<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, 1996
COMMISSION FILE NUMBER 1-3751
NORAM ENERGY CORP.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE
(STATE OR JURISDICTION OF INCORPORATION OR ORGANIZATION)
EMPLOYER IDENTIFICATION
(I.R.S. NO. 72-0120530)
1600 SMITH, 32ND FLOOR, HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICE)
(713) 654-5699
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
COMMON STOCK, $.625 PAR VALUE NEW YORK STOCK EXCHANGE
NORAM FINANCING I 6 1/4 CONVERTIBLE
TRUST ORIGINATED PREFERRED SECURITIES,
GUARANTEED BY NORAM ENERGY CORP. TO THE
EXTENT DESCRIBED THEREIN NEW YORK STOCK EXCHANGE
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 ('229.405 OF THIS CHAPTER) IS NOT
CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT'S
KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY
REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM
10-K.
THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-
AFFILIATES: $2,002,841,890 COMMON STOCK, $.625 PAR VALUE, BASED UPON THE
CLOSING SALES PRICE ON MARCH 20, 1997 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: 137,995,823 SHARES OF COMMON STOCK, $.625 PAR VALUE, AS OF MARCH
20, 1997.
DOCUMENTS INCORPORATED BY REFERENCE
NORAM ENERGY CORP. DEFINITIVE PROXY STATEMENT RESPECTING THE ANNUAL
MEETING OF STOCKHOLDERS TO BE HELD ON MAY 13, 1997, TO BE FILED PURSUANT
TO REGULATION 14A UNDER THE SECURITIES EXCHANGE ACT OF 1934 (TO THE
EXTENT SET FORTH IN ITEMS 10, 11, 12 AND 13 OF PART III OF THIS REPORT)
IS INCORPORATED BY REFERENCE.
THE EXHIBITS INCLUDED IN THIS REPORT ARE INDEXED ON PAGES 92 THROUGH 94.
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PART I
- ------
ITEM 1. BUSINESS 1
Natural Gas Distribution 2
Interstate Pipelines 5
Wholesale Energy Marketing 8
Natural Gas Gathering 8
Retail Energy Marketing 9
Market Factors 9
Regulation 10
Environmental Matters 12
Mergers, Acquisitions and Dispositions 12
Employees 14
ITEM 2. PROPERTIES 14
ITEM 3. LEGAL PROCEEDINGS 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 15
REGULATION S-K, ITEM 401(B) EXECUTIVE OFFICERS OF THE COMPANY 16
PART II
- -------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS 18
ITEM 6. SELECTED FINANCIAL DATA 19
ITEM 7. MANAGEMENT ANALYSIS 19
Merger With Houston Industries 19
Organization and Accounting Policies 20
Material Changes in the Results of Continuing Operations 21
General 21
Regulatory Matters 22
Change in Estimated Service Lives of Certain Assets 24
Operating Income (Loss) by Business Unit 25
Summary Table 25
Natural Gas Distribution 25
Interstate Pipelines 28
Wholesale Energy Marketing 34
Natural Gas Gathering 37
Retail Energy Marketing 39
Corporate and Other 41
Non-Operating Income and Expense 42
Discontinued Operations 43
Liquidity and Capital Resources 44
Commitments and Contingencies 52
Earnings Per Share 57
RATIO OF EARNINGS TO FIXED CHARGES 58
DEBT RETIREMENT SCHEDULE 58
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 58
Statement of Consolidated Income 59
Consolidated Balance Sheet 60
Statement of Consolidated Stockholders' Equity 62
Statement of Consolidated Cash Flows 63
Notes to Consolidated Financial Statements 64
Report of Independent Accountants 89
Management's Responsibility for Financial Statements 89
Quarterly Information 90
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE 91
</TABLE>
i
<PAGE> 3
<TABLE>
<CAPTION>
PAGE
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<S> <C> <C>
PART III
- ---------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT 91
ITEM 11. EXECUTIVE COMPENSATION 91
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 91
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 91
PART IV
- -------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K 91
</TABLE>
<PAGE> 4
NORAM ENERGY CORP. AND SUBSIDIARIES
PART I
ITEM 1. BUSINESS
NorAm Energy Corp. (the "Company") was incorporated in 1928 under the laws of
the State of Delaware and is principally engaged in the distribution and
transmission of natural gas including gathering, marketing and storage of
natural gas.
On August 11, 1996, the Company signed an Agreement and Plan of Merger
(the "Merger Agreement") among Houston Industries Incorporated ("Houston
Industries"), Houston Lighting & Power Company ("HL&P"), HI Merger, Inc.
("Merger Sub") and the Company. The Merger Agreement provides for:
o the merger of Houston Industries into HL&P (the "Houston Industries/HL&P
Merger"), as a result of which each outstanding share of Houston
Industries common stock will be converted into one share of common stock
of HL&P, which will be renamed "Houston Industries Incorporated" ("HII")
and will continue to conduct HL&P's electric utility business under
HL&P's name, and
o the merger of the Company into Merger Sub (the "NorAm Merger", and
together with the Houston Industries/HL&P Merger, the "Basic Mergers"),
as a result of which the Company will become a wholly owned subsidiary
of HII and the outstanding shares of common stock of the Company will be
converted into the right to receive cash or HII common stock as more
fully described herein, see "Management Analysis - Merger With Houston
Industries," (the term "Transaction" refers to the business combination
between the Company and Houston Industries).
