission capacity, see "Transportation Agreement" under "Commitments and
Contingencies" elsewhere herein.
In recognition of the economic impact of ratemaking, the Company applies
the provisions of SFAS 71 to MRT, and also applied these provisions to NGT until
December 31, 1992. As changes in NGT's economic and regulatory environment
began to subject NGT to increasing competitive pressures with an associated
decrease in earnings, the Company undertook an analysis and determined that it
was unlikely that it could take steps, through the regulatory process or
otherwise, that would cause NGT to return to a situation in which collection of
its traditional cost-based rates was probable. Accordingly, at December 31,
1992, the Company ceased to apply the provisions of SFAS 71 to NGT and,
pursuant to the provisions of Statement of Financial Accounting Standards No.
101, "Regulated Enterprises" "Accounting for the Discontinuance of Application
of FASB Statement No. 71", the Company (1) wrote-off those NGT assets which
would not be recorded by unregulated enterprises, principally amounts deferred
pursuant to FERC Order 528 ($237.9 million), (2) wrote down certain assets to
the lower of cost or market ($27.0 million), (3) accrued for cost in excess of
expected recovery for certain gas purchase contracts for which recovery could
no longer be anticipated through regulatory mechanisms ($19.9 million) and (4)
wrote down certain of its gathering assets pursuant to impairment guidelines
applicable to unregulated enterprises ($29.7 million). This pre-tax charge of
$314.5 million ($195.0 million after-tax) is included in the Company's 1992
Statement of Consolidated Income under the caption "Extraordinary item, less
taxes". This charge had no effect on NGT's ability to include the underlying
costs in its regulated rates and did not affect its efforts to collect such
rates from its customers.
In June 1993, the Company completed the sale of its intrastate pipeline
business as conducted by Louisiana Intrastate Gas Corporation ("LIG") to
Equitable Resources, Inc. ("Equitable") for $191 million in cash, and agreed
to indemnify Equitable against certain exposures, for which the Company has
established reserves equal to expected claims under the indemnity. The
following data and related discussion exclude LIG's results of operations for
the six months ended June 30, 1993, during which period LIG earned $5.6 million
of operating income on total throughput of 103.4 million MMBtu.
In February 1996, Pipeline announced a reorganization plan which resulted
in the elimination of a total of approximately 275 positions at NGT and MRT. The
reorganization plan is intended to allow Pipeline to operate more efficiently,
improving its ability to compete in its market areas. The Company expects to
record a first-quarter 1996 charge of less than $20 million associated with the
reorganization plan, which amount is expected to be substantially offset by the
associated cost savings during 1996.
NGT and MRT are regulated by the FERC (see "Regulatory Matters" elsewhere
herein) and implemented "unbundled" services pursuant to FERC Order 636 ("Order
636") in September and November 1993, respectively. Certain financial line
items and statistics are not comparable before and after these dates due, in
part, to the election of many customers to switch from sales to transportation
service which has the effect of transferring revenues from sales to
transportation and removing the cost of gas from both revenues and expenses.
As indicated in the accompanying table, Pipeline had revenues of $160.9
million, $171.6 million and $258.8 million in 1995, 1994 and 1993,
respectively, from sales to and transportation for Distribution, representing
46.4%, 42.8% and 42.9% of Pipeline's total operating revenues in these
respective years. Throughput associated with Distribution was approximately 15%
of Pipeline's total throughput in each year presented. These services are
provided pursuant to contractual arrangements, some of which are scheduled to
expire in 1996. The Company currently expects that services will continue to be
provided by Pipeline to Distribution in a manner which will not result in a
material and continuing decrease in Pipeline's earnings in comparison to the
historical trend, although negotiations are not yet completed and changes in
these arrangements are subject to regulatory approval. In addition, during
1995, Pipeline had revenues of approximately $58 million, approximately 16.7%
of Pipeline's total operating revenues, from sales to and transportation for
Laclede Gas Company (the local gas distribution company which serves the
greater St. Louis, Illinois area) pursuant to several long-term firm
transportation and storage agreements which expire in 1999.
38 N O R A M
<PAGE> 7
INTERSTATE PIPELINES - FINANCIAL RESULTS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(millions of dollars) 1995 1994 1993
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales
Sales to Distribution $ 64.9 $ 71.5 $ 218.3
Sales for resale and other 35.9 90.9 233.0
- ----------------------------------------------------------------------------
Total gas sales revenue 100.8 162.4 451.3
- ----------------------------------------------------------------------------
Transportation revenue
Distribution 96.0 100.1 40.5
Unaffiliated 149.9 138.1 110.9
- ----------------------------------------------------------------------------
Total transportation
revenue 245.9 238.2 151.4
- ----------------------------------------------------------------------------
Total operating revenues 346.7 400.6 602.7
- ----------------------------------------------------------------------------
Purchased gas cost 87.5 148.1 306.2
Operations and maintenance 61.8 52.7 85.9
Depreciation and amortization 33.7 36.7 43.2
General, administrative and other 59.9 57.7 66.8
- ----------------------------------------------------------------------------
Operating income $ 103.8 $ 105.4 $ 100.6
============================================================================
Average invested capital $ 832.7 $ 931.0 $ 1,040.6
============================================================================
</TABLE>
INTERSTATE PIPELINES - OPERATING STATISTICS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(million MMBtu) 1995 1994 1993
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales
Sales to Distribution 29.6 28.3 49.2
Sales for resale and other 49.9 34.9 65.9
- ----------------------------------------------------------------------------
Total sales 79.5 63.2 115.1
- ----------------------------------------------------------------------------
Transportation
Distribution 111.3 99.3 85.7
Other 863.0 732.5 694.4
- ----------------------------------------------------------------------------
Total transportation 974.3 831.8 780.1
- ----------------------------------------------------------------------------
Elimination(1) (77.5) (59.9) (24.2)
- ----------------------------------------------------------------------------
Total throughput 976.3 835.1 871.0
============================================================================
Average transportation margin
($/MMBtu) $ 0.268 $ 0.305 $ 0.210
- ----------------------------------------------------------------------------
</TABLE>
(1) When sold volumes are also transported by Pipeline, the throughput
statistics will include the same physical volumes in both the sales and
transportation categories, requiring an elimination to prevent the
overstatement of actual total throughput. No elimination is made for volumes
of 196.6 million MMBtu, 145.8 million MMBtu and 158.2 million MMBtu in 1995,
1994 and 1993, respectively, which were transported on both the NGT and MRT
systems.
1995 vs. 1994
Pipeline operating income for 1995 was $103.8 million, a decrease of $1.6
million (1.5%) from the $105.4 million earned in 1994, reflecting a decrease of
$5.0 million at MRT, partially offset by an increase of $3.4 million at NGT.
The decrease in MRT's earnings was largely due to the non-recurring 1994
positive impact of adjustments related to regulatory issues (approximately $3.2
million) and materials inventories (approximately $1.6 million). The
improvement in NGT's operating income was due to several factors including (1)
the positive impact of the 1995 rate case, (2) increased transportation
revenues, (3) a decrease in depreciation expense due to a change in the
depreciation rates associated with certain NGT assets, see "Change in Estimated
Service Lives of Certain Assets" elsewhere herein and (4) a favorable
adjustment to purchased gas cost as discussed following. These favorable NGT
variances were partially offset by the inclusion, in 1994 operating results, of
a favorable adjustment of approximately $4.0 million related to settlement of a
rate case. For additional information on regulatory issues, see "Regulatory
Matters" elsewhere herein.
Revenues from "Sales to Distribution" and "Sales for resale and other"
decreased from 1994 to 1995 by $6.6 million (9.2%) and $55.0 million (60.5%),
respectively. The former reduction is largely due to a 16% reduction from 1994
to 1995 in spot gas prices (a component of the sales rate), while the latter
reduction is largely due to the sale in 1994, at cost, of approximately $50.5
million of gas in storage inventory by MRT to its customers in conjunction with
implementation of services under Order 636.
Transportation revenues from Distribution decreased by $4.1 million (4.1%)
from 1994 to 1995 primarily due to (1) the favorable rate case adjustment as
described preceding and (2) Distribution affiliate volumes subject to the
"Capacity Release" program whereby volumes dedicated to the Distribution
affiliate are released (and billed) to third-party shippers. This program
results in a shift of these revenues from Distribution to unaffiliated revenues.
Additionally, 1994 transportation revenues from Distribution include revenues
related to services in the state of Kansas, which properties were sold by a
distribution affiliate in September 1994 and, accordingly, are not included in
1995 revenues. Unaffiliated transportation revenue increased by $11.8 million
(8.5%) primarily due to the shift from Distribution revenues mentioned
previously and incremental third-party transportation volumes which increased by
130.5 million MMBtu (17.8%). The average transportation margin decreased by
$0.037/MMBtu due to market forces which affect the differential in the delivered
price of gas at various points in the nation's natural gas delivery grid.
Total purchased gas cost decreased by $60.6 million (40.9%) from 1994 to
1995 principally due to the transfer of storage gas to customers in 1994 and the
reduction in the 1995 average market price of gas as discussed preceding. In
addition, 1995 purchased gas cost includes approximately $2.0 million of NGT
fuel usage in excess of tariff-allowed fuel recoveries from customers. Under the
present rate settlement, the fuel recovery percentage is adjusted each May and
November, including a provision for over or under recovery of fuel used in the
previous six-month period. The decrease in 1995 gas prices discussed preceding
also adversely affected the 1995 margin on gas sales due to purchases under
certain contracts which do not vary directly with spot market prices, although
1995 purchased gas cost also includes a favorable adjustment of approximately
$2.5 million resulting from the securing of supplies of gas at lower than
expected prices for delivery to Distribution under a fixed-price sales
commitment, see "Credit Risk and Off-Balance-Sheet Risk" under "Commitments and
Contingencies" elsewhere herein.
N O R A M 39
<PAGE> 8
"Operations and maintenance" expense ("O&M") increased by $9.1 million
(17.3%) from 1994 to 1995 due to a number of factors including a $5.7 million
increase in transportation expense. Approximately $2.1 million of the increase
in transportation expense is related to transportation fees paid to NFS. The
gathering assets of NGT were transferred to NFS effective February 1, 1995 (see
"Natural Gas Gathering" elsewhere herein) and, subsequent to this date, a
transportation fee is paid to NFS for gas purchased by NGT at the wellhead and
delivered to NGT through NFS's gathering systems. The remainder of the variance
in transportation expense principally relates to payments to the Gas Research
Institute, which amounts are collected from customers through a surcharge,
thereby offsetting the expense through increased transportation revenues. Prior
to the middle of 1995, these payments were recorded as a "flow through" with no
effect on income or expense. Other factors contributing to the increase in 1995
O&M include (1) a non-recurring 1994 transfer to inventory of approximately $1.6
million of cost previously expensed, (2) approximately $2.7 million of 1995
expense resulting from a FERC compliance audit, (3) increased 1995 labor cost
principally due to a reduction in labor charged to capital projects and (4) the
write-off of certain clearing account balances. These negative variances were
partially offset by reduced 1995 bad debts expense.
"Depreciation and amortization" decreased by $3.0 million (8.2%) from 1994
to 1995 principally due to the previously mentioned change in the estimated
service lives of certain NGT assets. This change was effective in July 1995,
reduced 1995 depreciation expense by $3.4 million and represents an annualized
expense decrease of $6.8 million.
"General, administrative and other" increased by $2.2 million (3.8%) from
1994 to 1995. Increased general and administrative expense accounts for $1.0
million (45.5%) of the increase, with the remainder primarily due to increased
property taxes reflecting higher 1995 millage rates in certain taxing
jurisdictions.
1994 vs. 1993
The 1993 tabular data presented preceding includes the results of operations of
NGT's natural gas gathering activities which were transferred to NFS in
February 1995, see "Natural Gas Gathering" elsewhere herein. During 1993, the
Company estimates that these activities contributed approximately $2.7 million
of operating income to Pipeline's operating results, although the integrated
nature of these operations during 1993 makes any such calculation problematic.
To the extent practicable, the following discussion of significant changes in
year-to-year operating results excludes the impact of the removal of the
results of operations for the transferred gathering business.
Operating income for 1994 was $105.4 million, an increase of $7.5 million
(7.7%) over the $97.9 million earned in 1993 (exclusive of gathering as
discussed preceding). Approximately $3.0 million (40.0%) of this increase is due
to improved margins on gas sales and transportation services, principally due to
regulatory matters as discussed preceding, with the remainder largely due to
reduced operating expenses as discussed following.
"Sales to Distribution" and "Sales for resale and other" decreased by
$146.8 million (67.2%) and $138.7 million (60.4%) from 1993 to 1994,
respectively, while "Purchased gas cost" decreased by $158.1 million (51.6%),
principally due to the previously discussed effects of the implementation of
Order 636. Also contributing to the reduction in "Sales to Distribution" was a
non-recurring one-time sale by NGT of approximately $28.5 million of gas in
storage, at cost, to a distribution affiliate. Transportation revenues from
Distribution and "Other transportation revenues" increased by $59.6 million
(147.2%) and $44.2 million (47.1%), respectively, primarily due to restructured
services under Order 636. Although transportation volumes increased by only 6.6%
in 1994, transportation revenues increased by 77.2% largely due to the
implementation of straight fixed variable rate design ("SFV"). Under SFV, a
larger portion of total costs are included in the demand component of the
transportation rate. Accordingly, when volumes actually transported are less
than the contract demand level, revenues will be higher for the same volume than
under the prior rate design.
"Operations and maintenance" expense decreased by $26.6 million (33.5%)
from 1993 to 1994, principally due to a $27.1 million decrease in transportation
expense paid to third-party pipelines, partially offset by higher labor and
other operating supplies and expenses. The reduced third-party transportation
expense is largely due to interstate pipeline customers making their own
transportation arrangements with third parties for gas sourced off-system, which
cost was previously expensed by Pipeline and recovered through the overall sales
rate.
"General, administrative and other" decreased by $4.5 million (7.2%) from
1993 to 1994, principally due to (1) a non-recurring $2.0 million payment in
1993 for certain severance costs and (2) a $1.9 million reduction in 1994 taxes
other than income. The reduction in taxes other than income is largely due to
reduced property taxes resulting from restructured services under Order 636,
pursuant to which Pipeline no longer owns the majority of gas in its storage
facilities. In addition, Pipeline recognized reductions in ad valorem taxes as a
result of the spindown of NGT as a separate subsidiary of NorAm in March 1993.
WHOLESALE ENERGY MARKETING
The Company's marketing of natural gas and risk management services to natural
gas resellers and certain large volume industrial consumers is principally
conducted by NorAm Energy Services, Inc., together with certain affiliates
(collectively, "NES"). NES, previously reported as a part of Pipeline,
historically has operated primarily in those states served by the NGT and MRT
systems but recently has had significant sales in various other states as it
seeks to extend its activities throughout North America. In addition, in recent
periods, NES has begun to market electricity in wholesale markets.
To minimize the risk from market fluctuations in the price of natural gas
and transportation, the Company, generally through NES, enters into futures
transactions, swaps and options in order to hedge certain commitments to buy,
sell and transport natural gas. Some of these financial instruments carry
off-balance-sheet risk, see "Credit Risk and Off-Balance-Sheet Risk" under
"Commitments and
40 N O R A M
<PAGE> 9
Contingencies" elsewhere herein. Gains and losses resulting from changes in the
market value of the various financial instruments utilized as hedges are
deferred and recognized as a component of expense when the physical volumes are
purchased, sold or transported under the relevant contracts.
WHOLESALE ENERGY MARKETING - FINANCIAL AND OPERATING RESULTS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------
(millions of dollars, except as noted) 1995 1994 1993
- ---------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales
Unaffiliated sales $ 771.4 $ 537.4 $ 386.2
Sales to Distribution 71.1 75.0 44.6
Sales to Pipeline 57.1 29.3 97.1
Other affiliated sales 5.8 5.7 2.8
- --------------------------------------------------------------------------------
Total gas sales revenue 905.4 647.4 530.7
- --------------------------------------------------------------------------------
Electricity sales 12.2 0.8 -
Other operating revenues 0.8 1.2 0.8
- --------------------------------------------------------------------------------
Total operating revenues 918.4 649.4 531.5
- --------------------------------------------------------------------------------
Purchased gas costs
Unaffiliated 787.9 574.5 487.5
Affiliated 62.3 31.0 30.3
Transportation and storage expense 43.2 38.0 29.4
Electricity purchases and
transmission costs 11.5 0.7 -
- --------------------------------------------------------------------------------
Operating margin 13.5 5.2 (15.7)
General and administrative 9.3 8.2 6.7
- --------------------------------------------------------------------------------
Subtotal 4.2 (3.0) (22.4)
Contract termination charge(1) - - 34.2
- --------------------------------------------------------------------------------
Operating income (loss) $ 4.2 $ (3.0) $ (56.6)
================================================================================
Natural gas sales volume (Bcf) 512.8 317.9 244.7
Average sales margin ($/Mcf) $ 0.026 $ 0.016 $ N/A
- --------------------------------------------------------------------------------
</TABLE>
(1) In December 1993, the Company completed a comprehensive settlement
agreement ("the Settlement") with certain subsidiaries of Samson Investment
Company ("Samson"), terminating or modifying a number of outstanding
contractual arrangements, including the Company's obligation to pay a
reservation fee for the right to purchase certain quantities of gas at
market prices through 1999, see the discussion following. The Settlement
resulted in a $34.2 million pre-tax charge to earnings, set forth in the
Company's Statement of Consolidated Income for 1993 as "Contract
termination charge".
1995 vs. 1994
Operating income for NES improved from a loss of $3.0 million in 1994 to income
of $4.2 million in 1995, an increase of $7.2 million. This improvement
reflected both increased operating revenues and increased operating expenses as
discussed following.
Operating revenues increased from $649.4 million in 1994 to $918.4 million
in 1995, an increase of $269.0 million (41.4%), principally due to an increase
of 194.9 Bcf (61.3%) in natural gas sales volumes, partially offset by a
decrease of approximately $0.271/Mcf (13.3%) from 1994 to 1995 in the average
natural gas sales price. The increase in 1995 natural gas sales volumes was
principally due to an increased staff of marketers executing a more nationally
focused marketing effort with an emphasis on increasing market share,
principally targeting end-use customers in the industrial, local distribution
and electric generation sectors. The decline in the average sales price of
natural gas from 1994 to 1995 principally was reflective of market conditions
which produced a general decline in spot market prices (the cost of gas is a
component of the overall sales rate).
"Purchased gas costs" increased from $605.5 million in 1994 to $850.2
million in 1995, an increase of $244.7 million (40.4%), principally due to the
increased 1995 sales volume as discussed preceding, partially offset by a
decline of approximately $0.247/Mcf (13.0%) from 1994 to 1995 in the average
cost of purchased gas. This decline in the average cost of purchased gas was
principally due to a general decline in spot market prices as discussed
preceding and, to a lesser extent, the increased use of risk management
strategies to obtain lower-cost term natural gas supplies. "Transportation and
storage expense" increased from $38.0 million in 1994 to $43.2 million in 1995,
an increase of $5.2 million (13.7%), principally in support of the increased
level of sales as discussed preceding. "Electricity sales" and "Electricity
purchases and transmission costs" of $12.2 million and $11.5 million,
respectively, in 1995 represented increases of $11.4 million and $10.8 million,
respectively from 1994. During 1995, NES increased both its emphasis on
electricity sales and its electric marketing staff in anticipation of increased
access to electric power markets.
