<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, 1994
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, 11th FLOOR, HOUSTON, TEXAS 77002
(Address of principal executive office)
(713) 654-5100
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Title of each class Name of Each Exchange on Which Registered
<S> <C>
Common Stock, $.625 par value New York Stock Exchange
Convertible Exchangeable Preferred New York Stock Exchange
Stock, Series A, Cumulative, $0.10 par value
</TABLE>
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. /x/
The aggregate market value of the voting stock held by non-affiliates:
$660,289,639 Common Stock, $.625 par value, based upon the closing sales price
on March 15, 1995 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: 123,451,043 shares of Common Stock, $.625
par value, as of March 15, 1995.
DOCUMENTS INCORPORATED BY REFERENCE
1. Portions of the NorAm Energy Corp. Annual Report to Stockholders for the
fiscal year ended December 31, 1994, 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 9, 1995, 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.
<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, storage and marketing of
natural gas. The natural gas distribution business provided approximately 60%
of the Company's operating income in 1994 while the natural gas transmission
business provided approximately 40% during the same time period. See "Natural
Gas Distribution" and "Natural Gas Pipeline". A significant portion of these
businesses are subject to rate regulation, see "Regulation". The Company
previously conducted operations in the exploration and production of natural
gas and the radio communications business, but on December 31, 1992, and July
31, 1992, respectively, the Company completed the sale of its exploration and
production subsidiary, Arkla Exploration Company ("AEC"), to Seagull Energy
Corporation ("Seagull") and completed the sale of its radio communications
subsidiary, E.F. Johnson Company ("Johnson"). This terminated the Company's
activities in the exploration and production business and in the radio
communications business. The Company has also participated in several other
acquisitions, dispositions and mergers in recent years, see "Mergers,
Acquisitions and Dispositions". The revenue, operating profit and identifiable
assets of the 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
discussions focus on, two operating units -- Natural Gas Distribution and
Natural Gas Pipeline -- to reflect the natural division of the Company's
operations.
In May of 1994, the Company changed its name from Arkla, Inc. to NorAm
Energy Corp. At that time, several of the Company's subsidiaries made
corresponding name changes.
NATURAL GAS DISTRIBUTION.
The Company's natural gas distribution business is conducted through
its three divisions, Arkla (formerly known as Arkansas Louisiana Gas Company),
Entex and Minnegasco, and their affiliates. Through these divisions and their
affiliates, the Company engages in both the natural gas distribution sales and
transport businesses.
Arkla provides service in approximately 603 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 1994, 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 96% of Arkla's
supplies were obtained from NorAm Gas Transmission Company ("NGT", formerly
known as Arkla Energy Resources Company) and Mississippi River Transmission
Corporation ("MRT"), or through transportation agreements with NorAm Energy
Services, Inc. ("NES", formerly known as Arkla Energy Marketing Company). 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 1994, approximately 88% of Entex's
total throughput was composed of sales of gas at
<PAGE> 3
retail and approximately 12% 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 1994, Minnegasco provided service in approximately 221
communities in Minnesota. The largest community served by Minnegasco is
Minneapolis, Minnesota and its suburbs. In 1994, approximately 96% of
Minnegasco's total throughput was composed of sales of gas at retail and
approximately 4% 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 $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,
1994:
<TABLE>
<CAPTION>
SERVICE AREA COMMUNITIES NUMBER OF
LOCATIONS SERVED CUSTOMERS
<S> <C> <C>
Texas 365 1,175,728
Minnesota 221 612,447
Arkansas 376 426,972
Louisiana 178 261,794
Oklahoma 95 115,075
Mississippi 91 117,209
-----------------------------------
1,326 2,709,225
=========== ===============
</TABLE>
The following table summarizes the estimated number of customers
served by each of the divisions as of December 31, 1994 and 1993, (the
estimated number of Arkla customers for 1993 included customers in Kansas.
Kansas distribution properties were sold in September of 1994):
<TABLE>
<CAPTION>
DECEMBER 31,
------------
CUSTOMERS BY DIVISION 1994 1993
---- ----
<S> <C> <C>
Entex 1,375,593 1,359,467
Arkla 721,185 739,488
Minnegasco 612,447 599,067
--------- ---------
Total 2,709,225 2,698,022
========= =========
</TABLE>
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<PAGE> 4
The Company's approximately 54,313 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 suppliers, 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.
Throughput information for each of the distribution divisions is as
follows:
<TABLE>
<CAPTION>
Year Ended December 31
------------------------
(billions of cubic feet)
Throughput 1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Entex 273.6 252.9 224.9
Arkla 116.2 126.4 115.3
Minnegasco 134.4 138.7 151.5
---------------------------------------
Total 524.2 518.0 491.7
=======================================
</TABLE>
-3-
<PAGE> 5
Consolidated revenue, throughput and customer data of the distribution
divisions are as follows:
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
(in millions of dollars)
1994 1993 1992
------------------------------------------
<S> <C> <C> <C>
Revenue
-------
Sales $1,983.1 $2,032.7 $1,787.4
Transportation 18.7 21.6 26.4
Other 23.2 22.6 21.4
------------------------------------------
Total $2,025.0 $2,076.9 $1,835.2
==========================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
(billions of cubic feet)
1994 1993 1992
-----------------------------------------
<S> <C> <C> <C>
Throughput
----------
Sales
Residential 180.0 193.6 185.7
Commercial 119.2 126.7 123.9
Industrial 136.4 111.7 99.5
Sales for resale 19.9 10.2 3.6
Transportation 68.7 75.8 79.0
------------------------------------------
Total 524.2 518.0 491.7
==========================================
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
1994 1993 1992
-------------------------------------------
<S> <C> <C> <C>
Approximate Average No. of
--------------------------
Customers
---------
Residential 2,463,789 2,424,758 2,477,102
Commercial 222,176 221,103 230,069
Industrial 2,709 2,624 2,699
Sales for resale 22 11 7
-------------------------------------------
Total 2,688,696 2,648,496 2,709,877
===========================================
</TABLE>
-4-
<PAGE> 6
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."
NATURAL GAS PIPELINE.
The Company's natural gas pipeline business (collectively referred to
as "Pipeline") is conducted principally through the following wholly-owned
subsidiaries of the Company: NGT, MRT, NES, NorAm Field Services Corp. ("NFS",
formerly known as Arkla Gathering Services Company) and NorAm Hub Services Inc.
("NHS"). Through these subsidiaries and their affiliates, the Company engages
in the transmission of natural gas, including gathering, storage and marketing
of natural gas. NGT and MRT are interstate pipeline companies, NES serves as
the Company's principal natural gas supply aggregator and marketer and NFS owns
and operates the natural gas gathering assets previously held by NGT. Through
these subsidiaries, the Company engages in both natural gas transportation and
sales businesses.
Effective February 1, 1995, after receipt of all necessary
authorization from the Federal Energy Regulatory Commission ("FERC"), NFS
assumed ownership and operation of NGT's gathering assets pursuant to a
transfer from NGT to NFS of the NGT gathering assets. While the FERC provided
for a two-year gathering service option for existing customers under existing
terms and conditions, the scope of the FERC's jurisdiction over NFS is limited,
and NFS is not generally subject to traditional cost-of-service rate
regulation. These gathering assets consist primarily of 3,500 miles of
gathering pipeline which collect gas from more than 200 separate systems in
major producing fields in Arkansas, Oklahoma, Louisiana and Texas.
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 FERC approving the transfer. As a result of this
transfer of assets, liabilities and service obligations, the FERC now has
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 state regulatory oversight. See
"Regulation."
During 1995, the Company plans to continue the upgrade of certain
facilities in order to increase deliverability to other interstate pipelines at
interconnects near Perryville, Louisiana. This natural gas marketing "hub"
known as the Perryville Hub, is operated by NHS.
Effective as of December 31, 1993, the Company completed a
comprehensive settlement agreement with certain subsidiaries of Samson
Investment Company pursuant to which a number of outstanding contractual
arrangements between the parties were terminated or substantially modified (see
"Natural Gas Pipeline" under "Material Changes in the Results of Continuing
Operations", included in the 1994 Annual Report to Stockholders and
incorporated herein by reference).
-5-
<PAGE> 7
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.
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, 1994, the NGT system consisted of
approximately 6,400 miles of transmission lines and approximately 3,000 miles
of gathering 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 product extraction plants and compressor facilities related to
its gas transmission business. NGT's peak day gas handled during the 1994/95
heating season was approximately 2.40 billion cubic feet ("Bcf"). The system
transports gas for third parties as an "open access" transporter, makes sales
of gas directly to end users located along its system, and delivers gas to
certain of the Company's distribution divisions for retail sales. In 1994,
NGT's throughput totaled 570.6 million MMBtu. Approximately 21% of the total
throughput was attributable to services provided to Arkla, 7% was attributable
to services provided to MRT, and 26% 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 1994, MRT's throughput totaled 307.2 million MMBtu.
Approximately half of MRT's total 1994 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 1994/95 heating season to its traditional market area
customers were approximately 951,000 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 655 million cubic feet ("mmcf") per day and a
working gas capacity of approximately 22.5 Bcf. NGT also owns an approximately
10% 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
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<PAGE> 8
mmcf per day. The other NGT storage fields, Ruston and Collinson, are located
near Ruston, La. and Winfield, Kansas. Three storage fields are associated with
MRT's pipeline and have a maximum aggregate deliverability of approximately 570
mmcf per 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 1994, 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.
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 11 of Notes to the Company's
Consolidated Financial Statements included in the Company's 1994 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 1994 were 318 million MMBtu of which approximately
82.2% 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.
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 $25.1 million for the year ended
December 31, 1992. LIG's total throughput was 103.4 million MMBtu for the six
months ended June 30, 1993 and 244.1 million MMBtu for the year ended December
31, 1992.
-7-
<PAGE> 9
Consolidated throughput and revenue data for Pipeline is as follows:
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
------------------------------------------
<S> <C> <C> <C>
Throughput (million MMBtu)
Sales 228.1 174.8 150.0
Transportation 831.8 780.1 752.5
------------------------------------------
FERC Order 636
Elimination(1) (63.0) (24.2) -
------------------------------------------
Total 996.9 930.7 902.5
==========================================
Revenues (in millions of
dollars)
Sales $751.2 $874.2 $752.9
Transportation 261.0 138.7 102.0
------------------------------------------
Total $1,012.2 $1,012.9 $854.9
==========================================
</TABLE>
(1) Prior to the implementation of unbundled services pursuant to FERC
Order 636, Pipeline's sales rate covered all related services,
including transportation to the customer's facility. Under FERC Order
636, when Pipeline acts as a merchant, the sales transaction is
independent of (and may not include) the transportation of the volume
sold. Therefore, when the 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.
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 $269 million related to these claims. The amount shown as "Gas
Purchased in Advance of Delivery" in the Company's Consolidated Balance Sheet
and the component of "Investments and Other Assets" bearing the same caption
(See Note 1 of Notes to Consolidated Financial Statements included in the
Company's 1994 Annual Report to Stockholders) represents, in substantial part,
amounts paid to suppliers in conjunction with the above referenced settlements.
These prepayments for gas were made at varying prices but have been reduced to
their estimated net realizable value (which approximates fair value) and, to
the extent that the Company is unable to realize at least this amount through
sale of the gas as delivered over the life of these agreements, its earnings
will be adversely affected, although such impact is not expected to be
material.
In addition, the Company's Consolidated Balance Sheet includes an
accrual representing its estimate of the amount it will be required to pay in
settlement of all remaining claims, including those not yet asserted. While
the vast majority of such claims have been settled, the Company is
-8-
<PAGE> 10
committed, under certain of these settlements, to make additional payments,
expects that other such claims may be asserted and that amounts may be expended
in settlement of such claims. The Company currently expects that the amount of
such settlements, if any, in excess of existing reserves will not be material.
The Company is committed under certain agreements to purchase certain
quantities of gas in the future. At December 31, 1994, the Company had the
following gas take commitments under its agreements which are not
variable-market-based priced:
<TABLE>
<CAPTION>
Volume Value Price
(millions of ($ in ($/MMBtu)
MMBtu) millions)
------------ --------- ---------
<S> <C> <C> <C>
1995 20.2 $45.7 $2.26
1996 15.7 36.0 2.29
1997 14.5 32.5 2.24
1998 11.5 24.0 2.08
Beyond 1998 5.7 $12.4 $2.17
</TABLE>
At December 31, 1994, 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
$1.74/MMBtu:
<TABLE>
<CAPTION>
Average
Volume Value Price
(millions of ($ in ($/MMBtu)
MMBtu) millions)
------------ --------- ---------
<S> <C> <C> <C>
1995 85.6(1) $137.0 $1.60
1996 9.0 18.3 2.03
1997 5.1 11.6 2.27
1998 3.0 7.7 2.57
Beyond 1998 4.1 $11.0 $2.68
</TABLE>
(1) Includes approximately 74.9 million MMBtu of gas subject to 3
- 6 month term purchase agreements at NES which, in general,
are matched with sales 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 11 of
Notes to Consolidated Financial Statements included in the Company's 1994
Annual Report to Stockholders). The Company has entered into swaps in which one
party agrees to pay either a fixed price or a fixed differential from the NYMEX
price per MMBtu of gas, while the other party agrees to pay a price based on a
published index. 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.
-9-
<PAGE> 11
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 transmission and marketing units
are most significantly affected by national trends in these areas. On the
other hand, the results of the Company's 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 transmission and 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.
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" to NGT's
transactions and balances in 1992, see Note 13 of Notes to Consolidated
Financial Statements included in the Company's 1994 Annual Report to
Stockholders and incorporated herein by reference. 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
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<PAGE> 12
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 and further such changes are anticipated. 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 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
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<PAGE> 13
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.
In 1992, the FERC promulgated its Order 636, which comprehensively revised
regulations regarding the sale and transportation of natural gas on interstate
pipeline systems. FERC Order 636 required interstate pipelines to "unbundle"
their service into their component parts, such as gas supply, storage and
transportation, and make such components separately available as services to
their customers. 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 distribution
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 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 are appealing 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").
During 1994, the FERC approved the parties' agreements (the "Agreement")
covering the transaction, but imposed certain conditions inconsistent with the
Agreement. NGT, MRT, and ANR are appealing the FERC's order. The Company
currently cannot predict with certainty the outcome of its appeal. This sale
by NGT and MRT to ANR is also subject to acceptable approval by the Federal
Trade Commission, which has issued an order approving the transaction. Should
the transaction not be completed as a sale, the Agreement requires that the
parties operate under separate agreements pursuant to which the Company would
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<PAGE> 14
instead provide transportation services generally to ANR until May 31, 2005.
See "Management Analysis - Commitments and Contingencies - Sale of Pipeline
Facilities" included in the Company's 1994 Annual Report to Stockholders.
As circumstances warrant, both NGT and MRT regularly seek
authorization from the FERC for changes in their rates. In late 1992, NGT
filed a two-phase case to fully implement service under FERC Order 636 by (1)
settling rates for historical pre-FERC Order 636 services and (2) establishing
new rates for services to be provided under FERC Order 636. The first phase
was approved by the FERC and accepted by all parties. A request for rehearing
on the second phase of the case had been filed by one party but was denied by
the FERC in November 1994. This action by the FERC terminated the proceeding
and established the level of rates for NGT's FERC Order 636 services
retroactive to September 1, 1993, which did not result in any refund in excess
of amounts previously reserved. 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. A
procedural schedule has been established for the rate proceeding, with a
hearing scheduled for August 1995.
In July, 1994, the FERC issued an order approving a settlement
resolving both MRT's rate case and the recovery of MRT's Order 636 gas supply
realignment costs from its customers. The rate case settlement established
rates retroactively from April, 1993 until MRT's next rate case, which MRT is
obligated to file no later than April 1, 1996. The rate case settlement
resulted in a refund of $12.7 million which had been collected subject to
refund and thus was fully reserved. MRT's gas supply realignment cost recovery
proceedings were also resolved as part of the rate case settlement, as well as
most issues regarding MRT's future recovery of these costs. MRT expects to
recover approximately 89% of all gas supply realignment costs pursuant to the
terms of the settlement.
Also in 1994, MRT received approval of its settlement with Koch
Gateway Pipeline Company, thus resolving nearly a decade of regulatory
proceedings before the FERC by MRT's upstream, historic pipeline suppliers to
recover a portion of their take-of-pay related costs.
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 1994
Minnegasco and Arkla obtained increases in their local rates from the
appropriate Minnesota, Arkansas, and Oklahoma regulatory agencies. Entex
engaged in no major rate initiatives during 1994.
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 $8.1 million, compared to $22.7
million requested, and $14.6 million allowed 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. The
revenue increase was based on an overall rate of return of 9.67% and a return
on equity of 11.0%. Minnegasco asked for reconsideration on certain issues in
the MPUC's decision. On February 2, 1995 the MPUC orally upheld its original
decision. The Company has provided a reserve for the interim rate refund,
including interest. It is currently Minnegasco's intention to appeal certain
portions of this order as well as prior MPUC's decisions (1) providing
that a portion of the cost of responding to certain gas leak
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<PAGE> 15
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.
In May 1994, Arkla filed for a $10 million annual rate increase in
Arkansas. In March 1995, the Arkansas Public Service Commission (the "APSC")
issued an order 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 not to file another rate
application in Arkansas before June of 1996. In November 1994, Arkla
implemented rates representing an annual increase of $1.8 million in Louisiana
pursuant to an Annual Rate Adjustment Mechanism filing made in September 1994.
In May 1994, Arkla filed for a $6 million rate increase in Oklahoma. In
December 1994, a settlement was reached in Oklahoma whereby Arkla (1) received
a $4.2 million annual rate increase, (2) agreed not to make an additional rate
increase filing prior to July 1997 unless its return on equity falls below a
specified level and (3) agreed to file a capacity and gas supply plan by
September 1995.
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 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.
In October 1994 , MRT was notified by the United States Environmental
Protection Agency that it, along with a number of other companies, had been
named under federal law as potentially responsible parties for the release or
threatened release of hazardous substances at the South 8th Street Landfill
located in West Memphis, Arkansas. MRT may be required to share in the cost of
the remediation of the 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.
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.
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<PAGE> 16
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 is working with the
Minnesota Pollution Control Agency to implement an appropriate response action.
At this time, however, the specific method and extent of required remediation
are not known for the entire site.
There are six other former MGP sites in Minnesota in the service
territory in which Minnegasco operated at December 31, 1994. 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. In
addition, there are seven former MGP sites in Nebraska and two in South Dakota
in the service territory in which Minnegasco operated at December 31, 1992. As
a part of the sale of the Nebraska operations, the buyer has assumed liability
for five Nebraska sites. Minnegasco had previously disposed of the other two
Nebraska sites. The South Dakota sites were not operated by Minnegasco or its
predecessors. Minnegasco believes it is not liable for remediation of the
Nebraska and South Dakota sites.
At December 31, 1994 and 1993, Minnegasco had recorded a deferred
charge of $.8 million and $1.3 million, respectively, related to the
Minneapolis Site and has estimated a range of $40 million to $129 million for
the possible remediation of Minnesota sites. The low end of the range was
determined using only those sites presently or once owned or known to have been
operated by Minnegasco, assuming Minnegasco's proposed remediation methods.
The upper estimate of the range was determined using the Minnesota sites once
owned by Minnegasco, whether or not operated by Minnegasco, and using
alternative, more costly remediation methods. The cost estimates for the
Minneapolis Site are based on studies made of that site. The remediation cost
for other sites is 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 by other potentially responsible
parties, if any, and the remediation methods used.
At December 31, 1994 and 1993, the Company had recorded a liability of
$43.8 million and $26.8 million, respectively, to cover the probable costs of
remediation. In connection with its 1992 rate case, Minnegasco was allowed to
recover through rates over five years, without carrying costs, the deferred
costs at December 31, 1992, and was allowed $3.1 million annually to cover
on-going clean-up costs. In its 1993 rate case, Minnegasco was allowed $2.1
million annually to recover amortization of previously deferred costs and
on-going clean-up costs. Any amounts in excess of $2.1 million in any
individual year are to be deferred for future rate recovery. The Company
currently expects that any cash expenditures for these costs in excess of the
amount recovered in rates during any year will not be material to the
Company's overall cash requirements. In accordance with SFAS 71, a regulatory
asset has been recorded equal to the amount accrued. The Company is pursuing
recovery of costs from its insurers and other potentially responsible parties.
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
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<PAGE> 17
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.
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 still subject to SFAS 71, corresponding regulatory assets
are set up in anticipation of recovery through the ratemaking process. At
December 31, 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 its 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
AEC to Seagull for approximately $397 million in cash (including $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 in the accompanying Consolidated Financial Statements included in
the Company's 1994 Annual Report to Stockholders.
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<PAGE> 18
The Company previously conducted operations in the radio
communications business through Johnson and 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, 1995, common stock representing ownership of approximately 12.5% of
the combined enterprise, which is managed by Itron. In December 1994 and
January 1995 the Company sold 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 12.5%. Based on
a March 1, 1995 price quotation on the NASDAQ, the market value of the Company's
interest is approximately $40.4 million. 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 through
the sale in 1986 of certain of the assets of Allied Materials Corporation, and
the sale in 1987 of the stock of University Savings Association, Entex
Petroleum, Inc., and Big Chief Drilling Company, and certain of the Entex coal
properties, with its remaining non-gas subsidiary, Datotek, disposed of by the
Company in 1990. For a further discussion of certain of these matters, see
Note 9 of Notes to Consolidated Financial Statements included in the Company's
1994 Annual Report to Stockholders incorporated herein by reference.
EMPLOYEES.
The Company employs approximately 6,840 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.
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.
In October 1992, the Resolution Trust Corporation filed suit
(initially seeking damages of at least $535 million, later amended to seek
damages of at least $520 million) in United States District Court for the
Southern District, Houston Division, against the Company (as a
successor-in-interest to Entex, Inc. which merged with the Company in 1988) and
certain other
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<PAGE> 19
defendants for alleged harm resulting from the 1989 failure of University
Savings Association ("USA"), a thrift institution in Houston, Texas. In
November 1994, the Company announced that it, together with the other
defendants, had entered into a final settlement of this litigation. The net
effect of this settlement, as adjusted for insurance recovery, legal expenses
incurred, certain other USA-related expenses and the legal expense reserve
previously recorded, was a pre-tax charge to discontinued operations of $3.3
million ($2.1 million after-tax) in the fourth quarter of 1994, see Note 10 of
Notes to Consolidated Financial Statements included in the Company's 1994
Annual Report to Stockholders.