For a discussion of the current status of the Transaction, see "Mergers,
Acquisitions and Dispositions."
The revenue, operating profit and identifiable assets of the Company's
natural gas segment exceed 90% of the respective totals for the Company.
Accordingly, the Company is not required to report on a "segment" basis,
although the Company is organized into, and the following business description
focuses on, the six operating units described below. In recognition of the
manner in which the Company manages its portfolio of businesses, the Company
has segregated its results of operations into (1) Natural Gas Distribution, (2)
Interstate Pipelines, (3) Wholesale Energy Marketing, (4) Natural Gas
Gathering, (5) Retail Energy Marketing and (6) Corporate and Other. Set forth
below is the Operating Income (Loss) by these Business Units.
1
<PAGE> 5
<TABLE>
<CAPTION>
OPERATING INCOME (LOSS) BY BUSINESS UNIT(1)
- -------------------------------------------------------------------------------
(millions of dollars) 1996 1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Distribution $ 183.9(2) $ 158.0 $ 145.5
Interstate Pipelines (3) 124.4(2) 103.8 105.4
Wholesale Energy Marketing 12.1 4.2 (3.0)
Natural Gas Gathering (3) 13.9 8.7 5.6
Retail Energy Marketing 29.7 22.2 18.4
Corporate and Other (4) (27.2) (9.6) (7.0)
- -------------------------------------------------------------------------------
Subtotal 336.8 287.3 264.9
Early Retirement and Severance (5) (22.3) -- --
- -------------------------------------------------------------------------------
Consolidated $ 314.5 $ 287.3 $ 264.9
===============================================================================
</TABLE>
(1) In general, transactions among business units are recorded at market
prices and material affiliate transactions within business units are
eliminated.
(2) Before the charge for early retirement and severance, see (5) following.
(3) Reflects a change in depreciation rates during 1995, see Note 1 of Notes
to Consolidated Financial Statements.
(4) Includes amortization of goodwill, see Note 1 of Notes to Consolidated
Financial Statements.
(5) Costs associated with early retirement and severance, see "Management
Analysis - Material Changes in the Results of Continuing Operations -
Natural Gas Distribution and Interstate Pipelines" elsewhere herein.
The Company is also pursuing opportunities for international investment.
The Company's efforts thus far have focused on opportunities emerging in Latin
America due to privatization initiatives currently underway in a number of
countries, as well as broad-based efforts to encourage international
investment, see "Management Analysis - Material Changes in the Results of
Continuing Operations - General." The Company's miscellaneous activities,
whose collective results of operations currently are not material, principally
consist of (1) home care services, including (i) appliance sales and service,
(ii) home security services, and (iii) resale of long distance telephone
service, and (2) utility services, principally line locating services.
NATURAL GAS DISTRIBUTION
The Company's natural gas distribution business is conducted through three
divisions, Arkla, Entex and Minnegasco, and their affiliates. These three
divisions serve over 2.7 million customers in six states, including the
metropolitan areas of Minneapolis, Minnesota, Houston, Texas, Little Rock,
Arkansas and Shreveport, Louisiana. Natural Gas Distribution as presently
constituted consists principally of natural gas sales to and natural gas
transportation for residential, commercial and a limited number of industrial
customers, substantially all of which are located behind the "city gate" and
subject to traditional cost-of-service rate regulation. 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 "Management Analysis - Material Changes in the
Results of Continuing Operations - Regulatory Matters"). During the first
quarter of 1996, approximately 100 employees of Entex accepted an early
retirement program and approximately 25 positions were eliminated at Minnegasco
as the result of the reorganization of certain functions. (See "Management
Analysis - Material Changes in the Results of Continuing Operations - Natural
Gas Distribution").
2
<PAGE> 6
Arkla provides service in approximately 621 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 1996, 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, approximately 62% of Arkla's
supplies were obtained from NorAm Gas Transmission Company ("NGT"),
Mississippi River Transmission Corporation ("MRT"), or NorAm Energy Services,
Inc. ("NES"). NGT, MRT and NES are wholly owned subsidiaries of the 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 1996, approximately 97% of Entex's
total throughput was composed of sales of gas at retail and approximately 3%
was attributable to transportation services. For the same period, Entex's
principal suppliers of gas were Cokinos Natural Gas, Enron Capital & Trade
Resources, Koch Gateway Pipeline Company, Tejas Corp. and certain affiliates of
each such company. No other supplier accounted for more than 10% of Entex's
purchases.