The operating margin increased from $5.2 million in 1994 to $13.5 million
in 1995, an increase of $8.3 million (159.6%), reflective of both an increase in
total sales volume as discussed preceding and an increase in the average sales
margin. The increase in the average sales margin from $0.016/Mcf in 1994 to
$0.026/Mcf in 1995, an increase of $0.01/Mcf (62.5%), was principally due to the
more intense and focused marketing efforts as discussed preceding, together with
increased use of risk management capabilities and expanded use of cyclable
storage.
The increase of $1.1 million (13.4%) in "General and administrative" from
1994 to 1995 was principally due to staffing increases made in support of the
increased level of 1995 sales activity as discussed preceding.
1994 vs. 1993
Operating income improved from a loss of $22.4 million (before the "Contract
termination charge") in 1993 to a loss of $3.0 million in 1994, an improvement
of $19.4 million, reflecting both increased operating revenues and increased
operating expenses as discussed following.
Operating revenues increased from $531.5 million in 1993 to $649.4 million
in 1994, an increase of $117.9 million (22.2%), principally due to an increase
of 73.2 Bcf (29.9%) in natural gas sales volumes, partially offset by a decrease
of approximately $0.132/Mcf (6.1%) in the average natural gas sales price from
1993 to 1994. The increased sales volumes principally reflected a more
aggressive marketing program which resulted in (1) increased sales in the
mid-continent region with focus on industrial, local distribution and electric
generation markets and (2) limited penetration into local distribution markets
in the Northeast. The decline in the average sales price for natural gas
N O R A M 41
<PAGE> 10
from 1993 to 1994 principally was reflective of market conditions which
produced an overall decline in the spot market price of natural gas.
Additionally, "Sales to Pipeline" of $29.3 million in 1994 represented a
decline of $67.8 million from 1993 principally due to the November 1993
implementation of Order 636 by MRT (see "Interstate Pipelines" elsewhere
herein), which substantially eliminated its gas merchant function. MRT had
previously purchased a significant portion of its system supply gas from NES.
Purchased gas cost increased from $517.8 million in 1993 to $605.5 million
in 1994, an increase of $87.7 million (16.9%), principally due to the increased
sales volume as discussed preceding, partially offset by a decline of
$0.211/Mcf (10.0%) in the average cost of gas from 1993 to 1994. In addition,
the cost of purchased gas for 1993 includes approximately $10.0 million
attributable to a reservation fee which was discontinued at December 31, 1993
as discussed preceding. "Transportation and storage expense" increased from
$29.4 million in 1993 to $38.0 million in 1994, an increase of $8.6 million
(29.3%), principally in support of the increased sales volume as discussed
preceding.
The operating margin improved from a loss of $(15.7) million in 1993 to
income of $5.2 million in 1994, an improvement of $20.9 million, principally
due to the increased sales volume and discontinuance of a reservation fee as
discussed preceding. In addition, the average sales margin in 1994 reflected a
smaller negative impact associated with purchases under certain fixed-price gas
purchase contracts.
The increase of $1.5 million (22.4%) in "General and administrative" from
1993 to 1994 was principally due to increases in staffing made in support of the
increased sales activity as discussed preceding.
NATURAL GAS GATHERING
On February 1, 1995, pursuant to a "spindown" order from the FERC, the Company
transferred the natural gas gathering assets of NGT into the Company's
wholly-owned subsidiary, NorAm Field Services Corp. ("Field Services"). These
assets consist principally of approximately 3,500 miles of gathering pipelines
which collect gas from more than 200 separate systems located in major
producing fields in Oklahoma, Louisiana, Arkansas and Texas. Field Services is
not generally subject to cost-of-service regulation, although the spindown
order required that it offer to continue any preexisting gathering services
generally under the terms of NGT's tariff, including the applicable stated
maximum gathering rate of $0.1417/MMBtu for a two-year period ("the Default
Contract"), except to the extent that separate terms and conditions have been
negotiated. While various parties, including Field Services, have appealed
certain of the FERC's findings and the case is pending before the D.C. Circuit
Court of Appeals, if the Default Contract provisions are not reversed in the
interim, Field Services will be unable to realize the full market value for
certain of its services until February 1, 1997. Competition from other
gatherers, including pipelines and producer-owned facilities, remains high in
this segment of the business. The Company, nevertheless, expects that efforts
will be made in certain states to enact legislation to regulate gathering rates
and services but the Company currently expects that any such efforts will be
successful only to the extent of providing for complaint-type proceedings
alleging undue discrimination or similar "light-handed" regulatory approaches.
Natural Gas Gathering ("NFS") as presented and discussed following also
includes Arkla Chemical Company which performs gas processing, liquids
extraction and marketing activities, generally in conjunction with certain of
NFS's gathering activities. In the future, the majority of NFS's existing gas
processing activities will be conducted by Waskom Gas Processing Company, a
joint venture of NFS and NGC Corp. (an affiliate of Natural Gas Clearinghouse).
During 1993, a significant portion of NFS's total throughput was billed
together with the interstate transmission services and not separately
identified in all cases. NFS's 1993 results are, therefore, not comparable with
its results for 1994 and 1995 and, accordingly, have been included with
Pipeline's 1993 operating results as set forth elsewhere herein.
NATURAL GAS GATHERING - FINANCIAL AND OPERATING RESULTS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------
(millions of dollars, except as noted) 1995 1994
- -----------------------------------------------------------------------
<S> <C> <C>
Gathering revenue $ 27.3 $ 22.6
Natural gas sales 20.2 -
Products extraction 7.6 7.9
Other operating revenue 1.2 2.2
- -----------------------------------------------------------------------
Total operating revenues 56.3 32.7
- -----------------------------------------------------------------------
Gas purchased, net 20.0 -
Cost of sales 4.7 4.7
Operation and maintenance 13.0 11.1
Administrative expense 4.5 3.9
Depreciation 4.1 6.2
Taxes other than income 1.3 1.2
- -----------------------------------------------------------------------
Operating income $ 8.7 $ 5.6
=======================================================================
Average invested capital $ 97.8 $ 102.1(1)
Total throughput (Bcf) 232.3 229.7
Margin/unit of throughput ($/MMBtu) $ 0.136 $ 0.122
Number of receipt points 2,887 2,871
- -----------------------------------------------------------------------
</TABLE>
(1) Balance as of December 31, 1994; the December 31, 1993 balance is not
available for the computation of an average.
During 1995, Field Services' first year as a separate subsidiary of NorAm
and its first year under a revised regulatory scheme as described preceding,
NFS's operating income was $8.7 million, an increase of $3.1 million (55.4%)
over the $5.6 million earned in 1994. This increase was principally
attributable to two factors as described following.
Despite downward pressure from competition and low wellhead commodity
prices, gross margin per unit of throughput increased from $0.122/MMBtu in
1994 to $0.136/MMBtu in 1995, an increase of $0.014/MMBtu (11.5%) largely due
to new compression, nomination, balancing and marketing services provided to
NFS customers. NFS's operating revenues for 1995 reflect $20.2 million of gas
sales revenues (with a corresponding, though slightly smaller, amount of
purchased gas cost), reflecting NFS's gas marketing and balancing activities
performed in support of its gathering customers.
42 N O R A M
<PAGE> 11
Pursuant to a review of natural gas reserves both attached and proximate to
NFS's gathering systems, in July 1995, NFS changed the depreciation rates
associated with certain of its facilities. This change had the effect of
decreasing NFS's 1995 depreciation expense by $2.0 million, and represents an
annualized decrease of $4.0 million.
Other expenses (exclusive of "Gas purchased, net" and "Depreciation")
increased by approximately $2.6 million (12.4%) from 1994 to 1995, largely due
to a $2.2 million increase in compression rental and related supplies and
expenses incurred in support of projects to lower pressures and increase
deliverability, together with additional staffing costs incurred to support the
additional services as described preceding.
NFS's total throughput increased from 229.7 Bcf in 1994 to 232.3 Bcf in
1995, an increase of 2.6 Bcf (1.1%), as increases in throughput attributable to
low pressure projects and other enhanced gathering services were partially
offset by approximately 6.5 Bcf of gas which was shut in by producers due to low
spot market gas prices. In general, NFS's gathering business is susceptible to
curtailments in production and drilling as a result of low gas prices and, to a
minor extent, state proration requirements.
RETAIL ENERGY MARKETING
The Company's marketing of natural gas and related services to those industrial
and commercial customers located behind the "city gate" of local gas
distribution companies but not utilizing traditional "bundled" utility service,
as well as certain industrial customers served by third-party pipelines on
which the Company holds capacity, is principally carried out by NorAm Energy
Management, together with certain affiliates (collectively, "NEM"). Certain of
NEM's activities, while not subject to traditional cost-of-service rate
determination, are subject to the jurisdiction of various regulatory bodies as
to the allocation of joint costs between such activities and certain of the
Company's regulated activities. This recently-formed business unit includes a
number of activities previously included with Distribution (see "Natural Gas
Distribution" elsewhere herein) and will execute the Company's plan for serving
these markets more coherently and effectively. NEM had sales to five chemical
facilities, operated by its largest customer and owned by a total of five
customers, which collectively represented approximately 38.3 Bcf (22.6%), 11.9
Bcf (10.2%) and 7.0 Bcf (8.6%) of NEM's total gas sales volumes in 1995, 1994,
and 1993, respectively.
NEM's results of operations as presented following also include the
Company's home care service activities ("HCS"), including (1) appliance sales
and service, (2) home security services and (3) resale of long distance
telephone service, the latter two of which businesses are essentially in a
"start-up" mode. HCS's activities contributed operating income (loss) of
approximately $(0.5) million, $(0.7) million and $1.1 million to NEM's overall
operating results in 1995, 1994 and 1993, respectively. Appliance sales and
service had $45.6 million of operating revenues during 1995, approximately 98.1%
of the total operating revenues derived from HCS's 1995 activities, and provided
substantially all of HCS's operating revenues in prior years. The future results
of operations for these appliance sale and service activities could be affected
by the outcome of certain regulatory proceedings, see "Regulatory Matters"
elsewhere herein.
RETAIL ENERGY MARKETING - FINANCIAL AND OPERATING RESULTS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------
(millions of dollars, except as noted) 1995 1994 1993
- ------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $ 295.8 $ 242.2 $ 234.0
Transportation 3.5 3.6 3.3
Other, principally home
care services 46.6 44.7 40.3
- ------------------------------------------------------------------------
Total operating revenues 345.9 290.5 277.6
- ------------------------------------------------------------------------
Purchased gas costs 270.5 220.9 218.7
Operations, maintenance,
cost of sales and other, principally
home care services 46.6 45.7 40.1
General and administrative 3.3 2.3 0.6
Depreciation and amortization 1.9 1.9 1.7
Taxes other than income 1.4 1.3 1.4
- ------------------------------------------------------------------------
Operating income $ 22.2 $ 18.4 $ 15.1
========================================================================
Natural gas sales volume (Bcf) 169.7 116.6 81.7
Average sales margin ($/Mcf) $ 0.149 $ 0.183 $ 0.187
Transportation volume (Bcf) 25.3 27.7 27.4
- ------------------------------------------------------------------------
</TABLE>
1995 vs. 1994
Operating income for NEM increased from $18.4 million in 1994 to $22.2 million
in 1995, an increase of $3.8 million (20.7%), reflecting both increased
revenues and increased expenses. Approximately $0.2 million of the increase in
operating income was attributable to a decreased operating loss at HCS, with
the balance attributable to NEM's gas sales and transportation activities as
discussed following.
Operating revenues increased from $290.5 million in 1994 to $345.9 million
in 1995, an increase of $55.4 million (19.1%), principally due to an increase of
53.1 Bcf (45.5%) in total sales volume, partially offset by a decrease of
approximately $0.30/Mcf (15.9%) in the average cost of purchased gas (a
component of the sales rate). The increase in 1995 sales volume was principally
due to the addition of several new industrial customers whose operations are
affiliated with those of NEM's largest customer, as well as 21.6 Bcf of
additional sales to NEM's largest customer brought about by its acquisition of
four large chemical plants along the Texas Gulf Coast. The decrease in the
average cost of purchased gas was directly reflective of the decline in spot
market natural gas prices from 1994 to 1995.
"Purchased gas costs" increased from $220.9 million in 1994 to $270.5
million in 1995, an increase of $49.6 million (22.5%), principally due to the
increase in sales volume, partially offset by the decrease in the average cost
of gas as discussed preceding. The decrease in the average sales margin
("Natural gas sales" minus "Purchased gas costs" divided by "Natural gas sales
volume") from $0.183/Mcf in 1994 to $0.149/Mcf in 1995 was principally due to
competitive pressures in NEM's market area which frequently require that NEM
accept lower
N O R A M 43
<PAGE> 12
margins in order to remain competitive in existing markets and/or acquire
incremental business.
1994 vs. 1993
Operating income for NEM increased from $15.1 million in 1993 to $18.4 million
in 1994, an increase of $3.3 million (21.9%), reflecting both increased
revenues and increased expenses. The contribution from HCS declined from
operating income of $1.1 million in 1993 to an operating loss of $0.7 million
in 1994, principally due to an increased allocation of costs from Minnegasco's
regulated operations pursuant to rate proceedings. This unfavorable impact was
more than offset by improved results from NEM's gas sales and transportation
activities as discussed following.
Operating revenues increased from $277.6 million in 1993 to $290.5 million
in 1994, an increase of $12.9 million (4.6%), principally due to an increase of
34.9 Bcf (42.7%) in total sales volume and increased HCS revenues, partially
offset by a decrease of approximately $0.78/Mcf (29.2%) in the average cost of
purchased gas. The increase in natural gas sales volume was principally due to
the 1994 addition of both new on-system industrial customers and off-system
sales. The decrease in the average cost of purchased gas generally was
reflective of the decline in spot market natural gas prices from 1993 to 1994,
but also reflected NEM's ability to purchase gas more competitively in support
of its off-system marketing activities. The increased HCS revenues were
principally due to an increase in residential service contracts.
"Purchased gas cost" increased from $218.7 million in 1993 to $220.9
million in 1994, an increase of $2.2 million (1.0%), as the increase in 1994
sales volume was largely offset by the decline in the average cost of gas as
discussed preceding.
CORPORATE AND OTHER
The $2.6 million increase in the operating loss from 1994 to 1995 was
principally due to (1) the expiration of a forward oil sale agreement in June
1995, pursuant to which $1.9 million of operating income was recognized in 1994
but only $0.9 million in 1995 and (2) 1995 expenditures associated with the
Company's evaluation of international investment opportunities. These
unfavorable variances were partially offset by a decline in 1995 depreciation
expense due to the transfer of certain Corporate assets to another business
unit in early 1995.
The $9.9 million decrease in the operating loss from 1993 to 1994 is
principally due to (1) increased 1993 expense resulting from amounts accrued
under certain employee benefit plans, (2) 1993 accruals for certain
intercompany billings which were not contractually permitted to be recorded at
their full face value by the receiving business unit, (3) a decrease in 1994
expense related to the Company's Long-Term Incentive Plan and Incentive Equity
Plan and (4) the 1993 accrual of estimated costs for facilities consolidation,
relocation and related expenses.
NON-OPERATING INCOME AND EXPENSE
Consolidated net income for 1995 was approximately $65.5 million, an
improvement of approximately $17.4 million (36.2%) over the $48.1 million
earned in 1994 while, as discussed preceding, operating income increased by
$22.4 million (8.5%) during the same period. The principal reason for this $5.0
million of increased net expense below the operating income line was an
increase of $21.0 million in income tax expense for 1995, reflecting an
increase in both pre-tax income and the effective tax rate, see Note 2 of Notes
to Consolidated Financial Statements. This unfavorable impact of increased
1995 income tax expense was partially offset by:
o A decrease of $11.4 million in 1995 "Interest expense, net" reflecting
decreases in both the average level of borrowings and the weighted average
interest rate, see "Net Cash Flow from Financing Activities" elsewhere
herein.
o The inclusion, in 1994 results, of $2.1 million of loss from
discontinued operations.
o Decreased 1995 expense of approximately $1.4 million and $1.1 million
attributable to "Other, net" and "Extraordinary item, less taxes",
respectively.
Consolidated net income for 1994 was approximately $48.1 million, an
improvement of approximately $12.0 million (33.2%) over the $36.1 million
earned in 1993 while, as discussed preceding, operating income increased by
$57.0 million during the same period. The principal reasons for this $45.0
million of increased net expense below the operating income line in 1994 were
as follows:
o The inclusion, in 1993 results, of approximately $42.8 million in gains
from sales of property, see Note 1 of Notes to Consolidated Financial
Statements.
o The increase of $10.3 million in 1994 net expense associated with
miscellaneous items of non-operating revenue and expense.
o The decrease of approximately $7.6 million in interest income from 1993
to 1994, largely due to the elimination of a note receivable as part of the
comprehensive settlement agreement with Samson, see "Wholesale Energy
Marketing" elsewhere herein.
o The inclusion, in 1994 results, of $2.1 million in after-tax expense
from discontinued operations, see "Discontinued Operations" following.
These unfavorable impacts were partially offset by:
o A decrease of approximately $12.1 million in 1994 income tax expense,
principally reflecting a decrease in the effective tax rate, see Note 2 of
Notes to Consolidated Financial Statements.
o A decrease of approximately $3.0 million in "Interest expense, net" from
1993 to 1994, principally due to a decreased level of borrowing and a $0.4
million increase in the 1994 allowance for borrowed funds used during
construction.
o A decrease of approximately $2.7 million in the 1994 extraordinary loss
on early retirement of debt.
44 N O R A M
<PAGE> 13
DISCONTINUED OPERATIONS
EXPLORATION AND PRODUCTION
On December 31, 1992, the Company completed the sale of Arkla Exploration
Company to Seagull Energy Corporation ("Seagull") for approximately $397
million in cash, the substantial portion of which was used to reduce the
Company's short-term borrowings. In conjunction with the sale, the Company
agreed to indemnify Seagull against certain exposures, for which the Company
has established reserves equal to anticipated claims under the indemnity. In
conjunction with its 1991 sale of Dyco Petroleum Company, the Company
established a reserve equal to its maximum exposure under the limited indemnity
provisions of the sale agreement.
RADIO COMMUNICATIONS AND ENERGY MEASUREMENT
In conjunction with the purchase of Diversified Energies, Inc. in November
1990, the Company acquired business units that conducted operations in radio
communications ("Johnson") and energy measurement products and systems
("EnScan"). In early 1992, EnScan merged with Itron, Inc. ("Itron") of Spokane,
Washington, a company which manufactures equipment and provides services
similar and complementary to those of EnScan, resulting in an exchange of the
Company's EnScan common stock for shares of Itron common stock (the "Itron
Shares"). After the Company's 1994 sale of 400,000 Itron Shares and its 1995
sale of 80,000 Itron Shares, each at approximately book value (yielding cash
proceeds of approximately $7.2 million and $1.4 million, respectively), at
December 31, 1995, the Company's remaining Itron Shares (approximately 1.5
million) represented ownership of approximately 12.3% of the combined
enterprise, which is managed by Itron. Based on price quotations on the NASDAQ,
the market value (and carrying value) of the Company's investment at December
31, 1995 was approximately $50.7 million, and had increased to approximately
$65.4 million at March 1, 1996, representing unrealized gains of $15.3 million
(net of tax of $8.7 million) and $24.6 million (net of tax of $14.1 million),
respectively, which gains are reported as a separate component of stockholders'
equity. The Company intends to dispose of its remaining Itron Shares over the
next several years, at times to be determined principally by economic factors
in the markets available for the sale or exchange of such securities. While
there are other ways in which the Company can monetize its investment in the
Itron Shares, in general, the market for the Itron Shares on the NASDAQ is not
sufficiently liquid to allow the Company to dispose of a significant portion of
its investment in a single transaction without accepting a significant discount
from the quoted price. In July 1992, the Company sold the common stock of
Johnson for total consideration of approximately $40 million, approximately its
book value, receiving cash proceeds of approximately $15 million at closing and
retaining an investment currently valued at approximately $5 million.