On August 6, 1993, the Company, its former subsidiary, AEC and Arkoma
Production Company ("Arkoma"), a subsidiary of AEC, were named as defendants in
a lawsuit (the "State Claim") filed in the Circuit Court of Independence
County, Arkansas (the "Court"). This complaint alleges that the Company, AEC
and Arkoma, acted to defraud ratepayers in a series of transactions arising out
of a 1982 agreement between the Company and Arkoma. On behalf of a purported
class composed of the Company's ratepayers, plaintiffs have alleged that the
Company, AEC and Arkoma are responsible for common law fraud and violation of
an Arkansas law regarding gas companies, and are seeking a total of $100
million in actual damages and $300 million in punitive damages. On November 1,
1993, the Company filed a motion to dismiss the claim. In a hearing held on
May 19, 1994, the Court heard arguments on this motion. On September 20, 1994,
the Court entered an order granting the Company's motion to dismiss. The
plaintiffs have appealed this order granting the motion to dismiss, but a
hearing date for the appeal has not yet been set. The underlying facts forming
the basis of the allegations in the State Claim also formed the basis for
allegations in a lawsuit (the "Federal Claim") filed in September 1990 in the
United States District Court for the Eastern District of Arkansas, by the same
plaintiffs. The Federal Claim was dismissed in August 1992. Since the State
Claim is based on essentially the same underlying factual basis as the Federal
Claim and in light of the Court's order granting the Company's motion to
dismiss the State Claim, the Company continues to believe the State Claim is
without merit, intends to vigorously contest the appeal of the order granting
dismissal and does not believe that the outcome will have a material adverse
effect on the financial position, results of operations or cash flows of the
Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
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 9, 1995:
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<PAGE> 20
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE DURING
NAME AGE PAST 5 YEARS
---- --- ------------
<S> <C> <C>
T. Milton Honea 62 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
Michael B. Bracy 53 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
Hubert Gentry, Jr. 63 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
</TABLE>
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<PAGE> 21
<TABLE>
<CAPTION>
NAME AGE BUSINESS EXPERIENCE DURING
---- ---
PAST 5 YEARS
------------
<S> <C> <C>
Rick L. Spurlock 49 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
William H. Kelly 55 Senior Vice President, Planning and
Treasurer of the Company, 2/94 to
present,
Senior Vice President, Planning and
Investor Relations of the Company,
10/91 to 2/94,
Senior Vice President and Chief
Financial Officer of the Company from
at least 1/90 to 10/91
Jack W. Ellis, II 41 Vice President and Controller of the
Company, 12/89 to present
Michael H. Means 46 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
Howard E. Bell 61 President and Chief Operating Officer-
Entex, 8/88 to 12/94
Retired effective 12/31/94
</TABLE>
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<PAGE> 22
<TABLE>
<CAPTION>
NAME AGE BUSINESS EXPERIENCE DURING
---- ---
PAST 5 YEARS
------------
<S> <C> <C>
Robert N. Jones 42 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
Michael T. Hunter 44 President and Chief Operating Officer
of Mississippi River Transmission
Corporation and Executive Vice
President, Arkla Pipeline Group, 12/89
to present
Gary N. Petersen 42 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
William A. Kellstrom 53 President of NorAm Energy Services,
Inc., 9/92 to present
President of Tenaska Marketing
Ventures from at least 1/90 to 9/92
</TABLE>
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<PAGE> 23
<TABLE>
<CAPTION>
Name Age Business Experience During
---- ---
Past 5 Years
------------
<S> <C> <C>
Dale C. Earwood 39 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
</TABLE>
On March 20, 1995, the Company appointed Charles M. Oglesby to be
President of the newly created NorAm Trading & Transportation Group, a division
of the Company. The appointment will be effective on April 1, 1995. This
group includes NGT, MRT, NES and NFS. Mr. Oglesby was previously a Vice
President of Coastal Corporation and President and Chief Executive Officer of
Coastal Gas Service Company, Coastal's gas marketing, gathering and processing
company.
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<PAGE> 24
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 52 of the 1994 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 1994 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 57 through 72 of the
1994 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 52 of the
1994 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 report are set forth on pages 53 through 73 of the 1994 Annual
Report to Stockholders, which pages are incorporated herein by reference.
Statement of Consolidated Income for the years ended December 31,
1994, 1993, and 1992.
Consolidated Balance Sheet as of December 31, 1994 and 1993.
Statement of Consolidated Stockholders' Equity for the years ended
December 31, 1994, 1993 and 1992.
Statement of Consolidated Cash Flows for the years ended December 31,
1994, 1993 and 1992.
Notes to Consolidated Financial Statements.
Report of Independent Accountants.
The required supplementary data concerning quarterly results of
operations is set forth on page 74 of the 1994 Annual Report to Stockholders,
which page is incorporated herein by reference.
-23-
<PAGE> 25
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 9, 1995, 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 9, 1995, to be filed pursuant to Regulation 14A
under the 1934 Act is incorporated herein by reference.
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 9, 1995 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 9, 1995 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:
-24-
<PAGE> 26
Statement of Consolidated Income for the years ended December 31, 1994, 1993
and 1992.
Consolidated Balance Sheet as of December 31, 1994 and 1993.
Statement of Consolidated Stockholders' Equity for the years ended December 31,
1994, 1993 and 1992.
Statement of Consolidated Cash Flows for the years ended December 31, 1994,
1993 and 1992.
Notes to Consolidated Financial Statements.
Report of Independent Accountants.
<TABLE>
<CAPTION>
(A)(2) FINANCIAL STATEMENT SCHEDULES Page
------------------------------------ ----
<S> <C>
Report of Independent Accountants 29
Schedule II - Valuation and Qualifying
Accounts 30
</TABLE>
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.
-25-
<PAGE> 27
(A)(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.
*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.
*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.
-26-
<PAGE> 28
*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).
*10.12 Employment Agreement, dated September 4, 1992, between NorAm
Energy Corp. and William A. Kellstrom, incorporated herein by
reference to Exhibit 10.14 to the Company's Annual Report on
Form 10-K for the Year Ended 1993.
*10.13 Employment Agreement, dated February 3, 1993 between NorAm
Energy Corp. and Howard E. Bell, incorporated herein by
reference to Exhibit 10.15 to the Company's Annual Report on
Form 10-K for the Year Ended 1993.
*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.
13 The portions of the Annual Report to Stockholders for the year
ended December 31, 1994 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
-27-
<PAGE> 29
(B) REPORTS ON FORM 8-K FILED DURING THE LAST QUARTER OF THE PERIOD
COVERED BY THIS REPORT
None
-28-
<PAGE> 30
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
73 of the 1994 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 25 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.
/s/ COOPERS & LYBRAND L. L. P.
Houston, Texas
March 24, 1995
-29-
<PAGE> 31
Schedule II - Valuation and Qualifying Accounts and Reserves
NORAM ENERGY CORP.
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(in thousands of dollars)
<TABLE>
<CAPTION>
Column Column Column Column Column
A B C D E
---------------------------------- --------- ------------------------ ----------- -----------
Additions
Balance Charged to Charged to Balance at
Beginning Costs and Other End of
Description of Period Expenses Accounts Deductions 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, 1994 $ 11,296 $ 10,774 $ 1,741 $ 12,420 $ 11,391
Year ended December 31, 1993 $ 12,003 $ 10,393 744 $ 11,844 $ 11,296
Year ended December 31, 1992 $ 9,265 $ 12,658 1,510 $ 11,430 $ 12,003
(b) Deferred Tax Asset Valuation Allowance
Year ended December 31, 1994 $ 10,023 $ $ 4,049 $ 5,974
Year ended December 31, 1993 $ 9,997 $ 26 $ $ 10,023
Year ended December 31, 1992 $ 18,429 $ 3 $ 8,435(1) $ 9,997
</TABLE>
(1) Valuation allowance associated with state net operating loss carryforward
benefits ("NOL's") of Arkla Exploration Company which was sold in 1992.
-30-
<PAGE> 32
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 30, 1995
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 30, 1995
------------------
(T. Milton Honea)
MICHAEL B. BRACY* Director
(Michael B. Bracy)
JOE E. CHENOWETH* Director
(Joe E. Chenoweth)
O. HOLCOMBE CROSSWELL* Director
(O. Holcombe Crosswell)
</TABLE>
-31-
<PAGE> 33
<TABLE>
<S> <C>
WALTER A. DeROECK* Director
(Walter A. DeRoeck)
DONALD H. FLANDERS* Director
(Donald H. Flanders)
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)
SIDNEY MONCRIEF* Director
(Sidney Moncrief)
LARRY C. WALLACE* Director
(Larry C. Wallace)
D. W. WEIR, SR.* Director
(D. W. Weir, Sr.)
*By /s/ T. Milton Honea March 30, 1995
----------------------
(T. Milton Honea
Attorney-in-Fact)
</TABLE>
-32-
<PAGE> 34
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES AND EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
COMMISSION FILE NUMBER 1-3751
NORAM ENERGY CORP.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE
(STATE OR OTHER JURISDICTION OF INCORPORATION OR ORGANIZATION)
EMPLOYER IDENTIFICATION
(I.R.S. NO. 72-0120530)
1600 SMITH, 11TH FLOOR, HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICE)
(713) 654-5100
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
EXHIBITS
<PAGE> 35
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------ -----------------------
<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.
*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).
</TABLE>
<PAGE> 36
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------ -----------------------
<S> <C>
*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).
</TABLE>
<PAGE> 37
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF EXHIBITS
------ -----------------------
<S> <C>
*10.12 Employment Agreement, dated September 4, 1992,
between NorAm Energy Corp. and William A. Kellstrom,
incorporated herein by reference to Exhibit 10.14
to the Company's Annual Report on Form 10-K for
the Year Ended 1993.
*10.13 Employment Agreement, dated February 3, 1993
between NorAm Energy Corp. and Howard E. Bell,
incorporated herein by reference to Exhibit 10.15
to the Company's Annual Report on Form 10-K for
the Year Ended 1993.
*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.
13 The portions of the Annual Report to Stockholders
for the year ended December 31, 1994 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>
<PAGE> 1
EXHIBIT 12
NORAM ENERGY CORP. AND SUBSIDIARIES
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(in thousands of dollars)
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Income from continuing operations
as set forth in Consolidated
Statement of Income $ 51,291 $ 39,935 $ 6,227 $ 16,515 $ 100,826
Add back:
Provision for income taxes 34,372 46,481 12,516 18,418 52,643
Less:
Non-utility interest capitalized 0 0 0 0 0
---------- ---------- ---------- ---------- ----------
85,663 86,416 18,743 34,933 153,469
---------- ---------- ---------- ---------- ----------
Fixed charges (from continuing
operations):
Interest 167,384 169,857 182,453 174,044 150,593
Amortization of debt discount
and expense 3,312 3,421 4,450 3,290 2,191
Portion of rents considered to
represent an interest factor 11,292 10,402 7,704 6,514 5,534
---------- ---------- ---------- ---------- ----------
Total fixed charges 181,988 183,680 194,607 183,848 158,318
---------- ---------- ---------- ---------- ----------
Earnings $ 267,651 $ 270,096 $ 213,350 $ 218,781 $ 311,787
========== ========== ========== ========== ==========
Ratio of earnings to fixed charges $ 1.47 $ 1.47 $ 1.10 $ 1.19 $ 1.97
========== ========== ========== ========== ==========
</TABLE>
<PAGE> 1
33
FINANCIAL CONTENTS
<TABLE>
<S> <C>
SELECTED FINANCIAL DATA 34
MANAGEMENT ANALYSIS
Name Change 34
Organization and Accounting Policies 34
Acquisitions and Dispositions 34
Significant Trends 35
Material Changes in the Results of Continuing Operations
General 35
Regulatory Matters 36
Operating Income (Loss) by Business Unit 37
Natural Gas Distribution 37
Natural Gas Pipeline 38
Corporate and Other 42
Consolidated 42
Discontinued Operations 42
Liquidity and Capital Resources 44
Commitments and Contingencies 47
Accounting Changes 51
Ratio of Earnings to Fixed Charges 52
Debt Retirement Schedule 52
Common Stock Prices and Dividends 52
FINANCIAL STATEMENTS & RELATED INFORMATION
Statement of Consolidated Income 53
Consolidated Balance Sheet 54
Statement of Consolidated Stockholders' Equity 55
Statement of Consolidated Cash Flows 56
Notes to Consolidated Financial Statements 57
Report of Independent Accountants 73
Management's Responsibility for Financial Statements 73
Quarterly Information 74
</TABLE>
<PAGE> 2
34
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 Minnegasco are
included subsequent to its acquisition in December 1990. The results of
operations of Louisiana Intrastate Gas Corporation are included from its
acquisition in July, 1989 to its sale at June 30, 1993, see "Acquisitions and
Dispositions" under "Management Analysis" elsewhere herein. Results of
operations for 1993, 1992 and 1991 include the impact of significant
non-recurring charges, see "Natural Gas Pipeline" 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) 1994 1993 1992 1991 1990
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 2,801.4 $ 2,949.6 $ 2,743.8 $ 2,724.4 $ 2,350.0
----------------------------------------------------------------------------------------------------------------------
Income from continuing operations $ 51.3 $ 39.9 $ 6.2 $ 16.5 $ 100.8
----------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations
per common share $ 0.36 $ 0.26 $ (0.01) $ 0.08 $ 1.04
----------------------------------------------------------------------------------------------------------------------
Total assets $ 3,561.5 $ 3,727.8 $ 4,059.0 $ 4,806.9 $ 4,785.6
----------------------------------------------------------------------------------------------------------------------
Long-term obligations $ 1,414.4 $ 1,629.4 $ 1,783.1 $ 1,551.5 $ 1,450.2
----------------------------------------------------------------------------------------------------------------------
Dividends per common share $ 0.28 $ 0.28 $ 0.48 $ 1.08 $ 1.08
----------------------------------------------------------------------------------------------------------------------
</TABLE>
MANAGEMENT ANALYSIS
NAME CHANGE
The Company changed its name from Arkla, Inc. to NorAm Energy Corp. ("NorAm"),
in May 1994 pursuant to a vote of the Company's stockholders. Certain of the
Company's subsidiaries also made corresponding name changes. As used herein,
"NorAm" and "the Company" refer to NorAm Energy Corp. and its subsidiaries.
ORGANIZATION AND ACCOUNTING POLICIES
The Company's principal activities are in the natural gas industry, currently
confined to the contiguous 48 states, with principal operations in Texas,
Louisiana, Mississippi, Arkansas, Oklahoma, Missouri and Minnesota. The Company
has operations in natural gas distribution ("Distribution") and natural gas
transmission, including marketing, gathering and storage ("Pipeline" or
"Natural Gas Pipeline"), with Distribution providing approximately 60% of the
Company's operating income in 1994 and Pipeline providing approximately 40%. A
significant portion of these businesses 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 have been discontinued as further described
under "Discontinued Operations" elsewhere herein and in Note 9 of Notes to
Consolidated Financial Statements. Approximately 18% of Arkla Exploration
Company was held by the public until early 1992, see "Discontinued Operations"
elsewhere herein. The Company's legal structure consists of a number of
divisions and subsidiaries, all of which are wholly owned.
The Company changed its method of accounting for postemployment
benefits, postretirement benefits and investments in debt and equity securities
as of January 1, 1992, 1993, and 1994, respectively, see "Accounting Changes"
elsewhere herein.
The reader is directed to Note 1 of Notes to Consolidated Financial
Statements for a discussion of the Company's other significant accounting
policies.
ACQUISITIONS AND DISPOSITIONS
In recent years, the Company has engaged in several transactions with respect
to its distribution properties, see "Natural Gas Distribution" under "Material
Changes in the Results of Continuing Operations" elsewhere herein.
On June 30, 1993, the Company completed the sale of its intrastate
pipeline business as conducted by Louisiana Intrastate Gas Corporation and
Subsidiaries ("LIG") to a subsidiary of Equitable Resources, Inc., see "Natural
Gas Pipeline" under "Material Changes in the Results of Operations" elsewhere
herein and Note 10 of Notes to Consolidated Financial Statements.
On December 31, 1992, the Company completed the sale of Arkla
Exploration Company to Seagull Energy Corporation. This sale terminated the
Company's activities in the oil and gas exploration and production business,
see "Discontinued Operations" elsewhere herein and Note 9 of Notes to
Consolidated Financial Statements.
In November 1990, the Company acquired Diversified Energies, Inc.
("DEI") in a purchase transaction. The Company has disposed of a portion of the
properties acquired but has (1) retained full ownership of Minnegasco, (2)
exchanged its ownership of EnScan for an equity
<PAGE> 3
35
investment in Itron, Inc. and (3) retained a minor investment in E. F. Johnson,
see "Discontinued Operations" elsewhere herein and Note 9 of Notes to
Consolidated Financial Statements.
SIGNIFICANT TRENDS
The Company's Pipeline business has shown significant increases in operating
income for the last two years. While the Company believes that it has the
opportunity to further improve Pipeline's operating results, it expects that
the rate of increase, if any, will decline, see "Natural Gas Pipeline" under
"Material Changes in the Results of Operations" elsewhere herein.
The Company's net cash provided by operating activities has increased
significantly in each of the last two years. While the Company believes that it
has the opportunity to further improve its cash flow, it currently does not
expect the historical rate of increase to continue, see "Cash Flow Analysis"
elsewhere herein.
MATERIAL CHANGES IN THE RESULTS
OF CONTINUING OPERATIONS
GENERAL
The Company's results of operations are seasonal due to fluctuations in the
demand for and price of natural gas, although, as further discussed elsewhere
herein, the Company has obtained rate design changes in its regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to seasonal weather patterns and further such changes are anticipated.
As previously described, the Company's principal operations are in
Pipeline and Distribution. The Company's pipeline businesses have experienced a
prolonged period of regulatory change in which they were required to (1)
restructure and reprice their services and (2) drastically reduce and
restructure their portfolio of gas purchase contracts. In response to item (2),
the Company, particularly through its NorAm Gas Transmission Company ("NGT")
subsidiary, was required to expend significant amounts of money, a substantial
portion of which it was not allowed to or was unable to recover through its
service rates, resulting in decreased earnings and an increased level of debt.
This regulatory change also has increasingly subjected certain portions of
these businesses to competitive market forces, thus limiting their ability to
reach historical levels of return on investment. The Company's distribution
businesses have faced increased competition in certain types of service and are
being required to assume certain functions previously provided by their
pipeline suppliers but, in general, have not faced the dramatic declines in
profitability experienced by certain interstate pipeline businesses, including
NGT. Indeed, the Company's distribution units (in some cases, after adjustment
for the impact of weather) generally have shown a trend of increasing
profitability.
Therefore, the Company's ability to improve its overall profitability
will depend, to a large extent, on its success in meeting the objectives of (1)
continuing to increase the profitability of Pipeline through improved rate
design, aggressive marketing of its services and further reduction of its
overall costs (thus increasing its competitiveness), (2) maintaining the
profitability of Distribution through timely and well-designed rate filings,
increasing its customer base through aggressive marketing and controlling its
costs in order to remain competitive and offset regulatory lag, (3) developing
and expanding the Company's unregulated natural gas marketing business through
the introduction of new products and services, the acquisition of new markets
and the provision of services at a unit cost which will allow it to compete
effectively with the industry leaders in this business and (4) reducing the
Company's overall leverage and related interest expense, thus increasing the
Company's financial flexibility to pursue future opportunities for attractive
investment.
The Company made measurable progress toward these objectives during
1994 and intends to vigorously pursue the objectives in the future, although
certain factors which are key to reaching these objectives are largely beyond
the Company's control. Growth in Distribution is, to a significant extent,
dependent on economic conditions in its service areas and on the cost and
efficiency of competing fuels and technologies. The rate initiatives planned by
all of the Company's regulated businesses are subject to the authority of
various regulatory bodies and, therefore, cannot be assured as to timing or
ultimate success. With respect to interest expense, the Company has a large
amount of fixed-rate long-term debt, a substantial portion of which cannot be
efficiently replaced with lower-cost debt in the near term due to restrictions
in the terms of each such series of debt, as well as restrictions placed on the
Company by certain of its financial arrangements. In addition, the Company's
interest expense is subject to change based on the movement of market interest
rates to the extent that it has floating-rate borrowings under its revolving
credit facility, continues to utilize its accounts receivable sales program,
maintains its portfolio of interest rate swaps or otherwise subjects itself to
interest rate risk.
With respect to lowering its overall level of debt, the level of
success will largely be a function of the Company's ability to generate cash
internally, through issuance of equity or otherwise. The internal generation of
cash will depend to a significant extent on the Company's success in meeting
its other objectives as described previously. The Company's ability to issue
equity for the purpose of reducing debt and the desirability of doing so are
dependent on, among other factors, the market for the Company's equity and for
equities in general and on the Company's ability to efficiently utilize the
cash proceeds.
Elsewhere herein are discussions of the results of operations for the
Company's businesses, including further discussion of the impact of the above
factors on each such business and the progress being made in reaching the
objectives discussed above. In such discussions, certain prior year amounts
have been reclassified to conform to current presentation.
<PAGE> 4
36
REGULATORY MATTERS
As with other similarly-situated firms, the Company's natural gas distribution
and interstate natural gas pipeline businesses are subject to various forms of
rate regulation which (1) are intended to allow the Company to recover its
prudently incurred costs, including a reasonable return on stockholder
investment and (2) create economic impacts which historically have been
reflected in the Company's financial statements in accordance with Statement of
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("SFAS 71"). The Company discontinued the application of
SFAS 71 to NGT effective as of December 31, 1992, see "Natural Gas Pipeline"
elsewhere herein.
As a result of applying SFAS 71 to Mississippi River Transmission
Corporation ("MRT") and its distribution divisions, the Company's financial
statements reflect certain assets and liabilities which would not be recognized
by non-regulated entities. In addition to regulatory assets related to
accounting for postretirement benefits other than pensions (see "Accounting
Changes" elsewhere herein), the Company's only other significant regulatory
asset is related to anticipated environmental remediation costs, see
"Environmental Matters" under "Commitments and Contingencies" elsewhere herein.
In general, the Company's NGT and MRT pipeline subsidiaries are
regulated by the Federal Energy Regulatory Commission ("the FERC") both as to
the services offered and the maximum rates which may be charged for such
services. These rates are determined at proceedings before the FERC, generally
pursuant to rate case filings made by the pipelines.