During 1996, Minnegasco provided service in approximately 245
communities in Minnesota. The largest community served by Minnegasco is
Minneapolis, Minnesota and its suburbs. In 1996, approximately 97% of
Minnegasco's total throughput was composed of sales of gas at retail and
approximately 3% 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, Tenaska Gas Marketing and
Trans-Canada Gas Marketing. No other supplier of natural gas accounted for
more than 5% 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 September 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,
1996:
<TABLE>
<CAPTION>
- --------------------------------------------------------
SERVICE AREA COMMUNITIES NUMBER OF
LOCATIONS SERVED CUSTOMERS
- --------------------------------------------------------
<S> <C> <C>
Texas 373 1,211,836
Minnesota 245 639,824
Arkansas 384 439,427
Louisiana 179 262,934
Mississippi 91 119,264
Oklahoma 96 114,605
- --------------------------------------------------------
Total 1,368 2,787,890
========================================================
</TABLE>
3
<PAGE> 7
The following table summarizes the estimated number of customers served
by each of the divisions as of December 31, 1996 and 1995:
<TABLE>
<CAPTION>
- --------------------------------------------------------
YEAR ENDED DECEMBER 31,
CUSTOMERS BY DIVISION 1996 1995
- --------------------------------------------------------
<S> <C> <C>
Entex 1,412,495 1,394,292
Arkla 735,571 727,235
Minnegasco 639,824 626,367
- --------------------------------------------------------
Total 2,787,890 2,747,894
========================================================
</TABLE>
The following table provides the average number of customers served
during 1996, 1995 and 1994:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
AVERAGE NUMBER OF CUSTOMERS 1996 1995 1994
- ----------------------------------------------------------------------
<S> <C> <C> <C>
Residential 2,531,775 2,495,022 2,458,520
Commercial 227,571 224,946 222,193
Industrial 2,326 2,338 2,462
- ----------------------------------------------------------------------
Total 2,761,672 2,722,306 2,683,175
======================================================================
</TABLE>
The Company's approximately 55,000 linear miles of gas distribution
mains vary in size from one-half inch to 24 inches. Generally, in each of the
cities, towns and rural areas it serves, the Company owns the underground gas
mains and service lines, metering and regulating equipment located on
customers' premises, and the district regulating equipment necessary for
pressure maintenance. With a few exceptions, the measuring stations at which
the Company receives gas from its suppliers are owned, operated and maintained
by others, and the distribution facilities of the Company begin at the outlet
of the measuring equipment. These facilities include odorizing equipment
usually located on the land owned by suppliers and district regulator
installations, in most cases located on small parcels of land which are leased
or owned by the Company.
Consolidated revenue, and throughput data of the distribution divisions
are as follows:
4
<PAGE> 8
<TABLE>
<CAPTION>
NATURAL GAS DISTRIBUTION
- -----------------------------------------------------------------------
(in millions of dollars) YEAR ENDED DECEMBER 31,
OPERATING REVENUES 1996 1995 1994
- -----------------------------------------------------------------------
<S> <C> <C> <C>
Sales $ 2,074.1 $ 1,678.6 $ 1,769.9
Transportation 16.0 19.1 17.6
Other 23.5 21.7 23.1
- -----------------------------------------------------------------------
Total $ 2,113.6 $ 1,719.4 $ 1,810.6
=======================================================================
</TABLE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------
(in billions of cubic feet) YEAR ENDED DECEMBER 31,
THROUGHPUT 1996 1995 1994
- -----------------------------------------------------------------------
<S> <C> <C> <C>
Sales
Residential 198.8 183.3 180.0
Commercial 133.7 123.3 119.1
Industrial 57.9 52.4 53.4
Transportation 42.0 49.4 44.9
- -----------------------------------------------------------------------
Total 432.4 408.4 397.4
=======================================================================
</TABLE>
INTERSTATE PIPELINES
The Company's interstate natural gas pipeline business (collectively referred
to as "Interstate Pipelines" or "Pipeline") is conducted principally through
NGT and MRT, two wholly owned subsidiaries of the Company together with certain
subsidiaries and affiliates. The Company's natural gas gathering activities
subsequent to 1993 and wholesale energy marketing activities for all periods,
previously included with Pipeline, are now separately discussed, see "Wholesale
Energy Marketing" and "Natural Gas Gathering" elsewhere herein.
In March 1993, the Company transferred assets, liabilities and service
obligations of Arkla Energy Resources, formerly a division of the Company, into
a then newly-formed wholly owned subsidiary of the Company, now called NGT,
pursuant to an order from the Federal Energy Regulatory Commission ("FERC")
approving the transfer. As a result of this transfer of assets, liabilities
and service obligations, the FERC now has sole jurisdiction over NGT's
interstate pipeline business, including transportation services and certain of
NGT's transactions with affiliates of the Company, which historically were
subject to both FERC and state regulatory oversight, see "Regulation."
On June 30, 1993, the Company completed the sale of its intrastate
pipeline business as conducted by Louisiana Intrastate Gas Corporation and its
subsidiaries, LIG Chemical Company, LIG Liquids Corporation and Tuscaloosa
Pipeline (the "LIG Group"), to a subsidiary of Equitable Resources, Inc.
("Equitable") for $191 million in cash. The Company agreed to indemnify
Equitable against certain exposures, for which the Company has established
reserves equal to anticipated claims under the indemnity. The Company acquired
the LIG Group in July of 1989. The LIG Group operated a natural gas pipeline
system located wholly within Louisiana.
In February 1996, Pipeline announced a reorganization plan which
resulted in the elimination of a total of approximately 275 positions at NGT
and MRT. See "Management Analysis - Material Changes in the Results of
Continuing Operations - Interstate Pipelines".
NGT owns and operates a natural gas pipeline system located in portions
of Arkansas, Louisiana, Mississippi, Missouri, Kansas, Oklahoma, Tennessee and
Texas. At December 31, 1996 the NGT system consisted of approximately 6,200
miles of transmission lines. The NGT pipeline system extends generally in an
easterly direction from the Anadarko Basin area of the Texas Panhandle and
western Oklahoma through the Arkoma Basin area of eastern Oklahoma and Arkansas
to the Mississippi River. Additional pipelines extend from east Texas to north
Louisiana and central Arkansas, and from the mainline system in Oklahoma and
Arkansas to south central Kansas and southwest Missouri. In its system, NGT
operates various compressor facilities related to its gas transmission
business. NGT's peak day gas handled during
5
<PAGE> 9
the 1996/97 heating season was approximately 2.3 billion cubic feet ("Bcf").