UNIVERSITY SAVINGS ASSOCIATION
University Savings Association was a wholly-owned subsidiary of Entex, Inc.
until its sale to a private group in May 1987, prior to the Company's February
1988 merger with Entex, see Note 1 of Notes to Consolidated Financial
Statements.
LIQUIDITY AND CAPITAL RESOURCES
INVESTED CAPITAL
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------
(millions of dollars) December 31,
1995 1994 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Long-term debt, less current maturities $ 1,474.9 $ 1,414.4 $ 1,629.4 $ 1,783.1 $ 1,551.5
Total equity 767.3 717.4 708.0 712.9 948.0
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization 2,242.2 2,131.8 2,337.4 2,496.0 2,499.5
Short-term debt, including current maturities 128.8 274.6 192.4 120.0 772.6
- -----------------------------------------------------------------------------------------------------------------------------
Total invested capital $ 2,371.0 $ 2,406.4 $ 2,529.8 $ 2,616.0 $ 3,272.1
==============================================================================================================================
Long-term debt as a percent of total capitalization 65.8% 66.3% 69.7% 71.4% 62.1%
Equity as a percent of total capitalization 34.2% 33.7% 30.3% 28.6% 37.9%
Total debt as a percent of total invested capital 67.6% 70.2% 72.0% 72.7% 71.0%
</TABLE>
CASH FLOW ANALYSIS
The following discussion of cash flows should be read in conjunction with the
Company's Statement of Consolidated Cash Flows and the additional cash flow
information provided in Note 1 of Notes to Consolidated Financial Statements.
NET CASH FLOW FROM FINANCING ACTIVITIES
The Company meets its needs for short-term financing through its revolving
credit facility with a major money center bank as agent and various other
commercial banks, through informal lines of credit and through a sale of
receivables facility, see "Net Cash Flow from Operating Activities" following.
In late 1995, the Company renewed, revised and extended its principal
short-term credit facility ("the Facility") with Citibank, N.A. as Agent and a
group of 18 other commercial banks which now provides a $400 million commitment
to the Company through December 11, 1998. Borrowings under the Facility are
unsecured (the stock of NGT and MRT, collateral under the prior facility, have
been released) and, at the option of the Company, bear interest at various
Eurodollar and domestic rates plus a credit spread, which credit spread is
subject to adjustment
N O R A M 45
<PAGE> 14
based on the rating of the Company's senior debt securities. The Company pays a
facility fee on the total commitment to each bank each year, currently 1/4% and
subject to decrease based on the Company's debt rating, and will pay incremental
rates of 1/8% to 1/4% on outstanding borrowings in excess of $200 million. Each
of these fees reflects a decline from the fee under the prior facility.
The Company had no borrowings under the Facility at December 31, 1995 or at
March 1, 1996, and had $10 million of borrowings under informal lines of credit
at December 31, 1995. The Company had, therefore, $400 million in capacity under
the Facility at March 1, 1996, which capacity is expected to be adequate to
cover the Company's current and projected needs for short-term financing. For
additional information on interest rates and amounts borrowed under short-term
financing agreements, see Note 3 of Notes to Consolidated Financial Statements.
The Facility contains a provision which requires the Company to maintain a
minimum level of total stockholders' equity, initially set at $675 million at
June 30, 1995, and increased annually thereafter by (1) 50% of positive
consolidated net income and (2) 50% of the proceeds (in excess of the first $100
million) from any incremental equity offering made after June 30, 1995. The
Facility also places a limitation of $2,055 million on total debt and a
limitation of $200 million on the amount of outstanding long-term debt which may
be reacquired, retired or otherwise prepaid prior to its maturity. Certain of
the Company's other financial arrangements contain similar provisions. Based on
these restrictions, the Company had incremental capacity for debt issuance,
dividends and debt reacquisitions of $416.3 million, $82.0 million and $200
million, respectively, at December 31, 1995.
The Company's long-term debt financing is obtained through the issuance of
debentures and notes and through a bank term loan as discussed following. The
issuance of additional mortgage bonds is precluded by the Company's unsecured
indenture dated as of December 1, 1986 with Citibank, N.A. The Company expects
that as its long-term debt matures, it will be able to fund these debt
retirements through additional borrowings and/or from cash provided by
operations. For additional information on the Company's outstanding long-term
debt securities, see Note 3 of Notes to Consolidated Financial Statements. In
late 1995, the Company filed a "shelf" registration statement with the
Securities and Exchange Commission pursuant to Rule 415 which will allow the
Company to issue up to $500 million of a wide variety of securities (including
both debt and equity) over an approximately two-year period following the March
1996 effective date of the filing.
In August 1995, the Company issued $200 million of 7.5% five-year notes in
a public offering. The proceeds were used to reduce the Company's bank
borrowings, participation in its sale of receivables program and for general
corporate purposes pending the October 1995 retirement, at maturity, of the
Company's $150 million of 9.45% notes.
In December 1995, the Company entered into a $150 million term loan
agreement ("the Loan") with a group of 18 commercial banks and used the proceeds
to redeem (at par) the $150 million of its 8% Notes due 1997. The Loan bears
interest at LIBOR + 87 1/2 basis points (a rate of 6.4375% at December 31, 1995,
to be reset in June 1996) and the rate is reset each 30, 60, 90 or 180 days at
the option of the Company. The Loan is due in four equal principal payments in
March, June, September and December of the year 2000, and may be repaid in whole
or in part at any time without premium.
REACQUISITIONS OF LONG-TERM DEBT (1)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(millions of dollars)
- --------------------------------------------------------------------------------
Principal Weighted Premium Paid(2)
Year Ended Amount Avg. Interest ----------------------------
December 31, Reacquired Rate Pre-tax Tax Benefit
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1995 $ 170.7(3) 8.2% $ 0.08 $ (0.03)
1994 50.4 9.8% 1.4 (0.3)
1993 $ 88.3 9.8% $ 5.5 $ (1.7)
</TABLE>
(1) The Company will continue to evaluate its debt portfolio and may elect
(subject to availability of funds, limitations contained in its revolving
credit facility and constraints imposed by the terms of the individual
series of debt securities) to refund/refinance additional debt as economic
factors indicate, see Note 3 of Notes to Consolidated Financial Statements.
(2) Includes the write-off of any associated unamortized debt issuance cost and
is reported in the Company's Statement of Consolidated Income under the
caption, "Extraordinary item, less taxes".
(3) Includes $150.0 million of 8% Notes due 1997 redeemed at par as
discussed preceding.
INTEREST RATE SWAPS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(millions of dollars)
- --------------------------------------------------------------------------------
Notional
Amount Unrealized Deferred Interest Rate
Outstanding Loss(1) Gains(2) Fixed/Floating
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
December 31, 1992
Additions $ 575.0 - - -
Terminations (375.0) - - -
December 31, 1993 200.0 $ (2.6) $ 5.0 5.1%/4.5%
Additions 75.0 - - -
Terminations - - - -
December 31, 1994 275.0 (18.0) 2.5 5.1%/6.7%
Additions 100.0 - - -
Terminations (25.0) - - -
December 31, 1995 $ 350.0 $ (0.8) $ 0.8 5.1%/6.6%(3)
- -------------------------------------------------------------------------------
</TABLE>
(1) Market value of swaps at date indicated.
(2) The economic value which transfers between the parties to these swaps is
reported as an adjustment to the effective interest rate on the underlying
debt securities and, when positions are closed prior to expiration, any
material gain or loss is deferred and amortized over the period remaining in
the original term of the swap. The effect of these swaps was to increase
(decrease) interest expense by approximately $(4.6) million, $0.5 million
and $(0.2) million in 1993, 1994 and 1995, respectively.
(3) Does not include swaps which are hedges of anticipated debt issuance as
discussed following.
In recognition of the fact that the Company had unusually low levels of
floating rate debt due, in large part, to the application of cash received from
divestitures, beginning in 1993, the Company entered into a number of interest
rate swaps which, in general, specified that the Company would pay a
LIBOR-based rate on the notional amount of the swap while the counterparty (a
commercial bank) paid a fixed rate, for the purpose of subjecting a reasonable
portion of the Company's debt portfolio to market interest rate fluctuations.
In early
46 N O R A M
<PAGE> 15
1996, the Company terminated the $250 million of such swaps
outstanding, resulting in no material gain or loss.
In late 1995, the Company entered into $100 million of swaps, in which it
agreed to pay a fixed rate of 5.92% on the notional amount for a 5-year period
beginning in April 1997 while the counterparties pay a LIBOR-based rate, for
the purpose of effectively fixing the interest rate on debt expected to be
issued in 1997 for refunding purposes (see Note 3 of Notes to Consolidated
Financial Statements for the maturity dates of the Company's various debt
issues). In early 1996, the Company entered into additional swaps with a total
notional amount of $100 million for the same period and purpose in which it
agreed to pay an average fixed rate of approximately 5.78%.
In order to take advantage of historically low rates and reduce the
Company's exposure to fluctuations in market interest rates arising from its
various LIBOR or A1/P1 commercial paper-based financing facilities as described
elsewhere herein, in February 1996, the Company entered into two swaps of $50
million notional amount each, beginning in March and June 1996, respectively,
and each of which expire at approximately year-end 1997, in which it agreed to
pay an average fixed rate of 4.74% while the counterparty pays a LIBOR-based
rate. The Company expects that it may enter into additional such swaps in the
future.
None of these swaps are "leveraged" and, accordingly, do not represent
exposure in excess of that suggested by the notional amounts and interest rates.
Off-balance-sheet credit risk exists to the extent that counterparties to these
swaps may fail to perform, although all counterparties are commercial banks
which are participants in the Company's revolving credit facility. The Company
routinely reviews the financial condition of these banks (utilizing independent
monitoring services and otherwise) and believes that the probability of default
by any of these counterparties is minimal.
The Company has equipment funding agreements ("EFA's") with affiliates of
major banks which provide for the purchase of vehicles, major work equipment
and, to a lesser extent, computers and other office equipment. For accounting
purposes, assets subject to these EFA's receive operating lease treatment,
with an initial non-cancellable term of one year. At December 31, 1995, the
Company had $14.7 million of available capacity under these EFA's, and
capacity under the EFA's will increase by $14 million in July 1996. The EFA's
extend through July 1997 unless renewed through mutual agreement of the parties.
Since late 1994, the Company has offered a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP") which affords customers and other
interested parties the opportunity to (1) purchase the Company's common stock
("the Common Stock") directly from the Company, avoiding brokerage fees and
commissions and (2) automatically reinvest their dividends in shares of Common
Stock. Sales of Common Stock under the DSPP were immaterial in 1994 and, in
1995, the Company received approximately $9.8 million (net of issuance cost of
approximately $0.7 million) from such sales. The Company also has several
programs pursuant to which shares of Common Stock may be issued or sold to
employees or directors, see Notes 5 and 6 of Notes to Consolidated Financial
Statements.
In December 1993, the Company refunded $34 million in conjunction with the
revision of an agreement for the sale of an interest in certain pipeline
facilities, refunded an additional $50 million in 1995 and will refund
additional amounts, see "Transportation Agreement" under "Commitments and
Contingencies" elsewhere herein.
During 1995, 1994 and 1993, the Company paid common dividends of
$0.07/share each quarter, resulting in total cash expenditures of $34.5
million, $34.3 million and $34.2 million, respectively, and preferred
dividends of $0.75/share each quarter, resulting in total cash expenditures of
$7.8 million in each year. On March 15, 1996, the Company paid dividends of
$0.07/share on common stock and $0.75/share on preferred stock.
NET CASH FLOW FROM OPERATING ACTIVITIES
1995 vs. 1994
As indicated in the accompanying Statement of Consolidated Cash Flows, "Net
cash provided by operating activities" increased from approximately $303.4
million in 1994 to approximately $347.4 million in 1995. This increase of
approximately $44.0 million (14.5%) was principally attributable to:
o An increase of $22.6 million in cash provided by other current
liabilities in 1995 principally due to the relatively larger December 31,
1993 balance in other current liabilities which was paid in 1994.
o An increase of $18.3 million in cash provided by other current assets
in 1995 principally due to the relatively larger December 31, 1994 balance
in other current assets which was collected in 1995.
o An increase of $13.5 million in 1995 income before depreciation,
amortization and deferred taxes.
o An increase of $8.9 million in 1995 cash provided by income taxes
payable, inclusive of the utilization of tax loss carry forwards,
principally due to increased 1995 current tax expense and the relatively
larger December 31, 1993 balance in income taxes payable which was paid in
1994.
o An increase of $8.4 million in 1995 cash provided by miscellaneous
working capital items, including a $2.9 million increase in cash provided
from recoveries under gas contract disputes.
o An increase of $6.2 million in 1995 cash provided from the net of
accounts receivable and accounts payable, principally due to the
seasonality of the Company's businesses.
o An increase of approximately $3.4 million in 1995 cash provided by the
net of discontinued operations, extraordinary items and other miscellaneous
items.
These favorable impacts were partially offset by:
o The increase of $19.8 million in cash used for deferred gas costs in
1995 principally due to purchases of gas in advance of collections from
customers.
o A decrease of $17.5 million in 1995 cash provided by inventories,
principally due to the 1994 sale of the majority of MRT's gas in storage
to its customers, see Note 1 of Notes to Consolidated Financial Statements.
N O R A M 47
<PAGE> 16
The Company has net operating loss carryforwards and an alternative minimum tax
credit carryforward which may reduce its future income tax payments, see Note 2
of Notes to Consolidated Financial Statements.
1994 vs. 1993
As indicated in the accompanying Statement of Consolidated Cash Flows, "Net
cash provided by operating activities" increased from approximately $173.4
million in 1993 to approximately $303.4 million in 1994. This increase of
approximately $130.0 million (75.0%) was principally attributable to the
following:
o An increase of $107.9 million from 1993 to 1994 in cash provided by the
collection of accounts receivable net of accounts payable, principally as a
result of the relatively larger December 31, 1993 accounts receivable
balance which was collected during 1994.
o An increase of $91.9 million from 1993 to 1994 in cash provided by
inventories, approximately $50.5 million of which is attributable to MRT's
non-recurring sale of its gas-in-storage to its customers during 1994 as a
result of implementing service pursuant to FERC Order 636, see Note 1 of
Notes to Consolidated Financial Statements. The balance of the change is
principally due to the normal fluctuations in December 31 gas-in-storage
inventories which result from weather-related changes in the demand for
natural gas.
o An increase of $53.8 million in 1994 from income before non-cash
credits and charges, discontinued operations, gains from sales of property,
extraordinary items, the cumulative effect of accounting changes and
utilization of tax loss carryforwards.
These favorable impacts were partially offset by:
o A decrease of $49.4 million in cash provided from other current assets
in 1994, principally due to the relatively larger December 31, 1992
balance in "Other current assets" which was collected during 1993.
o An increase of $33.2 million in cash used for other current liabilities
in 1994 principally due to the relatively larger December 31, 1993 balance
which was paid in 1994.
o A decrease of $31.6 million from 1993 to 1994 in cash received from
collections of deferred gas costs, due in part to Pipeline's 1993
implementation of services pursuant to FERC Order 636 as described elsewhere
herein.
o An increase of $9.4 million in cash used for miscellaneous working
capital accounts in 1994, inclusive of a $2.5 million increase in cash
provided from recoveries under gas contract disputes.
SALE OF RECEIVABLES
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(millions of dollars) Year Ended
December 31, December 31,
------------------------ --------------------------------------
Amount Pre-tax Average
Sold and Net Inflows Loss Receivables
Uncollected Collateral (Outflows) on Sale Sold
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1995 $ 235.0 $ 35.0 $ 42.2 $ (9.8) $ 136.6
1994 192.8 48.7 (33.6) (7.1) 116.0
1993 $ 226.4 $ 29.0 $ 13.8 $ (8.1) $ 122.6
- --------------------------------------------------------------------------
</TABLE>
Under an August 1995 agreement ("the Agreement") which expires in August
1996 (although the Company currently expects that it will renew the facility),
the Company sells, with limited recourse and subject to a floating interest rate
provision which varies with the buyer's A1/P1 commercial paper rate, an
undivided interest (limited to a maximum of $235 million) in a designated pool
of accounts receivable. Certain of the Company's remaining receivables serve
as collateral for receivables sold, which collateral represents the maximum
exposure to the Company should all receivables sold prove ultimately
uncollectible. The Company has retained servicing responsibility under the
Agreement for which it is paid a fee which does not differ materially from a
normal servicing fee and, to the extent that the Company utilizes this
facility more or less during a given period, it will experience a net cash
inflow or outflow. Losses realized upon sales of receivables under the
Agreement are reported in the Company's Statement of Consolidated Income under
the caption "Other, net".
NET CASH FLOW FROM INVESTING ACTIVITIES
In 1994 and 1993, the Company generated significant amounts of cash through
sales of property, see "Natural Gas Distribution" and "Interstate Pipelines"
under "Material Changes in the Results of Continuing Operations" elsewhere
herein. Also in 1994, the Company generated approximately $12.3 million from
the sale of certain gas prepayments. The Company terminated virtually all of
its "corporate-owned life insurance" policies during 1995, receiving cash
proceeds of approximately $12.3 million. The Company generated approximately
$1.4 million and $7.2 million from sales of Itron common stock in 1995 and
1994, respectively, see "Radio Communications and Energy Measurement" under
"Discontinued Operations" elsewhere herein.
48 N O R A M
<PAGE> 17
CAPITAL EXPENDITURES - CONTINUING OPERATIONS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
(millions of dollars) (Budgeted)
1996(1) 1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Distribution $ 120.8 $ 128.4 $ 120.4 $ 111.4 $ 105.0 $ 118.4
Interstate Pipelines 46.7 37.5 41.7 30.3 21.5 129.2
Wholesale Energy Marketing - - - - - -
Natural Gas Gathering(2) 14.7 6.0 5.8 - - -
Retail Energy Marketing 1.4 0.8 0.8 1.5 1.2 1.0
Corporate and Other 0.7 0.9 1.7 1.1 2.1 2.4
- --------------------------------------------------------------------------------------------------------------------------------
Subtotal 184.3 173.6 170.4 144.3 129.8 251.0
LIG(3) - - - 1.9 5.1 4.0
- --------------------------------------------------------------------------------------------------------------------------------
Consolidated $ 184.3 $ 173.6 $ 170.4 $ 146.2 $ 134.9 $ 255.0
================================================================================================================================
</TABLE>
(1) Does not include anticipated expenditures for international projects which
the Company expects will total approximately $25 million during 1996 and,
on average, will not exceed $25 million per year over the next 3-5 years.
(2) Natural Gas Gathering expenditures are included with Interstate Pipelines
in 1993 and prior years, see "Natural Gas Gathering" under "Material
Changes in the Results of Continuing Operations" elsewhere herein.
(3) LIG's capital expenditures are included until its sale in June 1993, see
"Interstate Pipelines" under "Material Changes in the Results of Continuing
Operations" elsewhere herein.