In July 1994, the FERC issued an order approving settlement of MRT's
October 1992 filing in which it had requested an annual rate increase of $6.9
million, resulting in the refund of $12.7 million which had been collected
subject to refund and thus was fully reserved. MRT was not granted an increase
in conjunction with the settlement but achieved favorable resolution of a
number of issues, including being granted the ability to recover more of its
costs as a fixed charge to its customers. In addition, MRT agreed to file its
next rate case no later than April 1, 1996. Also in July 1994, the FERC
approved a settlement which provides for recovery by MRT of approximately 89%
of its gas supply realignment costs and resolved virtually all prudence and
eligibility issues related to such costs. Additional filings made by MRT and
approved by the FERC during 1994 provided for the disposition of MRT's deferred
gas costs and upstream pipeline transportation costs, resulting in a net refund
(for which reserves had been previously provided) of approximately $9.4 million
to certain of MRT's former jurisdictional sales customers.
In late 1992, NGT filed a two-phase case to fully implement service
under FERC Order 636 by (1) settling rates for historical pre-FERC Order 636
services and (2) establishing new rates for services to be provided under FERC
Order 636. The first phase was approved by the FERC and accepted by all
parties. A request for rehearing on the second phase of the case had been filed
by one party but was denied by the FERC in November 1994. This action by the
FERC terminated the proceeding and established the level of rates for NGT's
FERC Order 636 services retroactive to September 1, 1993, which did not result
in any refund in excess of amounts previously reserved. In August 1994, NGT
filed at the FERC for a $42.5 million annual rate increase, which rates became
effective in February 1995 subject to refund. A procedural schedule has been
established for the rate proceeding, with a hearing scheduled for August 1995.
The Company's distribution divisions, Arkla, Entex, and Minnegasco,
are generally subject to either state or municipal regulation as to services
offered and the rates charged for such services. State regulatory agencies are
the principal regulatory bodies responsible for setting rates in Minnesota,
Arkansas, Louisiana, Oklahoma and Mississippi, while rates in Texas are
generally governed by municipalities.
In October 1994, the Minnesota Public Utilities Commission issued an
order in the rate case filed by Minnegasco in November 1993, granting
Minnegasco an $8.1 million annual rate increase (it had filed for $22.7
million), based on an 11% return on equity. It is currently Minnegasco's
intention to appeal certain portions of the order including (1) the requirement
that Minnegasco's non-regulated appliance sales and service operations pay the
regulated operations a fee for the use of Minnegasco's name, image and
reputation and (2) the requirement that a portion of the cost of responding to
certain gas leak calls not be allowed in regulated rates. These issues have
previously been appealed to the courts by Minnegasco in conjunction with other
proceedings.
In May 1994, Arkla (formerly Arkansas Louisiana Gas Company) filed for
a $10 million annual rate increase in Arkansas. In March 1995, an order was
issued approving a settlement among Arkla, the Arkansas Public Service
Commission ("the APSC") and certain of Arkla's customers which provided for (1)
an annual increase of approximately $7 million and (2) an agreement not to file
another rate application in Arkansas before June, 1996. In November 1994, Arkla
implemented rates representing an annual increase of $1.8 million in Louisiana
pursuant to an Annual Rate Adjustment Mechanism filing made in September 1994.
In May 1994, Arkla filed for a $6 million rate increase in Oklahoma. In
December 1994, a settlement was reached in Oklahoma whereby Arkla (1) received
a $4.2 million annual rate increase, (2) agreed not to make an additional rate
increase filing prior to July 1997, unless its return on equity falls below a
specified level and (3) agreed to file a capacity and gas supply plan by
September 1995.
Entex engaged in no major rate initiatives during 1994, although it
was granted a total of approximately $2.2 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.
Pursuant to a settlement with the APSC in June 1991, the Company was
required to issue credits of $8.25 million to certain of
<PAGE> 5
37
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 as a component of income from continuing operations.
OPERATING INCOME (LOSS) BY BUSINESS UNIT
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(millions of dollars) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas distribution $ 163.2 $ 174.8 $ 168.0
Natural gas pipeline 108.1 78.2 15.7
Corporate and other (5.3) (17.4) (20.2)
------------------------------------------------------------------------------------------
Subtotal 266.0 235.6 163.5
LIG - 5.6 25.1
Contract termination charge - (34.2) -
------------------------------------------------------------------------------------------
Consolidated $ 266.0 $ 207.0 $ 188.6
==========================================================================================
</TABLE>
NATURAL GAS DISTRIBUTION
The Company's natural gas distribution business is conducted by the Arkla,
Entex and Minnegasco divisions of NorAm. Entex, Inc. merged with NorAm in
February 1988 in a pooling of interests, while Minnegasco became part of NorAm
effective with the Company's December 1990 purchase of DEI.
In August 1993, Minnegasco acquired Midwest Gas's Minnesota
distribution business (serving 41 communities with approximately 82,000
customers) in exchange for Minnegasco's South Dakota distribution properties
(serving 18 communities with approximately 45,000 customers) plus $38 million
in cash. The acquired properties were recorded in the Company's accounting
records at the sum of the cash paid plus the historical cost of the surrendered
properties 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 business 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. This
system serves approximately 124,000 customers in 63 eastern Nebraska
communities. In September 1994, the Company completed the sale of its Kansas
distribution properties (and certain related pipeline facilities) to UtiliCorp
United for approximately $23 million in cash. This system serves approximately
23,000 customers in 14 communities. For additional information on these
transactions, see Note 10 of Notes to Consolidated Financial Statements.
The above sale/exchange transactions resulted in a modest reduction in
the total number of distribution customers but the retained properties
currently are experiencing growth in excess of that which was expected from the
divested properties and, thus, these transactions are not expected to result in
a material and continuing decrease in earnings compared to historical
Distribution levels.
FINANCIAL RESULTS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(millions of dollars) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $ 1,983.1 $ 2,032.7 $ 1,787.4
Transportation revenue 18.7 21.6 26.4
Other revenue 23.2 22.6 21.4
------------------------------------------------------------------------------------------
Total operating revenues 2,025.0 2,076.9 1,835.2
------------------------------------------------------------------------------------------
Purchased gas cost
Affiliated 269.0 315.0 285.3
Unaffiliated 1,053.4 1,062.4 883.3
Operations and maintenance 368.3 358.0 341.8
Depreciation and amortization 87.3 82.2 75.2
Other operating expenses 83.8 84.5 81.6
------------------------------------------------------------------------------------------
Operating income $ 163.2 $ 174.8 $ 168.0
------------------------------------------------------------------------------------------
Average invested capital $ 914.9 $ 910.7 $ 864.1
==========================================================================================
</TABLE>
OPERATING STATISTICS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(billions of cubic feet) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential sales 180.0 193.6 185.7
Commercial sales 119.2 126.7 123.9
Industrial sales 136.4 111.7 99.5
Sales for resale 19.9 10.2 3.6
Transportation 68.7 75.8 79.0
------------------------------------------------------------------------------------------
Total throughput 524.2 518.0 491.7
==========================================================================================
Arkla actual degree days 2,806 3,314 2,762
------------------------------------------------------------------------------------------
Arkla normal degree days 3,038 3,063 3,081
------------------------------------------------------------------------------------------
Entex actual degree days 1,348 1,632 1,404
------------------------------------------------------------------------------------------
Entex normal degree days 1,554 1,582 1,592
------------------------------------------------------------------------------------------
Minnegasco actual degree days 7,617 8,057 7,141
------------------------------------------------------------------------------------------
Minnegasco normal degree days 7,786 7,929 7,718
------------------------------------------------------------------------------------------
Average number of customers 2,688,696 2,648,496 2,709,877
------------------------------------------------------------------------------------------
Number of employees 5,423 5,586 5,824
------------------------------------------------------------------------------------------
Average sales price ($/Mcf)
Residential $ 5.99 $ 5.77 $ 5.38
------------------------------------------------------------------------------------------
Commercial $ 4.66 $ 4.65 $ 4.24
------------------------------------------------------------------------------------------
Industrial $ 2.43 $ 2.71 $ 2.49
------------------------------------------------------------------------------------------
Annual revenues per
residential customer $ 437.84 $ 460.49 $ 402.13
------------------------------------------------------------------------------------------
Annual residential use
per customer - Mcf 73.05 79.82 74.79
------------------------------------------------------------------------------------------
</TABLE>
DISCUSSION OF OPERATING RESULTS
1994 vs. 1993
Distribution operating income for 1994 was $163.2 million, a decrease of $11.6
million (6.6%) from the $174.8 million earned in 1993. This decrease reflects
both reduced operating revenues and operating expenses as discussed following.
Operating revenues decreased from $2,076.9 million in 1993 to $2,025.0
million in 1994 principally due to (1) the warmer 1994
<PAGE> 6
38
weather (11,771 degree days in 1994 compared to 13,003 degree days in 1993) and
(2) a decrease in the weighted average cost of gas from $3.11/Mcf in 1993 to
$2.90/Mcf in 1994 (the cost of gas is a component of the sales rate). These
unfavorable revenue impacts were partially offset by the corresponding decrease
in purchased gas cost, the increased industrial sales as discussed following
and the favorable impact of rate increases as described under "Regulatory
Matters" elsewhere herein. Weather-sensitive residential and commercial sales
volumes declined from 320.3 Bcf in 1993 to 299.2 Bcf in 1994 (a decrease of
21.1 Bcf or 6.6%) principally due to the warmer 1994 weather as discussed
preceding. The continued improvement in economic conditions (most notably in
Entex's service area) and intensified marketing efforts were principally
responsible for an increase of 24.7 Bcf (22.1%) in industrial sales from 1993
to 1994.
Purchased gas cost decreased by $55.0 million (4.0%) from 1993 to 1994
despite a 13.3 Bcf (3.0%) increase in total sales volume principally due to the
decrease in the average cost of gas as described preceding. The gross margin
(natural gas sales minus purchased gas cost) increased by approximately $5.4
million (0.8%) from 1993 to 1994 despite the fact that sales volume increased
by a total of 13.3 Bcf (3.0%), principally due to the decline in residential
and commercial sales volume as described preceding and the fact that 9.7 Bcf
(72.9%) of the volume increase was attributable to low-margin sales for resale.
Operating expenses, exclusive of purchased gas cost, increased by $14.7 million
(2.8%) 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 1994 depreciation expense due to increased investment.
1993 vs. 1992
Distribution operating income for 1993 was $174.8 million, an increase of 4.0%
over the $168.0 million earned in 1992. This $6.8 million increase reflected
both increased operating revenues and operating expenses as discussed
following.
Operating revenues increased from $1,835.2 million in 1992 to $2,076.9
million in 1993 due primarily to (1) colder weather in 1993, (2) increased
industrial sales, (3) an increased average unit cost of gas (which is a
component of the sales rate) and (4) rate increases obtained by Arkla and
Minnegasco. Partially offsetting these favorable effects was the revenue
reduction due to Minnegasco's February sale of its Nebraska distribution
properties. Weather-sensitive residential and commercial sales volumes
increased by 7.9 Bcf and 2.8 Bcf, respectively, due largely to the colder 1993
weather. The continued improvement in economic conditions in Entex's service
area was primarily responsible for the 12.2 Bcf (12.3%) increase in industrial
sales volume.
While purchased gas cost in 1993 increased by approximately 17.9% to
$1,377.4 million from $1,168.6 million in 1992 (largely due to an increase in
the average cost of purchased gas), the gross margin (natural gas sales minus
purchased gas cost) increased approximately in proportion to the increased
sales volume. Operating expenses, exclusive of purchased gas cost, increased by
$26.1 million (5.2%) over 1992 principally due to (1) increased 1993 operations
and maintenance expense reflecting increased throughput, (2) increased 1993
depreciation and amortization expense due to increased investment and, to a
lesser extent, increases in depreciation rates pursuant to regulatory orders
and (3) non-recurring favorable adjustments to certain benefit costs in 1992.
NATURAL GAS PIPELINE
The Company's natural gas pipeline business historically has been conducted by
the Company's NGT (formerly Arkla Energy Resources), MRT, LIG and NorAm Energy
Services, Inc. ("NES", formerly Arkla Energy Marketing) subsidiaries.
On June 30, 1993, the Company completed the sale of LIG to a
subsidiary of 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,
see "Commitments and Contingencies" elsewhere herein. In order to focus on
ongoing operations, the following Pipeline data have been restated to exclude
LIG's results of operations for all periods presented, 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 and $25.1 million for the six months ended June 30, 1993 and the
year ended December 31, 1992, respectively, and its total throughput was 103.4
million MMBtu and 244.1 million MMBtu for the six months ended June 30, 1993
and the year ended December 31, 1992, respectively.
On February 1, 1995, the Company transferred the natural gas gathering
assets of NGT into a wholly-owned subsidiary called NorAm Field Services Corp.
("NFS"). NFS is not generally subject to cost-of-service rate regulation and
owns and operates approximately 3,500 miles of gathering pipelines which
collect gas from more than 200 separate systems in major producing fields in
Arkansas, Oklahoma, Louisiana and Texas.
The Company has an agreement with ANR Pipeline Company pursuant to
which the Company has contracted to sell an ownership interest in 250 MMcf/day
of capacity in existing pipeline facilities (principally the Company's Line
AC), see "Sale of Pipeline Facilities" under "Commitments and Contingencies"
elsewhere herein.
While the economic and regulatory environment in which distribution
companies operate has changed only modestly in recent years, the interstate
pipeline industry has seen significantly greater change. Most recently, FERC
Order 636 has largely completed the unbundling and deregulation of natural gas
commodity sales markets, requiring interstate pipelines to partially
restructure and reprice their services. In addition to requiring unbundling of
pipeline gas sales from services such as gathering, transportation and storage,
FERC Order 636 expresses a preference for a "straight fixed variable" or "SFV"
rate structure which affords pipelines the opportunity (subject
<PAGE> 7
39
to competitive pressures) to recover their fixed costs (including return on
investment) through the demand component of their rates, thus decreasing the
sensitivity of revenues to changes in the level of throughput. As an additional
result of this restructuring, certain financial line items and statistical data
are not comparable when periods before and after FERC Order 636 implementation
are compared due, in part, to customers electing to switch from sales to
transportation which has the effect of removing the cost of gas from revenues
and expenses. Services pursuant to the provisions of FERC Order 636 were
implemented by NGT in September 1993 and by MRT in November 1993, see
"Regulatory Matters" elsewhere herein.
The Company historically has applied the provisions of SFAS 71 to all
of its rate regulated businesses. With respect to the Company's NGT subsidiary,
however, the Company concluded that, effective as of December 31, 1992,
continued application of SFAS 71 was no longer appropriate. The Company based
its conclusion on its analysis of NGT's regulatory and economic environment and
the extent to which such environment would allow NGT to collect its cost-based
rates. The Company had begun its analysis when it became apparent that changes
in NGT's regulatory environment, largely due to the actions of the FERC, were
subjecting NGT to increasing competitive pressures, resulting in significant
underrecovery of NGT's cost-based revenue requirements. The Company determined
that it was unlikely that it could take steps through the regulatory process or
otherwise which would cause NGT to return to a situation in which the Company
could conclude that collection of NGT's cost-based rates was probable.
Accordingly, at December 31, 1992, the Company ceased to apply the
provisions of SFAS 71 to NGT's transactions and balances, which accounting
change was implemented pursuant to Statement of Financial Accounting Standards
No. 101, "Regulated Enterprises - Accounting for the Discontinuance of
Application of FASB Statement No. 71" ("SFAS 101"). The methodology for this
accounting change is contained within SFAS 101 and, simply stated, requires the
removal from NGT's balance sheet of the impact of the effects of the actions of
regulators. More specifically, the Company (1) identified and wrote-off those
NGT assets which would not be recognized as assets by non-regulated
enterprises, principally amounts associated with take-or-pay settlement costs
and deferred pursuant to FERC Order 528 ($237.9 million), (2) wrote down
certain current assets based on "lower of cost or market" rules applicable to
non-regulated enterprises ($27.0 million), (3) accrued for expected costs in
excess of current market value for certain gas purchase contracts for which
recovery could no longer be assumed through regulatory mechanisms ($19.9
million) and (4) wrote down certain of its gathering assets pursuant to
impairment guidelines applicable to enterprises in general ($29.7 million).
This pre-tax charge, which totalled $314.5 million ($195.0 million after-tax),
is shown in the Company's Statement of Consolidated Income for 1992 under the
caption "Extraordinary items, 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.
The Company concluded that its Distribution divisions continued to
qualify for the application of SFAS 71 because their exposure to competition
has had minimal effect and is limited by the nature of their business, and
because their regulatory climate has changed only modestly from its historical
structure, although there are some indications that more significant changes in
the form of regulation may occur. However, due to the fact that distribution
companies are regulated at the state and/or municipal level and the preliminary
stages of the relevant discussions and proceedings, it is unclear as to the
timing of any further regulatory change or the form it will take. Similarly,
the Company concluded that continued application of SFAS 71 to its MRT
interstate pipeline subsidiary was appropriate because, unlike NGT, MRT's
"long-line" configuration and customer base have sheltered it to a large degree
from the negative impacts which regulatory change and related increased
competition have had and continue to have on NGT.
Effective as of December 31, 1993, the Company completed a
comprehensive settlement agreement ("the Settlement") with certain subsidiaries
of Samson Investment Company ("Samson"), pursuant to which a number of
outstanding contractual arrangements between the parties were terminated or
substantially modified, resulting in a pre-tax charge to earnings of
approximately $34 million, included in the Company's Statement of Consolidated
Income for 1993 under the caption "Contract termination charge". This charge
resulted principally from the early termination of a gas supply agreement which
was expected to prove economically disadvantageous to the Company over its
term. Consideration for the Settlement included the delivery to Samson by the
Company of a note for $34 million and the receipt by the Company of the right
to 6 Bcf of gas from Samson without additional charge over the period from
January 1994 through March 15, 1995. The Settlement also resulted in the offset
and cancellation of certain other contractual arrangements between the parties,
including long-term obligations, notes receivable and gas purchased in advance
of delivery.
The net cash flow from the Settlement is expected to be positive for
the years 1995-1999. The impact of the Settlement on the Company's future
earnings for the periods covered by the previous arrangements is expected to be
positive but will be reduced to the extent that the Company is required to
replace the availability of gas previously provided under these arrangements.
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
and sell natural gas. Some of these financial instruments carry
off-balance-sheet risk, see "Commitments and 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 in the
Company's cost of natural gas purchased, net as the physical production is
purchased or sold under the related contracts.
<PAGE> 8
40
FINANCIAL RESULTS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(millions of dollars) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas sales revenue
Sales to Distribution $ 156.8 $ 265.4 $ 238.0
Sales for resale and other 594.4 608.8 514.9
------------------------------------------------------------------------------------------
Total gas sales revenue 751.2 874.2 752.9
------------------------------------------------------------------------------------------
Transportation revenue
Distribution 96.5 46.1 17.9
Other 164.5 92.6 84.1
------------------------------------------------------------------------------------------
Total transportation revenue 261.0 138.7 102.0
------------------------------------------------------------------------------------------
Total operating revenue 1,012.2 1,012.9 854.9
------------------------------------------------------------------------------------------
Purchased gas cost
Affiliated 4.1 5.0 41.5
Unaffiliated 687.9 710.7 566.2
Operations and maintenance 99.3 102.6 115.9
Depreciation and amortization 42.9 43.2 44.2
Other operating expenses 69.9 73.2 71.4
Contract termination charge - 34.2 -
------------------------------------------------------------------------------------------
Operating income $ 108.1 $ 44.0 $ 15.7
==========================================================================================
Average invested capital $ 935.6 $ 1,018.4 $ 1,266.6
==========================================================================================
</TABLE>
OPERATING STATISTICS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(million MMBtu) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Sales to Distribution 70.6 71.2 73.5
Sales for resale and other 157.5 103.6 76.5
------------------------------------------------------------------------------------------
Total sales 228.1 174.8 150.0
------------------------------------------------------------------------------------------
Transportation
Distribution 99.3 85.7 53.7
Other 732.5 694.4 698.8
------------------------------------------------------------------------------------------
Total transportation 831.8 780.1 752.5
------------------------------------------------------------------------------------------
Less: FERC Order 636
elimination (1) (63.0) (24.2) -
------------------------------------------------------------------------------------------
Total throughput 996.9 930.7 902.5
==========================================================================================
Average interstate pipeline
transportation margin
($/MMBtu) $ 0.330 $ 0.209 $ 0.184
------------------------------------------------------------------------------------------
Average pipeline sales
margin ($/MMBtu) $ 0.169 $ 0.856 $ 0.922
------------------------------------------------------------------------------------------
</TABLE>
(1) Prior to the implementation of unbundled services pursuant to FERC
Order 636, Pipeline's sales rate covered all related services,
including transportation to the customer's facility. Under FERC Order
636, when Pipeline acts as a merchant, the sales transaction is
independent of (and may not include) the transportation of the volume
sold. Therefore, when the 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.
DISCUSSION OF OPERATING RESULTS
Pipeline's operating income before the contract termination charge increased by
$29.9 million and $62.5 million from 1993 to 1994 and from 1992 to 1993,
respectively. These increases, while partially attributable to improvements in
ongoing business operations, also reflect the impacts of (1) the unbundling and
repricing of the interstate pipelines' services, (2) the elimination of the
amortization of amounts deferred pursuant to FERC Order 528 as a result of the
discontinued application of SFAS 71 to NGT and (3) the elimination of the
demand charge under a contract with Samson which was terminated as discussed
elsewhere herein. Certain other items partially responsible for the significant
year-to-year increases, such as (1) decreases in costs, (2) revenue requirement
increases obtained in recent rate cases and (3) the effects of NES's increased
storage and risk management activities will provide recurring benefits but are
not expected to create the same level of future year-to-year improvements.
Therefore, while Pipeline's earnings are affected by various factors as
discussed elsewhere herein, the Company believes that it has the opportunity to
further improve Pipeline's earnings, although it expects that the percent
improvement in earnings, if any, will be less than that of the most recent few
years.
1994 vs. 1993
Operating income for 1994 was $108.1 million, a $29.9 million (38.2%) increase
over 1993 (before reduction for the $34.2 million contract termination charge).
This increase is largely attributable to the improved operating income of NES
which accounts for 58% of the increase in Pipeline operating income. The
improved earnings of NES are partially attributable to the comprehensive
settlement with Samson at December 1993 as described preceding. In 1993, NES
paid approximately $10.0 million of reservation fees under a contract with
Samson which did not recur in 1994 due to the previously mentioned settlement
agreement, and which were not replaced with a similar amount of reservation
fees to other parties due to NES's activities as described following. NES has
contracted for gas storage which, combined with its risk management activities,
has helped reduce the costs associated with meeting its contractual obligations
in periods marked by significant swings in spot market prices and demand for
gas. Approximately $7.0 million of the improvement in operating income resulted
from final approval of two pipeline rate cases (see "Regulatory Matters"
elsewhere herein), with the remaining increase attributable to improved
transportation margins and reduced operating expenses of NGT and MRT as
discussed following.