NGT, on behalf of various shippers, transports and delivers gas to distributors
for resale and ultimate public consumption, to industrial customers for their
own use and consumption, and to third party pipeline interconnects located in
the states of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma,
Tennessee and Texas. In 1996, NGT's throughput totaled 607.8 million MMBtu.
Approximately 18% of the total throughput was attributable to services provided
to Arkla, and 28% 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 2,000 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 includes
various other branch, lateral and transmission lines and compressor stations.
During 1996, MRT's throughput totaled 409.6 million MMBtu. Approximately half
of MRT's total 1996 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 1996/97 heating
season to its traditional market area customers were approximately one million
MMBtu. MRT's largest customer is Laclede Gas Company, which serves
metropolitan St. Louis and to which MRT provides service under several long-
term firm transportation and storage agreements and an agency agreement. The
FERC has jurisdiction over MRT with regard to its interstate pipeline business.
See "Regulation".
The Company owns and operates seven gas storage fields. Four storage
fields are associated with NGT's pipeline and have a combined maximum
deliverability of approximately 655 million cubic feet ("MMcf") per day and a
working gas capacity of approximately 22.4 Bcf. NGT also owns a 1/12 interest
in Koch Gateway Pipeline Company's Bistineau storage field which provides an
additional 100 MMcf per day of deliverability and additional working gas
capacity of 8 Bcf. The two largest NGT storage fields are located in Oklahoma:
the Ada field - capable of delivering approximately 330 MMcf per day, and the
Chiles Dome field - capable of delivering 265 MMcf per day. The other NGT
storage fields, Ruston and Collinson, are located near Ruston, Louisiana and
Winfield, Kansas, respectively. The Collinson storage field is currently being
prepared for abandonment. Three storage fields are associated with MRT's
pipeline and have a maximum aggregate deliverability of approximately 580 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 1996, 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.
6
<PAGE> 10
Consolidated revenue and throughput data for Pipeline is as follows:
<TABLE>
<CAPTION>
INTERSTATE PIPELINES
- -----------------------------------------------------------------------
(in millions of dollars) YEAR ENDED DECEMBER 31,
OPERATING REVENUES 1996 1995 1994
- -----------------------------------------------------------------------
<S> <C> <C> <C>
Sales $ 86.4 $ 100.8 $ 162.4
Transportation 260.4 245.9 238.2
- -----------------------------------------------------------------------
Total $ 346.8 $ 346.7 $ 400.6
=======================================================================
</TABLE>
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
(million MMBtu) YEAR ENDED DECEMBER 31,
THROUGHPUT 1996 1995 1994
- -------------------------------------------------------------------
<S> <C> <C> <C>
Sales 33.2 51.7 45.9
Transportation 952.0 974.3 831.8
FERC Order 636 Elimination (1) (31.3) (49.7) (42.6)
- -------------------------------------------------------------------
Total 953.9 976.3 835.1
===================================================================
</TABLE>
(1) When sold volumes are also transported by Pipeline, the throughput
statistics will include the same physical volumes in both the sales and
transportation categories, requiring an elimination to prevent the
overstatement of actual total throughput. No elimination is made for
volumes of 204.2 million MMBtu, 196.6 million MMBtu and 145.8 million
MMBtu in 1996, 1995 and 1994, respectively, which were transported on
both the NGT and MRT systems.
During the 1980s, the Company, as most other pipelines, was compelled to
resolve a number of significant disputes with its suppliers under contracts
which allegedly required the Company to take or, if not taken pay for,
quantities of gas in excess of its available sales markets and/or at prices
generally above the levels required by such markets. These disputes, generally
referred to as "take-or-pay" claims, have been resolved in a number of ways,
including both buy-out/buy-downs and payments for gas in advance of its
delivery. In the third quarter of 1989, the Company recorded a pre-tax Special
Charge of $269 million related to these claims. The amount shown as "Gas
purchased in advance of delivery" in the Company's Consolidated Balance Sheet
and the component of "Investments and other assets" bearing the same caption
represent, in substantial part, amounts paid to suppliers in conjunction with
the above referenced settlements. These prepayments for gas have been recorded
at their net realizable value and, to the extent that the Company is unable to
realize at least this amount through sale of the gas as delivered over the life
of these agreements, its earnings will be adversely affected, although such
impact is not expected to be material.