The Company's total capital expenditures did not change significantly from
1994 to 1995, as an increase of $8.0 million (6.6%) at Distribution was
partially offset by a decrease of $4.2 million (10.1%) at Pipeline. These
variances are within the normal range of variation in the Company's capital
spending program, although Pipeline's capital spending was significantly lower
than originally budgeted for 1995 due, in large part, to a return of
transmission capacity by ANR Pipeline Company, see "Transportation Agreement"
under "Commitments and Contingencies" elsewhere herein. This increased capacity
allowed Pipeline to cancel or postpone certain expenditures budgeted to increase
throughput capacity at facilities near Perryville, Louisiana.
Capital expenditures for 1996 are budgeted at $184.3 million, an increase
of $10.7 million (6.2%) over actual 1995 expenditures, principally due to
projected increases at Pipeline ($9.2 million or 24.5%) and Natural Gas
Gathering ($8.7 million or 145%), partially offset by a projected decrease of
$7.6 million (5.9%) at Distribution. The projected increase at Pipeline
represents a return to a more normal level of spending, while the projected
increase at Natural Gas Gathering is principally for well connects and projects
to lower pressure and increase deliverability. The Company expects that its
capital spending will be funded through internally generated funds and, if
necessary, through incremental borrowings.
The Company's capital expenditures increased from $146.2 million in 1993 to
$170.4 million in 1994, an increase of $24.2 million (16.6%), reflecting
increased spending at Pipeline and Distribution. The $11.4 million (37.6%)
increase at Pipeline was principally associated with the Company's program to
increase throughput at facilities near Perryville, Louisiana. The $9.0 million
(8.1%) increase in Distribution spending was principally due to increased
expenditures for facilities to serve new towns, and the impact of spending
associated with the Midwest properties for all of 1994 and only part of 1993,
see "Natural Gas Distribution" under "Material Changes in the Results of
Continuing Operations" elsewhere herein.
COMMITMENTS AND CONTINGENCIES
CAPITAL SPENDING
At December 31, 1995, the Company had capital commitments of less than $25
million which are expected to be funded through cash provided by operations
and/or incremental borrowings. The Company's other planned capital projects are
discretionary in nature, with no substantial capital commitment made in advance
of the actual expenditures.
DEBT RETIREMENTS AND LEASE OBLIGATIONS
The Company's debt retirement schedule for the years 1996-2000 and all years
thereafter is $118.8 million, $277.0 million, $76.0 million, $200.6 million,
$371.5 million and $549.8 million, respectively, see Note 3 of Notes to
Consolidated Financial Statements. The Company has obligations under certain of
its leasing arrangements, see Note 8 of Notes to Consolidated Financial
Statements. The Company expects that, in general, its lease obligations and
other miscellaneous accrued liabilities will be settled with internally
generated cash and that, as its long-term debt matures, it will generally be
replaced with newly-issued debt of a similar tenor, although certain of such
debt retirements may be made with short-term borrowings on an interim basis
until permanent refinancing is obtained.
LETTERS OF CREDIT
At December 31, 1995, the Company was obligated under letters of credit
totalling approximately $31.2 million which are incidental to its ordinary
business operations.
INDEMNITY OBLIGATIONS
The Company has obligations under indemnification provisions of certain sale
agreements, see "Interstate Pipelines" under "Material Changes in the Results
of Continuing Operations" and "Discontinued Operations" elsewhere herein.
N O R A M 49
<PAGE> 18
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been sold, see "Sale of Receivables" under "Net Cash Flows from Operating
Activities" elsewhere herein.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has
prepaid for certain volumes of gas, which prepayments have been recorded at
their net realizable value and, to the extent that the Company is unable to
realize at least the carrying amount as the gas is delivered and sold, the
Company's earnings will be adversely affected, although such impact is not
expected to be material. In addition to these prepayments, the Company is a
party to a number of agreements which require it to either purchase or sell gas
in the future at prices which may differ from then-prevailing market prices or
which require it to deliver gas at a point other than the expected receipt
point for volumes to be purchased. The Company operates an ongoing risk
management program designed to eliminate or limit the Company's exposure from
its obligations under these purchase/sale commitments, see the discussion under
"Credit Risk and Off-Balance-Sheet Risk" following. To the extent that the
Company expects that these commitments will result in losses over the contract
term, the Company has established reserves equal to such expected losses.
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250 MMcf/day,
and pursuant to which ANR had advanced $125 million to the Company. The ANR
Agreement has been restructured as a lease of capacity and, after refunds of
$50 million and $34 million in 1995 and 1993, respectively, the Company
currently retains $41 million (recorded as a liability) in exchange for ANR's
use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in 2003
with a refund of $5 million to ANR and the ANR Agreement will terminate in 2005
with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company operates in various phases of the natural gas industry with sales
to resellers such as pipeline companies and local distribution companies as
well as to end-users such as commercial businesses, industrial concerns and
residential consumers. While certain of these customers are affected by
periodic downturns in the economy in general or in their specific segment of
the natural gas industry, the Company believes that its level of credit-related
losses due to such economic fluctuations has been adequately reserved for and
will remain relatively stable in the long-term.
The Company has entered into a number of interest rate swaps which carry
off-balance-sheet risk, see "Net Cash Flows from Financing Activities" elsewhere
herein.
The Company's gas supply, marketing, gathering and transportation
activities subject the Company's earnings to variability based on fluctuations
in both the market price of natural gas and the value of transportation as
measured by changes in the delivered price of natural gas at various points in
the nation's natural gas grid. In order to mitigate the financial risk
associated with these activities both for itself and for certain customers who
have requested the Company's assistance in managing similar exposures, the
Company routinely enters into natural gas swaps, futures contracts and options,
collectively referred to herein as "derivatives". This use of derivatives for
the purpose of reducing exposure to risk is generally referred to as hedging
and, through deferral accounting, results in matching the financial impact of
these derivative transactions with the cash impact resulting from consummation
of the transactions being hedged, see Note 1 of Notes to Consolidated Financial
Statements.
The futures contracts are purchased and sold on the NYMEX and generally are
used to hedge a portion of the Company's storage gas and provide risk management
assistance to certain customers, to whom the cost of the derivative activity is
generally passed on as a component of the sales price of the service being
provided. Futures contracts are also utilized to fix the price of compressor
fuel or other future operational gas requirements, although usage to date for
this purpose has not been material. The options are entered into with various
third parties and principally consist of options which serve to limit the
year-to-year escalation from January 1997 to April 1999 in the purchase price of
gas which the Company is committed to deliver to a distribution affiliate. These
options covered 13.2 Bcf, 30.5 Bcf and 49.3 Bcf at December 31, 1995, 1994 and
1993, respectively and, due to their nature and term, have no readily
determinable fair market value. The Company has established a reserve equal to
its projected maximum exposure to losses during the term of this commitment and,
accordingly, no impact on future earnings is expected. The swaps, also entered
into with various third parties, are principally associated with the Company's
marketing and transportation activities and generally require that one party pay
either a fixed price or fixed differential from the NYMEX price per MMBtu of gas
while the other party pays a price based on a published index. These swaps allow
the Company to (1) commit to purchase gas at one location and sell it at another
location without assuming unacceptable risk with respect to changes in the cost
of the intervening transportation, (2) effectively set the value to be received
for transportation of certain volumes on the Company's facilities in the future
and (3) effectively fix the base price for gas to be delivered in conjunction
with the commitment described preceding. None of these derivatives are held for
speculative purposes and, in general, the Company's risk management policy
requires that positions taken in derivatives be offset by positions in physical
transactions or in other derivatives.
In the table which follows, the term "notional amount" refers to the
contract unit price times the contract volume for the relevant derivative
category and, in general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is
<PAGE> 19
intended to be indicative of the Company's level of activity in such
derivatives, although the amounts at risk are significantly smaller because, in
general, changes in the market value of these derivatives are offset by changes
in the value associated with the underlying physical transactions or in other
derivatives.
SWAPS(1)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Volume Volume Estimated Fair
as Fixed as Fixed Market Value
Price Payor Price Receiver (Loss)(2)
- --------------------------------------------------------------------------
<S> <C> <C> <C>
December 31, 1993 101.2 82.2 $ (6.6)
Additions 137.1 170.9 -
Maturities (106.4) (139.0) -
December 31, 1994 131.9 114.1 (16.7)
Additions 335.6 343.4 -
Maturities (231.8) (243.2) -
December 31, 1995 235.7 214.3 $ (2.3)
- --------------------------------------------------------------------------
</TABLE>
FUTURES CONTRACTS(4)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Purchased Sold Estimated
----------------- ----------------- Fair Market
Notional Notional Value
Volume Amount Volume Amount Gain (Loss)(2)
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Dec. 31, 1993 N/M(3) N/M N/M N/M N/M
Dec. 31, 1994 6.7 $ 13.8 1.7 $ 2.8 $ (2.9)
Additions 119.2 198.6 117.3 198.9 -
Maturities (110.8) (182.8) (110.8) (182.8) -
Dec. 31, 1995 15.1 $ 29.6 8.2 $ 18.9 3.3
- --------------------------------------------------------------------------
</TABLE>
(1) The financial impact of these swaps was to increase earnings by $1.0
million, $2.8 million and $1.0 million during 1993, 1994 and 1995,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The amount
which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the case
of certain commitments described preceding, no earnings impact is expected
due to existing accruals. Swaps associated with these commitments had fair
market values of $(1.0) million, $(17.6) million and $(5.9) million at
December 31, 1995, 1994 and 1993, respectively.
(3) Indicates that the item is not material.
(4) There was no material financial impact from these futures contracts in
1993 or 1994 and the effect during 1995 was to decrease earnings by $4.1
million as futures transactions were matched with the hedged transactions.
While, as yet, the Company has experienced no significant losses due to the
credit risk associated with these arrangements, the Company has
off-balance-sheet risk to the extent that the counterparties to these
transactions may fail to perform as required by the terms of each such contract.
In order to minimize this risk, the Company enters into such transactions solely
with firms of acceptable financial strength, in most cases limiting such
transactions to counterparties whose debt securities are rated "A" or better by
recognized rating agencies. For long-term arrangements, the Company periodically
reviews the financial condition of such firms in addition to monitoring the
effectiveness of these financial contracts in achieving the Company's
objectives. Should the counterparties to these arrangements fail to perform, the
Company would seek to compel performance at law or otherwise, or to obtain
compensatory damages in lieu thereof, but the Company might be forced to acquire
alternative hedging arrangements or be required to honor the underlying
commitment at then-current market prices. In such event, the Company might incur
additional loss to the extent of amounts, if any, already paid to the
counterparties.
In view of its criteria for selecting counterparties, its process for
monitoring the financial strength of these counterparties and its experience to
date in successfully completing these transactions, the Company believes that
the risk of incurring a significant loss due to the nonperformance of
counterparties to these transactions is minimal.
LITIGATION
On August 6, 1993, the Company, its former subsidiary, Arkla Exploration
Company ("AEC") and Arkoma Production Company, a subsidiary of AEC, were named
as defendants in a lawsuit filed in the Circuit Court of Independence County,
Arkansas. On September 20, 1994, the Circuit Court entered an order granting
the Company's motion to dismiss. On October 23, 1995, the Supreme Court of
Arkansas affirmed the Circuit Court's order granting the Company's motion to
dismiss.
The Company is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
along the Mississippi River in Minnesota known as the former Minneapolis Gas
Works ("FMGW") until 1960. The Company is working with the Minnesota Pollution
Control Agency to implement an appropriate remediation plan. There are six
other former MGP sites in the Company's Minnesota service territory. Of the six
sites, the Company believes that two were neither owned nor operated by the
Company; two were owned at one time but were operated by others and are
currently owned by others; one is presently owned by the Company but was
operated by others; and one was operated by the Company and is now owned by
others. The Company believes it has no liability with respect to the sites it
neither owned nor operated.
At December 31, 1995, the Company has estimated a range of $20 million to
$177 million for possible remediation of the Minnesota sites. The low end of the
range was determined using only those sites presently owned or known to have
been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once
N O R A M 51
<PAGE> 20
owned by the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to
recover amortization of previously deferred and ongoing clean-up costs. Any
amounts in excess of $2.1 million annually were deferred for future recovery.
In its 1995 rate case, Minnegasco asked that the annual allowed recovery be
increased to approximately $7 million and that such costs be subject to a
true-up mechanism whereby any over or under recovered amounts, net of certain
insurance recoveries, would be deferred until the next rate case. Such
accounting was implemented effective October 1, 1995 pending final approval in
the existing rate case. At December 31, 1995 and 1994, the Company had net
deferred expenses of $2.3 million and $0.2 million, respectively. At December
31, 1995 and 1994, the Company had recorded a liability of $45.2 million and
$40.1 million, respectively, to cover the cost of remediation. The Company
expects that the majority of its accrual as of December 31, 1995 will be
expended within the next five years. In accordance with the provisions of SFAS
71, a regulatory asset has been recorded equal to the liability accrued. The
Company is pursuing recovery of these costs from insurers. The Company believes
the difference between any cash expenditures for these costs and the amounts
recovered in rates during any year will not be material to the Company's
overall cash requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites
in the service territories of the distribution divisions. At the present time,
the Company is aware of some plant sites in addition to the Minnesota sites and
is investigating certain other locations. While the Company's evaluation of
these other MGP sites is in its preliminary stages, it is likely that some
compliance costs will be identified and become subject to reasonable
quantification. To the extent that such potential costs are quantified, as with
the Minnesota remediation costs for MGP described preceding, the Company
expects to provide an appropriate accrual and seek recovery for such
remediation costs through all appropriate means, including regulatory relief.
On October 24, 1994, the United States Environmental Protection Agency
advised the Company that MRT and a number of other companies have been named
under federal law as potentially responsible parties for a landfill site in
West Memphis, Arkansas and may be required to share in the cost of remediation
of this site. However, considering the information currently known about the
site and the involvement of MRT, the Company does not believe that this matter
will have a material adverse effect on the financial position, results of
operations or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company that the Company, through one of its subsidiaries and
together with several other unaffiliated entities, had been named under state
law as potentially responsible parties with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any, of the site. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or
cash flows of the Company.
In addition, the Company, as well as other similarly situated firms in the
industry, is investigating the possibility that it may elect or be required to
perform remediation of various sites where meters containing mercury were
disposed of improperly, or where mercury from such meters may have leaked or
been disposed of improperly. While the Company's evaluation of this issue is in
its preliminary stages, it is likely that compliance costs will be identified
and become subject to reasonable quantification.
To the extent that potential environmental compliance costs are quantified
within a range, the Company establishes reserves equal to the most likely level
of costs within the range and adjusts such accruals as better information
becomes available. If justified by circumstances within the Company's
businesses subject to SFAS 71, corresponding regulatory assets are set up in
anticipation of recovery through the ratemaking process. At December 31, 1995
and 1994, the Company had recorded an accrual of $3.3 million (with a maximum
estimated exposure of approximately $18 million) for environmental matters in
addition to the accrual for MGP sites as discussed preceding, with an
offsetting regulatory asset.
While the nature of environmental contingencies makes complete evaluation
impracticable, the Company currently is aware of no other environmental matter
which could reasonably be expected to have a material impact on its results of
operations, financial position or cash flows.
52 N O R A M
<PAGE> 21
ACCOUNTING CHANGES
POSTRETIREMENT BENEFITS
The Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other than Pensions" ("SFAS
106"), as of January 1, 1993. While the costs of postretirement benefits other
than pensions (such as retiree health care benefits) historically had been
expensed by the Company on a "pay-as-you-go" basis, SFAS 106 requires accrual
of such benefits during the years of service in which they are earned, see Note
5 of Notes to Consolidated Financial Statements.
POSTEMPLOYMENT BENEFITS
In 1992, the Company adopted Statement of Financial Accounting Standards No.
112, "Employers' Accounting for Postemployment Benefits", which requires the
accrual of postemployment benefits payable to former or inactive employees
after employment but before retirement. The cumulative effect of adoption as of
January 1, 1992 was an after-tax charge of approximately $4.9 million which was
recorded in the first quarter of 1992 and is reported in the Company's
Statement of Consolidated Income for 1992 under the caption "Cumulative effect
of change in accounting principle".
RATIO OF EARNINGS TO FIXED CHARGES
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993 1992 1991
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1.69 1.47 1.47 1.10 1.19
- --------------------------------------------------------------------------------
</TABLE>
DEBT RETIREMENT SCHEDULE
The debt retirement schedule at December 31, 1995 is as follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(millions of dollars)
1996 1997 1998 1999 2000 Beyond 2000
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$118.8 $277.0 $76.0 $200.6 $371.5 $549.8
- --------------------------------------------------------------------------------
</TABLE>
COMMON STOCK PRICES AND DIVIDENDS
The common stock of the Company is listed for trading on the New York Stock
Exchange under the symbol "NAE". At December 31, 1995, there were 34,441
common stockholders of record. Following is selected data concerning the
Company's common stock price and cash dividends paid:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common Cash Dividends
1995 Stock Price Per Share
- --------------------------------------------------------------------------------
Quarter High Low Common Preferred
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1st $ 6 $ 5 1/8 $ 0.07 $ 0.75
2nd $ 6 3/4 $ 5 1/4 $ 0.07 $ 0.75
3rd $ 8 1/8 $ 6 1/4 $ 0.07 $ 0.75
4th $ 9 $ 7 5/8 $ 0.07 $ 0.75
- --------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Common Cash Dividends
1994 Stock Price Per Share
- --------------------------------------------------------------------------------
Quarter High Low Common Preferred
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1st $ 9 $ 6 3/4 $ 0.07 $ 0.75
2nd $ 6 1/2 $ 5 5/8 $ 0.07 $ 0.75
3rd $ 7 3/4 $ 5 3/4 $ 0.07 $ 0.75
4th $ 6 1/2 $ 5 1/4 $ 0.07 $ 0.75
- --------------------------------------------------------------------------------
</TABLE>
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common Cash Dividends
Stock Price Per Share
- --------------------------------------------------------------------------------
Quarter High Low Common Preferred
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1993 $10 5/8 $ 7 3/8 $ 0.28 $ 3.00
1992 $12 3/8 $ 6 7/8 $ 0.48 $ 3.00
1991 $20 1/4 $ 9 3/4 $ 1.08 $ 3.00
</TABLE>
Under the provisions of the Company's revolving credit facility, the
Company's total debt capacity is limited and it is required to maintain a
minimum level of stockholders' equity, which requirements effectively serve to
limit the Company's ability to pay dividends, see "Net Cash Flow from Financing
Activities" included in "Management Analysis" elsewhere herein.