Revenues from "Sales to Distribution" and "Sales for resale and other"
decreased from 1993 to 1994 by $108.6 million (40.9%) and $14.4 million (2.4%),
respectively. These sales revenue categories decreased a total of $253.2
million in the Company's interstate pipelines, due primarily to the previously
mentioned effects of restructured services under FERC Order 636. This decrease
was partially offset by increased sales revenues by NES, which also accounts
<PAGE> 9
41
for the majority of the 53.3 million MMBtu (30.5%) increase in sales volumes
over 1993.
Transportation revenues from Distribution increased by $50.4 million
(109.3%) and other transportation revenues increased by $71.9 million (77.6%)
from 1993 to 1994 primarily due to restructured services under FERC Order 636
whereby transportation services are independent of (and not included in) the
sales transaction. Although transportation revenues increased by 77.6% in 1994,
transportation volumes increased by only 6.6%, largely due to the change to SFV
rate design. Under this rate structure, a larger portion of total costs are
included in the demand (fixed) 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 prior rate
design which placed more costs in the volumetric (variable) portion of the
rate. This change in rate design also contributed to the $0.121 per MMBtu (58%)
increase in 1994 in the average interstate pipeline transportation margin. In
addition, under FERC Order 636, services previously included in the sales rate
(e.g., storage) have now been "unbundled" and are billed separately and
included as transportation revenue.
Total purchased gas cost decreased by $23.7 million (3.3%) from 1993
to 1994. Gas cost for the Company's interstate pipelines decreased by $127.6
million principally due to the previously discussed restructured services under
FERC Order 636. In addition, NES experienced a decrease in gas cost due to the
reservation fees paid in 1993 that did not recur due to the comprehensive
settlement with Samson discussed above. These decreases in gas cost were offset
by increased purchases by NES to support the previously mentioned increase in
sales volumes.
Operation and maintenance expense decreased by $3.3 million (3.2%)
primarily due to a $6.7 million (13.2%) decrease in transportation expense paid
to third-party pipelines, partially offset by higher labor and other operating
supplies and expenses. Lower third-party transportation cost is largely
attributable to interstate pipeline customers making their own transportation
arrangements with third parties for gas sourced off-system under FERC Order
636, which cost would have previously been reported by the pipeline and
recovered through the "bundled" sales rates.
Other operating expenses decreased by $3.3 million from 1993 to 1994,
principally due to a non-recurring $2.0 million payment in 1993 for certain
severance costs as well as a $1.1 million reduction in property taxes in 1994.
The reduction in property taxes is largely attributable to restructured storage
services under FERC Order 636 in which the Pipeline provides only the use of
the storage facility for a fee, but no longer "owns" the majority of gas in
storage and, therefore, no longer has an obligation for the property tax on the
inventory. The Company also recognized certain ad valorem tax rate reductions
associated with the "spindown" of NGT in March 1993.
1993 vs. 1992
Operating income for 1993 was $78.2 million (before the pre-tax "Contract
termination charge" of $34.2 million), a $62.5 million increase over 1992,
reflecting both increased operating revenues and increased operating expenses.
This significant improvement is attributable to several factors including (1)
increased sales and transportation volumes, (2) rate increases obtained by NGT
and MRT, (3) more favorable 1993 weather (approximately 23% cooler than 1992)
and (4) accounting adjustments included in 1992 results as discussed following.
Revenues from sales to Distribution increased by $27.4 million (11.5%)
in 1993 while sales volumes decreased by 2.3 million MMBtu (3.1%). This unusual
relationship is attributable to the one-time sale by NGT of approximately $28.5
million of gas in storage inventory to a distribution affiliate in accordance
with the provisions of FERC Order 636. This sale represented a sale of
inventory in place, thus resulting in no additional Pipeline throughput and was
made at cost with no gain or loss recognized. Effective with FERC Order 636
implementation, NGT now offers unbundled storage services, retaining only a
relatively small amount of storage gas (approximately 5 Bcf) for system
operational purposes.
"Sales for resale and other" increased by $93.9 million (18.2%) in 1993
with approximately 78% of the increase attributable to increased 1993 NES sales
revenues. The average NES sales rate increased by approximately $0.29/MMBtu in
1993 primarily due to a corresponding increase of $0.34/MMBtu in Mid-continent
spot gas prices which served to increase the gas cost component of the total
sales rate. The remainder of the increase is attributable to a 27.1 million
MMBtu (35.4%) increase in sales volumes, rate increases obtained by Pipeline's
regulated business units during the year and the effect of implementing
restructured services in the last quarter of 1993.
Transportation revenues increased by $36.7 million in 1993 primarily
due to a 13.6% increase in the average interstate pipeline transportation rate
and, to a lesser degree, a 3.7% increase in transportation volumes. The
increase in the transportation rate reflects rate increases obtained in 1993
and the effect of higher demand charges due to implementing restructured
services under FERC Order 636. Additionally, 1992 transportation revenues
included an $8.1 million charge to amortize amounts deferred for recovery
pursuant to FERC Order 528, which amortization did not recur in 1993 due to the
discontinuance of the application of SFAS 71 to NGT.
Purchased gas cost from affiliates in 1993 decreased by $36.5 million
or 88.0% due to the sale of Arkla Exploration Company in December 1992, see
"Acquisitions and Dispositions" elsewhere herein. Third party gas purchases
increased by $144.5 million or 25.5% due to a 16.5% increase in sales volumes,
the previously mentioned impact of increased spot gas prices and the sale of
Arkla Exploration Company.
Operation and maintenance expenses for 1993 decreased by 11.5% in
comparison to 1992, with approximately 48.9% of the
<PAGE> 10
42
decrease attributable to lower transportation costs paid to third-party
pipelines and 35.3% of the decrease attributable to a non-recurring write-off
of certain non-collectible accounts during 1992. The remainder of the decrease
is principally attributable to (1) lower labor cost due to manpower reductions
since 1992 and (2) lower supplies and expenses resulting from the continuing
focus on cost reduction.
Depreciation and amortization decreased by 2.3% in 1993 primarily due
to the write-down of certain gathering assets in conjunction with the
discontinued application of SFAS 71 to NGT at year-end 1992, as described
preceding.
Other operating expenses increased by 2.5% in 1993 as a result of
increased regulatory and legal expenses and cost allocations from the Company's
Corporate division. The increased legal and regulatory expenses are largely
attributable to several significant events during the year including (1) the
spindown of the former Arkla Energy Resources division to create NGT, (2) a
filing with the FERC for spindown of the gathering function to a separate
corporation, (3) implementation of restructured services under FERC Order 636
and (4) various other regulatory and legal matters.
CORPORATE AND OTHER
The $12.1 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.
The $2.8 million decrease in the operating loss from 1992 to 1993 is
principally due to the inclusion, in 1992 results, of accruals for certain
severance and related benefits, partially offset by certain increased 1993
expenses as described preceding.
CONSOLIDATED
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
$59.0 million during the same period. The principal reasons for this $47.0
million of increased expense below the operating income line were as follows,
the majority of which are discussed elsewhere herein:
- 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.
- The decrease of approximately $7.7 million in interest income from
1993 to 1994, largely due to the comprehensive settlement agreement
with Samson.
- The inclusion, in 1994 results, of $2.1 million in after-tax expense
from discontinued operations.
- The impact of miscellaneous other items of income and expense which
represented income of $4.5 million in 1993 but expense of $6.9 million
in 1994.
These unfavorable impacts were partially offset by:
- A decrease of $2.6 million in interest expense from 1993 to 1994
principally due to a decreased level of borrowings.
- A decrease in 1994 income tax expense, reflecting a decrease in the
effective tax rate, see Note 2 of Notes to Consolidated Financial
Statements.
Consolidated net income for 1993 was approximately $36.1 million, an
improvement of approximately $264.6 million over 1992 while, as discussed
above, operating income increased by approximately $18.4 million during the
same period. The principal reasons for this $246.2 million of increased income
below the operating income line were as follows, each of which is discussed
elsewhere herein:
- The inclusion in 1992 results of the $195 million after-tax loss due
to the discontinued application of SFAS 71 to NGT.
- The inclusion in 1992 results of the $4.9 million after-tax loss due
to the cumulative effect of adopting SFAS 112.
- The inclusion in 1992 results of a $34.8 million after-tax loss
attributable to discontinued operations, see Note 9 of Notes to
Consolidated Financial Statements.
- The increase of $36.5 million in 1993 other income, principally due to
gains from sales of property, see Note 1 of Notes to Consolidated
Financial Statements.
- The decrease of $13.6 million in 1993 interest expense, principally
due to decreased borrowings.
These favorable impacts were partially offset by:
- The increase of $34.0 million in the 1993 provision for income taxes,
principally due to the increase in income from continuing operations
before income taxes.
- The inclusion in 1993 results of a $3.8 million after-tax loss due to
premiums on the early retirement of debt.
DISCONTINUED OPERATIONS
EXPLORATION AND PRODUCTION
In early 1992, the Company reacquired the 6,000,000 publicly-held shares of
Arkla Exploration Company ("E&P") representing minority ownership of
approximately 18% through an exchange offer and merger, resulting in (1) the
issuance of approximately 5.7 million shares of the Company's common stock and
(2) a return to 100% ownership of E&P by the Company. This minority interest
had been outstanding as a result of an initial public offering of E&P's common
stock in 1989. The common stock issued to reacquire the minority interest
increased the Company's stockholders' equity by its fair market value of
approximately $59.8 million. The difference between the fair market value of
the stock issued and the carrying value of the minority interest reacquired
served to increase the Company's invest-
<PAGE> 11
43
ment in E&P, resulting in an increase of approximately $42.4 million in the
carrying value of E&P's oil and gas reserves, which reserves were subsequently
sold as described following.
On December 31, 1992, the Company completed the sale of E&P to Seagull
Energy Corporation for approximately $397 million in cash (including $7.3
million removed from E&P prior to closing), the substantial portion of which
was used to reduce the Company's short-term borrowings, see Note 9 of Notes to
Consolidated Financial Statements. In conjunction with the sale, the Company
(1) agreed to indemnify Seagull against certain exposures (for which the
Company has established reserves equal to anticipated claims under the
indemnity) and (2) retained a volumetric production payment representing the
right to receive the cash proceeds from the sale of approximately 1.2 million
barrels of oil over three years. Approximately 153,900 barrels remained to be
delivered at December 31, 1994, in which the Company has a book investment of
approximately $13/barrel. The Company has purchased a "floor" sales price of
$17/barrel for this production payment, based upon which the fair value of the
oil to be delivered was approximately $2.6 million at December 31, 1994.
RADIO COMMUNICATIONS
In conjunction with the purchase of DEI in November 1990, the Company acquired
business units that conducted operations in radio communications ("Johnson")
and energy measurement products and systems ("EnScan"), see Note 9 of Notes to
Consolidated Financial Statements.
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. The Itron stock received by the
Company in this exchange of interests was valued on a public exchange at
approximately the Company's recorded investment in EnScan and, accordingly, no
gain or loss was recognized. After Itron's 1993 initial public offering of its
common stock and the Company's December 1994 sale of 400,000 Itron shares
(yielding cash proceeds of approximately $7.2 million) at December 31, 1994,
the Company owned a common stock interest representing ownership of
approximately 13.25% of the combined enterprise, which is managed by Itron. The
December 1994 sale generated net proceeds of approximately $18.00/share,
approximately equal to the Company's then existing basis of approximately
$17.80/share.
The Company changed its method of accounting for its investment in
Itron from the equity method to the cost method as of December 31, 1993 and,
based on price quotations on the NASDAQ, the market value (and carrying value)
of the Company's investment at December 31, 1994 was approximately $32.1
million, and had increased to approximately $40.4 million at March 1, 1995. The
Company marks its investment in Itron to market in accordance with the
provisions of Statement of Financial Accounting Standards No. 115, "Accounting
for Certain Investments in Debt and Equity Securities", which was effective for
fiscal years beginning after December 15, 1993, see Note 9 of Notes to
Consolidated Financial Statements. The Company intends to dispose of its
remaining Itron investment 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. The consideration received was
approximately equal to the carrying value of the Company's investment and,
accordingly, no gain or loss was recognized.
UNIVERSITY SAVINGS ASSOCIATION
University Savings Association ("USA") 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. In early 1992, the Resolution Trust
Corporation instituted actions against several former officers and directors of
USA and filed a suit against the Company, which suit was recently settled, see
Notes 9 and 11 of Notes to Consolidated Financial Statements.
ARKLA PRODUCTS
In 1984, as a part of a larger transaction, the Company sold its gas grill
manufacturing business to Preway, Inc. ("Preway"). As a result of Preway's
subsequent default on certain industrial revenue bonds which were
collateralized by the gas grill manufacturing assets and for which the Company
had remained secondarily liable, the Company reacquired the gas grill business
and conducted operations in its Arkla Products subsidiary as it sought to
dispose of this business. In late 1992, the Company sold the principal assets
and recorded a loss on disposition, see Note 9 of Notes to Consolidated
Financial Statements.
<PAGE> 12
44
LIQUIDITY AND CAPITAL RESOURCES
INVESTED CAPITAL
The following table illustrates the sources of the Company's capital during the
past five years.
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
(millions of dollars) December 31,
1994 1993 1992 1991 1990
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Long-term debt, less current maturities $ 1,414.4 $ 1,629.4 $ 1,783.1 $ 1,551.5 $ 1,450.2
Total equity 717.4 708.0 712.9 948.0 1,115.4
----------------------------------------------------------------------------------------------------------------------
Total capitalization 2,131.8 2,337.4 2,496.0 2,499.5 2,565.6
Short-term debt, including current maturities 274.6 192.4 120.0 772.6 712.4
----------------------------------------------------------------------------------------------------------------------
Total invested capital $ 2,406.4 $ 2,529.8 $ 2,616.0 $ 3,272.1 $ 3,278.0
======================================================================================================================
Long-term debt as a percent of total
capitalization 66.3% 69.7% 71.4% 62.1% 56.5%
Equity as a percent of total capitalization 33.7% 30.3% 28.6% 37.9% 43.5%
Total debt as a percent of total
invested capital 70.2% 72.0% 72.7% 71.0% 66.0%
</TABLE>
CASH FLOW ANALYSIS
The Company's "Net cash provided by operating activities" as shown in the
accompanying Statement of Consolidated Cash Flows exceeded the sum of capital
expenditures and dividend payments by approximately $92.5 million in 1994, and
was less than the sum of these cash requirements by approximately $15.7 million
and $94.3 million in 1993 and 1992, respectively. This increasing amount of
cash available after capital expenditures and dividends occurred, in part, due
to a decrease in common stock dividends beginning with 1993 and despite an
increase in the level of capital spending, but is principally due to an
increase in the level of "Net cash provided by operating activities", see "Net
Cash Flow from Operating Activities" elsewhere herein.
NET CASH FLOW FROM FINANCING ACTIVITIES
The Company historically has met its needs for short-term borrowings through
its revolving credit facility with a major money center bank as agent and
various other commercial banks, through informal lines of credit and/or through
the issuance of commercial paper, although it no longer has access to the
commercial paper market as described following.
Prior to November 1994, the Company had a revolving credit facility
(the "Previous Facility") which made a total commitment of $400 million
available to the Company through June 30, 1995. Effective November 2, 1994, the
Company executed a new Credit Agreement (the "New Facility") with Citibank,
N.A., as Agent, and a group of sixteen other commercial banks which provides a
$400 million commitment to the Company through October 31, 1997. The terms and
conditions of the New Facility are similar to the Previous Facility with one
significant exception. Although the New Facility continues to be collateralized
by the stock of MRT and NGT, if the Company is rated investment-grade by both
Moody's Investor Service, Inc. and Standard & Poor's Corporation, this
collateral would be released.
As with the Previous Facility, borrowings under the New Facility bear
interest at various Eurodollar and domestic rates, at the option of the
Company, and these rates are 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 .30%, and subject to decrease
based on the Company's debt rating, and will pay an incremental rate of 1/8% on
outstanding borrowings in excess of $200 million. Both of these fees reflect
declines from the fees under the Previous Facility.
The Company had borrowings under its Previous Facility of $95.0
million at December 31, 1993 and borrowings under the New Facility of $110.0
million and $35.0 million at December 31, 1994 and March 1, 1995, respectively.
In addition, at March 1, 1995, the Company had borrowings of $15.0 million
under informal lines of credit, none of which were outstanding at December 31,
1994. The Company had, therefore, approximately $365.0 million in capacity
under the New Facility at March 1, 1995, which capacity is expected to be
adequate to cover the Company's current and projected needs for short-term
financing.
The New Facility contains a provision which requires the Company to
maintain a specific level of total stockholders' equity, initially set at $650
million at December 31, 1993, and increased annually thereafter by (1) 50% of
positive consolidated net income and (2) 50% of the proceeds (in excess of the
first $50 million) from any incremental equity offering made after June 30,
1994. The New Facility also places a limitation of $2,055 million on total debt
and a limitation of $100 million on the amount of outstanding long-term debt
which may be retired in advance of its maturity. Certain of the Company's other
financial arrangements contain similar provisions. Based on these restrictions,
the Company had incremental debt capacity and incremental dividend capacity of
$321.2 million and $43.3 million, respectively, at December 31, 1994.
During 1992, the ratings on the Company's senior debt and commercial
paper were lowered by various rating agencies, generally to
<PAGE> 13
45
one level below investment grade. These rating changes have prevented the
Company from issuing commercial paper and have affected the markets for the
Company's long-term debt securities through increased interest rates, but the
Company has not experienced and does not expect any lasting material adverse
effect on its ability to raise capital in long-term markets.
The Company's long-term debt financing is obtained through the
issuance of debentures and notes. 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.
As a part of its ongoing program to reduce its overall cost of debt,
the Company reacquired approximately $50.4 million and $88.3 million principal
amount of its long-term debt during 1994 and 1993, respectively. The weighted
average interest rate was approximately 9.8% for the debt retired during 1994
and 1993 and this debt was reacquired for total net premiums of approximately
$1.4 million and $5.5 million (approximately $1.1 million and $3.8 million,
respectively, after-tax) for 1994 and 1993, respectively, reported in the
Company's Statement of Consolidated Income under the caption, "Extraordinary
items, less taxes". 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.
Largely as a result of the application of the proceeds received from
the Company's recent divestitures, the Company has significantly reduced its
level of total debt and specifically has reduced its short-term borrowings (its
only significant floating-rate debt) to low levels. In order to manage its debt
portfolio such that a reasonable portion is subject to changes in market
interest rates and take advantage of available spreads between 2-3 year
fixed-rate and 6-12 month floating-rate debt instruments, the Company has
entered into a number of transactions generally described as "interest rate
swaps". The terms of these arrangements vary but, in general, specify that the
Company will pay an amount of interest on the notional amount of the swap which
varies with LIBOR while the other party (a commercial bank) pays a fixed rate.
The Company had no swaps in effect at December 31, 1992 and, during 1993, the
Company entered into a total of $575 million notional amount of swaps, of which
$200 million remained at December 31, 1993. During 1994, the Company entered
into an additional $75 million notional amount of swaps. At December 31, 1994,
$275 million notional amount of these swaps were outstanding, terminating at
various dates through February 1997. None of these swaps are "leveraged" and,
therefore, they do not represent exposure in excess of that suggested by the
notional amount and reported interest rates. At December 31, 1994, the
Company's obligation under these arrangements, which is calculated using 6-12
month floating LIBOR, was based on a weighted average interest rate of
approximately 6.7%, while the counterparties' obligations were based on a
weighted average fixed rate of approximately 5.1%. The Company's performance
under these swaps is collateralized by the stock of MRT and NGT, and the
Company is permitted to increase the amount outstanding under such
collateralized arrangements to a total of $350 million, a limitation imposed by
the terms of the New Facility.
In accordance with authoritative accounting guidelines, the economic
value which transfers between the parties to these swaps is treated as an
adjustment to the effective interest rate on the Company's underlying debt
securities. When positions are closed prior to the expiration of the stated
term, any gain or loss on termination is amortized over the remaining period in
the original term of the swap. The effect of these swaps was to increase the
Company's interest expense by $0.5 million for 1994 and to decrease the
Company's interest expense by $4.6 million for 1993. The deferred gain
associated with interest rate swaps terminated prior to their expiration was
approximately $2.5 million at December 31, 1994. This gain is expected to be
amortized as follows: 1995 - $1.7 million; 1996 - $0.7 million; all remaining
periods - $0.1 million. At December 31, 1994, the unrealized loss
(mark-to-market value) associated with outstanding swap arrangements was
approximately $18.0 million, which unrealized loss had declined to $10.3
million at March 1, 1995.
Off-balance-sheet credit risk exists to the extent of the possibility
that the counterparties to these swaps might fail to perform. The Company has
limited these transactions to arrangements with commercial banks that are
participants in the Company's revolving credit facility. The Company routinely
reviews the financial strength of these banks (utilizing independent monitoring
services and otherwise) and believes that the probability of default by any
counterparty to these swaps is minimal.
In July 1994, the Company entered into an equipment funding agreement
with an affiliate of a major bank to provide up to $50 million to be used to
purchase new vehicles, major work equipment and a small amount of computer and
other office equipment over a three-year period. For accounting purposes, these
assets will be subject to operating lease treatment, with an initial
non-cancellable term of one year.
In July 1994, the Company amended its previously-filed registration
statement to convert it to a Rule 415 or "shelf" offering (the "Shelf"). The
Shelf will allow the Company to issue up to 14.95 million shares of additional
common stock for a period of up to two years from the effective date. The net
proceeds from shares issued pursuant to the Shelf are expected to be used for
general corporate purposes.
<PAGE> 14
46
In late 1994, the Company instituted a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP/DRIP") which offers its customers and
other interested parties an 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. The purpose of the DSPP/DRIP is to provide new investors with a
convenient means to make an initial investment in the Common Stock and to
provide existing holders of the Common Stock with (1) a means to have their
dividends automatically reinvested in shares of the Common Stock and (2) a
convenient and economical way to purchase additional shares. While individual
purchases under the plan are generally small, the Company believes that, over
time, a significant amount of additional equity capital may be raised through
this program.
The Company has several programs pursuant to which shares of Common
Stock may be issued or sold to employees or directors, see Notes 6, 7 and 8 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 and may refund additional amounts, see "Sale of Pipeline Facilities"
elsewhere herein. During 1992, the Company returned $20 million which had been
advanced by another party in conjunction with a proposed transaction related to
capacity in the Company's Line AC, which transaction was not consummated.