In addition to these prepayments, the Company is committed under certain
agreements to purchase certain quantities of gas in the future. At December
31, 1996, the Company had the following gas take commitments under its
agreements which are not variable-market-based priced:
<TABLE>
<CAPTION>
VOLUME VALUE AVERAGE
(MILLIONS OF ($ IN PRICE
MMBTU) MILLIONS) ($/MMBTU)
------ --------- ---------
<S> <C> <C> <C>
1997 14.8 $32.1 $2.17
1998 11.6 24.8 2.14
1999 5.8 13.1 2.25
2000 0.6 2.1 3.47
Beyond 2000 0.5 $ 1.7 $3.47
</TABLE>
7
<PAGE> 11
At December 31, 1996, 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 $3.53/MMBtu:
<TABLE>
<CAPTION>
VOLUME VALUE AVERAGE
(MILLIONS OF ($ IN PRICE
MMBTU) MILLIONS) ($/MMBTU)
------ --------- ---------
<S> <C> <C> <C>
1997 139.0 $507.9 $3.65
1998 5.5 12.3 2.24
1999 4.3 9.2 2.15
2000 3.7 $ 8.3 $2.24
Beyond 2000 -- -- --
</TABLE>
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 operates an ongoing risk management program designed to limit the
Company's exposure from its obligations under these commitments, (see Notes 1
and 7 of Notes to Consolidated Financial Statements). To the extent that the
Company expects that these commitments will result in losses over the contract
term, the Company has established reserves equal to such expected losses.
WHOLESALE ENERGY MARKETING
The Company's marketing of natural gas and risk management services to natural
gas resellers and certain large volume industrial consumers is principally
conducted by NES, together with certain affiliates. NES historically has
operated primarily in those states served by the NGT and MRT systems but
recently has had significant sales in various other states as it seeks to
extend its activities throughout North America. In addition, in recent
periods, NES has begun to market electricity in wholesale markets.
NES markets gas under daily, baseload and term agreements which include
either market sensitive or fixed pricing provisions. In general, fixed-priced
sales or purchase contracts are hedged using gas futures contracts or other
derivative financial instruments. See Notes 1 and 7 of Notes to Consolidated
Financial Statements. 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 volume for 1996 was approximately 877.1 Bcf of
which approximately 80.2% 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.
NATURAL GAS GATHERING
On February 1, 1995, pursuant to a "spindown" order from the FERC, the Company
transferred the natural gas gathering assets of NGT into the Company's wholly
owned subsidiary, NorAm Field Services Corp. ("NFS"). These assets consist
principally of approximately 3,600 miles of gathering pipelines which collect
gas from more than 200 separate systems located in major producing fields in
Oklahoma, Louisiana, Arkansas and Texas. NFS is not generally subject to cost-
of-service regulation, although the spindown order required that it offer to
continue through January 31, 1997, any pre-existing gathering services
generally under the terms of NGT's tariff, including the applicable stated
maximum gathering rate of $0.1417 per MMBtu (the "Default Contract"), except to
the extent that separate terms and conditions have been negotiated. Various
parties, including NFS, appealed certain of the FERC's findings before the D.C.
Circuit Court of Appeals, which upheld the FERC's findings that the facilities
and services are nonjurisdictional and remanded the matter to FERC to justify
imposition of the Default Contract condition. On February 18, 1997, the U. S.
Supreme Court denied cert. on the appeal of the D. C. Circuit Court of Appeals
order. The Company expects that efforts will be made in certain states to
enact legislation to regulate gathering rates and services but the Company
currently expects that any such efforts will be successful only to the extent
of providing for complaint-type proceedings alleging undue
8
<PAGE> 12
discrimination or similar "light-handed" regulatory approaches. Natural Gas
Gathering also includes gas processing, liquids extraction and marketing
activities, generally in conjunction with certain of NFS's gathering
activities. In the future, the majority of NFS's current gas processing
activities will be conducted by Waskom Gas Processing Company, a joint venture
of NFS and NGC Corp. (an affiliate of Natural Gas Clearinghouse).
RETAIL ENERGY MARKETING
The Company's marketing of natural gas and other energy services to those
industrial and commercial customers located behind the "city gate" of local gas
distribution companies but not utilizing traditional "bundled" utility service,
as well as certain industrial customers served by third-party pipelines on
which the Company holds capacity, is principally carried out by NorAm Energy
Management, Inc., together with certain affiliates (collectively, "NEM").
Certain of NEM's activities, while not subject to traditional cost-of-service
rate determination, are subject to the jurisdiction of various regulatory
bodies as to the allocation of joint costs between such activities and certain
of the Company's regulated activities. NEM significantly expanded its product
offerings and market coverage in 1996, opening retail energy sales offices in
Columbus, Ohio and Edison, New Jersey. NEM's sales to its largest customer
represented 38.4 Bcf (19.3%), 38.3 Bcf (22.6%), and 11.9 Bcf (10.2%) of NEM's
natural gas sales volumes of 198.7 Bcf, 169.7 Bcf, and 116.6 Bcf in 1996, 1995,
and 1994 respectively.
MARKET FACTORS
The Company's business is generally affected by a number of market factors,
including competition, seasonality and the general economic climate.
Increasingly, the activities of the Company's Interstate Pipelines, Wholesale
Energy Marketing and Retail Energy Marketing units are most significantly
affected by national trends in these areas. On the other hand, the results of
the Company's Natural Gas Distribution units continue to be influenced most
significantly by local trends in these factors.
Historically, competition in the sale and transportation of natural gas
was limited due to the pervasive nature of the regulation of the industry and
the long-term nature of the service obligations assumed by its participants.
As a result, the Company's results of operations were largely affected by local
factors, including the effects of local regulation. Over the past few years,
however, regulatory and economic developments have significantly reduced the
influence of such factors, particularly with respect to the Company's
Interstate Pipelines, Wholesale Energy Marketing and Retail Energy Marketing
operations. At the federal level, regulations governing natural gas
transmission and marketing have been redesigned in order to promote intense
competition between natural gas transporters and marketers. From an economic
perspective, in recent years the energy industry, including the natural gas
industry, has been characterized by a surplus of product deliverability (and,
in the case of natural gas transportation in certain locations during certain
seasons, a surplus of capacity), which also has increased the level of
competition.