N O R A M 53
<PAGE> 22
STATEMENT OF CONSOLIDATED INCOME NorAm Energy Corp. and Subsidiaries
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
(thousands of dollars, except per share amounts) Year Ended December 31,
1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Natural gas sales $ 2,725,927 $ 2,593,665 $ 2,759,718
Natural gas transportation, including storage 159,142 184,219 110,640
Appliance sales and service 45,581 43,598 39,527
Chemical and petroleum products 6,090 4,627 41,220
Other 27,939 31,793 37,155
- --------------------------------------------------------------------------------------------------------------------------
2,964,679 2,857,902 2,988,260
- --------------------------------------------------------------------------------------------------------------------------
Operating Expenses
Cost of natural gas purchased, net 1,857,166 1,779,481 1,900,852
Operation, maintenance, cost of sales and other 570,508 559,580 588,732
Depreciation and amortization (Note 1) 147,109 153,035 151,841
Taxes other than income taxes 102,591 100,882 104,715
Contract termination charge -- -- 34,230
- --------------------------------------------------------------------------------------------------------------------------
2,677,374 2,592,978 2,780,370
- --------------------------------------------------------------------------------------------------------------------------
Operating Income 287,305 264,924 207,890
- --------------------------------------------------------------------------------------------------------------------------
Other (Income) and Deductions
Interest expense, net 157,959 169,365 172,407
Other, net 8,438 9,896 (50,933)
- --------------------------------------------------------------------------------------------------------------------------
166,397 179,261 121,474
- --------------------------------------------------------------------------------------------------------------------------
Income From Continuing Operations Before Income Taxes 120,908 85,663 86,416
Provision for Income Taxes 55,379 34,372 46,481
- --------------------------------------------------------------------------------------------------------------------------
Income from Continuing Operations 65,529 51,291 39,935
Loss from discontinued operations, less taxes -- (2,102) --
- --------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 65,529 49,189 39,935
Extraordinary item, less taxes (Note 3) (52) (1,123) (3,848)
- --------------------------------------------------------------------------------------------------------------------------
Net Income 65,477 48,066 36,087
Preferred dividend requirement 7,800 7,800 7,800
- --------------------------------------------------------------------------------------------------------------------------
Earnings Available to Common Stock $ 57,677 $ 40,266 $ 28,287
==========================================================================================================================
Earnings (Loss) Per Common Share
Continuing operations (1) $ 0.47 $ 0.36 $ 0.26
Discontinued operations, less taxes -- (0.02) --
Extraordinary item, less taxes 0.00 (0.01) (0.03)
- --------------------------------------------------------------------------------------------------------------------------
Earnings Per Common Share $ 0.47 $ 0.33 $ 0.23
==========================================================================================================================
Weighted average common shares outstanding (in thousands) 123,868 122,424 122,305
- --------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Earnings per common share from continuing operations is computed after
reduction for the preferred dividend requirement.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
54 N O R A M
<PAGE> 23
CONSOLIDATED BALANCE SHEET NorAm Energy Corp. and Subsidiaries
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Property, Plant and Equipment $ 3,969,539 $ 3,836,782
Less: Accumulated depreciation and amortization 1,561,764 1,459,638
- --------------------------------------------------------------------------------------------------------------------------
2,407,775 2,377,144
Investments and Other Assets 683,909 704,154
Current Assets
Cash and cash equivalents 13,311 17,632
Accounts and notes receivable, principally customer 335,779 215,846
Deferred income taxes 13,601 10,287
Inventories 86,982 112,094
Deferred gas costs 13,019 (6,812)
Gas purchased in advance of delivery 23,440 26,571
Other current assets 25,496 36,157
- --------------------------------------------------------------------------------------------------------------------------
511,628 411,775
- --------------------------------------------------------------------------------------------------------------------------
Deferred Charges 62,671 68,425
- --------------------------------------------------------------------------------------------------------------------------
Total Assets $ 3,665,983 $ 3,561,498
==========================================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Stockholders' Equity
$3.00 Convertible exchangeable preferred stock, Series A ($50 liquidation preference),
cumulative, non-voting; authorized 10,000,000 shares, issued 2,600,000 shares $ 130,000 $ 130,000
Common stock ($.625 par) authorized 250,000,000; 124,803,693 and 122,530,248
shares issued and outstanding at December 31, 1995 and 1994, respectively 78,002 76,581
Paid-in capital 880,885 868,289
Accumulated deficit (336,940) (360,079)
Unrealized gain on investment, net 15,316 2,586
- --------------------------------------------------------------------------------------------------------------------------
767,263 717,377
- --------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, Less Current Maturities 1,474,924 1,414,374
Current Liabilities
Current maturities of long-term debt 118,750 151,000
Notes payable to banks 10,000 110,000
Other notes payable -- 13,600
Accounts payable, principally trade 472,374 310,941
Income taxes payable 5,337 4,690
Interest payable 38,730 42,180
General taxes 48,320 45,717
Customers' deposits 35,651 35,501
Other current liabilities 96,645 91,494
- --------------------------------------------------------------------------------------------------------------------------
825,807 805,123
- --------------------------------------------------------------------------------------------------------------------------
Other Liabilities and Deferred Credits
Accumulated deferred income taxes 303,445 257,839
Other deferred credits and non-current liabilities 294,544 366,785
- --------------------------------------------------------------------------------------------------------------------------
597,989 624,624
- --------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 8)
- --------------------------------------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 3,665,983 $ 3,561,498
==========================================================================================================================
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
N O R A M 55
<PAGE> 24
<TABLE>
<CAPTION>
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY NorAm Energy Corp. and Subsidiaries
- ------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) Year Ended December 31,
1995 1994 1993
- ------------------------------------------------------------------------------------------------------------------------------
Shares Amount Shares Amount Shares Amount
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CAPITAL STOCK
Preferred, $3.00 Convertible
exchangeable preferred stock,
Series A ($50.00 liquidation
preference), cumulative,
non-voting; authorized
10,000,000 shares(1)
- ------------------------------------------------------------------------------------------------------------------------------
Issued and outstanding 2,600,000 $130,000 2,600,000 $130,000 2,600,000 $130,000
- ------------------------------------------------------------------------------------------------------------------------------
Common, $.625 par, authorized
250,000,000 shares
Balance at beginning of year 122,530,248 76,581 122,361,578 76,476 122,258,367 76,411
Issuance under Direct Stock
Purchase Plan 1,610,148 1,006 48,968 30 -- --
Issuance of stock in
Hunter acquisition (Note 7) -- -- -- -- 125,000 78
Other issuance (reduction) 663,297 415 119,702 75 (21,789) (13)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 124,803,693 78,002 122,530,248 76,581 122,361,578 76,476
- ------------------------------------------------------------------------------------------------------------------------------
PAID-IN CAPITAL
Balance at beginning of year 868,289 867,641 866,635
Issuance under Direct Stock
Purchase Plan 8,795 (153) --
Issuance of stock in
Hunter acquisition (Note 7) -- -- 1,156
Other issuance (reduction) 3,801 801 (150)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 880,885 868,289 867,641
- ------------------------------------------------------------------------------------------------------------------------------
RETAINED DEFICIT
Balance at beginning of year (360,079) (366,080) (360,121)
Net income 65,477 48,066 36,087
Cash dividends
Preferred stock - $3.00 per share (7,800) (7,800) (7,800)
Common stock - $0.28 per share (34,538) (34,265) (34,246)
- ------------------------------------------------------------------------------------------------------------------------------
Balance at end of year (336,940) (360,079) (366,080)
- ------------------------------------------------------------------------------------------------------------------------------
Unrealized gain on investment, net 15,316 2,586 --
- ------------------------------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $767,263 $717,377 $708,037
==============================================================================================================================
</TABLE>
(1) The Series A preferred stock ("the Preferred") is convertible into common
stock in the ratio of approximately 1.7467 shares of common stock for each
share of the Preferred, equivalent to a conversion price of $28 5/8 for
each common share, which conversion price is subject to adjustment should
certain events occur. The Preferred, which has preference over the
Company's common stock with respect to payment of dividends, is redeemable
in whole or in part at the option of the Company at a price of
$50.30/share, declining to $50/share in March 1997, and is exchangeable in
whole but not in part, at the option of the Company on any dividend payment
date, for the Company's 6% Convertible Subordinated Debentures due 2012
("the Debentures") at the rate of $50 principal amount of Debentures per
share of the Preferred. The Debentures, if issued, will have conversion
rights similar to the Preferred. Should dividends on the Preferred be in
arrears for an amount equal to six quarterly dividend payments, the holders
of the Preferred would be entitled, as a class, to elect a special class of
two directors to the Company's Board of Directors to serve until such time
as dividends on the Preferred are brought current.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
56 N O R A M
<PAGE> 25
STATEMENT OF CONSOLIDATED CASH FLOWS NorAm Energy Corp. and Subsidiaries
<TABLE>
<CAPTION>
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
- ---------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1995 1994 1993
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 65,477 $ 48,066 $ 36,087
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization 147,109 153,035 151,841
Deferred income taxes 34,883 32,855 29,692
Contract termination charge - - 34,230
Gains from significant sales of property - - (41,619)
Discontinued operations - 2,102 -
Extraordinary item, less taxes (Note 3) 52 1,123 3,848
Utilization of tax loss carryforwards (19,797) (6) (11,787)
Other 3,483 (3,065) (22,013)
Changes in certain assets and liabilities,
net of non-cash transactions and the effects
of acquisitions and dispositions (Note 1) 116,154 69,330 (6,830)
- ---------------------------------------------------------------------------------------------------
Net cash provided by operating activities 347,361 303,440 173,449
- ---------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (173,600) (170,371) (146,195)
Sale of distribution properties - 23,172 93,090
Exchange of distribution properties - - (38,000)
Sale of LIG, net of related expenditures - - 169,950
Cash surrender value of life insurance 12,276 - -
Other asset sales - 12,315 -
Sale of Itron stock 1,441 7,204 -
Other, net (14,296) 4,735 (26,690)
- ---------------------------------------------------------------------------------------------------
Net cash provided by (used in) investing activities (174,179) (122,945) 52,155
- ---------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Issuance of 7 1/2% notes due 2000 200,000 - -
Bank term loan, due 2000 150,000 - -
Common and preferred stock dividends (42,338) (42,065) (42,046)
Retirements and reacquisitions of long-term debt (335,352) (148,913) (212,188)
Other interim borrowings (repayments) (100,000) 15,000 95,000
Return of advance received under contingent sales agreement (50,000) - (34,000)
Issuance of common stock under Direct Stock Purchase Plan 9,801 (123) -
Decrease in cash overdrafts (9,614) (1,672) (43,685)
- ---------------------------------------------------------------------------------------------------
Net cash used in financing activities (177,503) (177,773) (236,919)
- ---------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash equivalents (4,321) 2,722 (11,315)
- ---------------------------------------------------------------------------------------------------
Cash and cash equivalents - beginning of year 17,632 14,910 26,225
- ---------------------------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 13,311 $ 17,632 $ 14,910
===================================================================================================
</TABLE>
For supplemental cash flow information, see Note 1.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
N O R A M 57
<PAGE> 26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES AND COMPONENTS OF
CERTAIN FINANCIAL STATEMENT LINE ITEMS
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
NorAm Energy Corp. and its subsidiaries, all of which are wholly owned, and all
significant affiliated transactions and balances have been eliminated. As used
herein, "NorAm" and "the Company" refer to NorAm Energy Corp. and its
consolidated subsidiaries. Certain prior year amounts have been reclassified to
conform to current presentation.
NATURE OF OPERATIONS
The Company's principal activities are in the natural gas industry
(representing in excess of 90% of the Company's total revenues, income or loss
and identifiable assets), currently confined to the contiguous 48 states, with
principal operations in Texas, Louisiana, Mississippi, Arkansas, Oklahoma,
Missouri and Minnesota. The Company is evaluating opportunities for
international investment, although it has not yet made any significant
commitments. The Company has operations in various phases of the natural gas
industry, including distribution, transmission, marketing and gathering which,
during 1995, provided approximately 53%, 35%, 9% and 3%, respectively, of the
Company's consolidated operating income (exclusive of the net operating loss
attributable to Corporate and certain miscellaneous activities). The Company's
distribution operations are conducted by its Entex, Minnegasco and Arkla
divisions, its interstate pipeline operations are conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), its marketing activities are conducted by NorAm Energy Services, Inc.
("NES") and NorAm Energy Management, Inc. ("NEM"), and its gathering activities
are conducted by NorAm Field Services Corp. ("NFS"), in each case also
including certain subsidiaries and affiliates. The Company's miscellaneous
activities, whose collective results of operations currently are not material,
principally consist of home care services, including (1) appliance sales and
service, (2) home security services and (3) resale of long distance telephone
service, which services generally are provided to certain of the Company's
retail gas distribution customers.
During 1995, the Company had revenues of $58 million, approximately 2% of
consolidated operating revenues, from sales to and transportation for Laclede
Gas Company (the local gas distribution company which serves the greater St.
Louis, Illinois area) pursuant to several long-term firm transportation and
storage agreements which expire in 1999. The Company's interstate pipelines
received revenues of approximately $161 million in 1995 from services provided
to the Company's Arkla distribution division, approximately 5.4% of consolidated
operating revenues, pursuant to several agreements, some of which expire during
1996.
USE OF ESTIMATES
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 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.
RATE REGULATION
Methods of allocating costs to accounting periods in the portion of the
Company's business subject to federal, state or local rate regulation may
differ from methods generally applied by unregulated companies. However, when
accounting allocations prescribed by regulatory authorities are used for
rate-making, the resultant accounting follows the concept of matching costs
with related revenues. The Company's rate-regulated divisions/subsidiaries bill
customers on a monthly cycle billing basis. Revenues are recorded on an accrual
basis, including an estimate for gas delivered but unbilled at the end of each
accounting period.
All of the Company's rate-regulated businesses historically have followed
the accounting guidance contained in Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71").
The Company discontinued application of SFAS 71 to NGT effective with year-end
1992 reporting. As a result of the continued application of SFAS 71 to MRT and
the Company's distribution divisions, the accompanying consolidated financial
statements contain certain assets and liabilities which would not be recognized
by unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions (see Note 5), the Company's only
other significant regulatory asset is related to anticipated environmental
remediation costs, see Note 8.
CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas gathering and pipeline assets. This change had the effect of
increasing 1995 "Income before extraordinary item" and "Net income" by
approximately $3.2 million ($0.03 per share).
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
To minimize the risk from market fluctuations in the price of natural gas and
transportation, the Company enters into futures transactions, swaps and options
in order to hedge certain commitments to buy, sell and transport natural gas,
some of which carry off-balance-sheet risk, see Note 8. Gains and losses
resulting from changes in the market value of the various financial instruments
utilized as hedges are deferred and recognized in the Company's Statement of
Consolidated Income, together with the gain or loss on consummation of the
hedged transaction, as the physical production is purchased, sold or
transported under the relevant contracts.
CONTRACT TERMINATION CHARGE
In December 1993, the Company completed a comprehensive settlement agreement
("the Settlement") with certain subsidiaries of Samson Investment Company
("Samson"), terminating or modifying a number of outstanding contractual
arrangements. The Settlement resulted in a
58 N O R A M
<PAGE> 27
$34.2 million pre-tax charge to earnings, set forth in the accompanying
Statement of Consolidated Income for 1993 as "Contract termination charge", and
the delivery to Samson by the Company of a note for $34 million, which note has
been repaid.
INTEREST EXPENSE
Interest expense includes, where applicable, amortization of debt issuance cost
and amortization of gains and losses on interest rate hedging transactions
related to the Company's debt financing activities, see Note 3. "Interest
expense, net" as presented in the accompanying Statement of Consolidated Income
is net of an allowance for borrowed funds used during construction of $1.1
million, $1.3 million and $0.9 million in 1995, 1994 and 1993, respectively.
OTHER, NET - STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
(Income) Expense 1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest income $ (3,841) $ (3,948) $(11,613)
(Gains) losses on sales of property:
Nebraska distribution
properties - - (23,900)
LIG - - (17,719)
Other (68) 631 (1,141)
Loss on sale of
accounts receivable 9,771 7,139 8,132
Miscellaneous 2,576 6,074 (4,692)
- -------------------------------------------------------------------------------
$ 8,438 $ 9,896 $(50,933)
===============================================================================
</TABLE>
DISCONTINUED OPERATIONS
"Loss from discontinued operations, less taxes" as presented in the
accompanying Statement of Consolidated Income for 1994 represents a pre-tax
loss of $3.3 million, less tax benefit of $(1.2) million, related to litigation
associated with the discontinued operations of University Savings Association,
a former subsidiary of Entex.
EARNINGS PER SHARE
Earnings per common share is based on net income less preferred dividend
requirements, using the weighted average number of the Company's common shares
outstanding during each period. Fully diluted earnings per share is not
presented because the relevant options and convertible securities are either
immaterial, anti-dilutive or both.
PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Natural gas distribution $ 2,059,376 $ 1,913,738
Natural gas pipeline 1,666,017 1,649,465
Natural gas gathering 208,989 207,831
Other (1) 35,157 65,748
- -------------------------------------------------------------------------------
$ 3,969,539 $ 3,836,782
===============================================================================
</TABLE>
(1) The majority of the decline in "Other" property, plant and equipment from
December 31, 1994 to December 31, 1995 is attributable to the transfer of
certain assets from Corporate to other business units during 1995.
Property, plant and equipment, in general, is carried at cost and
depreciated or amortized on a straight-line basis over its estimated useful
life. Additions to and betterments of utility property are charged to property
accounts at cost, while the costs of maintenance, repairs and minor replacements
are charged to expense as incurred. Upon normal retirement of units of utility
property, plant and equipment, the cost of such property, together with cost of
removal less salvage, is charged to accumulated depreciation. Costs of
individually significant internally developed and purchased computer software
systems are capitalized and amortized over their expected useful life.
The Company recorded an impairment of certain property, plant and equipment
as a result of the discontinued application of SFAS 71 to NGT at December 31,
1992, see "Rate Regulation" elsewhere herein. The Company currently does not
expect to record additional impairments as a result of its initial adoption of
Statement of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
("SFAS 121"), which is applicable to all long-lived assets and is effective for
fiscal years beginning after December 15, 1995. SFAS 121 requires that assets be
evaluated for impairment on an ongoing basis (as indicators of possible
impairment are noted) and, therefore, changing circumstances could result in
additional impairments at some future date.
INVESTMENTS AND OTHER ASSETS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Goodwill, net (1) $481,125 $495,311
Prepaid pension asset (Note 5) 57,965 56,665
Investment in Itron, Inc. (2) 50,711 32,046
Regulatory asset for environmental
costs (Note 8) 48,500 43,800
Gas purchased in advance of delivery 24,284 43,547
Cash surrender value of life insurance (3) 63 11,483
Other 21,261 21,302
- -------------------------------------------------------------------------------
$683,909 $704,154
===============================================================================
</TABLE>
(1) Goodwill, none of which is subject to recovery in regulated service rates,
is amortized on a straight-line basis over 40 years. Approximately $14.2
million, $14.2 million and $14.8 million of goodwill was amortized during
1995, 1994 and 1993, respectively. Accumulated amortization of goodwill was
$89.2 million and $75.0 million at December 31, 1995 and 1994,
respectively. The Company periodically compares the carrying value of its
goodwill to the anticipated undiscounted future operating income from the
businesses whose acquisition gave rise to the goodwill and, as yet, no
impairment is indicated or expected.
(2) Itron, Inc. ("Itron") is a publicly-traded Spokane, Washington company
which manufactures and markets automated meter-reading devices and provides
related services. The Company accounts for its investment in Itron on the
cost method (its ownership of approximately 1.5 million Itron common shares
at December 31, 1995 represents an ownership interest of approximately
12.3%), revalues its investment to market value as of each balance sheet
date and reports any unrealized gain or loss, net of tax, as a separate
component of stockholders' equity, which unrealized gain was approximately
$15.3 million (net of tax of $8.7 million) at December 31, 1995. At March
1, 1996, the market value of the Company's investment in Itron had
increased to approximately $65.4 million and the unrealized gain to
approximately $24.6 million (net of tax of $14.1 million).
(3) The Company terminated virtually all of its "corporate-owned life
insurance" policies during 1995, receiving cash proceeds of approximately
$12.3 million.
N O R A M 59
<PAGE> 28
ALLOWANCE FOR DOUBTFUL ACCOUNTS
"Accounts and notes receivable, principally customer" as presented in the
accompanying Consolidated Balance Sheet are net of an allowance for doubtful
accounts of $11.1 million and $12.6 million at December 31, 1995 and 1994,
respectively.