During 1994 and 1993, the Company paid common dividends of $0.07/share
each quarter, resulting in total cash expenditures of $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,
1995, the Company paid dividends of $0.07/share on common stock and $0.75/share
on preferred stock.
NET CASH FLOW FROM OPERATING ACTIVITIES
1994 vs. 1993
As indicated in the accompanying Statement of Consolidated Cash Flows, the net
cash flow from operating activities increased from approximately $172.6 million
in 1993 to approximately $304.9 million in 1994. This increase of approximately
$132.3 million (76.7%) was principally attributable to the following:
- An increase of $91.9 million from 1993 to 1994 in cash provided by
inventories, approximately $51 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.
- An increase of $156.4 million from 1993 to 1994 in cash provided by
the collection of accounts receivable, principally as a result of the
relatively large December 31, 1993 accounts receivable balance which
was collected during 1994. Given the December 31, 1994 balance of
$213.3 million (as compared to $314.5 million at December 31, 1993),
the Company expects that cash provided from accounts receivable
collections will decline in 1995.
- An increase of $53.7 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.
- A decrease of $32.4 million from 1993 to 1994 in cash used for other
accounts payable, principally due to the relatively higher December
31, 1992 other accounts payable balance.
These favorable impacts were partially offset by:
- An increase of $78.4 million from 1993 to 1994 in cash used for gas
accounts payable, due in part to Pipeline's 1993 implementation of
services under FERC Order 636 as described elsewhere herein, and to
normal seasonal fluctuations in the Company's distribution businesses.
- 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.
- 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.
- An increase of $42.7 million in cash used for miscellaneous working
capital accounts in 1994, inclusive of a $2.5 million increase in cash
provided from recovery under gas contract disputes.
1993 vs. 1992
As indicated in the accompanying Statement of Consolidated Cash Flows, the net
cash flow from operating activities increased from $107.1 million in 1992 to
$172.6 million in 1993. This $65.5 million (61.2%) increase is principally
attributable to the following:
- The 1993 cash inflows from recovery under gas contract disputes, which
disputes had resulted in a net outflow in 1992.
- Increased 1993 cash collections of deferred gas costs due, in part, to
Pipeline's implementation of restructured services pursuant to FERC
Order 636.
- Decreased 1993 cash used for reduction of gas accounts payable.
- Decreased 1993 cash used for miscellaneous working capital items.
These favorable impacts were partially offset by:
- Decreased 1993 cash provided from sale of inventories, principally due
to the relatively higher December 31, 1993 balance of gas in
underground storage, including a significant amount of gas sold to
<PAGE> 15
47
MRT's customers in early 1994, see Note 1 of Notes to Consolidated
Financial Statements.
- Increased 1993 cash income tax payments.
SALE OF ACCOUNTS RECEIVABLE
In June 1990, the Company entered into an agreement to sell an undivided
percentage ownership interest in a designated pool of accounts receivable on a
revolving basis, with limited recourse and subject to a floating interest rate
provision and for which the Company is paid a normal servicing fee. This
agreement, after amendment in early 1994, allows for the sale of accounts
receivable up to a maximum of $235 million and expires in August 1995, although
the Company currently expects that it will renew the facility. At December 31,
1994, the Company had $192.8 million of receivables sold and uncollected under
the program. These receivables were collateralized by approximately $48.7
million of the Company's remaining receivables, which collateral represents the
maximum exposure to the Company should all receivables prove ultimately
uncollectible. During 1994, 1993 and 1992, the Company experienced net cash
outflows (inflows) of $33.6 million, $(13.8) million and $6.0 million,
respectively, under the program.
NET CASH FLOW FROM INVESTING ACTIVITIES
In 1994, 1993 and 1992, the Company generated significant amounts of cash
through sales of property, see Notes 9 and 10 of Notes to Consolidated
Financial Statements and various headings elsewhere herein.
CAPITAL EXPENDITURES - CONTINUING OPERATIONS (1)
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
(millions of dollars) (Planned)
1995 1994 1993 1992 1991 1990
----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural gas distribution $ 130.9 $ 121.2 $ 112.9 $ 106.2 $ 119.4 $ 76.6
Natural gas pipeline 74.1 47.5 30.3 21.5 129.2 258.9
Corporate and other 2.4 1.7 1.1 2.1 2.4 4.2
----------------------------------------------------------------------------------------------------------------------
Subtotal 207.4 170.4 144.3 129.8 251.0 339.7
LIG - - 1.9 5.1 4.0 4.8
----------------------------------------------------------------------------------------------------------------------
Total $ 207.4 $ 170.4 $ 146.2 $ 134.9 $ 255.0 $ 344.5
======================================================================================================================
</TABLE>
(1) Includes the capital expenditures of Minnegasco subsequent to its
acquisition by the Company in December 1990, and the capital
expenditures of LIG from its acquisition by the Company in July 1989
to its sale in June 1993.
The Company's capital expenditures increased from $146.2 million in 1993 to
$170.4 million in 1994, an increase of $24.2 million or 16.6%, reflecting
increased spending in both Pipeline and Distribution. The $17.2 million (56.8%)
increase in Pipeline capital spending was principally due to expenditures
(including on the Company's Line F) associated with the Company's program to
increase throughput at its facilities near Perryville, Louisiana. The $8.3
million (7.4%) increase in Distribution capital spending was primarily due to
increased spending at Minnegasco for the addition of 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.
The Company's capital expenditures for 1995 are budgeted at $207.4 million,
reflecting increases of approximately $26.6 million and $9.7 million for
Pipeline and Distribution, respectively, over actual 1994 spending. The
projected increase in Pipeline spending is principally due to increased
spending for system replacements, while the increased Distribution spending is
principally projected to be at Entex for system enhancements and increases
necessitated by public works projects. The Company expects that it will be able
to fund its 1995 capital expenditures through internally generated cash and, if
necessary, incremental borrowings.
The Company's capital expenditures increased from $134.9 million in
1992 to $146.2 million in 1993, an increase of $11.3 million (8.4%) principally
due to increased spending in Pipeline and Distribution. The increased spending
in both business units was primarily due to an increased level of replacement
of existing facilities.
COMMITMENTS AND CONTINGENCIES
CAPITAL SPENDING
At December 31, 1994, 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 1995-1999 and all years
thereafter is $164.6 million, $118.8 million, $427.0 million, $76.0 million,
$210.6 million and $582.0 million, respectively. The Company has obligations
under certain of its leasing arrangements, see Note 11 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
<PAGE> 16
48
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.
PENDING SALE TRANSACTION
The Company received (and recorded as a liability) $125 million from another
party pending completion of a transaction related to capacity on the Company's
Line AC, of which approximately $34 million was returned in December 1993 due
to changes in the underlying agreement and, under certain circumstances, the
Company may be required to return additional amounts, see "Sale of Pipeline
Facilities" elsewhere herein.
LETTERS OF CREDIT
At December 31, 1994, the Company was obligated under letters of credit
totalling approximately $25 million which are incidental to its ordinary
business operations.
INDEMNITY OBLIGATIONS
The Company has obligations under indemnification provisions of certain sale
agreements, see "Acquisitions and Dispositions" elsewhere herein.
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been sold, see "Sale of Accounts Receivables" elsewhere herein.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company operates principally in the transmission and distribution 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.
In addition to its other gas supply arrangements, the Company
routinely enters into agreements which commit it to either buy or sell gas in
the future at prices which may differ from prevailing market prices at the time
such transactions are consummated, or deliver gas at a point other than the
expected receipt point for the volumes to be purchased. In order to mitigate
the risk from market fluctuations in the price of natural gas and
transportation during the term of these commitments, the Company enters into
futures contracts, swaps and options, collectively referred to as "financial
contracts". The Company also utilizes these financial contracts to meet certain
of its customers' needs for fixed price gas supply as discussed following. In
no case are these financial contracts held for speculative trading purposes. In
the discussion which follows, contract quantities (notional amounts) are
provided for the purpose of establishing the extent of the Company's activities
involving these financial contracts although, in general, the amounts at risk
are significantly smaller when the offsetting physical transactions are
considered.
The Company has entered into swaps in which one party agrees to pay
either a fixed price or a fixed differential from the NYMEX price per MMBtu of
gas, while the other party agrees to pay a price based on a published index. As
of December 31, 1994 and 1993, the Company was obligated to pay either a fixed
price or a fixed differential from the NYMEX price on swaps covering 70.2 Bcf
and 15.8 Bcf of gas, respectively. During 1994, there were 117.7 Bcf of
additions to these swaps and 63.3 Bcf of maturities. As of December 31, 1994
and 1993, the Company was entitled to receive either a fixed price or a fixed
differential from the NYMEX price on swaps covering 87.4 Bcf and 39.9 Bcf of
gas, respectively. During 1994, there were 151.5 Bcf of additions to these
swaps and 104.0 Bcf of maturities. At December 31, 1994 and 1993, these swaps
(including both those where the Company is a fixed price payor and those where
the Company is a fixed price receiver) represented an unrealized gain (loss) of
$0.9 million and $(0.7) million, respectively, and the effect of these swaps
was to decrease the cost of natural gas purchased, net by $2.8 million and $1.0
million for 1994 and 1993, respectively.
The Company enters into NYMEX futures contracts which are primarily
used to hedge the Company's storage gas and meet certain customers' needs to
mitigate or eliminate their risk from market fluctuations in the price of
natural gas. As of December 31, 1994, the Company held contracts covering the
purchase of approximately 6.7 Bcf of gas through March 1996, a notional amount
of $13.8 million. As of December 31, 1994, the Company held contracts covering
the sale of approximately 1.7 Bcf of gas through January 1996, a notional
amount of $2.8 million. These contracts (both purchases and sales) represented
an unrealized loss of $2.9 million at December 31, 1994. The Company's
portfolio of futures contracts was not material at December 31, 1993. Due to
the fact that, in many cases, the cost of these activities are offset by
revenues from the customers who requested this service, the impact of these
futures on earnings is not material.
In conjunction with agreements existing at December 31, 1994, which
commit the Company to deliver specified quantities of gas at fixed prices
ratably through April 1999, the Company instituted a price risk management
program ("the Program") whereby financial contracts (principally swaps and
options) and fixed price purchase
<PAGE> 17
49
contracts are utilized to mitigate the risk associated with changes in the
market price of gas during the term of these arrangements. As of December 31,
1994, the Company had entered into swaps covering 61.7 Bcf of gas in which it
is the fixed price payor. During 1994, there were 43.1 Bcf of maturities and
19.4 Bcf of additions to such swaps. As of December 31, 1994 the Company had
entered into swaps covering 26.7 Bcf of gas in which it is the fixed price
receiver. During 1994, there were 35.0 Bcf of maturities and 19.4 Bcf of
additions to such swaps. As of December 31, 1993, the Company had entered into
swaps covering 85.4 Bcf of gas in which it was the fixed price payor and 42.3
Bcf of gas in which it was the fixed price receiver. As of December 31, 1994
and 1993, the unrealized loss associated with these swaps (including both those
where the Company is a fixed price payor and those where the Company is a fixed
price receiver) was $(17.6) million and $(5.9) million, respectively. The
Company also has purchased options under the Program which serve to limit the
year-to-year escalation in prices for gas to be delivered from January 1997 to
April 1999. At December 31, 1994 and 1993, options were outstanding covering
the purchase of 30.5 Bcf and 49.3 Bcf of gas, respectively, and options
covering 18.8 Bcf of gas expired during 1994. The Company has previously
established reserves equal to its projected maximum exposure to losses from the
agreements covered by the Program and, accordingly, there was no impact from
the Program on earnings in 1994 or 1993.
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 of
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
In October 1992, the Resolution Trust Corporation ("the RTC") filed suit
(ultimately seeking damages of at least $520 million) in United States District
Court for the Southern District, Houston Division, against the Company (as a
successor-in-interest to Entex, Inc. which merged with the Company in 1988) and
certain other defendants for alleged harm resulting from the 1989 failure of
University Savings Association ("USA"), a thrift institution in Houston, Texas.
In November 1994, the Company announced that it, together with the other
defendants, had entered into a final settlement of this litigation. The net
effect of this settlement, as adjusted for insurance recovery, legal expenses
incurred, certain other USA-related expenses and the legal expense reserve
previously recorded, was a pre-tax charge to discontinued operations of $3.3
million ($2.1 million after-tax) in the fourth quarter of 1994, see Note 9 of
Notes to Consolidated Financial Statements.
On August 6, 1993, the Company, its former subsidiary, Arkla
Exploration Company and Arkoma Production Company ("Arkoma"), a subsidiary of
E&P, were named as defendants in a lawsuit (the "State Claim") filed in the
Circuit Court of Independence County, Arkansas. This complaint alleges that the
Company, E&P and Arkoma, acted to defraud ratepayers in a series of
transactions arising out of a 1982 agreement between the Company and Arkoma. On
behalf of a purported class composed of the Company's ratepayers, plaintiffs
have alleged that the Company, E&P and Arkoma are responsible for common law
fraud and violation of an Arkansas law regarding gas companies, and are seeking
a total of $100 million in actual damages and $300 million in punitive damages.
On November 1, 1993, the Company filed a motion to dismiss the State Claim. In
a hearing held on May 19, 1994, the Court heard arguments on this motion. On
September 20, 1994, the Court entered an order granting the Company's motion to
dismiss. The plaintiffs have appealed this order granting the motion to
dismiss, but a hearing date for the appeal has not yet been set. The underlying
facts forming the basis of the allegations in the State Claim also formed the
basis for allegations in a lawsuit (the "Federal Claim") filed in September
1990 in the United States District Court for the Eastern District of Arkansas,
by the same plaintiffs. The Federal Claim was dismissed in August 1992. Since
the State Claim is based on essentially the same underlying factual basis as
the Federal Claim and in light of the Court's order granting the Company's
motion to dismiss the State Claim, the Company continues to believe the State
Claim is without merit, intends to vigorously contest the appeal of the order
granting dismissal and does not believe that the outcome will have a material
adverse effect on the financial position, results of operations or cash flows
of the Company.
The Company is a party to litigation (other than that specifically
noted) which arises in the normal course of business. Management reg-
<PAGE> 18
50
ularly 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.
GAS SUPPLY CONTRACT MATTERS
During the 1980s, the Company resolved a number of claims made by suppliers
under gas purchase contracts through various forms of settlement, including
buy-out/buy-downs and payments for gas in advance of its delivery and, in the
third quarter of 1989, recorded a pre-tax "Special Charge" of $269 million
related to these claims. The remaining prepayments for gas made in conjunction
with these settlements are carried at their estimated net realizable 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. While the Company has settled the vast majority of such claims, the
Company is committed to make additional payments under certain settlements,
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
to the Company's results of operations, financial position or cash flows.
In addition to the prepayments for gas discussed above, 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 prevailing market prices at
the time such transactions are consummated or require it to deliver gas at a
point other than the expected receipt point for the volumes to be purchased.
The Company operates an ongoing risk management program designed to remove or
limit the Company's market risk from its obligations under these gas
purchase/sale commitments, see "Credit Risk and Off-Balance-Sheet Risk"
elsewhere herein. 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.
Effective as of December 31, 1993, the Company completed a
comprehensive settlement agreement with certain subsidiaries of Samson
Investment Company, see "Natural Gas Pipeline" under "Material Changes in the
Results of Operations" elsewhere herein.
SALE OF PIPELINE FACILITIES
The Company has an agreement ("the Agreement") with ANR Pipeline Company
("ANR") which contemplates the transfer to ANR of an ownership interest in 250
MMcf/day of capacity in the Company's Line AC and certain related transmission
facilities in exchange for approximately $90 million in cash. In conjunction
with the Agreement, the Company had received (and recorded as a liability) $125
million in cash, $34 million of which was refunded in December 1993 due to
changes in the Agreement, primarily related to the deletion of certain
gathering facilities from the transaction. The Agreement is subject to
acceptable approvals by the Federal Trade Commission and by the FERC which have
issued orders approving the transaction. The FERC's order, however, contained
conditions unacceptable to the parties and each party has filed a notice of
appeal of the order with the D.C. Circuit Court of Appeals.
Should the transaction not be completed as a sale, the Agreement
requires that the parties operate under separate agreements ("the Backup
Agreements") pursuant to which the Company would instead provide transportation
services generally to ANR until 2005. The Backup Agreements currently provide
initially for the transportation of 250,000 MMBtu/day, which level would
decrease to 130,000 MMBtu/day on June 1, 1995, with a refund to ANR by the
Company of $50 million from the amounts previously received. The level of
transportation services provided pursuant to the Backup Agreements would
further decrease to 100,000 MMBtu/day on April 1, 2003, with an additional
refund to ANR of $5 million, and the Backup Agreements will terminate on June
1, 2005, with a refund of the remaining balance. The Company's consideration
for such transportation services would be provided by the interest-free use of
the previously-advanced money until its return to ANR. The Company expects
that, if the sale is not completed, the required refunds will be funded by
internally generated cash and/or incremental borrowings.
ENVIRONMENTAL MATTERS
From the late 1800s to 1960, Minnegasco (acquired by the Company in November
1990) 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 is
working with the Minnesota Pollution Control Agency to implement an appropriate
response action. At this time, however, the specific method and extent of
required remediation are not known.
There are six other former manufactured gas plant ("MGP") sites in
Minnesota in the service territory in which Minnegasco operated at December 31,
1994. 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.
In addition, there are seven former MGP sites in Nebraska and two in South
Dakota in the service territory in which Minnegasco operated at December 31,
1992. As a part of the sale of the Nebraska operations, the buyer has assumed
liability for five Nebraska sites. Minnegasco had previously disposed of the
other two Nebraska sites. The South Dakota sites were not operated by
Minnegasco or its predecessors. Minnegasco believes it is not liable for
<PAGE> 19
51
remediation of the Nebraska and South Dakota sites.
At December 31, 1994 and 1993, Minnegasco had recorded a deferred
charge of $0.8 million and $1.3 million, respectively, related to the
Minneapolis Site and has estimated a range of $40 million to $129 million for
the 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 Minnegasco, assuming Minnegasco's proposed remediation methods. The
upper estimate of the range was determined using the Minnesota sites once owned
by Minnegasco, whether or not operated by Minnegasco, and using alternative,
more costly remediation methods. The cost estimates for the Minneapolis Site
are based on studies made of that site. The remediation cost for other sites is
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 by other potentially responsible parties, if any, and the
remediation methods used.
At December 31, 1994 and 1993, the Company had recorded a liability of
$43.8 million and $26.8 million, respectively, to cover the probable costs of
remediation. In connection with its 1992 rate case, Minnegasco was allowed to
recover through rates over five years, without carrying costs, the deferred
costs at December 31, 1992, and was allowed $3.1 million annually to cover
on-going clean-up costs. In its 1993 rate case, Minnegasco was allowed $2.1
million annually to recover amortization of previously deferred costs and
ongoing clean-up costs. Any amounts in excess of $2.1 million in any individual
year are to be deferred for future recovery. The Company currently expects that
any cash expenditures for these costs in excess of the amount recovered in
rates during any year will not be material to the Company's overall cash
requirements. In accordance with SFAS 71, a regulatory asset has been recorded
equal to the amount accrued. The Company is pursuing recovery of costs from its
insurers and other potentially responsible parties.
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.
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 still subject to SFAS 71, corresponding regulatory assets
are set up in anticipation of recovery through the ratemaking process. At
December 31, 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 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 its results of operations, financial position or cash flows.
ACCOUNTING CHANGES
POSTRETIREMENT BENEFITS ("SFAS 106")
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 have been
expensed by the Company on a pay-as-you-go basis, SFAS 106 requires accrual of
such benefits during years of service in which they are earned, see Note 6 of
Notes to Consolidated Financial Statements.
POSTEMPLOYMENT BENEFITS ("SFAS 112")
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
<PAGE> 20
52
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 under the caption "Cumulative effect of change in
accounting principle".
CERTAIN INVESTMENTS IN
DEBT AND EQUITY SECURITIES ("SFAS 115")
In 1994, the Company adopted Statement of Financial Accounting Standards No.
115, "Accounting for Investments in Certain Debt and Equity Securities", which
requires that investments in debt and equity securities be classified as "held
to maturity", "available for sale" or "trading", with mark to market accounting
required for securities not in the held to maturity category. The Company's
only significant such investment is its common stock interest in Itron, see
"Radio Communications" under "Discontinued Operations" elsewhere herein.
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
-------------------------------------------------------------
Year Ended December 31,
1994 1993 1992 1991 1990
-------------------------------------------------------------
<S> <C> <C> <C> <C>
1.47 1.47 1.10 1.19 1.97
-------------------------------------------------------------
</TABLE>
DEBT RETIREMENT SCHEDULE
The debt retirement schedule at December 31, 1994 is as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
(millions of dollars)
1995 1996 1997 1998 1999 Beyond 1999
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$164.6 $118.8 $427.0 $76.0 $210.6 $582.0
--------------------------------------------------------------------------------
</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, 1994, there were 37,180 common
stockholders of record. Following is selected data concerning the Company's
common stock price and cash dividends paid:
<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
1993 Stock Price Per Share
----------------------------------------------------------------------------
Quarter High Low Common Preferred
----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1st $ 9 $ 7 3/8 $ 0.07 $ 0.75
2nd $ 10 5/8 $ 8 3/4 $ 0.07 $ 0.75
3rd $ 10 1/8 $ 8 1/8 $ 0.07 $ 0.75
4th $ 8 7/8 $ 7 3/8 $ 0.07 $ 0.75
----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
----------------------------------------------------------------------------
Common Cash Dividends
Stock Price Per Share
----------------------------------------------------------------------------
High Low Common Preferred
----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1992 $ 12 3/8 $ 6 7/8 $ 0.48 $ 3.00
1991 $ 20 1/4 $ 9 3/4 $ 1.08 $ 3.00
1990 $ 27 1/4 $ 18 5/8 $ 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.