Currently, the Company generally faces competition in all aspects of its
operations, both from other companies engaged in the natural gas business and
from companies providing other energy products. This has an effect both on the
quantity of the services sold by the Company and the prices it receives. At
all levels of the industry in which the Company is engaged, competition
generally occurs on the basis of price, the ability to meet individual customer
requirements, access to supplies and markets and reliability. In the current
environment, the ability of the Company to respond to this competition is tied
directly to its ability to maintain operational flexibility, achieve low
operating costs and maintain continued access to reliable sources of
competitively priced gas and a broad range of gas markets.
These developments have had the effect of increasing the number of
competitors and competitive options faced by the Company. As a consequence,
changes in the market for natural gas and gas transportation services at the
national level increasingly influence the demand and prices paid for the
natural gas and gas transportation services offered by the Company.
Additionally, to the extent that the customers served by those units are
relatively large volume customers using gas to meet industrial or electric
power generation requirements, the Company faces significant competition from
fuel oil, waste products used as a source of fuel for the generation of process
heat or steam, energy conservation products, and, with respect to electric
generation customers, low cost energy available to such customers from other
electric generators.
9
<PAGE> 13
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 1 of Notes to Consolidated
Financial Statements. These trends in competition are expected to continue,
although not necessarily at the same rate as in the past.
The Company's distribution units also face competition. As with
customers served by the Company's transmission and marketing units, over the
last few years the Company's small industrial and large commercial customers
served through its distribution units increasingly have been the target of
other companies engaged in the natural gas business seeking to sell gas
directly or transport third-party gas to customers currently served through the
Company's distribution units. In some cases, these other companies seek to
provide such service through newly constructed facilities, thereby bypassing
the facilities installed by the Company to serve such customers. The Company
has met such competition by adopting new programs which, in some instances,
have provided its competitors with access to its sales customers, but through
the use of the Company's facilities. The Company also faces competition with
respect to such customers from fuel oil, electricity, energy conservation
products, and in certain instances, liquefied petroleum gas.
While with certain limited exceptions, the Company currently is not in
direct competition with any other distributors of natural gas with respect to
its existing small commercial and residential customers, the Company
nevertheless faces significant competition for such customers from electric
utilities and providers of energy conservation products. Moreover, while the
Company currently holds franchises in almost all of the communities which it
serves, such franchises generally are not by their terms exclusive and
competition has been experienced in certain instances as the Company has sought
to extend service from existing service areas to geographically adjacent areas.
In addition to competition, the Company's business is also affected at
all levels by the seasonality of weather and general economic conditions.
Because one of the significant markets for natural gas is use in space heating,
demand for natural gas and gas transportation services is generally seasonal in
nature. The Company has obtained rate design changes in its regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to changes in natural gas consumption prompted by seasonal weather
patterns. Additionally, in recent years, the Company's transmission and
marketing units have increased the volume of their off-season sales by
expanding their markets to include additional industrial users of gas,
gas-fired electric generators, and customers seeking gas in the summer to fill
storage. Even with increased summer demand, however, the price of natural gas
and gas transportation services continues to be seasonal in nature, with prices
generally significantly lower in the summer than in winter. While the Company's
distribution units also have sought to increase the level of their off-season
sales, the opportunity to do so within their historic service areas is limited.
General economic conditions also significantly influence the demand for
gas. The national demand for gas has increased in recent years and currently
is expected to continue to increase in future years. This, in turn, at certain
times and in certain market segments, has influenced the price for natural gas
and gas transportation services. However, this increased 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 cannot readily redirect their activities to
other markets when the demand for gas in their local service areas declines.
In recent years, the level of economic activity in the areas served by these
units has remained relatively stable.
REGULATION
The Company's business operations are significantly affected by regulation.
This regulation occurs at all levels -- federal, state and local -- and has the
effect, among other things, of: (i) requiring that the Company seek and obtain
certain approvals before it may undertake certain acts, (ii) regulating the
level of rates which the Company may charge for certain of its services and
products, and (iii) imposing certain conditions on the Company's conduct of its
business. Specifically, since the Company's December 31,
10
<PAGE> 14
1992 sale of its oil and gas exploration and production business, the
substantial majority of the Company's earnings have been attributable to
operations which are rate regulated. The operations of the Natural Gas
Distribution and Interstate Pipelines business units are subject to rate
regulation, while the operations of Wholesale Energy Marketing, Retail Energy
Marketing and Natural Gas Gathering are not generally subject to direct
regulation as to the rates which may be charged.
The Company is significantly affected by the regulations of the FERC.