INVENTORIES(1)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- ----------------------------------------------------------------------------
<S> <C> <C>
Gas in underground storage(2) $ 53,183 $ 73,755
Materials and supplies 33,354 38,156
Other 445 183
- ----------------------------------------------------------------------------
$ 86,982 $112,094
============================================================================
</TABLE>
(1) Inventories principally follow the average cost method and all non-utility
inventories held for resale are valued at the lower of cost or market.
(2) The balance in "Gas in underground storage" fluctuates due to
weather-related changes in the demand for natural gas.
ACCOUNTS PAYABLE
Certain of the Company's cash balances reflect credit balances to the extent
that checks written have not yet been presented for payment. Such balances
included in "Accounts payable, principally trade" were approximately $44.4
million and $54.1 million at December 31, 1995 and 1994, respectively.
OTHER LIABILITIES AND DEFERRED CREDITS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- ----------------------------------------------------------------------------
<S> <C> <C>
Estimated environmental remediation
costs (Note 8) $ 48,500 $ 43,800
Payable under capacity lease
agreement (Note 8) 41,000 91,000
Supplemental retirement and deferred
compensation 40,869 38,599
Estimated obligations under indemnification
provisions of sale agreements (Note 7) 34,207 36,553
Refundable excess deferred income taxes 26,599 27,699
Retiree life and medical accruals (Note 5) 25,204 18,678
Estimated losses under gas purchase/sale
commitments (Note 8) 24,803 48,877
Insurance reserves 20,302 18,722
Other 33,060 42,857
- ----------------------------------------------------------------------------
$294,544 $366,785
============================================================================
</TABLE>
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying Statement of Consolidated Cash Flows reflects the assumption
that all highly liquid investments purchased with original maturities of three
months or less are cash equivalents. Cash flows resulting from the Company's
risk management (hedging) activities are classified in the accompanying
Statement of Consolidated Cash Flows in the same category as the item being
hedged.
In June 1991, the Company acquired The Hunter Company in a non-cash
transaction through the issuance of the Company's common stock and issued
additional shares in 1993. The Company's 1993 exchange of its South Dakota
distribution properties for certain other distribution properties in Minnesota
included both cash and non-cash components. Effective as of December 31, 1993,
the Company issued a $34 million note to a subsidiary of Samson Investment
Company in conjunction with a comprehensive settlement agreement. The Company
issues its common stock in conjunction with certain compensation plans. For
additional information on these matters, see "Contract Termination Charge"
elsewhere herein and Notes 6 and 7.
SUPPLEMENTAL CASH FLOW INFORMATION
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1995 1994 1993
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Cash interest payments, net
of capitalized interest $ 154,866 $ 162,743 $ 174,964
- ----------------------------------------------------------------------------
Cash income tax payments, net $ 19,970 $ 6,477 $ 22,494
- ----------------------------------------------------------------------------
</TABLE>
The caption "Changes in certain asset and liabilities, net of non-cash
transactions and the effects of acquisitions and dispositions" as shown in the
accompanying Statement of Consolidated Cash Flows includes the following:
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1995 1994 1993
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Accounts and notes receivable,
principally customer $(119,933) $ 98,641 $ (55,273)
Inventories(1) 25,112 42,626 (49,300)
Deferred gas costs (19,831) (78) 31,549
Other current assets 10,661 (7,637) 41,730
Accounts payable, principally
trade 171,047 (53,708) (7,687)
Income taxes payable 20,444 (8,216) (768)
Interest payable (3,450) (2,497) (5,688)
General taxes 2,603 (4,394) 4,625
Customers' deposits 150 734 (615)
Other current liabilities 5,151 (17,441) 15,797
Recovery under gas
contract disputes 24,200 21,300 18,800
- ----------------------------------------------------------------------------
$ 116,154 $ 69,330 $ (6,830)
============================================================================
</TABLE>
(1) Gas in underground storage inventory at December 31, 1993 included
approximately $51.2 million of gas attributable to the operations of MRT.
Substantially all of this gas was sold to MRT's customers during 1994 and
was replaced with customer-owned gas, with MRT retaining only the quantity
of gas necessary for system operational purposes.
60 N O R A M
<PAGE> 29
2. INCOME TAXES
The Company and its subsidiaries file a consolidated U.S. Federal income tax
return. Such returns have been audited and settled through the year 1986.
Investment tax credits are generally deferred and amortized over the lives of
the related assets.
PROVISION FOR INCOME TAXES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
Expense (Benefit) 1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal
Current $ 18,760 $ 41 $ 15,773
Deferred 24,377 38,965 26,332
Investment Tax Credit (639) (641) (2,023)
State
Current 2,375 2,117 3,039
Deferred 10,506 (6,110) 3,360
- -------------------------------------------------------------------------------
$ 55,379 $ 34,372 $ 46,481
===============================================================================
</TABLE>
The provision for income taxes differs from the amount computed by applying
the statutory federal income tax rate of 35% to income from continuing
operations. The reasons for this difference are as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed "expected" federal
income tax $ 42,318 $ 29,982 $ 30,246
Increase (decrease) in tax
resulting from:
State income taxes, net of
federal income tax benefit(1) 8,373 (2,596) 4,159
Investment tax credit (639) (641) (2,023)
Stock basis difference in
sale of subsidiary - - 8,093
Research and
experimentation credit (375) (1,500) -
Adjustments to prior
year accruals 510 1,492 4,299
Goodwill amortization 4,163 4,167 4,449
Effect of 1% increase in
statutory federal
income tax rate - - (2,267)
Other, net 1,029 3,468 (475)
- -------------------------------------------------------------------------------
Provision for income taxes $ 55,379 $ 34,372 $ 46,481
===============================================================================
</TABLE>
(1) Calculation of the accrual for state income taxes at the end of each year
requires that the Company estimate the manner in which its income for that
year will be allocated and/or apportioned among the various states in which
it conducts business, which states have widely differing tax rules and
rates. These allocation/apportionment factors change from year to year and
the amount of taxes ultimately payable may differ from that estimated as a
part of the accrual process. For these reasons, the amount of state income
tax expense may vary significantly from year-to-year, even in the absence
of significant changes to state income tax valuation allowances or changes
in individual state income tax rates.
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 1995 and
1994, were as follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX ASSETS
Employee benefit accruals $ 25,153 $ 24,813
Inventory revaluation and capitalization 1,101 1,316
Gas purchase contract accruals 21,972 37,894
Regulatory obligations 10,806 1,652
Indemnifications and other reserves 9,714 10,473
Deferred state income taxes 12,915 9,373
Miscellaneous 30,797 30,850
Operating and capital loss carryforwards 30,547 61,882
Alternative minimum tax and general
business credit carryforwards 78,233 60,378
Valuation allowance (6,188) (5,974)
- -------------------------------------------------------------------------------
Total deferred tax assets 215,050 232,657
- -------------------------------------------------------------------------------
DEFERRED TAX LIABILITIES
Property, plant and equipment
principally due to depreciation
methods and lives 450,312 443,475
Deferred gas costs 15,431 2,780
Employee benefit accruals 10,354 10,618
Miscellaneous 28,797 23,336
- -------------------------------------------------------------------------------
Total deferred tax liabilities 504,894 480,209
- -------------------------------------------------------------------------------
Net deferred tax liabilities $289,844 $247,552
===============================================================================
</TABLE>
At December 31, 1995, the Company had approximately $424 million of state
net operating losses available to offset future state taxable income through the
year 2010, and approximately $2.6 million of federal net operating losses
available to offset future federal taxable income through the year 2010. In
addition, at December 31, 1995, the Company had approximately $6.8 million of
general business credit carryforwards that expire between 1998-2010, and
approximately $71 million of federal alternative minimum tax credits which are
available to reduce future federal income taxes payable, if any, over an
indefinite period (although not below the tentative minimum tax otherwise due in
any year).
3. FINANCING
The Company meets its needs for short-term financing through utilization of
both formal and informal lines of credit with commercial banks and through a
sale of receivables facility as discussed following. The Company obtains
long-term financing through the issuance of common stock in public offerings
and pursuant to a number of plans (see Notes 5 and 6 and "Other Long-Term
Financing" following), through public offerings of unsecured debt (the Company
is prohibited under an indenture from issuing mortgage debt), through a bank
term loan as discussed following and has issued $130 million of preferred
stock. In late 1995, the Company filed a "shelf" registration statement with
the Securities and Exchange Commission pursuant to Rule 415,
N O R A M 61
<PAGE> 30
allowing the Company to issue up to $500 million of a wide variety of
securities (including both debt and equity) over an approximately two-year
period following the March 1996 effective date of the filing.
SHORT-TERM CREDIT FACILITIES (1)
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars) Year Ended
December 31, (2) December 31,
----------------------- ---------------------------------------
Borrowed Wtg. Avg. Wtg. Avg. Wtg. Avg. Max. Amt.
Amount Int. Rate Borrowed Rate Borrowed
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1995 $ 10.0 6.68% $ 56.5 6.73% $ 135.0
1994 110.0 7.04% 55.9 5.85% 170.0
1993 $ 95.0 4.65% $ 28.4 5.30% $ 120.0
- -------------------------------------------------------------------------------
</TABLE>
(1) Includes both formal and informal facilities.
(2) There were no borrowings at March 1, 1996.
In late 1995, the Company renewed, revised and extended its principal
short-term credit facility ("the Facility"), an arrangement with Citibank, N.A.
as agent and a group of 18 other commercial banks, which now provides a $400
million commitment to the Company through December 11, 1998. Borrowings under
the Facility are unsecured (the stock of NGT and MRT, collateral under the prior
facility, have been released) and, at the option of the Company, bear interest
at various Eurodollar and domestic rates plus a credit spread, which credit
spread is subject to adjustment based on the rating of the Company's senior debt
securities. The Company pays a facility fee on the total commitment to each bank
each year, currently 1/4% and subject to decrease based on the Company's debt
rating, and will pay incremental rates of 1/8% to 1/4% on outstanding borrowings
in excess of $200 million.
SALE OF RECEIVABLES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars) Year Ended
December 31, December 31,
----------------------- ---------------------------------------
Amount Pre-tax Average
Sold and Net Inflows Loss Receivables
Uncollected Collateral (Outflows) On Sale Sold
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1995 $235.0 $ 35.0 $ 42.2 $ (9.8) $ 136.6
1994 192.8 48.7 (33.6) (7.1) 116.0
1993 $226.4 $ 29.0 $ 13.8 $ (8.1) $ 122.6
- -------------------------------------------------------------------------------
</TABLE>
Under an August 1995 agreement ("the Agreement") which expires in August
1996 (although the Company currently expects to renew the facility), the Company
sells, with limited recourse and subject to a floating interest rate provision
which varies with the buyer's A1/P1 commercial paper rate, an undivided interest
(limited to a maximum of $235 million) in a designated pool of accounts
receivable. The receivables sold have been deducted from "Accounts and notes
receivable, principally customer" in the accompanying Consolidated Balance
Sheet. Certain of the Company's remaining receivables serve as collateral for
receivables sold and represent the maximum exposure to the Company should all
receivables sold prove ultimately uncollectible. The Company has retained
servicing responsibility under the Agreement for which it is paid a fee which
does not differ materially from a normal servicing fee and, to the extent that
the Company utilizes this facility more or less during a given period, it will
experience net cash inflows or outflows.
LONG-TERM DEBT (1)
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars) December 31,
1995 1994
-------------------- ---------------------
Due in Due in
Long- One Long- One
Term Year(2) Term Year
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Medium-term notes,
Series A and B
due through 2001,
weighted average
rate of 8.99% $ 293.6 $ 118.8 $ 412.4 $ 1.0
9.45% Series due 1995 - - - 150.0
8% Series due 1997 - - 150.0 -
9.875% Series due 1997 225.0 - 225.0 -
8.875% Series due 1999 200.0 - 200.0 -
7 1/2% Series due 2000 (3) 200.0 - - -
8.90% Series due 2006 145.1 - 145.1 -
9.875% Series due 2018 (4) 116.4 - 122.1 -
10% Series due 2019 (5) 144.2 - 159.2 -
Bank term loan due 2000 (6) 150.0 - - -
Note payable to gas supplier - - - 13.6
Other 0.6 - 0.6 -
- -------------------------------------------------------------------------------
$1,474.9 $ 118.8 $1,414.4 $164.6
===============================================================================
</TABLE>
(1) Noncallable and without sinking fund requirements except as noted.
(2) The aggregate amount of long-term debt maturities (excluding certain
scheduled sinking fund requirements, see (4) following) for each of the
five years following December 31, 1995 is: 1996 - $118.8 million; 1997
- $277.0 million; 1998 - $76.0 million; 1999 - $200.6 million; 2000 -
$371.5 million.
(3) In August 1995, the Company issued $200 million of 7 1/2% five-year
notes in a public offering. The proceeds were used to reduce the
Company's bank borrowings, participation in its sale of receivables
program and for general corporate purposes pending the October 1995
retirement, at maturity, of the Company's $150 million of 9.45% notes.
(4) Callable at December 31, 1995 at a price of 106.42% and thereafter at
prices declining to par in February 2008. Mandatory sinking fund
payments of $10 million (which may be increased by up to an additional
$10 million at the option of the Company) are payable beginning in
February 1999 and each year thereafter, and $83.6 million principal
amount previously reacquired and retired by the Company may, at its
option, be credited against the sinking fund requirements.
(5) Callable beginning in 1999 at redemption prices beginning at 105.0% and
declining to par in November 2009. Mandatory sinking fund payments of
$10 million (which may be increased by up to an additional $20 million
at the option of the Company) are payable beginning in November 2005
and each year thereafter, and $55.8 million principal amount previously
reacquired and retired by the Company may, at its option, be credited
against the sinking fund requirements.
(6) In December 1995, the Company entered into a $150 million term loan
agreement ("the Loan") with a group of 18 commercial banks, using the
proceeds to redeem (at par) the $150 million of its 8% Notes due 1997.
The Loan bears interest at LIBOR + 87 1/2 basis points (a rate of
6.4375% at December 31, 1995, to be reset in June 1996) and the rate is
reset each 30, 60, 90 or 180 days at the option of the Company. The
Loan is due in four equal principal payments in March, June, September
and December of the year 2000, and may be repaid in whole or in part
any time without premium.
62 N O R A M
<PAGE> 31
REACQUISITIONS OF LONG-TERM DEBT
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars)
Principal Weighted Premium Paid(1)
Year Ended Amount Avg. Interest -------------------------
December 31, Reacquired Rate Pre-tax Tax Benefit
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1995 $ 170.7(2) 8.2% $ 0.08 $ (0.03)
1994 50.4 9.8% 1.4 (0.3)
1993 $ 88.3 9.8% $ 5.5 $ (1.7)
- -------------------------------------------------------------------------------
</TABLE>
(1) Includes the write-off of any associated unamortized debt issuance cost
and is reported in the accompanying Statement of Consolidated Income
under the caption, "Extraordinary item, less taxes".
(2) Includes $150.0 million of 8% Notes due 1997 redeemed at par as
discussed preceding.
INTEREST RATE SWAPS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars)
Notional
Amount Unrealized Deferred Interest Rate
Outstanding Loss(1) Gain(2) Fixed/Floating
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
December 31, 1992 - - - -
Additions $ 575.0 - - -
Terminations (375.0) - - -
December 31, 1993 200.0 $ (2.6) $ 5.0 5.1%/4.5%
Additions 75.0 - - -
Terminations - - - -
December 31, 1994 275.0 (18.0) 2.5 5.1%/6.7%
Additions 100.0 - - -
Terminations (25.0) - - -
December 31, 1995 $ 350.0 $ (0.8) $ 0.8 5.1%/6.6%(3)
- -------------------------------------------------------------------------------
</TABLE>
(1) Market value of swaps at date indicated.
(2) The economic value which transfers between the parties to these swaps
is reported as an adjustment to the effective interest rate on the
underlying debt securities and, when positions are closed prior to
expiration, any material gain or loss is deferred and amortized over
the period remaining in the original term of the swap. The effect of
these swaps was to increase (decrease) interest expense by
approximately $(4.6) million, $0.5 million and $(0.2) million in 1993,
1994 and 1995, respectively.
(3) Does not include swaps which are hedges of anticipated debt issuance as
discussed following.
In recognition of the fact that the Company had unusually low levels of
floating rate debt due, in large part, to the application of cash received from
divestitures, beginning in 1993, the Company entered into a number of interest
rate swaps which, in general, specified that the Company would pay a
LIBOR-based rate on the notional amount of the swap while the counterparty (a
commercial bank) paid a fixed rate, for the purpose of subjecting a reasonable
portion of the Company's debt portfolio to market interest rate fluctuations.
In early 1996, the Company terminated the $250 million of such swaps
outstanding, resulting in no material gain or loss.
In late 1995, the Company entered into $100 million of swaps, in which it
agreed to pay a fixed rate of 5.92% on the notional amount for a 5-year period
beginning April 1, 1997, while the counterparties pay a LIBOR-based rate, for
the purpose of effectively fixing the interest rate on debt expected to be
issued in 1997 for refunding purposes. In early 1996, the Company entered into
additional swaps for the same period and purpose with a total notional amount
of $100 million in which it agreed to pay an average fixed rate of
approximately 5.78%.
In order to take advantage of historically low rates and reduce the
Company's exposure to fluctuations in market interest rates arising from its
various LIBOR and A1/P1 commercial paper-based financing facilities as
described elsewhere herein, in February 1996, the Company entered into two
swaps of $50 million notional amount each, beginning in March and June 1996,
respectively, and each of which expire at approximately year-end 1997, in which
it agreed to pay an average fixed rate of 4.74% while the counterparty pays a
LIBOR-based rate. The Company expects that it may enter into additional such
swaps in the future.
None of these interest rate swaps are "leveraged" and, accordingly, do not
represent exposure in excess of that suggested by the notional amounts and
interest rates and, in general, the future cash flows are measured as the
notional amount times the interest rate. Off-balance-sheet credit risk exists
to the extent that counterparties to these swaps may fail to perform, although
all counterparties are commercial banks which are participants in the Company's
revolving credit facility. The Company routinely reviews the financial
condition of these banks (utilizing independent monitoring services and
otherwise) and believes that the probability of default by any of these
counterparties is minimal.
OTHER LONG-TERM FINANCING
The Company has equipment funding agreements ("EFA's") with affiliates of major
banks which provide for the purchase of vehicles, major work equipment and, to
a lesser extent, computers and other office equipment. For accounting purposes,
assets subject to these EFA's receive operating lease treatment, with an
initial non-cancellable term of one year. At December 31, 1995 the Company had
$14.7 million of available capacity under these EFA's, and capacity under the
EFA's will increase by $14 million in July 1996. The EFA's extend through July
1997 unless renewed through mutual agreement of the parties.
Since late 1994, the Company has offered a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP") which affords customers and other
interested parties the opportunity to (1) purchase the Company's common stock
("the Shares") directly from the Company, avoiding brokerage fees and
commissions and (2) automatically reinvest their dividends in additional
Shares. Sales of Shares under the DSPP were immaterial in 1994 and, in 1995,
the Company received approximately $9.8 million (net of issuance cost of
approximately $0.7 million) from such sales.