<PAGE> 21
53
STATEMENT OF CONSOLIDATED INCOME NORAM ENERGY CORP. AND SUBSIDIARIES
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(thousands of dollars, except per share amounts) Year Ended December 31,
1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Revenues
Natural gas sales $2,578,595 $ 2,759,718 $ 2,517,954
Gas transportation 172,859 108,424 119,518
Chemical and petroleum products 4,627 41,220 79,717
Other 45,365 40,203 26,640
------------------------------------------------------------------------------------------
2,801,446 2,949,565 2,743,829
------------------------------------------------------------------------------------------
Operating Expenses
Cost of natural gas purchased, net 1,767,708 1,900,852 1,758,419
Operation, maintenance, cost of sales
and other 514,900 551,894 545,272
Depreciation and amortization 152,009 150,955 150,741
Taxes other than income taxes 100,783 104,636 100,773
Contract termination charge (Note 12) -- 34,230 --
------------------------------------------------------------------------------------------
2,535,400 2,742,567 2,555,205
------------------------------------------------------------------------------------------
Operating Income 266,046 206,998 188,624
------------------------------------------------------------------------------------------
Other (Income) and Deductions
Interest expense 170,696 173,278 186,903
Allowance for borrowed funds used
during construction (1,331) (871) (1,675)
Other, net 11,018 (51,825) (15,347)
------------------------------------------------------------------------------------------
180,383 120,582 169,881
------------------------------------------------------------------------------------------
Income From Continuing Operations Before
Income Taxes 85,663 86,416 18,743
Provision for Income Taxes 34,372 46,481 12,516
------------------------------------------------------------------------------------------
Income from Continuing Operations 51,291 39,935 6,227
Loss from discontinued operations,
less taxes (Note 9) (2,102) -- (34,797)
------------------------------------------------------------------------------------------
Income (Loss) Before Extraordinary Items
and Cumulative Effect of Change in
Accounting Principle 49,189 39,935 (28,570)
Extraordinary items, less taxes
(Notes 3 and 13) (1,123) (3,848) (195,003)
------------------------------------------------------------------------------------------
Income (Loss) Before Cumulative
Effect of Change in Accounting Principle 48,066 36,087 (223,573)
Cumulative effect of change in
accounting principle (Note 6) -- -- (4,920)
------------------------------------------------------------------------------------------
Net Income (Loss) 48,066 36,087 (228,493)
Preferred dividend requirement 7,800 7,800 7,800
------------------------------------------------------------------------------------------
Earnings (Loss) Available to Common Stock $ 40,266 $ 28,287 $ (236,293)
==========================================================================================
Earnings (Loss) Per Common Share
Continuing operations (1) $ 0.36 $ 0.26 $ (0.01)
Discontinued operations, less taxes (0.02) -- (0.29)
Extraordinary items, less taxes (0.01) (0.03) (1.60)
Cumulative effect of change in
accounting principle -- -- (0.04)
------------------------------------------------------------------------------------------
Earnings (Loss) Per Common Share $ 0.33 $ 0.23 $ (1.94)
==========================================================================================
Weighted average common shares
outstanding (in thousands) 122,424 122,305 121,820
------------------------------------------------------------------------------------------
</TABLE>
(1) Earnings (loss) 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.
<PAGE> 22
54
CONSOLIDATED BALANCE SHEET NORAM ENERGY CORP. AND SUBSIDIARIES
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Property, Plant and Equipment $ 3,710,348 $ 3,593,861
Less: Accumulated depreciation and amortization 1,424,204 1,327,725
------------------------------------------------------------------------------------------
2,286,144 2,266,136
Investments and Other Assets 792,254 856,552
Current Assets
Cash and cash equivalents 17,632 14,910
Accounts and notes receivable,
principally customer 213,346 314,487
Deferred income taxes 10,287 12,976
Inventories 112,094 153,815
Deferred gas costs (6,812) (9,390)
Gas purchased in advance of delivery 26,571 35,998
Other current assets 36,157 25,548
------------------------------------------------------------------------------------------
409,275 548,344
------------------------------------------------------------------------------------------
Deferred Charges 73,825 56,756
------------------------------------------------------------------------------------------
Total Assets $ 3,561,498 $ 3,727,788
=========================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Stockholders' Equity
Preferred stock $ 130,000 $ 130,000
Common stock ($.625 par) authorized 150,000,000;
122,530,248 and 122,361,578 shares issued and
outstanding at December 31, 1994 and 1993,
respectively 76,581 76,476
Paid-in capital 868,289 867,641
Accumulated deficit (360,079) (366,080)
Unrealized gain on Itron investment, net of
tax (Note 9) 2,586 --
------------------------------------------------------------------------------------------
Total stockholders' equity 717,377 708,037
------------------------------------------------------------------------------------------
Long-term Debt, Less Current Maturities 1,414,374 1,629,364
Current Liabilities
Current maturities of long-term debt 151,000 77,000
Notes payable to banks 110,000 95,000
Other notes payable 13,600 20,400
Gas accounts payable 215,221 267,279
Other accounts payable 186,720 190,042
Income taxes payable 4,690 12,912
Interest payable 42,180 44,677
General taxes 45,717 50,111
Customers' deposits 55,729 46,921
Other current liabilities 71,266 98,881
------------------------------------------------------------------------------------------
896,123 903,223
------------------------------------------------------------------------------------------
Other Liabilities and Deferred Credits
Accumulated deferred income taxes 257,839 225,243
Other deferred credits and non-current
liabilities 275,785 261,921
------------------------------------------------------------------------------------------
533,624 487,164
------------------------------------------------------------------------------------------
Commitments and Contingencies (Note 11)
------------------------------------------------------------------------------------------
Total Liabilities and Stockholders' Equity $ 3,561,498 $ 3,727,788
=========================================================================================
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement
<PAGE> 23
55
NORAM ENERGY CORP. AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993 1992
------------------------------------------------------------------------------------------------------------------------------
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
150,000,000 shares
Balance at beginning of year 122,361,578 76,476 122,258,367 76,411 116,488,089 72,805
Issuance of stock to reacquire
E&P minority interest
(Note 9) -- -- -- -- 5,699,967 3,562
Issuance of stock in
Hunter acquisition (Note 10) -- -- 125,000 78 -- --
Other issuance (reduction) 168,670 105 (21,789) (13) 70,311 44
------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 122,530,248 76,581 122,361,578 76,476 122,258,367 76,411
------------------------------------------------------------------------------------------------------------------------------
Paid-In Capital
Balance at beginning of year 867,641 866,635 810,351
Issuance of stock to reacquire
E&P minority interest
(Note 9) -- -- 56,203
Issuance of stock in
Hunter acquisition (Note 10) -- 1,156 --
Other issuance (reduction) 648 (150) 81
------------------------------------------------------------------------------------------------------------------------------
Balance at end of year 868,289 867,641 866,635
------------------------------------------------------------------------------------------------------------------------------
Retained Deficit
Balance at beginning of year (366,080) (360,121) (65,132)
Net income (loss) 48,066 36,087 (228,493)
Cash dividends
Preferred stock - $3.00 per share (7,800) (7,800) (7,800)
Common stock - $0.28 per share in
1994, $0.28 per share in 1993 and
$0.48 per share in 1992 (34,265) (34,246) (58,696)
------------------------------------------------------------------------------------------------------------------------------
Balance at end of year (360,079) (366,080) (360,121)
------------------------------------------------------------------------------------------------------------------------------
Unrealized gain on Itron investment,
net of tax (Note 9) 2,586 -- --
------------------------------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $ 717,377 $ 708,037 $ 712,925
==============================================================================================================================
</TABLE>
(1) The Series A preferred stock is convertible into common stock in the
ratio of approximately 1.7467 shares of common stock for each share
of Series A preferred stock, 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 Notes to Consolidated Financial Statements are an integral part of this
statement.
<PAGE> 24
56
STATEMENT OF CONSOLIDATED CASH FLOWS NORAM ENERGY CORP. AND SUBSIDIARIES
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 48,066 $ 36,087 $ (228,493)
Adjustments to reconcile net income (loss)
to cash provided by operating activities:
Depreciation and amortization 152,009 150,955 150,741
Deferred income taxes 32,855 29,692 85,920
Contract termination charge (Note 12) -- 34,230 --
Gains from sales of property -- (41,619) --
Discontinued operations, less taxes 2,102 -- 34,797
Extraordinary items, less taxes
(Notes 3 and 13) 1,123 3,848 195,003
Cumulative effect of change in accounting
principle (Note 6) -- -- 4,920
Utilization of tax loss carryforwards (6) (11,787) (23,316)
Other (3,065) (22,013) (9,408)
Changes in certain assets and liabilities,
net of non-cash transactions and the
effects of acquisitions and
dispositions (Note 1) 71,830 (6,830) (103,111)
------------------------------------------------------------------------------------------
Net cash provided by operating activities 304,914 172,563 107,053
------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (170,371) (146,195) (134,890)
Sale of distribution properties 23,172 93,090 --
Exchange of distribution properties -- (38,000) --
Sale of LIG, net of related expenditures -- 169,950 --
Cash proceeds from sale of E&P -- -- 389,957
Proceeds from sale and leaseback of assets -- -- 53,175
Cash proceeds from sale of E. F. Johnson
and Arkla Products -- -- 21,220
Net investing activities of discontinued
operations -- -- 64,322
Other asset sales 12,315 -- --
Sale of Itron stock 7,204 -- --
Other, net 3,138 (25,804) (31,012)
------------------------------------------------------------------------------------------
Net cash provided by (used in)
investing activities (124,542) 53,041 362,772
------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of 9 7/8% notes due 1997 -- -- 225,000
Issuance of 8 7/8% notes due 1999 -- -- 200,000
Common and preferred stock dividends (42,065) (42,046) (66,496)
Retirements and reacquisitions of
long-term debt (148,913) (212,188) (192,689)
Other interim borrowings (repayments) 15,000 95,000 (648,677)
Return of advances received under
contingent sales agreements -- (34,000) (20,000)
Increase (decrease) in overdrafts (1,672) (43,685) 21,483
------------------------------------------------------------------------------------------
Net cash used in financing activities (177,650) (236,919) (481,379)
------------------------------------------------------------------------------------------
Net increase (decrease) in cash and
cash equivalents 2,722 (11,315) (11,554)
------------------------------------------------------------------------------------------
Cash and cash equivalents - beginning of year 14,910 26,225 37,779
------------------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 17,632 $ 14,910 $ 26,225
==========================================================================================
</TABLE>
For supplemental cash flow information, see Note 1.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
<PAGE> 25
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1 ACCOUNTING POLICIES AND COMPONENTS OF
CERTAIN FINANCIAL STATEMENT LINE ITEMS
NAME CHANGE
The Company changed its name from Arkla, Inc. to NorAm Energy Corp. ("NorAm"),
in May 1994 pursuant to a vote of the Company's stockholders. Certain of the
Company's subsidiaries made corresponding name changes. As used herein, "the
Company" refers to NorAm and its subsidiaries.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of NorAm and its
subsidiaries, all of which are wholly owned. All significant affiliated
transactions and balances for the Company's continuing businesses have been
eliminated.
In December 1992, the Company completed the sale of Arkla Exploration
Company to Seagull Energy Corporation, terminating the Company's activities in
the oil and gas exploration and production business, see Note 9. In June 1993,
the Company completed the sale of its intrastate pipeline business as conducted
by Louisiana Intrastate Gas Corporation and Subsidiaries ("LIG") to a
subsidiary of Equitable Resources, Inc., see Note 10. In recent years, the
Company has engaged in several transactions with respect to its distribution
properties, see Note 10.
In the accompanying consolidated financial statements, certain prior
year amounts have been reclassified to conform to current presentation.
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.
SEGMENT INFORMATION
The Company operates predominantly in a single segment, the natural gas
segment, which accounts for in excess of 90% of the Company's total revenues,
income or loss and identifiable assets.
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 nonregulated 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 its NorAm Gas
Transmission Company interstate pipeline subsidiary ("NGT", formerly Arkla
Energy Resources) effective with year-end 1992 reporting, see Note 13.
As a result of applying SFAS 71 to Mississippi River Transmission
Corporation ("MRT") and NorAm's distribution divisions, the Company's financial
statements contain certain assets and liabilities which would not be recognized
by non-regulated entities. In addition to regulatory assets related to
accounting for postretirement benefits other than pensions (see Note 6), the
Company's only other significant regulatory asset is related to anticipated
environmental remediation costs, see Note 11.
CHANGES IN ACCOUNTING POLICIES
The Company changed its method of accounting for postemployment benefits,
postretirement benefits and investments in debt and equity securities effective
as of January 1, 1992, 1993 and 1994, respectively, see Notes 6 and 9.
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. In early 1992, the Company reacquired the
publicly-held minority ownership of Arkla Exploration Company through the
issuance of the Company's common stock. The Company's 1993 exchange of its
South Dakota distribution properties for certain other distribution properties
in Minnesota and its 1992 sale of E. F. Johnson included both cash and non-cash
components. In February 1992, the Company exchanged its investment in EnScan
for an equity investment in Itron, Inc. in a non-cash transaction. 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. For additional information on these matters, see Notes 9, 10 and 12.
The caption "Changes in certain asset and liabilities, net of noncash
transactions and the effects of acquisitions and dispositions" as
<PAGE> 26
58
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,
1994 1993 1992
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Accounts and notes
receivable $101,141 $(55,273) $ (42,685)
Inventories 42,626 (49,300) 16,419
Deferred gas costs (78) 31,549 (810)
Other current assets (7,637) 41,730 (5,580)
Gas accounts payable (52,058) 26,382 5,553
Other accounts payable (1,650) (34,069) 9,139
Income taxes payable (8,216) (768) (38,556)
Interest payable (2,497) (5,688) 6,619
General taxes (4,394) 4,625 3,122
Customers' deposits 8,808 2,615 (1,397)
Other current liabilities (25,515) 12,567 (39,235)
Recovery under
(settlement of)
gas contract disputes 21,300 18,800 (15,700)
------------------------------------------------------------------------------------------------------------
$ 71,830 $ (6,830) $(103,111)
============================================================================================================
</TABLE>
SUPPLEMENTAL CASH FLOW INFORMATION
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993 1992
---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash interest payments,
net of capitalized
interest $ 162,743 $ 174,964 $ 188,303
---------------------------------------------------------------------------------------------------------------
Cash income tax
payments (refunds), net $ 6,477 $ 22,494 $ (16,962)
---------------------------------------------------------------------------------------------------------------
</TABLE>
PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
(millions of dollars) December 31, Depreciation
1994 1993 Range
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas distribution $ 1,930.9 $ 1,850.6 0.7%-20.0%
Natural gas pipeline 1,730.8 1,703.9 1.4%-10.0%
Other 48.6 39.4 5.0%-20.0%
------------------------------------------------------------------------------------------------------------
$ 3,710.3 $ 3,593.9
============================================================================================================
</TABLE>
Property, plant and equipment, in general, is carried at cost and
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. Pipeline property,
plant and equipment held for sale has been reclassified to "Investments and
Other Assets" as shown following.
INVESTMENTS AND OTHER ASSETS
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
------------------------------------------------------------------------------
<S> <C> <C>
Goodwill, net $ 495,311 $ 509,498
Pipeline assets held for
sale 91,000 91,000
Gas purchased in advance
of delivery 43,547 79,667
Notes receivable 6,066 8,659
Other 156,330 167,728
------------------------------------------------------------------------------
$ 792,254 $ 856,552
==============================================================================
</TABLE>
"Pipeline assets held for sale" are assets subject to a sale of
interests agreement, see Note 14. 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, $14.8 million and $15.4 million of
goodwill was amortized during 1994, 1993 and 1992, respectively. Accumulated
amortization of goodwill was $75.0 million and $60.8 million at December 31,
1994 and 1993, 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.
INVENTORIES
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
--------------------------------------------------------------------------------------------
<S> <C> <C>
Gas in underground storage $ 73,755 $ 116,665
Materials and supplies 38,156 36,757
Other 183 393
--------------------------------------------------------------------------------------------
$ 112,094 $ 153,815
============================================================================================
</TABLE>
Inventories principally follow the average cost method and all
non-utility inventories held for resale are valued at the lower of cost or
market. Gas in underground storage at December 31, 1993, includes approximately
$51.2 million of gas attributable to the operations of MRT. This gas was sold
to MRT's customers during early 1994 and was replaced with customer-owned gas
in accordance with the provisions of Federal Energy Regulatory Commission
("FERC") Order 636, with MRT retaining only the quantity of gas necessary for
system operational purposes.
ALLOWANCE FOR DOUBTFUL ACCOUNTS
"Accounts and notes receivable, principally customer" as presented on the
accompanying Consolidated Balance Sheet are net of an allowance for doubtful
accounts of $11.4 million and $11.3 million at December 31, 1994 and 1993,
respectively.
<PAGE> 27
59
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 and, where applicable, has
been reduced for interest expense allocated to discontinued operations, see
Notes 3 and 9.
OTHER, NET - STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
(Income) Expense 1994 1993 1992
-----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Interest income $ (3,948) $ (11,613) $ (10,905)
Sales of property:
Nebraska distribution
properties - (23,900) -
LIG - (17,719) -
Other 631 (1,141) (203)
Loss on sale of
accounts receivable 7,139 8,132 10,063
Gain on termination
of partnership - - (4,139)
Appliance repair service 246 (1,109) (4,333)
Income from equity
basis investment - - (3,454)
Miscellaneous 6,950 (4,475) (2,376)
-----------------------------------------------------------------------------------------
$ 11,018 $ (51,825) $ (15,347)
=========================================================================================
</TABLE>
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 were approximately $54.1 million and $55.7 million
at December 31, 1994 and 1993, respectively.
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.
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 and sell natural gas, some of
which carry off-balance-sheet risk, see Note 11. 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 cost of natural gas
purchased as the physical production is purchased or sold under the related
contracts.
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" in the accompanying Statement
of Consolidated Income includes the following:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
Expense (Benefit) 1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal
Current $ 41 $ 15,773 $ (64,658)
Deferred 38,965 26,332 73,229
Investment Tax Credit (641) (2,023) (804)
State
Current 2,117 3,039 (7,942)
Deferred (6,110) 3,360 12,691
------------------------------------------------------------------------------------------
$ 34,372 $ 46,481 $ 12,516
==========================================================================================
</TABLE>
The provision for income taxes differs from the amount computed by
applying the statutory federal income tax rate to income from continuing
operations. The reasons for this difference are as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993 1992
------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory federal
income tax rate 35% 35% 34%
------------------------------------------------------------------------------------------
Computed "expected"
federal income tax $ 29,982 $ 30,246 $ 6,373
Increase (decrease) in tax
resulting from:
State income taxes, net of
federal income tax benefit (2,596) 4,159 3,134
Investment tax credit (641) (2,023) (804)
Stock basis difference in
sale of subsidiary - 8,093 -
Research and
experimentation credit (1,500) - -
Adjustments to prior
year accruals 1,492 4,299 -
Goodwill amortization 4,167 4,449 4,497
Effect of 1% increase in
statutory federal
income tax rate - (2,267) -
Other, net 3,468 (475) (684)
------------------------------------------------------------------------------------------
Provision for income taxes $ 34,372 $ 46,481 $ 12,516
==========================================================================================
</TABLE>
<PAGE> 28
60
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 1994 and
1993, were as follows:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
----------------------------------------------------------------------------
<S> <C> <C>
DEFERRED TAX ASSETS
Employee benefit accruals $ 24,813 $ 22,087
Inventory revaluation and capitalization 1,316 6,691
Gas purchase contract accruals 2,288 77,158
Regulatory obligations 17,417 26,156
Indemnifications and other reserves 30,314 30,186
Deferred state income taxes 9,373 11,494
Miscellaneous 30,850 26,260
Operating and capital loss carryforwards 61,882 29,421
Alternative minimum tax and general
business credit carryforwards 60,378 57,524
Valuation allowance (5,974) (10,023)
----------------------------------------------------------------------------
Total deferred tax assets 232,657 276,954
----------------------------------------------------------------------------
DEFERRED TAX LIABILITIES
Property, plant and equipment,
principally due to depreciation
methods and lives 443,475 441,647
Deferred gas costs 2,780 16,059
Employee benefit accruals 10,618 12,781
Miscellaneous 23,336 18,734
----------------------------------------------------------------------------
Total deferred tax liabilities 480,209 489,221
----------------------------------------------------------------------------
Net deferred tax liabilities $ 247,552 $ 212,267
============================================================================
</TABLE>
The change in the total valuation allowance for the year ended
December 31, 1994 was a net decrease of approximately $4 million. Contributing
to this change were decreases of approximately $6 million related to revised
estimates of state net operating loss carryforwards expected to be realized and
$0.2 million due to the expiration of state net operating losses, for which a
valuation allowance had been provided. Partially offsetting these decreases to
the valuation allowance were increases principally resulting from $1.6 million
of net operating losses in states that have a capital based tax for which
realization is not anticipated.
At December 31, 1994, the Company had approximately $537.5 million of
state net operating losses available to offset future state taxable income
through the year 2009, and approximately $64.8 million of federal net operating
losses, of which $46.9 million can be carried back to prior years generating
additional alternative minimum tax credits, and the remaining $17.9 million is
available to offset future federal taxable income through the year 2009. The
Company had $21.4 million of alternative minimum tax net operating losses
available to be carried back to prior years, generating refunds of
approximately $4 million. The Company had $2.1 million of charitable
contribution carryover to be utilized through the year 1999. The Company also
had $0.9 million of charitable contributions that are available to be utilized
pending the outcome of federal audits for the years 1989 through 1991, which
contributions cannot be utilized beyond 1991. In addition, at December 31,
1994, the Company had approximately $6.4 million of general business credit
carryforwards that expire between 1998-2009, and approximately $54 million of
alternative minimum tax credits (before carryback of the amounts discussed
preceding) 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 debt of the Company is as follows:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
---------------------------------------------------------------------------------
<S> <C> <C>
LONG-TERM, INCLUDING CURRENT MATURITIES
Medium-term notes, Series A
and B due through 2001 $ 413,375 $ 500,375
9.45% Series due 1995 150,000 150,000
8% Series due 1997 150,000 150,000
9.875% Series due 1997 225,000 225,000
8.875% Series due 1999 200,000 200,000
8.90% Series due 2006 145,070 147,000
9.875% Series due 2018 122,155 134,385
10% Series due 2019 159,170 185,400
Note payable to gas supplier 13,600 34,000
Other 604 604
---------------------------------------------------------------------------------
$1,578,974 $ 1,726,764
==================================================================================
SHORT-TERM
Current maturities of long-term debt $ 151,000 $ 77,000
Notes payable to banks 110,000 95,000
Note payable to gas supplier 13,600 20,400
---------------------------------------------------------------------------------
$ 274,600 $ 192,400
=================================================================================
</TABLE>
The aggregate amount of long-term debt maturities for each of the five years
following December 31, 1994 is: 1995 - $164.6 million; 1996 - $118.8 million;
1997 - $427.0 million; 1998 - $76.0 million; 1999 - $210.6 million.
As a part of its ongoing program to reduce its overall cost of debt,
the Company reacquired approximately $50.4 million and $88.3 million principal
amount of its long-term debt during 1994 and 1993, respectively. The weighted
average interest rate was approximately
<PAGE> 29
61
9.8% for the debt retired during 1994 and 1993 and this debt was reacquired for
total pre-tax net premiums of approximately $1.4 million and $5.5 million
(approximately $1.1 million and $3.8 million after-tax) for 1994 and 1993,
respectively, reported in the accompanying Statement of Consolidated Income
under the caption, "Extraordinary items, less taxes".