The changes to the industry brought about by FERC Order 636, which was largely
affirmed on appeal by the U.S. Court of Appeals, D.C. Circuit, and addressed by
FERC on remand in Order No. 636-C issued on February 27, 1997, also have
affected and will continue to affect the business environment in which the
Company's local distribution units operate in those geographical areas where
gas supplies are delivered on interstate pipelines. The impact is less
pronounced in the case of Entex, where a significant portion of supplies are
delivered on intrastate pipelines. FERC Order 636 has increased, and in some
cases likely will continue to increase, the number and diversity of potential
suppliers and products available to meet the supply needs of each unit. In
addition, the requirement that pipelines "unbundle" their services permits the
Company's distribution units to avoid the purchase -- and, thus, the cost -- of
services which they do not require. On the other hand, the elimination of the
right of local distribution companies to require service from interstate
pipelines in the absence of a contract will expose local distributors to an
increased risk of supply disruption and the potential for increased review from
some state regulatory agencies. In addition, the ability of holders of firm
transportation capacity entitlements to assign their capacity rights to other
parties, coupled with the ability of those holders to change the points at
which that capacity is used, likely will increase the competitive pressures
faced by local distributors. This is because such provisions will expand the
incentives for and capabilities of third parties to build new facilities
extending 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.
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 sales services. 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 rate-regulated services provided by
the Company at retail.
See "Material Changes in the Results of Continuing Operations -
Regulatory Matters" for a discussion of recent significant regulatory actions
and developments relating to Natural Gas Distribution and Interstate Pipelines.
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.
11
<PAGE> 15
ENVIRONMENTAL MATTERS
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. For a discussion of certain legal proceedings
relating to environmental matters, see "Legal Proceedings."
With the acquisition of Diversified Energies, Inc. ("DEI") in November
1990, the Company acquired Minnegasco which owns or is otherwise associated
with a number of sites where manufactured gas plants ("MGP's") were previously
operated. Minnegasco and its predecessors operated a manufactured gas plant
until 1960, 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 remediation plan. There are six
other former MGP sites in the Company's Minnesota service territory. 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. See
"Management Analysis - Commitments and Contingencies - Environmental Matters"
for a discussion about the estimated range of remediation costs and the
potential for rate and insurance recovery of remediation costs.
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 remains 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 under "Management
Analysis - Commitments and Contingencies - Environmental Matters," 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
remains in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
While the nature of environmental contingencies makes complete
evaluation impracticable, the Company currently is aware of no other
environmental matter which could reasonably be expected to have a material
impact on the results of operations, financial position or cash flows of the
Company.
Other legislative proposals affecting the industry have been and may be
introduced before the Congress and state legislatures, and the FERC and various
state agencies currently have under consideration various policies and
proposals, in addition to those discussed above, that may affect the natural
gas industry. It is not possible to predict what actions, if any, the
Congress, the FERC or the states will take on these matters, or the effect any
such legislation, policies, or proposals may have on the activities of the
Company.
MERGERS, ACQUISITIONS AND DISPOSITIONS
As described in more detail above, the Merger Agreement is expected to result
in the merger of the Company with and into a wholly owned subsidiary of Houston
Industries, such that the Company will ultimately become a wholly owned
subsidiary of HII. The Merger Agreement was approved and adopted at Special
Meetings of Stockholders of the Company and of Houston Industries on December
17, 1996. The Company, Houston Industries and HL&P are in the process of
obtaining regulatory approvals necessary to close the Transaction. Approvals
have been received from all state regulatory commissions and municipalities
whose prior approval was required. In addition, the pre-merger notification
period prescribed under the Hart-Scott-Rodino Antitrust Improvements Act of
1976 has expired. There remains pending with the U. S. Securities and Exchange
Commission (the "SEC") an application by Houston
12
<PAGE> 16
Industries for an order exempting HII from regulation as a registered public
utility holding company under the Public Utility Holding Company Act of 1935
following the merger. It is the Company's and Houston Industries' current
intention to defer closing until the SEC issues its ruling on the exemption
request regarding the Basic Mergers, although there are two alternative
structures, one of which would not require SEC approval. Additional
information concerning the alternative structures, as well as other information
about the Transaction, is contained in the Joint Proxy Statement/Prospectus of
Houston Industries, HL&P and the Company dated October 29, 1996. Adoption of
either of these alternative structures, however, would require that the Company
and Houston Industries make new filings to obtain the various state and
municipal regulatory approvals because, thus far, such approvals were only
obtained for the Basic Mergers.
In September 1996, a subsidiary of the Company, NES, which is engaged,
among other things, in the business of power marketing in interstate commerce
at market-based rates, filed a notification with the FERC advising of its
pending change in status by virtue of the Transaction. On February 5, 1997,
the FERC initiated a jurisdictional inquiry (the "Order") to determine whether
its prior approval of the Transaction is required under Section 203 of the
Federal Power Act (the "FPA"). FERC directed NES, within 30 days of the Order
to either, set forth its views as to whether such prior approval may be
required because of the jurisdictional status of NES as a power marketer or
submit an application for approval of the Transaction under Section 203 of the
FPA. On March 7, NES filed a response with the FERC stating its view that
FERC does not have jurisdiction over the Transaction. Although the NES
response disclaimed any FERC jurisdiction over the merger, the response
acknowledged that one of the options being considered was to file an
application with FERC for approval of the Transaction under Section 203 of the
FPA, in anticipation of an expedited review under the FERC's new merger
guidelines. The Company continues to believe that the Transaction will be
completed as contemplated, although, in light of the pending regulatory issues
as described herein, the Company cannot predict with any certainty when the
Transaction will be consummated.