RESTRICTIONS ON STOCKHOLDERS' EQUITY AND DEBT
Under the provisions of the Company's revolving credit facility as described
preceding, and under similar provisions in certain of the Company's other
financial arrangements, the Company's total debt capacity is limited and it is
required to maintain a minimum level of stockholders' equity. The Company's
total debt is limited to $2,055 million and the Company's ability to reacquire,
retire or otherwise prepay its long-term debt prior to its maturity is limited
to a total of $200 million. The required minimum level of stockholders' equity
was initially set at $675 million at June 30, 1995, increasing annually
thereafter by (1) 50% of positive consolidated net income and (2) 50% of the
proceeds (in excess of the first $100 million) from any incremental
N O R A M 63
<PAGE> 32
equity offering made after June 30, 1995. Based on these restrictions, the
Company had incremental capacity for debt issuance, dividends and debt
reacquisitions of $416.3 million, $82.0 million and $200 million, respectively,
at December 31, 1995.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and fair values of certain of
the Company's financial instruments. Statement of Financial Accounting
Standards No. 107, "Disclosures about Fair Value of Financial Instruments",
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale. The estimated fair value amounts
have been determined by the Company using quoted market prices of the same or
similar securities when available or other estimation techniques. The items
presented below without a carrying value are off-balance-sheet financial
instruments and all of the Company's financial instruments are held for
purposes other than trading.
The carrying amounts of certain financial instruments employed by the
Company, including cash and cash equivalents, accounts and notes receivable and
payable, gas purchased in advance of delivery and other current assets and
liabilities, approximate fair value. The fair value of the Company's interest
rate swaps, natural gas swaps and futures contracts generally reflect the
estimated amounts that the Company would pay or receive to terminate the
contracts at the reporting date, thereby taking into account the unrealized
gains and losses on open contracts. There is no readily available market for the
natural gas options.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------
(millions of dollars) December 31,
1995 1994
- ------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FINANCIAL ASSETS
Investment in Itron (Note 1) $ 50.7 $ 50.7 $ 32.1 $ 32.1
Natural gas options (Note 8) $ 1.3 - $ 2.2 -
Natural gas futures (Note 8) - $ 3.3 - $ (2.9)
- ------------------------------------------------------------------------------
FINANCIAL LIABILITIES
Long-term debt (Note 3) $1,593.7 $1,677.1 $1,579.0 $1,548.3
Interest rate swaps (Note 3) - 0.8 - 18.0
Natural gas swaps (Note 8) - $ 2.3 - $ 16.7
- ------------------------------------------------------------------------------
</TABLE>
5. EMPLOYEE BENEFIT PLANS
The Company has two qualified pension plans ("the Qualified Plans") which cover
substantially all employees; (1) the plan which covers the Company's employees
other than Minnegasco employees and (2) the plan which covers Minnegasco
employees. The Qualified Plans provide benefits based on the participant's
years of service and highest average compensation. The funding policy for the
Qualified Plans is to contribute at least the minimum amount required to be
funded as determined by the Company's consulting actuaries. Plan assets are
made up of marketable equity and high-grade fixed income securities.
In addition to the Qualified Plans, the Company maintains certain
non-qualified plans which principally consist of (1) a retirement restoration
plan which allows participants to retain the benefit to which they would have
been entitled under the Qualified Plans except for the federally mandated limits
on such benefits or on the level of salary on which such benefits may be
calculated and (2) certain supplemental benefit plans which, in the past, were
entered into with individual employees or with small groups of employees.
Participants in these non-qualified plans are general creditors of the Company
with respect to these benefits, as these plans are not funded by the Company in
advance of the cash payment of benefits. Expense of approximately $2.1 million,
$2.3 million and $4.8 million associated with these non-qualified plans was
recorded during 1995, 1994 and 1993, respectively.
64 N O R A M
<PAGE> 33
PENSION PLAN STATUS
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- ------------------------------------------------------------------------------------------------------------------------
Qualified Non-Qualified Qualified Non-Qualified
Plans Plans Plans Plans
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net assets available for benefits $ 439,153 - $ 353,306 -
- ------------------------------------------------------------------------------------------------------------------------
Actuarial present value of accumulated plan benefits
Vested (assuming immediate separation) 304,361 $ 18,681 244,339 $ 16,274
Non-vested 32,831 1,660 24,423 377
- ------------------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation 337,192 20,341 268,762 16,651
Additional amount related to projected pay increases 75,713 845 52,577 1,955
- ------------------------------------------------------------------------------------------------------------------------
Total projected benefit obligation 412,905 21,186 321,339 18,606
- ------------------------------------------------------------------------------------------------------------------------
Funded status 26,248 (21,186) 31,967 (18,606)
Unrecognized net obligation at January 1 (12,123) - (13,734) -
Unrecognized prior service costs - 5,529 - 6,054
Unrecognized net loss from past experience different
from that assumed and effects of changes
in actuarial assumptions 43,840 (1,654) 38,432 (3,554)
- ------------------------------------------------------------------------------------------------------------------------
Pension prepaid asset (liability) $ 57,965 $ (17,311) $ 56,665 $ (16,106)
========================================================================================================================
</TABLE>
PENSION PLAN RATE ASSUMPTIONS
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 7.25% 8.5% 7.25%
Assumed rate of increase in future
compensation 4% 4% 4%
Expected long-term rate of return
on fund assets 10% 10% 11%
- -------------------------------------------------------------------------------
</TABLE>
PERIODIC PENSION COST (QUALIFIED PLANS ONLY)
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
(thousands of dollars) 1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned
during the period $ 9,900 $ 11,757 $ 9,799
Interest cost on projected
benefit obligation 27,097 25,633 26,376
Actual return on plan
assets (36,909) (3,067) (24,517)
Amortization and deferral (1,388) (33,774) (15,431)
- -------------------------------------------------------------------------------
Net pension cost (credit) $ (1,300) $ 549 $ (3,773)
===============================================================================
</TABLE>
The Company has an employee savings plan ("the ESP") which covers
substantially all employees other than Minnegasco employees. Under the terms of
the ESP, employees may contribute up to 12% of total compensation, which
contributions up to 6% are matched by the Company. Employer contributions to the
ESP of $8.9 million, $8.8 million and $5.2 million were expensed during 1995,
1994 and 1993, respectively. The ESP and the Entex Stock Purchase Plan for
salaried employees merged into a single plan effective in June 1993. Under the
provisions of its previously existing employee stock purchase plans, Entex made
$3.5 million of contributions during 1993. The Minnegasco employees are covered
by various thrift and profit sharing plans, the terms of which vary from plan to
plan. Expense of approximately $1.4 million, $1.3 million and $1.5 million
related to these plans was recorded during 1995, 1994 and 1993, respectively.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees, collectively
referred to as "postretirement benefits". The Company provides these benefits
under a defined benefit plan for all former employees who retired prior to July
1, 1992, and under a defined contribution plan for all others. A substantial
number of the Company's employees may become eligible for postretirement
benefits if they are participating in such plans when they reach normal
retirement age. Effective January 1, 1993, the Company began to account for
these benefits pursuant to Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other than Pensions", which
replaced the historical cash method with a method whereby expense is booked as
these benefits are earned. As of December 31, 1995, the Company had contributed
$1.8 million to an external fund (associated with Minnegasco employees) to
provide for these benefits. The Company currently expects that it may fund these
benefits utilizing external funding techniques for additional employees in the
future.
POSTRETIREMENT BENEFIT PLAN STATUS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) December 31,
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees $ 129,425 $ 128,140
Fully-eligible plan participants 4,929 5,969
Other active plan participants 5,574 5,210
- -------------------------------------------------------------------------------
Total 139,928 139,319
Fair value of plan assets 1,800 -
- -------------------------------------------------------------------------------
138,128 139,319
Unrecognized transition obligation (113,261) (120,977)
Unrecognized prior service cost - 1,053
Unrecognized net actuarial (gain) loss 337 (717)
- -------------------------------------------------------------------------------
Accrued postretirement benefit liability $ 25,204 $ 18,678
===============================================================================
</TABLE>
N O R A M 65
<PAGE> 34
The weighted average discount rate used in determining the accumulated
benefit obligation for postretirement benefits was 7.25%, 8.5% and 7.25% for
1995, 1994 and 1993, respectively. The cost of covered health care benefits
(for those participants entitled to a defined benefit as a result of having
retired prior to July 1, 1992) is assumed to increase by 11% per year initially
and then increase at a decreasing rate to an annual and continuing increase of
4.5% after 11 years. Based on these assumptions, a one percentage point
increase in the assumed health care cost trend rate would increase the annual
net periodic postretirement benefit cost (before any deferral for regulatory
reasons) and the accumulated benefit obligation at December 31, 1995 by
approximately $0.9 million and $14.6 million, respectively.
POSTRETIREMENT BENEFITS EXPENSE
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(thousands of dollars) 1995 1994 1993
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 291 $ 408 $ 247
Interest cost on accumulated
benefit obligation 10,183 10,436 11,670
Amortization of transition
obligation on a straight
line basis over 20 years 6,663 6,721 6,721
Deferral of asset loss (195) (87) -
- -------------------------------------------------------------------------------
Net periodic cost $16,942 $17,478 $18,638
===============================================================================
</TABLE>
The Company's regulated businesses are subject to the jurisdiction of
various regulatory bodies which are in differing stages of establishing policy
with respect to the rate treatment of these postretirement benefit costs. The
Company has made rate filings concerning these costs which are in various
stages of progression through the regulatory process and, in other
jurisdictions, the Company has not yet filed rate cases to seek recovery of the
SFAS 106 calculated costs (as opposed to the cash costs currently included in
rates). In light of this regulatory uncertainty and the guidance provided by
authoritative accounting pronouncements concerning the appropriate accounting
treatment for the excess of accrual SFAS 106 costs over the amount includable
in rates prior to final regulatory determination, at December 31, 1995, the
Company had deferred approximately $5.1 million of such costs in certain
jurisdictions pending final regulatory actions. This deferral will be subject
to continuing review and may require adjustment depending on the ultimate
regulatory disposition of these costs.
The Company has several plans which provide for the issuance of its common
stock to employees and directors or provide for the sale of the Company's
common stock to these individuals, see Note 6.
6. STOCK COMPENSATION/STOCK PURCHASE PLANS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
Stock Options SAR's
------------------------------ -------------------------- Year Ended,
Restricted Avg. Exercise Avg. Exercise Charge (Credit)
Stock (1) Shares Price/Shr. Shares Price/Shr. to Earnings
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
December 31, 1992 770,392 312,453 $ 16.59 400,592 $ 12.93 $ 1.7
Granted/Issued 215,885 - - - - -
Forfeited/Expired (56,588) (50,880) 15.08 (25,000) 13.00 -
Exercised - - - -
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1993 929,689 261,573 16.88 375,592 12.92 1.5
Granted/Issued 162,284 313,418 6.50 - - -
Forfeited/Expired (149,404) (38,053) 14.49 (250,000) 12.00 -
Exercised - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1994 942,569 536,938 10.99 125,592 14.75 (0.2)
Granted/Issued 262,461 546,550 5.54 - - -
Forfeited/Expired (103,894) (164,469) 14.05 (32,478) 18.44 -
Exercised - - - - - -
- --------------------------------------------------------------------------------------------------------------------------------
December 31, 1995 1,101,136 919,019 $ 7.20 93,114 $ 13.47 $ 0.5
================================================================================================================================
</TABLE>
(1) Shares are included when granted. Does not include restricted stock (i)
issued to the Company's Chairman in lieu of cash salary or (ii) issued
pursuant to the Restricted Stock Plan for Non-Employee Directors as
discussed following.
The Company has an Incentive Equity Plan ("the IEP") intended to
facilitate the attraction and retention of key employees and to provide an
incentive for superior performance. The IEP provides for the issuance of up to
3.8 million shares of the Company's common stock ("Shares"), no more than 2
million of which may be issued or transferred as Restricted Stock, as well as
stock options and stock appreciation rights ("SAR's"). Options and SAR's issued
pursuant to the IEP are exercisable for a period of 10 years from the date of
issuance and vest at the rate of 1/3 per year, beginning with the year of
issuance. At December 31, 1995, options on 94,095 shares at an average exercise
price of $6.50/share and all SAR's were vested. Provisions of the IEP determine
the amount of these securities initially granted to employees, while the amount
ultimately retained by each employee is determined by the Company's performance
as measured by the Board of Directors during three-year performance cycles.
66 N O R A M
<PAGE> 35
While no additional options may be issued pursuant to either plan, some
stock options remain outstanding pursuant to (1) a Non-Qualified Stock Option
Plan adopted by the Company in 1983, which options expire in 1997 and (2) a
former Diversified Energies Plan, which options expire from 1996 to 2000.
The Company has a Restricted Stock Plan for Non-Employee Directors ("the
DRSP") which is intended to assist in attracting and retaining highly qualified
individuals to serve as directors of the Company. Shares issued pursuant to the
DRSP will not exceed a total of 125,000 and may be Shares of original issuance,
treasury Shares or both. At December 31, 1995, a total of 42,096 Shares had been
issued pursuant to the DRSP.
The Company has an Employee Stock Purchase Plan ("the ESPP") which provides
employees with an incentive to increase their Share ownership by affording them
the opportunity to purchase Shares at a price equivalent to 85% of fair market
value. The ESPP provides for payment via payroll deduction and is limited to a
total of 2 million Shares, which may be unissued Shares, reacquired Shares,
Shares purchased on the open market or a combination thereof.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), which is effective for transactions entered into in
fiscal years beginning after December 15, 1995. SFAS 123 provides the options of
(1) recording compensation expense in accordance with its provisions or (2)
continuing the current principles for expense recognition, with disclosure of
what expense would have been, had it been computed pursuant to the valuation and
recognition methodology in SFAS 123. The Company expects that it will adopt the
disclosure option provided for in SFAS 123 and, accordingly, will experience no
impact on its earnings subsequent to adoption.
7. ACQUISITIONS AND DISPOSITIONS
DISTRIBUTION PROPERTY TRANSACTIONS
In September 1994, the Company sold all of its Kansas distribution properties
(together with certain related pipeline assets) for approximately $23 million
in cash, approximately the carrying value. This system serves approximately
23,000 customers in 14 communities.
Effective September 1, 1993, the Company completed an exchange of natural
gas distribution properties with Midwest Gas ("Midwest"), a unit of Midwest
Resources. Under the terms of the exchange, the Company received the Minnesota
distribution properties of Midwest (serving 41 communities with approximately
82,000 customers) in exchange for Minnegasco's South Dakota properties (serving
18 communities with approximately 45,000 customers) plus $38 million in cash.
The utility properties acquired were recorded at the historical cost of the
properties surrendered plus cash paid and no gain or loss was recognized. A gas
plant acquisition adjustment of $14 million was recorded, for which the Company
is seeking recovery through the regulatory process.
In February 1993, Minnegasco completed the sale of its Nebraska
distribution system to Peoples Natural Gas of Omaha, Nebraska (a division of
UtiliCorp United) for $75.3 million in cash plus an additional payment of $17.8
million for net working capital transferred, resulting in an after-tax gain of
approximately $15.1 million (net of tax expense of $8.7 million), included in
the accompanying Statement of Consolidated Income under the caption "Other,
net". This system serves approximately 124,000 customers in 63 eastern Nebraska
communities.
LOUISIANA INTRASTATE GAS CORPORATION ("LIG")
In June 1993, the Company completed the sale of LIG to a subsidiary of
Equitable Resources, Inc. ("Equitable") for $191 million in cash, resulting in
an after-tax gain of approximately $3.4 million (net of tax expense of $14.3
million), included in the accompanying Statement of Consolidated Income under
the caption "Other, net", and agreed to indemnify Equitable against certain
exposures, for which the Company has established reserves equal to anticipated
claims under the indemnity. Contemporaneously with the sale, the Company funded
LIG's portion of a litigation settlement in the amount of approximately $21.1
million. This amount had been fully reserved by LIG and has been netted against
the gross sales proceeds in the accompanying Statement of Consolidated Cash
Flows for 1993 under the caption "Sale of LIG, net of related expenditures".
EXPLORATION AND PRODUCTION
On December 31, 1992, the Company completed the sale of Arkla Exploration
Company, its subsidiary engaged in oil and gas exploration and production, to
Seagull Energy Corporation ("Seagull") for approximately $397 million in cash.
The Company agreed to indemnify Seagull against certain exposures, for which
the Company has established reserves equal to anticipated claims under the
indemnity. In conjunction with its 1991 sale of Dyco Petroleum Company, the
Company established a reserve equal to its maximum exposure under the limited
indemnity provisions of the sale agreement.
THE HUNTER COMPANY
In June 1991, the Company acquired The Hunter Company, a Shreveport-based
company whose principal assets consisted of approximately 16 Bcf of natural gas
reserves, cash and cash equivalents and certain real estate, through an
exchange of stock accounted for as a purchase. The Company ultimately issued a
total of 1.1 million shares of common stock to effect the acquisition. A
majority of the Company's investment in the former Hunter Company assets was
conveyed to Seagull Energy Corporation in conjunction with the sale of Arkla
Exploration Company as described preceding.
8. COMMITMENTS AND CONTINGENCIES
<TABLE>
<CAPTION>
MINIMUM LEASE COMMITMENTS AT DECEMBER 31, 1995 (1)
- --------------------------------------------------------------------------------
(thousands of dollars)
- --------------------------------------------------------------------------------
<S> <C>
1996 $ 27,717
1997 16,390
1998 14,052
1999 13,261
2000 11,566
2001 and beyond 36,336
- --------------------------------------------------------------------------------
Subtotal 119,322
- --------------------------------------------------------------------------------
Less subleases (906)
- --------------------------------------------------------------------------------
Net $ 118,416
================================================================================
</TABLE>
(1) Principally consisting of rental agreements for building space, data
processing equipment and vehicles (including major work equipment).
N O R A M 67
<PAGE> 36
Lease payments related to assets transferred under the Company's leasing
arrangements (see Note 3) are included in the preceding table for only their
primary (non-cancelable) term. Subsequent to the primary term, the Company
could terminate its obligations under these arrangements by electing to
purchase the relevant assets for an amount approximating fair market value.
Total rental expense for all leases was $48.9 million, $36.8 million and $36.5
million in 1995, 1994 and 1993, respectively.
LETTERS OF CREDIT
At December 31, 1995, the Company was obligated under letters of credit
totalling approximately $31.2 million which are incidental to its ordinary
business operations.
INDEMNITY PROVISIONS
The Company has obligations under indemnification provisions of certain sale
agreements, see Note 7.
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been sold, see Note 3.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has
prepaid for certain volumes of gas, which prepayments have been recorded at
their net realizable value and, to the extent that the Company is unable to
realize at least the carrying amount as the gas is delivered and sold, the
Company's earnings will be adversely affected, although such impact is not
expected to be material. In addition to these prepayments, the Company is a
party to a number of agreements which require it to either purchase or sell gas
in the future at prices which may differ from then-prevailing market prices or
which require it to deliver gas at a point other than the expected receipt
point for volumes to be purchased. As discussed following, the Company operates
an ongoing risk management program designed to eliminate or limit the Company's
exposure from its obligations under these purchase/sale commitments. To the
extent that the Company expects that these commitments will result in losses
over the contract term, the Company has established reserves equal to such
expected losses.