Prior to November 1994, the Company had a revolving credit facility
(the "Previous Facility") which made a total commitment of $400 million
available to the Company through June 30, 1995. Effective November 2, 1994, the
Company executed a new Credit Agreement (the "New Facility") with Citibank,
N.A., as Agent, and a group of sixteen other commercial banks which provides a
$400 million commitment to the Company through October 31, 1997. The terms and
conditions of the New Facility are similar to the Previous Facility with one
significant exception. Although the New Facility continues to be collateralized
by the stock of MRT and NGT, if the Company is rated investment-grade by both
Moody's Investor Service, Inc. and Standard & Poor's Corporation, this
collateral would be released. The New Facility imposes certain restrictions on
the Company, see Note 5.
As with the Previous Facility, borrowings under the New Facility will
bear interest at various Eurodollar and domestic rates, at the option of the
Company, which rates are 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 .30%, and subject to decrease
based on the Company's debt rating, and will pay an incremental rate of 1/8% on
outstanding borrowings in excess of $200 million. Both of these fees reflect
declines from the fees under the Previous Facility.
During 1994, borrowings under the Company's short-term credit
facilities, in the aggregate, averaged $55.9 million with a weighted average
interest rate of 5.85% and the maximum outstanding at any point in the year was
$170 million. Borrowings under the New Facility were $110.0 million and $35.0
million at December 31, 1994 and March 1, 1995, respectively, and, at March 1,
1995, the Company had borrowings of $15.0 million under informal lines of
credit. Borrowings under the Company's short-term credit facilities carried
weighted average interest rates of 7.04% and 4.65% at December 31, 1994 and
1993, respectively.
Under a March 1994 agreement (the "Agreement") which expires in August
1995, the Company sells an undivided interest (limited to a maximum of $235
million) in a designated pool of accounts receivable with limited recourse. 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.
Total receivables sold under the Agreement but not yet collected were
approximately $192.8 million and $226.4 million at December 31, 1994 and 1993,
respectively, which amounts have been deducted from "Accounts and notes
receivable, principally customer" in the accompanying Consolidated Balance
Sheet. At December 31, 1994, $48.7 million of the Company's remaining
receivables were collateral for receivables which had been sold. During 1994,
1993 and 1992, the Company experienced cash outflows(inflows) of $33.6 million,
$(13.8) million and $6.0 million, respectively, under the program. In
accordance with authoritative accounting guidelines, cash flows related to
these sales of accounts receivable are included in the accompanying Statement
of Consolidated Cash Flows under the category "Cash flows from operating
activities".
The Company has entered into a number of transactions generally
described as "interest rate swaps". The terms of these arrangements vary but,
in general, specify that the Company will pay an amount of interest on the
notional amount of the swap which varies with LIBOR while the other party (a
commercial bank) pays a fixed rate. The Company had no swaps in effect at
December 31, 1992 and, during 1993, the Company entered into a total of $575
million notional amount of swaps, of which $200 million remained at December
31, 1993. During 1994, the Company entered into an additional $75 million
notional amount of swaps. At December 31, 1994, $275 million notional amount of
these swaps were outstanding, terminating at various dates through February
1997. None of these swaps are "leveraged" and, therefore, they do not represent
exposure in excess of that suggested by the notional amount and reported
interest rates. At December 31, 1994, the Company's obligation under these
arrangements, which is calculated using 6-12 month floating LIBOR, was based on
a weighted average interest rate of approximately 6.7%, while the
counterparties' obligations were based on a weighted average fixed rate of
approximately 5.1%. The Company's performance under these swaps is
collateralized by the stock of MRT and NGT, and the Company is permitted to
increase the amount outstanding under such collateralized arrangements to a
total of $350 million, a limitation imposed by the terms of the New Facility.
In accordance with authoritative accounting guidelines, the economic
value which transfers between the parties to these swaps is treated as an
adjustment to the effective interest rate on the Company's underlying debt
securities. When positions are closed prior to the expiration of the stated
term, any gain or loss on termination is amortized over the remaining period in
the original term of the swap. The effect of these swaps was to increase the
Company's interest expense by $0.5 million for 1994 and to decrease the
Company's interest expense by $4.6 million for 1993. The deferred gain
associated with interest rate swaps terminated prior to their expiration was
approximately $2.5
<PAGE> 30
62
million at December 31, 1994. This gain is expected to be amortized as follows:
1995 - $1.7 million; 1996 - $0.7 million; all remaining periods - $0.1 million.
At December 31, 1994, the unrealized loss (mark-to-market value) associated
with outstanding swap arrangements was approximately $18.0 million, which
unrealized loss had declined to $10.3 million at March 1, 1995.
Off-balance-sheet credit risk exists to the extent of the possibility
that the counterparties to these swaps might fail to perform. The Company has
limited these transactions to arrangements with commercial banks that 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 counterparty to these swaps is minimal.
In July 1994, the Company entered into an equipment funding agreement
with an affiliate of a major bank to provide up to $50 million to be used to
purchase new vehicles, major work equipment and a small amount of computer and
other office equipment over a three-year period. For accounting purposes, these
assets will be subject to operating lease treatment, with an initial
non-cancellable term of one year.
In July 1994, the Company amended its previously-filed registration
statement to convert it to a Rule 415 or "shelf" offering (the "Shelf"). The
Shelf will allow the Company to issue up to 14.95 million shares of additional
common stock for a period of up to two years from the effective date. The net
proceeds from shares issued pursuant to the Shelf are expected to be used for
general corporate purposes.
In late 1994, the Company instituted a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP/DRIP") which offers its customers and
other interested parties an 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. The purpose of the DSPP/DRIP is to provide new investors with a
convenient means to make an initial investment in the Common Stock and to
provide existing holders of the Common Stock with (1) a means to have their
dividends automatically reinvested in shares of the Common Stock and (2) a
convenient and economical way to purchase additional shares. While individual
purchases under the plan are generally small, the Company believes that, over
time, a significant amount of additional equity capital may be raised through
this program.
During 1992, the Company returned $20 million which had
been advanced in conjunction with a proposed transaction related to
capacity in Line AC, which transaction was not consummated.
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.
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
(millions of dollars) December 31,
1994 1993
------------------------------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
FINANCIAL ASSETS
Investment in
Itron (1) $ 32.1 $ 32.1 $ 35.4 $ 35.2
Oil production
payment (1) $ 1.9 $ 2.6 $ 6.7 $ 9.0
Natural gas
options (2) $ 2.2 - $ 2.2 -
FINANCIAL LIABILITIES
Long-term debt (3) $ 1,579.0 $ 1,548.3 $1,726.8 $ 1,851.3
Interest rate swaps (3) - $ 18.0 - $ 2.6
Natural gas swaps (2) - $ 16.7 - $ 6.6
Natural gas futures (2) - $ 2.9 - -
------------------------------------------------------------------------------------------------------------
</TABLE>
(1) See Note 9.
(2) See Note 11.
(3) See Note 3.
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.
<PAGE> 31
63
5 RESTRICTIONS ON STOCKHOLDERS'
EQUITY AND DEBT
Under the provisions of the Company's revolving credit facility as described in
Note 3, 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 required
minimum level of stockholders' equity was initially set at $650 million at
December 31, 1993, increasing annually thereafter by (1) 50% of positive
consolidated net income and (2) 50% of the proceeds (in excess of the first $50
million) of any incremental equity offering made after June 30, 1994. The
Company's total debt is limited to $2,055 million. Based on these restrictions,
the Company had incremental debt issuance and dividend capacity of $321.2
million and $43.3 million, respectively, at December 31, 1994. The Company's
revolving credit facility also contains a provision which limits the Company's
ability to reacquire, retire or otherwise prepay its long-term debt prior to
its maturity to a total of $100 million.
6 EMPLOYEE BENEFIT PLANS
The Company and its subsidiaries have three qualified pension plans ("the
Qualified Plans") which cover substantially all employees; (1) the plan which
covers the Company's employees other than Entex hourly employees and Minnegasco
employees, (2) the plan which covers Minnegasco employees and (3) the plan
which covers Entex hourly 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 pension plan 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. Prior to 1993, these
plans were accounted for in the Company's financial records but were not
included in the pension disclosures which follow due to their relative
immateriality. Expense of approximately $2.3 million and $4.8 million
associated with these non-qualified plans was recorded during 1994 and 1993,
respectively.
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
Assets Exceed Accumulated Assets Exceed Accumulated
Accumulated Benefits Accumulated Benefits
Benefits Exceed Assets Benefits Exceed Assets
--------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net assets available for benefits $ 353,306 $ - $ 366,469 $ -
--------------------------------------------------------------------------------------------------------------
Actuarial present value of accumulated plan
benefits
Vested (assuming immediate separation) 244,339 16,274 274,151 12,630
Non-vested 24,423 377 28,896 175
--------------------------------------------------------------------------------------------------------------
Accumulated benefit obligation 268,762 16,651 303,047 12,805
Additional amount related to projected pay
increases 52,577 1,955 64,867 1,296
--------------------------------------------------------------------------------------------------------------
Total projected benefit obligation 321,339 18,606 367,914 14,101
--------------------------------------------------------------------------------------------------------------
Funded status 31,967 (18,606) (1,445) (14,101)
Unrecognized net obligation at January 1 (13,734) - (16,628) -
Unrecognized net loss from past experience
different from that assumed and
effects of changes in
actuarial assumptions 38,432 2,500 75,287 -
--------------------------------------------------------------------------------------------------------------
Pension prepaid asset (liability) $ 56,665 $ (16,106) $ 57,214 $ (14,101)
==============================================================================================================
</TABLE>
<PAGE> 32
64
The following weighted average rates were used in the above calculations, and
in 1992 which is not shown:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 8.5% 7.25% 9%
Assumed rate of increase in
future compensation 4% 4% 6%
Expected long-term rate of
return on fund assets 10% 11% 11%
-------------------------------------------------------------------------------------------------
</TABLE>
The components of periodic pension cost (Qualified Plans only) were as
follows:
<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993 1992
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits
earned during the period $ 11,757 $ 9,799 $ 9,178
Interest cost on projected
benefit obligation 25,633 26,376 25,408
Actual return on plan assets (3,067) (24,517) (14,092)
Amortization and deferral (33,774) (15,431) (27,450)
-------------------------------------------------------------------------------------------------
Net pension cost (credit) $ 549 $ (3,773) $ (6,956)
=================================================================================================
</TABLE>
The Company has an employee savings plan ("the ESP") which currently
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 $8.8 million, $5.2 million and $5.9 million were expensed during
1994, 1993 and 1992, 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 contributions during 1993 and 1992 of $3.5 million and $2.9 million,
respectively. The Minnegasco employees are covered by various thrift and profit
sharing plans, the terms of which vary from plan to plan. Expense of
approximately $1.3 million, $1.5 million and $1.6 million related to these
plans was recorded during 1994, 1993 and 1992, 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 currently
does not contribute to an external fund to provide for these benefits. 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. In early 1992, the Company changed its retiree medical
plan to a defined contribution plan for all employees who retire after June 30,
1992. 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
historically had been expensed by the Company as paid, SFAS 106 requires the
accrual and expensing of such benefits during the years of service in which
they are earned.
The Company's estimated obligation for postretirement benefits at
December 31, 1994 and 1993 was as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
(thousands of dollars) December 31,
1994 1993
------------------------------------------------------------------------------
<S> <C> <C>
Retirees $ 128,140 $ 149,047
Fully eligible plan participants 5,969 4,939
Other active plan participants 5,210 4,731
------------------------------------------------------------------------------
Accumulated postretirement
benefit obligation $ 139,319 $ 158,717
==============================================================================
</TABLE>
The weighted average discount rate used in determining the accumulated
benefit obligation was 8.5% for 1994 and 7.25% for 1993. 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 12 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, 1994 by approximately $0.8 million and $11.0 million,
respectively.
The periodic cost of these postretirement benefits, which was recorded
on an "as-paid" basis during 1992 was $9.3 million. The periodic cost of these
postretirement benefits (in accordance with the provisions of SFAS 106)
expensed during 1994 and 1993, including amortization of the transition
obligation on a straight-line basis over a 20-year period, was as follows:
<TABLE>
<CAPTION>
------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1993
------------------------------------------------------------------------------
<S> <C> <C>
Service cost $ 408 $ 247
Interest cost on accumulated
benefit obligation 10,436 11,670
Amortization of transition obligation 6,721 6,721
Amortization of prior service cost (87) -
------------------------------------------------------------------------------
Net periodic cost $ 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
<PAGE> 33
65
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, 1994, the Company had deferred
approximately $3.2 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 the
Company's common stock to employees and directors or provide for the sale of
the Company's common stock to these individuals, see Note 8.
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 is shown in the accompanying Statement of Consolidated Income for
1992 under the caption "Cumulative effect of change in accounting principle".
7 STOCK OPTION PLANS
In 1983, the Company adopted a Non-qualified Stock Option Plan (the "Plan")
with stock appreciation rights applicable to those eligible employees as
determined by the Board of Directors. The Plan included options to purchase
650,000 shares of the Company's common stock.
At December 31, 1994, 11,000 options at $21.25/share remained
outstanding under the Plan. No options were exercised in 1994, 1993 or 1992,
nor was any charge made to expense. However, 12,500 options at $20.25/share and
100,000 options at $21.25/share were forfeited by Plan participants during
1992. Options granted under the Plan terminate on August 12, 1997.
At December 31, 1994, under a former Diversified Energies, Inc. ("DEI")
plan, 78,500 options (which expire at various dates from 1995 to 1996) and
62,770 options (which expire during the year 2000) were outstanding at weighted
average exercise prices of $15.73/share and $16.56/share, respectively. No
options under these plans were exercised in 1994, 1993 or 1992. Options issued
on July 14, 1987 expired on July 13, 1994 and, as a result, 21,269 options were
forfeited.
8 STOCK ISSUANCE PLANS
In May 1994, the Company's stockholders approved the adoption of an Incentive
Equity Plan ("the IEP") to replace the Company's Long-Term Incentive Plan ("the
LTIP"). The IEP is similar to the LTIP in many respects and is intended to
facilitate the attraction and retention of key employees and to provide such
persons incentives and rewards for superior performance. The IEP provides for
the issuance of up to 3.8 million shares of the Company's common stock (of
which no more than 2 million shares may be issued or transferred as Restricted
Stock) as well as stock options and stock appreciation rights ("SARS"). The
transactions described following, were associated with either the IEP or the
predecessor LTIP, collectively referred to hereinafter as "the IEP".
During 1994, IEP participants were granted an additional 162,284
restricted shares and an additional 313,418 stock options (at an average
exercise price of $6.50/share) which were not yet exerciseable. During 1994,
IEP participants forfeited 149,404 restricted shares and 250,000 SARS (at an
average exercise price of $12.00/share). Also during 1994, 208,750 restricted
shares which had been previously granted were issued. At December 31, 1994,
780,285 restricted shares, 71,250 stock options (at an average exercise price
of $19.03/share) and 125,592 SARS (at an average exercise price of
$14.75/share) had been issued, all of which were outstanding and exercisable.
Expense (credit) of approximately $(0.2) million, $1.5 million and $1.7 million
related to the IEP was recorded during 1994, 1993 and 1992, respectively.
In May 1994, the Company's stockholders approved an Employee Stock
Purchase Plan ("the ESPP") to provide an incentive for employees of NorAm to
increase their holdings of the Company's common stock. The total number of
shares which may be issued under the ESPP (and paid for via payroll deduction)
will not exceed 2 million shares, which may be unissued shares, reacquired
shares, shares bought on the market, or any combination of the foregoing. The
ESPP generally provides for the shares to be sold to employees at a price
equivalent to 85% of its fair market value.
In May 1994, the Company's stockholders also adopted a Restricted
Stock Plan for Nonemployee Directors ("the DRSP") to (1) improve the Company's
ability to attract and retain highly qualified individuals to serve as
directors of the Company, (2) provide competitive remuneration for Board
service and (3) strengthen the commonality of interest between directors and
shareholders. Shares issued under the DRSP will be in the form of restricted
stock, will not exceed a total of 125,000 shares and may be shares of original
issuance, treasury shares or both.
<PAGE> 34
66
9 Discontinued Operations
"Loss from discontinued operations, less taxes" as presented in the
accompanying Statement of Consolidated Income includes the following:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1994 1992
--------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues (1) $ - $195,935
--------------------------------------------------------------------------------
Discontinued Operations
Pre-tax income (loss) (2)
E&P - 6,759
Products - (1,977)
USA (3,343) -
Income tax expense (benefit)
E&P - 2,529
Products - (1,019)
USA (1,241) -
--------------------------------------------------------------------------------
(2,102) 3,272
--------------------------------------------------------------------------------
Loss on Disposal (3)
E&P - (23,912)
Products - (4,067)
USA - (10,090)
--------------------------------------------------------------------------------
- (38,069)
--------------------------------------------------------------------------------
$ (2,102) $(34,797)
================================================================================
</TABLE>
(1) Operating revenues do not reflect the elimination of
intercompany/inter-divisional sales.
(2) Where applicable, results of discontinued operations include, in
addition to interest expense directly attributable to such operations,
an allocation of interest expense based on the ratio of the
discontinued assets to consolidated net assets.
(3) E&P, Products and USA losses on disposal are net of tax expense
(benefit) of $72.4 million, $(2.4) million and $(5.2) million,
respectively.
EXPLORATION AND PRODUCTION
In early 1992, the Company reacquired the 6,000,000 publicly-held shares of
Arkla Exploration Company ("E&P"), representing minority ownership of
approximately 18% through an exchange offer and merger, resulting in (1) the
issuance of approximately 5.7 million shares of the Company's common stock and
(2) a return to 100% ownership of E&P by the Company. This minority interest
had been outstanding as a result of an initial public offering of E&P's common
stock in 1989. The common stock issued to reacquire the minority interest
increased the Company's stockholders' equity by its fair market value of
approximately $59.8 million. The difference between the fair market value of
the stock issued and the carrying value of the minority interest reacquired
served to increase the Company's investment in E&P, resulting in an increase of
approximately $42.4 million in the carrying value of E&P's oil and gas
reserves, which reserves were subsequently sold as described following.
On December 31, 1992, the Company completed the sale of E&P to Seagull
Energy Corporation ("Seagull") for approximately $397 million in cash, the
substantial portion of which proceeds were used to reduce the Company's
short-term borrowings. The Company agreed to indemnify Seagull against certain
exposures, for which the Company has established reserves equal to anticipated
claims under the indemnity.
In connection with the sale, the Company retained a volumetric
production payment representing the right to receive the cash proceeds from the
sale of 1.2 million barrels of oil over a period of three years. Approximately
153,900 barrels remained to be delivered at December 31, 1994, in which the
Company has a book investment of approximately $13/barrel. The Company has
purchased a "floor" sales price of $17/barrel for this production payment,
based upon which the fair value of the oil to be delivered was approximately
$2.6 million at December 31, 1994.
RADIO COMMUNICATIONS
As a result of the purchase of DEI in November 1990, the Company acquired E. F.
Johnson Company ("Johnson") and EnScan, Inc. ("EnScan"), two firms which
operate in the radio communications business.
In February 1992, the Company exchanged its investment in EnScan for a
common stock interest in Itron, Inc. ("Itron") of Spokane, Washington, which
manufactures equipment and provides services similar and complementary to those
of EnScan. The stock received in this exchange of interests was valued on a
public exchange at approximately the Company's recorded investment in EnScan
and, accordingly, no gain or loss was recognized. After Itron's 1993 initial
public offering of its common stock and the Company's December 1994 sale of
400,000 Itron shares (yielding cash proceeds of approximately $7.2 million) in
a secondary offering, the Company's investment at December 31, 1994 represented
ownership of approximately 13.25%. The December 1994 sale generated net
proceeds of approximately $18.00/share, approximately equal to the Company's
then existing basis of approximately $17.80/share. The Company changed its
method of accounting for its investment in Itron from the equity method to the
cost method as of December 31, 1993, and plans to dispose of its ownership
interest over the next several years, with the exact timing of such disposition
principally determined by economic factors in the markets available for the
sale or exchange of such interests. Based on price quotations on the NASDAQ,
the market value of the Company's interest at December 31, 1994 was
approximately $32.1 million, and in accordance with Statement of Financial
Accounting Standards No. 115, "Accounting for Certain Investments in Debt and
Equity Securities" which was effective for fiscal years beginning after
December 15, 1993, the Company has revalued its investment to such market value
and reported an unrealized gain of
<PAGE> 35
67
$4.0 million ($2.6 million after-tax) as a separate component of stockholders'
equity. At March 1, 1995, the market value of the Company's investment in Itron
had increased to approximately $40.4 million and the unrealized gain to
approximately $12.3 million.
In July 1992, the Company sold the stock of Johnson (the corporation
which had operated the remaining portion of the Company's discontinued radio
communications business) for total consideration of approximately $40 million,
receiving approximately $15 million in cash at closing and retaining an
investment currently valued at approximately $5 million. This consideration was
approximately equal to the carrying value of the Company's investment and,
accordingly, no gain or loss was recognized.
UNIVERSITY SAVINGS ASSOCIATION
University Savings Association ("USA") was a wholly-owned subsidiary of Entex,
Inc. until its sale to a private group in May 1987, prior to Entex's February
1988 merger with the Company. In early 1992, the Resolution Trust Corporation
instituted actions against several former officers and directors of USA and
filed a suit against the Company, which suit was settled during 1994, see Note
11.
ARKLA PRODUCTS
In 1984, as a part of a larger transaction, the Company sold its gas grill
manufacturing business to Preway, Inc. ("Preway"). As a result of Preway's
subsequent default on certain industrial revenue bonds which were
collateralized by the gas grill manufacturing assets and for which the Company
had remained secondarily liable, the Company reacquired the gas grill business
and conducted operations in its Arkla Products subsidiary ("Products") as it
sought to dispose of this business. In late 1992, the Company sold the
principal assets and recorded a loss on disposition.
10 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. 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 a pre-tax gain of
approximately $23.9 million, which is 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
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), 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 under the caption "Sale of LIG, net of related expenditures". These net
cash proceeds were used principally to reduce the Company's participation in
its receivable sales program and to reduce short-term borrowings.
ARKLA EXPLORATION COMPANY
In December 1992, the Company sold the stock of E&P to Seagull Energy
Corporation, see Note 9.
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 E&P, see
Note 9.
<PAGE> 36
68
11 COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
Total rental expense for all leases was $36.8 million, $36.5 million and $27.8
million in 1994, 1993 and 1992, respectively. At December 31, 1994, the minimum
rental commitments under non-cancelable operating leases, principally
consisting of rental agreements for building space, data processing equipment
and vehicles (including major work equipment) were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
(thousands of dollars)
Year Ended December 31,
--------------------------------------------------------------------------------
<S> <C>
1995 $37,547
1996 17,134
1997 15,180
1998 12,206
1999 11,532
2000 and beyond 43,737
--------------------------------------------------------------------------------
Subtotal 137,336
Less subleases 1,630
--------------------------------------------------------------------------------
Net $135,706
================================================================================
</TABLE>
Lease payments related to assets transferred under the Company's
leasing arrangements (see Note 3) are included 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.
PENDING SALE TRANSACTION
The Company received $125 million from another party pending completion of a
transaction related to capacity principally in the Company's Line AC, of which
approximately $34 million was returned in December 1993 due to changes in the
underlying agreement and, under certain circumstances, the Company may be
required to return additional amounts, see Note 14.
LETTERS OF CREDIT
At December 31, 1994, the Company was obligated under letters of credit
totalling approximately $25 million which are incidental to its ordinary
business operations.
INDEMNITY PROVISIONS
The Company has obligations under indemnification provisions of certain sale
agreements, see Notes 9 and 10.
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been sold, see Note 3.
GAS PURCHASE CLAIMS
The Company is a party to certain claims involving, and has certain commitments
under, its gas purchase contracts, see Note 12.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company operates principally in the transmission and distribution 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 Note 3.
In addition to its other gas supply arrangements, the Company
routinely enters into agreements which commit it to either buy or sell gas in
the future at prices which may differ from prevailing market prices at the time
such transactions are consummated, or deliver gas at a point other than the
expected receipt point for the volumes to be purchased. In order to mitigate
the risk from market fluctuations in the price of natural gas and
transportation during the term of these commitments, the Company enters into
futures contracts, swaps and options, collectively referred to as "financial
contracts". The Company also utilizes these financial contracts to meet certain
of its customers' needs for fixed price gas supply as discussed following. In
no case are these financial contracts held for speculative trading purposes. In
the discussion which follows, contract quantities (notional amounts) are
provided for the purpose of establishing the extent of the Company's activities
involving these financial contracts although, in general, the amounts at risk
are significantly smaller when the offsetting physical transactions are
considered.
The Company has entered into swaps in which one party agrees to pay
either a fixed price or a fixed differential from the NYMEX price per MMBtu of
gas, while the other party agrees to pay a price based on a published index. As
of December 31, 1994 and 1993, the Company was obligated to pay either a fixed
price or a fixed differential from the NYMEX price on swaps covering 70.2 Bcf
and 15.8 Bcf of gas, respectively. As of December 31, 1994 and 1993, the
Company was entitled to receive either a fixed price or a fixed differential
from the NYMEX price on swaps covering 87.4 Bcf and 39.9 Bcf of gas,
<PAGE> 37
69
respectively. At December 31, 1994 and 1993, these swaps (including both those
where the Company is a fixed price payor and those where the Company is a fixed
price receiver) represented a unrealized gain (loss) of $0.9 million and $(0.7)
million, respectively, and the effect of these swaps was to decrease the cost
of natural gas purchased, net by $2.8 million and $1.0 million for 1994 and
1993, respectively.
The Company enters into NYMEX futures contracts which are primarily
used to hedge the Company's storage gas and meet certain customers' needs to
mitigate or eliminate their risk from market fluctuations in the price of
natural gas. As of December 31, 1994, the Company held contracts covering the
purchase of approximately 6.7 Bcf of gas through March 1996, a notional amount
of $13.8 million. As of December 31, 1994, the Company held contracts covering
the sale of approximately 1.7 Bcf of gas through January 1996, a notional
amount of $2.8 million. These contracts (both purchases and sales) represented
an unrealized loss of $2.9 million at December 31, 1994. The Company's
portfolio of futures contracts was not material at December 31, 1993. Due to
the fact that, in many cases, the cost of these activities are offset by
revenues from the customers who requested this service, the impact of these
futures on earnings is not material.
In conjunction with agreements existing at December 31, 1994, which
commit the Company to deliver specified quantities of gas at fixed prices
ratably through April 1999, the Company instituted a price risk management
program ("the Program") whereby financial contracts (principally swaps and
options) and fixed price purchase contracts are utilized to mitigate the risk
associated with changes in the market price of gas during the terms of these
arrangements. As of December 31, 1994, the Company had entered into swaps
covering 61.7 Bcf of gas in which it was the fixed price payor and 26.7 Bcf of
gas in which it was the fixed price receiver. As of December 31, 1993, the
Company had entered into swaps covering 85.4 Bcf of gas in which it was the
fixed price payor and 42.3 Bcf of gas in which it was the fixed price receiver.
As of December 31, 1994 and 1993, the unrealized loss associated with these
swaps (including both those where the Company is a fixed price payor and those
where the Company is a fixed price receiver) was $(17.6) million and $(5.9)
million, respectively. The Company also has purchased options under the Program
which serve to limit the year-to-year escalation in prices for gas to be
delivered from January 1997 to April 1999. At December 31, 1994 and 1993,
options were outstanding covering the purchase of 30.5 Bcf and 49.3 Bcf of gas,
respectively. The Company has previously established reserves equal to its
projected maximum exposure to losses from the agreements covered by the Program
and, accordingly, there was no impact from the Program on earnings in 1994 or
1993.
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 of
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
In October 1992, the Resolution Trust Corporation ("the RTC") filed suit
(ultimately seeking damages of at least $520 million) in United States District
Court for the Southern District, Houston Division, against the Company (as a
successor-in-interest to Entex, Inc. which merged with the Company in 1988) and
certain other defendants for alleged harm resulting from the 1989 failure of
USA, a thrift institution in Houston, Texas. In November 1994, the Company
announced that it, together with the other defendants, had entered into a final
settlement of this litigation. The net effect of the settlement, as adjusted
for insurance recovery, legal expenses incurred, certain other USA-related
expenses and the legal expense reserve previously recorded, was a pre-tax
charge to discontinued operations of $3.3 million ($2.1 million after tax) in
the fourth quarter of 1994, see Note 9.
On August 6, 1993, the Company, its former subsidiary, Arkla
Exploration Company and Arkoma Production Company ("Arkoma"), a subsidiary of
E&P, were named as defendants in a lawsuit (the "State Claim") filed in the
Circuit Court of Independence County, Arkansas. This complaint alleges that the
Company, E&P and Arkoma, acted to defraud ratepayers in a series of
transactions arising out of a 1982 agreement between the Company and Arkoma. On
behalf of a purported class composed of the Company's ratepayers, plaintiffs
have alleged that the Company, E&P and Arkoma are
<PAGE> 38
70
responsible for common law fraud and violation of an Arkansas law regarding gas
companies, and are seeking a total of $100 million in actual damages and $300
million in punitive damages. On November 1, 1993, the Company filed a motion to
dismiss the State Claim. In a hearing held on May 19, 1994, the Court heard
arguments on this motion. On September 20, 1994, the Court entered an order
granting the Company's motion to dismiss. The plaintiffs have appealed this
order granting the motion to dismiss, but a hearing date for the appeal has not
yet been set. The underlying facts forming the basis of the allegations in the
State Claim also formed the basis for allegations in a lawsuit (the "Federal
Claim") filed in September 1990 in the United States District Court for the
Eastern District of Arkansas, by the same plaintiffs. The Federal Claim was
dismissed in August 1992. Since the State Claim is based on essentially the
same underlying factual basis as the Federal Claim and in light of the Court's
order granting the Company's motion to dismiss the State Claim, the Company
continues to believe the State Claim is without merit, intends to vigorously
contest the appeal of the order granting dismissal and does not believe that
the outcome will have a material adverse effect on the financial position,
results of operations or cash flows of the Company.
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
From the late 1800s to 1960, Minnegasco (acquired by the Company in November
1990) 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 is
working with the Minnesota Pollution Control Agency to implement an appropriate
response action. At this time, however, the specific method and extent of
required remediation are not known.
There are six other former Manufactured Gas Plant ("MGP") sites in
Minnesota in the service territory in which Minnegasco operated at December 31,
1994. 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.
In addition, there are seven former MGP sites in Nebraska and two in South
Dakota in the service territory in which Minnegasco operated at December 31,
1992. As a part of the sale of the Nebraska operations, the buyer has assumed
liability for five Nebraska sites. Minnegasco had previously disposed of the
other two Nebraska sites. The South Dakota sites were not operated by
Minnegasco or its predecessors. Minnegasco believes it is not liable for
remediation of the Nebraska and South Dakota sites.
At December 31, 1994 and 1993, Minnegasco had recorded a deferred
charge of $0.8 million and $1.3 million, respectively, related to the
Minneapolis Site and has estimated a range of $40 million to $129 million for
the 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 Minnegasco, assuming Minnegasco's proposed remediation methods. The
upper estimate of the range was determined using the Minnesota sites once owned
by Minnegasco, whether or not operated by Minnegasco, and using alternative,
more costly remediation methods. The cost estimates for the Minneapolis Site
are based on studies made of that site. The remediation cost for other sites is
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 by other potentially responsible parties, if any, and the
remediation methods used.
At December 31, 1994 and 1993, the Company had recorded a liability of
$43.8 million and $26.8 million, respectively, to cover the probable costs of
remediation. In connection with its 1992 rate case, Minnegasco was allowed to
recover through rates over five years, without carrying costs, the deferred
costs at December 31, 1992, and was allowed $3.1 million annually to cover
on-going clean-up costs. In its 1993 rate case, Minnegasco was allowed $2.1
million annually to recover amortization of previously deferred costs and
ongoing clean-up costs. Any amounts in excess of $2.1 million in any individual
year are to be deferred for future recovery. The Company currently expects that
any cash expenditures for these costs in excess of the amount recovered in
rates during any year will not be material to the Company's overall cash
requirements. In accordance with SFAS 71, a regulatory asset has been recorded
equal to the amount accrued. The Company is pursuing recovery of costs from its
insurers and other potentially responsible parties.
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 cer-
<PAGE> 39
71
tain 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.
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 still subject to SFAS 71, corresponding regulatory assets
are set up in anticipation of recovery through the ratemaking process. At
December 31, 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 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 its results of operations, financial position or cash flows.
12 GAS SUPPLY CONTRACT MATTERS
During the 1980s, the Company resolved a number of claims made by suppliers
under gas purchase contracts through various forms of settlement, including
buy-out/buy-downs and payments for gas in advance of its delivery and, in the
third quarter of 1989, recorded a pre-tax "Special Charge" of $269 million
related to these claims. The prepayments for gas made in conjunction with these
settlements are carried at their estimated net realizable 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 remaining life of these agreements, its
earnings will be adversely affected, although such impact is not expected to be
material. While the Company has settled the vast majority of such claims, the
Company is committed to make additional payments under certain settlements,
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 future settlements, if any, in excess of existing accruals will not be
material to the Company's results of operations, financial position or cash
flows.
In addition to the prepayments for gas discussed above, 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 prevailing market prices at
the time such transactions are consummated or require it to deliver gas at a
point other than the expected receipt point for the 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 gas
purchase/sale commitments, see Notes 1 and 11. 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.
Effective as of December 31, 1993, the Company completed a
comprehensive settlement agreement ("the Settlement") with certain subsidiaries
of Samson Investment Company ("Samson"), pursuant to which a number of
outstanding contractual arrangements (including long-term obligations, notes
receivable and gas purchased in advance of delivery) between the parties were
terminated or substantially modified, resulting in a $34.2 million pre-tax
charge to earnings, set forth in the accompanying Statement of Consolidated
Income as "Contract termination charge". Consideration for the Settlement
included an exchange of cash (the net effect of which was immaterial) and the
delivery by the Company to Samson of a note for $34 million, bearing interest
at 6% and payable in equal installments of principal and interest through May
31, 1995.
<PAGE> 40
72
13 DISCONTINUATION OF REGULATORY
ACCOUNTING FOR NORAM GAS TRANSMISSION
The Company historically has applied the provisions of SFAS 71 to all of its
rate-regulated businesses. With respect to the Company's NGT subsidiary,
however, the Company concluded that, effective as of December 31, 1992,
continued application of SFAS 71 was no longer appropriate. The Company based
its conclusion on its analysis of NGT's regulatory and economic environment and
the extent to which such environment would allow NGT to collect its cost-based
rates. The Company had begun its analysis when it became apparent that changes
in NGT's regulatory environment, largely due to the actions of the FERC, were
subjecting NGT to increasing competitive pressures, resulting in significant
underrecovery of NGT's cost-based revenue requirements. The Company determined
that it was unlikely that it could take steps through the regulatory process or
otherwise which would cause NGT to return to a situation in which the Company
could conclude that collection of NGT's cost-based rates was probable.
Accordingly, at December 31, 1992, the Company ceased to apply the
provisions of SFAS 71 to NGT's transactions and balances, which accounting
change was implemented pursuant to Statement of Financial Accounting Standards
No. 101, "Regulated Enterprises - Accounting for the Discontinuance of
Application of FASB Statement No. 71" ("SFAS 101"). The methodology for this
accounting change is contained within SFAS 101 and, simply stated, requires the
removal from NGT's balance sheet of the impact of the effects of the actions of
regulators. More specifically, the Company (1) identified and wrote-off those
NGT assets which would not be recognized as assets by non-regulated
enterprises, principally amounts associated with take-or-pay settlement costs
and deferred pursuant to FERC Order 528 ($237.9 million), (2) wrote down
certain current assets based on "lower of cost or market" rules applicable to
nonregulated enterprises ($27.0 million), (3) accrued for expected costs in
excess of current market value for certain gas purchase contracts for which
recovery could no longer be assumed through regulatory mechanisms ($19.9
million) and (4) wrote down certain of its gathering assets pursuant to
impairment guidelines applicable to enterprises in general ($29.7 million).
This charge, which totalled $314.5 million pre-tax ($195.0 million after-tax),
is shown in the accompanying Statement of Consolidated Income for 1992 under
the caption "Extraordinary items, 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.
14 SALE OF PIPELINE FACILITIES
The Company has an agreement ("the Agreement") with ANR Pipeline Company
("ANR") which contemplates the transfer to ANR of an ownership interest in 250
MMcf/day of capacity in the Company's Line AC and certain related transmission
facilities in exchange for approximately $90 million in cash. In conjunction
with the Agreement, the Company had received (and recorded as a liability) $125
million in cash, $34 million of which was refunded in December 1993 due to
changes in the Agreement, primarily related to the deletion of certain
gathering facilities from the transaction. The Agreement is subject to
acceptable approvals by the Federal Trade Commission and by the FERC which have
issued orders approving the transaction. The FERC's order, however, contained
conditions unacceptable to the parties and each party has filed a notice of
appeal of the order with the D.C. Circuit Court of Appeals.
Should the transaction not be completed as a sale, the Agreement
requires that the parties operate under separate agreements ("the Backup
Agreements") pursuant to which the Company would instead provide transportation
services generally to ANR until 2005. The Backup Agreements currently provide
initially for the transportation of 250,000 MMBtu/day, which level would
decrease to 130,000 MMBtu/day on June 1, 1995 with a refund to ANR by the
Company of $50 million from the amounts previously received. The level of
transportation services provided pursuant to the Backup Agreements would
further decrease to 100,000 MMBtu/day on April 1, 2003, with an additional
refund to ANR of $5 million and the Backup Agreements will terminate on June 1,
2005, with a refund of the remaining balance. The Company's consideration for
such transportation services would be provided by the interest-free use of the
previously-advanced money until its return to ANR.
<PAGE> 41
73
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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the consolidated financial position of NorAm
Energy Corp. and Subsidiaries as of December 31, 1994 and 1993, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1994, in conformity with generally
accepted accounting principles.
As discussed in Note 6 to the consolidated financial statements, the
Company changed its method of accounting for postretirement benefits effective
January 1, 1993.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 24, 1995
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 independent
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.
<PAGE> 42
Q U A R T E R L Y I N F O R M A T I O N ( U N A U D I T E D )
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
(thousands of dollars, except per share amounts) 1994 Quarter Ended
March 31 June 30 Sept 30 Dec 31
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 1,092,319 $ 535,487 $ 460,559 $ 713,081
------------------------------------------------------------------------------------------------------------------------------------
Gross profit (1) $ 345,216 $ 217,058 $ 196,367 $ 275,097
------------------------------------------------------------------------------------------------------------------------------------
Operating income $ 146,071 $ 29,524 $ 7,381 $ 83,070
------------------------------------------------------------------------------------------------------------------------------------
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>
<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
(thousands of dollars, except per share amounts) 1993 Quarter Ended
March 31(3)(4) June 30(3) Sept 30 Dec 31(5)
------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 1,011,076 $ 613,376 $ 457,087 $ 868,026
------------------------------------------------------------------------------------------------------------------------------------
Gross profit (1) $ 344,434 $ 217,805 $ 193,022 $ 293,452
------------------------------------------------------------------------------------------------------------------------------------
Operating income $ 139,644 $ 19,416 $ 2,083 $ 45,855
------------------------------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations $ 76,705 $ (7,991) $ (24,561) $ (4,218)
Extraordinary item, less taxes (3,411) - (56) (381)
------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 73,294 $ (7,991) $ (24,617) $ (4,599)
====================================================================================================================================
Per Share Data (2)
Continuing operations $ 0.61 $ (0.08) $ (0.22) $ (0.05)
Extraordinary item, less taxes (0.03) - 0.00 0.00
------------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.58 $ (0.08) $ (0.22) $ (0.05)
====================================================================================================================================
Weighted average shares outstanding 122,258 122,256 122,346 122,357
------------------------------------------------------------------------------------------------------------------------------------
(1) "Gross profit" is operating revenues less "Cost of natural gas purchased, net".
(2) Earnings from continuing operations per common share is based on income (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.
(3) LIG was sold effective June 30, 1993, see Note 10 of Notes to Consolidated Financial Statements. LIG's operating revenues were
$69.7 million and $81.4 million for the quarters ended March 31, 1993 and June 30, 1993, respectively, and its operating income
was $2.8 million in each of the first two quarters of 1993.
(4) Results for the first quarter of 1993 include a preliminary pre-tax gain of $26.8 million (the final gain was $23.9 million)
from the sale of the Company's Nebraska distribution properties, see Note 10 of Notes to Consolidated Financial Statements.
(5) Results for the fourth quarter of 1993 include a pre-tax contract termination charge of $34.2 million ($20.9 million after-tax
or $0.17/share), see Note 12 of Notes to Consolidated Financial Statements.
</TABLE>
<PAGE> 1
The subsidiaries of NorAm Energy Corp. are:
AER - Arkansas Gas Transit Company
Subsidiaries:
Blue Jay Gas Company
Raven Gas Company
Seahawk 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 Material Corporation
Arkansas Louisiana Finance Corporation
Arkla Chemical Corporation
Arkla Finance Corporation
Arkla Industries Inc.
Arkla Intratex Transmission Company
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
Subsidiary:
MRT Energy Marketing Company
National Furnace Company
NorAm Energy Services, Inc. (f/k/a Arkla Energy Marketing Company)
NorAm Field Services Corp.
NorAm Gas Transmission Company (f/k/a Arkla Energy Resources Company)
NorAm Hub Services Inc.
Unit Gas Transmission Company
United Gas, Inc.
<PAGE> 1
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.
33-41493, 33-48750, 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, and 33-54253) of
our report, which includes an explanatory paragraph concerning the Company's
change in accounting method for postretirement benefits, dated March 24, 1995
on our audits of the consolidated financial statements and financial statement
schedule of the Company as of December 31, 1994 and 1993, and for the years
ended December 31, 1994, 1993 and 1992, which report is incorporated by
reference in this Annual Report on Form 10-K.
/s/ COOPERS & LYBRAND L. L. P.
Houston, Texas
March 29, 1995
<PAGE> 1
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, 1994 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, 1995.
/s/ Michael B. Bracy
----------------------------------
<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, 1994 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, 1995.
/s/ Joe E. Chenoweth
----------------------------------
<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, 1994 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, 1995.
/s/ O. Holcombe Crosswell
--------------------------------------
<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, 1994 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, 1995.
/s/ Walter A. DeRoeck
---------------------------------------
<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, 1994 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, 1995.
/s/ Mickey P. Foret
-----------------------------------
<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, 1994 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, 1995.
/s/ Donald H. Flanders
------------------------------------
<PAGE> 7
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, 1994 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, 1995.
/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, 1994 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, 1995.
/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, 1994 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, 1995.
/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, 1994 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, 1995.
/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, 1994 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, 1995.
/s/ T. Milton Honea
------------------------------------
<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, 1994 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, 1995.
/s/ Myra Jones
-----------------------------------
<PAGE> 13
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, 1994 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, 1995.
/s/ Sidney Moncrief
------------------------------------
<PAGE> 14
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, 1994 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, 1995.
/s/ Larry C. Wallace
--------------------------------------
<PAGE> 15
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, 1994 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, 1995.
/s/ D. W. Weir, Sr.
-----------------------------------
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,286,144
<OTHER-PROPERTY-AND-INVEST> 792,254
<TOTAL-CURRENT-ASSETS> 409,275
<TOTAL-DEFERRED-CHARGES> 73,825
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,561,498
<COMMON> 76,581
<CAPITAL-SURPLUS-PAID-IN> 868,289
<RETAINED-EARNINGS> (360,079)
<TOTAL-COMMON-STOCKHOLDERS-EQ> 587,377
0
130,000
<LONG-TERM-DEBT-NET> 1,414,374
<SHORT-TERM-NOTES> 110,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 164,600
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,155,147
<TOT-CAPITALIZATION-AND-LIAB> 3,561,498
<GROSS-OPERATING-REVENUE> 2,801,446
<INCOME-TAX-EXPENSE> 34,372
<OTHER-OPERATING-EXPENSES> 0
<TOTAL-OPERATING-EXPENSES> 2,535,400
<OPERATING-INCOME-LOSS> 266,046
<OTHER-INCOME-NET> (11,018)
<INCOME-BEFORE-INTEREST-EXPEN> 255,028
<TOTAL-INTEREST-EXPENSE> 169,365
<NET-INCOME> 48,066
7,800
<EARNINGS-AVAILABLE-FOR-COMM> 40,266
<COMMON-STOCK-DIVIDENDS> 34,265
<TOTAL-INTEREST-ON-BONDS> 70,259
<CASH-FLOW-OPERATIONS> 304,914
<EPS-PRIMARY> 0.33
<EPS-DILUTED> 0.33
</TABLE>