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250 MMcf/day,
and pursuant to which ANR had advanced $125 million to the Company. The ANR
Agreement has been restructured as a lease of capacity and, after refunds of
$50 million and $34 million in 1995 and 1993, respectively, the Company
currently retains $41 million (recorded as a liability) in exchange for ANR's
use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in the
year 2003 with a refund of $5 million to ANR and the ANR Agreement will
terminate in 2005 with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company's gas supply, marketing, gathering and transportation activities
subject the Company's earnings to variability based on fluctuations in both the
market price of natural gas and the value of transportation as measured by
changes in the delivered price of natural gas at various points in the nation's
natural gas grid. In order to mitigate the financial risk associated with these
activities both for itself and for certain customers who have requested the
Company's assistance in managing similar exposures, the Company routinely
enters into natural gas swaps, futures contracts and options, collectively
referred to herein as "derivatives". This use of derivatives for the purpose of
reducing exposure to risk is generally referred to as hedging and, through
deferral accounting, results in matching the financial impact of these
derivative transactions with the cash impact resulting from consummation of the
transactions being hedged, see Note 1.
The futures contracts are purchased and sold on the NYMEX and generally are
used to hedge a portion of the Company's storage gas and provide risk management
assistance to certain customers, to whom the cost of the derivative activity is
generally passed on as a component of the sales price of the service being
provided. Futures contracts are also utilized to fix the price of compressor
fuel or other future operational gas requirements, although usage to date for
this purpose has not been material. The options are entered into with various
third parties and principally consist of options which serve to limit the
year-to-year escalation from January 1997 to April 1999 in the purchase price of
gas which the Company is committed to deliver to a distribution affiliate. These
options covered 13.2 Bcf, 30.5 Bcf and 49.3 Bcf at December 31, 1995, 1994 and
1993, respectively and, due to their nature and term, have no readily
determinable fair market value. The Company previously established a reserve
equal to its projected maximum exposure to losses during the term of this
commitment and, accordingly, no impact on earnings is expected. The swaps, also
entered into with various third-parties, are principally associated with the
Company's marketing and transportation activities and generally require that one
party pay either a fixed price or fixed differential from the NYMEX price per
MMBtu of gas while the other party pays a price based on a published index.
These swaps allow the Company to (1) commit to purchase gas at one location and
sell it at another location without assuming unacceptable risk with respect to
changes in the cost of the intervening transportation, (2) effectively set the
value to be received for transportation of certain volumes on the Company's
facilities in the future and (3) effectively fix the base price for gas to be
delivered in conjunction with the commitment described preceding. None of these
derivatives are held for speculative purposes and, in general, the Company's
risk management policy requires that positions taken in derivatives be offset by
positions in physical transactions or in other derivatives.
In the table which follows, the term "notional amount" refers to the
contract unit price times the contract volume for the relevant derivative
category and, in general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative of the Company's level of activity in such derivatives,
although the amounts at risk are significantly smaller because, in general,
changes in the market value of these derivatives are offset by changes in the
value associated with the underlying physical transactions or in other
derivatives.
68 N O R A M
<PAGE> 37
SWAPS (1)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Volume Volume Estimated Fair
as Fixed as Fixed Market Value
December 31, Price Payor Price Receiver (Loss) (2)
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
1995 235.7 214.3 $ (2.3)
1994 131.9 114.1 (16.7)
1993 101.2 82.2 $ (6.6)
- --------------------------------------------------------------------------------
</TABLE>
FUTURES CONTRACTS (3)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Purchased Sold
------------------- ------------------ Estimated Fair
Notional Notional Market Value
December 31, Volume Amount Volume Amount Gain(Loss) (2)
- --------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1995 15.1 $ 29.6 8.2 $ 18.9 $ 3.3
1994 6.7 $ 13.8 1.7 $ 2.8 $ (2.9)
1993 N/M(4) N/M N/M N/M N/M
- --------------------------------------------------------------------------------
</TABLE>
(1) The financial impact of these swaps was to increase earnings by $1.0
million, $2.8 million and $1.0 million during 1995, 1994 and 1993,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The
amount which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the
case of certain commitments described preceding, no earnings impact is
expected due to existing accruals. Swaps associated with these commitments
and included in the above totals had fair market values of $(1.0) million,
$(17.6) million and $(5.9) million at December 31, 1995, 1994 and 1993,
respectively.
(3) There was no material financial impact from these futures contracts in 1993
or 1994 and the effect during 1995 was to decrease earnings by $4.1 million
as futures transactions were matched with hedged transactions.
(4) Indicates that the item is not material.
While, as yet, the Company has experienced no significant losses due to the
credit risk associated with these arrangements, the Company has
off-balance-sheet risk to the extent that the counterparties to these
transactions may fail to perform as required by the terms of each such contract.
In order to minimize this risk, the Company enters into such transactions solely
with firms of acceptable financial strength, in most cases limiting such
transactions to counterparties whose debt securities are rated "A" or better by
recognized rating agencies. For long-term arrangements, the Company periodically
reviews the financial condition of such firms in addition to monitoring the
effectiveness of these financial contracts in achieving the Company's
objectives. Should the counterparties to these arrangements fail to perform, the
Company would seek to compel performance at law or otherwise, or to obtain
compensatory damages in lieu thereof, but the Company might be forced to acquire
alternative hedging arrangements or be required to honor the underlying
commitment at then-current market prices. In such event, the Company might incur
additional loss to the extent of amounts, if any, already paid to the
counterparties. In view of its criteria for selecting counterparties, its
process for monitoring the financial strength of these counterparties and its
experience to date in successfully completing these transactions, the Company
believes that the risk of incurring a significant loss due to the nonperformance
of counterparties to these transactions is minimal.
LITIGATION
On August 6, 1993, the Company, its former subsidiary, Arkla Exploration
Company ("AEC") and Arkoma Production Company, a subsidiary of AEC, were named
as defendants in a lawsuit filed in the Circuit Court of Independence County,
Arkansas. On September 20, 1994, the Circuit Court entered an order granting
the Company's motion to dismiss. On October 23, 1995, the Supreme Court of
Arkansas affirmed the Circuit Court's order granting the Company's motion to
dismiss.
The Company is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
along the Mississippi River in Minnesota known as the former Minneapolis Gas
Works ("FMGW") until 1960. The Company is working with the Minnesota Pollution
Control Agency to implement an appropriate remediation plan. There are six
other former MGP sites in the Company's Minnesota service territory. Of the six
sites, the Company believes that two were neither owned nor operated by the
Company; two were owned at one time but were operated by others and are
currently owned by others; one is presently owned by the Company but was
operated by others; and one was operated by the Company and is now owned by
others. The Company believes it has no liability with respect to the sites it
neither owned nor operated.
At December 31, 1995, the Company has estimated a range of $20 million to
$177 million for possible remediation of the Minnesota sites. The low end of the
range was determined using only those sites presently owned or known to have
been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned by
the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to
recover amortization of previously deferred and ongoing clean-up costs. Any
amounts in excess of $2.1 million annually were deferred for future recovery.
In its 1995 rate case, Minnegasco asked that the annual allowed recovery be
increased to approximately $7 million and that such costs be subject to a
true-up mechanism whereby any over or under recovered amounts, net of certain
insurance recover-
N O R A M 69
<PAGE> 38
ies, would be deferred until the next rate case. Such accounting was
implemented effective October 1, 1995 pending final approval in the existing
rate case. At December 31, 1995 and 1994, the Company had net deferred expenses
of $2.3 million and $0.2 million, respectively. At December 31, 1995 and 1994,
the Company had recorded a liability of $45.2 million and $40.1 million,
respectively, to cover the cost of remediation. The Company expects that the
majority of its accrual as of December 31, 1995 will be expended within the
next five years. In accordance with the provisions of SFAS 71, a regulatory
asset has been recorded equal to the liability accrued. The Company is pursuing
recovery of these costs from insurers. The Company believes the difference
between any cash expenditures for these costs and the amounts recovered in
rates during any year will not be material to the Company's overall cash
requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites in
the service territories of the distribution divisions. At the present time, the
Company is aware of some plant sites in addition to the Minnesota sites and is
investigating certain other locations. While the Company's evaluation of these
other MGP sites is in its preliminary stages, it is likely that some compliance
costs will be identified and become subject to reasonable quantification. To the
extent that such potential costs are quantified, as with the Minnesota
remediation costs for MGP described preceding, the Company expects to provide an
appropriate accrual and seek recovery for such remediation costs through all
appropriate means, including regulatory relief.
On October 24, 1994, the United States Environmental Protection Agency
advised the Company that MRT and a number of other companies have been named
under federal law as potentially responsible parties for a landfill site in West
Memphis, Arkansas and may be required to share in the cost of remediation of
this site. However, considering the information currently known about the site
and the involvement of MRT, the Company does not believe that this matter will
have a material adverse effect on the financial position, results of operations
or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company that the Company, through one of its subsidiaries and
together with several other unaffiliated entities, had been named under state
law as potentially responsible parties with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any, of the site. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
In addition, the Company, as well as other similarly situated firms in the
industry, is investigating the possibility that it may elect or be required to
perform remediation of various sites where meters containing mercury were
disposed of improperly, or where mercury from such meters may have leaked or
been disposed of improperly. While the Company's evaluation of this issue is in
its preliminary stages, it is likely that compliance costs will be identified
and become subject to reasonable quantification.
To the extent that potential environmental compliance costs are quantified
within a range, the Company establishes reserves equal to the most likely level
of costs within the range and adjusts such accruals as better information
becomes available. If justified by circumstances within the Company's businesses
subject to SFAS 71, corresponding regulatory assets are set up in anticipation
of recovery through the ratemaking process. At December 31, 1995 and 1994, the
Company had recorded an accrual of $3.3 million (with a maximum estimated
exposure of approximately $18 million) for environmental matters in addition to
the accrual for MGP sites as discussed preceding, with an offsetting regulatory
asset.
While the nature of environmental contingencies makes complete evaluation
impracticable, the Company currently is aware of no other environmental matter
which could reasonably be expected to have a material impact on its results of
operations, financial position or cash flows.
9. PIPELINE REORGANIZATION
In February 1996, the Company announced a reorganization plan affecting NGT and
MRT which resulted in the elimination of approximately 275 positions. The
Company expects to record a first-quarter 1996 charge of less than $20 million
associated with this plan.
70 N O R A M
<PAGE> 39
REPORT OF INDEPENDENT ACCOUNTANTS
BOARD OF DIRECTORS AND STOCKHOLDERS
NORAM ENERGY CORP.
We have audited the accompanying consolidated balance sheet of NorAm Energy
Corp. and Subsidiaries as of December 31, 1995 and 1994, and the related
statements of consolidated income, consolidated stockholders' equity and
consolidated 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 consolidated financial position of NorAm Energy
Corp. and Subsidiaries as of December 31, 1995 and 1994, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1995, in conformity with generally accepted
accounting principles.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 25, 1996
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
Management is responsible for the preparation of the Company's financial
statements and associated data in conformity with generally accepted accounting
principles. Some of the amounts are estimates based on judgment of current
conditions and circumstances.
To provide reasonable assurance that assets are safeguarded against loss
from unauthorized use or disposition and that accounting records are reliable
for preparing financial statements, management maintains a system of internal
accounting and managerial controls, including review of these controls by our
independent accountants and internal audit department who have free access to
the Audit Committee of the Board of Directors composed of non-employee
directors.
Management continues to improve its controls in response to changes in
business conditions and to assure ethical business practices. The independent
accountants have been engaged to examine and express an opinion on the Company's
annual consolidated financial statements.
Management believes that the Company's system of internal accounting and
managerial controls, including policies and procedures, provides reasonable
assurance that in all material respects assets are safeguarded and financial
information is reliable. All information in the annual report is consistent with
the financial statements.
N O R A M 71
<PAGE> 40
QUARTERLY INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
(thousands of dollars) 1995 Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 888,148 $ 565,842 $ 542,611 $ 968,078
====================================================================================================================
Gross profit (1) $ 346,972 $ 219,129 $ 217,865 $ 323,547
====================================================================================================================
Operating income $ 134,719 $ 27,263 $ 16,119 $ 109,204
====================================================================================================================
Income (loss) from continuing operations $ 51,996 $ (7,072) $ (14,284) $ 34,889
Extraordinary item, less taxes (52) - - -
- --------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 51,944 $ (7,072) $ (14,284) $ 34,889
====================================================================================================================
Per Share Data (2)
Continuing operations $ 0.41 $ (0.07) $ (0.13) $ 0.26
Extraordinary item, less taxes 0.00 - - -
- --------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.41 $ (0.07) $ (0.13) $ 0.26
====================================================================================================================
Weighted average shares outstanding 122,960 123,735 124,103 124,654
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
(thousands of dollars) 1994 Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $1,100,869 $ 547,146 $ 475,626 $ 734,261
====================================================================================================================
Gross profit(1) $ 353,766 $ 227,138 $ 208,524 $ 288,993
====================================================================================================================
Operating income $ 143,464 $ 29,119 $ 8,198 $ 84,143
====================================================================================================================
Income (loss) from continuing operations $ 55,487 $ (6,375) $ (21,657) $ 23,836
Loss from discontinued operations, less taxes - - - (2,102)
Extraordinary item, less taxes - (517) - (606)
- --------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 55,487 $ (6,892) $ (21,657) $ 21,128
====================================================================================================================
Per Share Data (2)
Continuing operations $ 0.44 $ (0.07) $ (0.19) $ 0.18
Discontinued operations, less taxes - - - (0.02)
Extraordinary item, less taxes - 0.00 - 0.00
- --------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.44 $ (0.07) $ (0.19) $ 0.16
====================================================================================================================
Weighted average shares outstanding 122,370 122,390 122,442 122,492
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) "Gross profit" is operating revenues less "Cost of natural gas
purchased, net".
(2) Income (loss) from continuing operations per common share is based on
income or loss from continuing operations less preferred dividend
requirements, and all per share data are computed using the weighted
average number of the Company's common shares outstanding during each
period.
72 N O R A M
<PAGE> 41
N O R A M 73
<PAGE> 1
EXHIBIT 21
NORMAN ENERGY CORP.
Divisions:
Arkla
Entex
Minnegasco
NorAm Trading & Transportation Group
Subsidiaries:
AER - Arkansas Gas Transit Company
Subsidiaries: Blue Jay Gas Company
Raven Gas Company
ALG Gas Supply Company
Subsidiaries: ALG Gas Supply Company of Arkansas
ALG Gas Supply Company of Kansas
ALG Gas Supply Company of Louisiana
ALG Gas Supply Company of Oklahoma
ALG Gas Supply Company of Texas
Allied Materials Corporation
Arkansas Louisiana Finance Corporation
Arkla Chemical Corporation
Arkla Finance Corporation
Arkla Industries Inc.
Arkla Products Company
Entex Coal Company
Entex Gas Marketing Company
Entex NGV, Inc.
Entex Oil Company
Entex Oil & Gas Co.
Industrial Gas Supply Corporation
Intex, Inc.
Louisiana Unit Gas Transmission Company
Minnesota Intrastate Pipeline Company
Mississippi River Transmission Corporation
Subsidiaries: MRT Energy Marketing Company
MRT Services Company
National Furnace Company
NorAm Damage Prevention, Inc.
NorAm Energy Management, Inc.
NorAm Energy Services, Inc.
NorAm Field Services Corp.
NorAm Gas Processing Company
NorAm Gas Transmission Company
NorAm Hub Services Inc.
NorAm Latin America, Inc.
NorAm Trading and Transportation Group, Inc.
Unit Gas Transmission Company
United Gas, Inc.
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
NorAm Energy Corp. and Subsidiaries (the "Company") on Form S-3 (File Nos.
33-64001, 33-41493, 33-52853 and 33-55071) and Form S-8 (File Nos. 2-61923,
33-10806, 33-20594, 33-38063, 33-38064, 33-54241, 33-54247, 33-54253) of our
reports dated March 25, 1996, on our audits of the consolidated financial
statements and financial statement schedule of the Company as of December 31,
1995 and 1994, and for the years ended December 31, 1995, 1994, and 1993, which
reports are included or incorporated by reference in this Annual Report on
Form 10-K.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 28, 1996
<PAGE> 1
EXHIBIT 24
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report
on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 for fiscal year ended December 31, 1995 together with any and all exhibits
and other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or either
of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as of
the 15th day of March, 1996.
/s/ T. Milton Honea
-------------------------------------
<PAGE> 2
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Michael B. Bracy
----------------------------------
<PAGE> 3
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Joe E. Chenoweth
--------------------------------------
<PAGE> 4
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ O. Holcombe Crosswell
--------------------------------------
<PAGE> 5
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Walter A. DeRoeck
--------------------------------------
<PAGE> 6
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Mickey P. Foret
---------------------
<PAGE> 7
POWER OF ATTORNEY
WHEREAS, NORAMENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ John P. Gover
----------------------------------
<PAGE> 8
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Joseph M. Grant
--------------------------------------
<PAGE> 9
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Robert C. Hanna
-----------------------------------
<PAGE> 10
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or either
of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ W. Jeffrey Hart
---------------------------------------
<PAGE> 11
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report on
Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
for fiscal year ended December 31, 1995 together with any and all exhibits and
other documents having relation to said Annual Report on Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Myra Jones
-------------------------------
<PAGE> 12
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the
"Company") intends to file with the Securities and Exchange Commission its
Annual Report on Form 10-K pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for fiscal year ended December 31, 1995 together with any
and all exhibits and other documents having relation to said Annual Report on
Form 10-K;
NOW, THEREFORE, the undersigned, in the capacity of Director of the
Company, does hereby appoint, T. MILTON HONEA and MICHAEL B. BRACY, or
either of them, his or her true and lawful attorney-in-fact, with full power of
substitution and resubstitution, to execute in his or her name, place and stead
in the capacity of Director of the Company, said Annual Report on Form 10-K and
all documents necessary or incidental in connection therewith and to file the
same with the Securities and Exchange Commission. Said attorneys-in-fact shall
have full power and authority to do and perform in the name and on behalf of
the undersigned in any and all capacities every act whatsoever necessary or
desirable to be done in the premises as fully and to all intents and purposes
as the undersigned might or could do in person, hereby ratifying and confirming
the acts that said attorneys-in-fact may lawfully do or cause to be done by
virtue hereof.
IN WITNESS WHEREOF, the undersigned has executed this instrument as
of the 15th day of March, 1996.
/s/ Larry C. Wallace
--------------------------------------
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,407,775
<OTHER-PROPERTY-AND-INVEST> 683,909
<TOTAL-CURRENT-ASSETS> 511,628
<TOTAL-DEFERRED-CHARGES> 62,671
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,665,983
<COMMON> 78,002
<CAPITAL-SURPLUS-PAID-IN> 880,885
<RETAINED-EARNINGS> (336,940)
<TOTAL-COMMON-STOCKHOLDERS-EQ> 637,263
0
130,000
<LONG-TERM-DEBT-NET> 1,474,924
<SHORT-TERM-NOTES> 10,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 118,750
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,295,046
<TOT-CAPITALIZATION-AND-LIAB> 3,665,983
<GROSS-OPERATING-REVENUE> 2,964,679
<INCOME-TAX-EXPENSE> 55,379
<OTHER-OPERATING-EXPENSES> 0
<TOTAL-OPERATING-EXPENSES> 2,677,374
<OPERATING-INCOME-LOSS> 287,305
<OTHER-INCOME-NET> (8,438)
<INCOME-BEFORE-INTEREST-EXPEN> 278,867
<TOTAL-INTEREST-EXPENSE> 157,959
<NET-INCOME> 65,477
7,800
<EARNINGS-AVAILABLE-FOR-COMM> 57,677
<COMMON-STOCK-DIVIDENDS> 34,538
<TOTAL-INTEREST-ON-BONDS> 62,191
<CASH-FLOW-OPERATIONS> 347,361
<EPS-PRIMARY> 0.47
<EPS-DILUTED> 0.47
</TABLE>