In addition to the Transaction described herein, 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. 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 September of 1993, the sale of the LIG Group in June
of 1993 and the sale of Minnegasco's Nebraska distribution properties in
February 1993, and as described more fully below, the sale of the Company's
exploration and production business in December 1992, the sale of Dyco
Petroleum and the acquisition of The Hunter Company in 1991, its merger with
DEI, the parent company of Minnegasco in 1990, its acquisition of the LIG Group
in 1989 and its merger with Entex in 1988. The Company reviews possible
transactions from time to time and may engage in other business combinations in
the future that are not specifically described herein.
On December 31, 1992, the Company completed the sale of the stock of
Arkla Exploration Company ("AEC") to Seagull Energy Corporation ("Seagull") for
approximately $397 million in cash. 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 conjunction with the sale, the Company agreed to indemnify
Seagull against certain exposures, for which the Company has established
reserves equal to anticipated claims under the indemnity.
The Company previously conducted operations in the radio communications
business through E. F. Johnson ("Johnson") and the energy measurement business
through EnScan, Inc. ("EnScan") which were acquired in conjunction with the
merger with DEI. In early 1992, EnScan merged with Itron, Inc. ("Itron") of
Spokane, Washington, of which, the Company owned at December 31, 1996, common
stock representing ownership of approximately 11.2% of the combined enterprise,
which is managed by Itron. In December 1994 and January 1995 the Company sold
a total of 480,000 shares of Itron common stock in a public offering, resulting
in the reduction of the Company's stock ownership percentage of Itron common
stock from 18.5% to the current 11.2%. Based on price quotations on the
NASDAQ, the market value of the Company's interest was approximately $29.3
million at March 14, 1997. In July 1992, the Company sold the stock of Johnson
for total consideration of approximately $40 million, receiving cash
13
<PAGE> 17
proceeds of approximately $15 million at closing and retaining an investment
currently valued at approximately $5 million.
EMPLOYEES
The Company employs approximately 6,434 persons, 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 "Interstate Pipelines".
ITEM 3. LEGAL PROCEEDINGS
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the Transaction or to rescind the Transaction
and/or to recover damages in the event that the Transaction is consummated.
The complaint alleges, among other things, that the merger consideration is
inadequate, that the Company's Board of Directors breached its fiduciary duties
and that Houston Industries aided and abetted such breaches of fiduciary
duties. In addition, the plaintiff seeks certification as a class action. The
Company believes that the claims are without merit and intends to vigorously
defend against the lawsuit. The Company does not believe that the matter will
have a material adverse effect on the financial position, results of operations
or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company, that the Company, through one of its subsidiaries, and
together with several other unaffiliated entities, have been named under state
law as potentially responsible parties with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any are incurred. However, considering the information currently
known about the site and the involvement of the Company and its subsidiaries
with respect to the site, the Company does not believe that the matter will
have a material adverse effect on the financial position, results of operations
or cash flows of the Company.
On October 24, 1994, the United States Environmental Protection Agency
(the "EPA") 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. The EPA is continuing to investigate the possibility
that other companies may have sent waste material to this site. 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.
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 theses matters will not be
material.
14
<PAGE> 18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At a special meeting of the Company's stockholders held on December 17,
1996, the stockholders of the Company approved and adopted the Merger
Agreement. The number of votes cast for, cast against or withheld, as well as
the number of abstentions and broker non-votes, with respect to approval of the
Merger Agreement are as follows:
<TABLE>
<S> <C>
Votes in Favor: 106,258,830
Votes Against or Withheld: 809,775
Abstentions: 356,850
Broker Non-Votes: None
</TABLE>
15
<PAGE> 19
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 25, 1997:
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE DURING
NAME AGE PAST 5 YEARS
---- --- ------------
<S> <C> <C>
Rollie B. Bohall 50 Senior Vice President and Chief
Operating Officer of NorAm Energy
Management, Inc., 3/95 to present,
Senior Vice President, Large Volume
Sales and Gas Supply, Entex
Michael B. Bracy 55 Executive Vice President and Principal
Financial Officer of the Company,
10/91 to present, Chief Executive
Officer, Arkla Pipeline Group and
Executive Vice President of the
Company from at least 1/90 to 10/91
Michael A. Creel 43 Vice President and Treasurer of the
Company from 10/95 to present,
Assistant Treasurer of Corporate
Finance of Enron Corp. and Treasurer
of Enron Oil & Gas Company
Dale C. Earwood 41 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
Jack W. Ellis, II 44 Vice President and Controller of the
Company, 12/89 to present
Hubert Gentry, Jr. 65 Senior Vice President and General
Counsel of the Company, 8/90 to
present, Secretary of the Company,
7/92 to present
</TABLE>
16
<PAGE> 20
<TABLE>
<CAPTION>
BUSINESS EXPERIENCE DURING
NAME AGE PAST 5 YEARS
---- --- ------------
<S> <C> <C>
T. Milton Honea 64 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
Robert N. Jones 44 President and Chief Operating Officer
of Entex, 1/95 to present, Executive
Vice President of Entex, 4/94 to 1/95,
Vice President & Manager of Houston
Division, 3/92 to 4/94, Vice President
& Manager of Mississippi Division,
from at least 1/90 to 3/92
William A. Kellstrom 55 Senior Vice President, Corporate
Business Development, 7/95 to present,
President of NorAm Energy Services,
Inc., 9/92 to 7/95, President of
Tenaska Marketing Ventures from at
least 1/90 to 9/92
Michael H. Means 49 President and Chief Operating
Officer, Arkansas Louisiana Gas
Company, 10/91 to present, Vice
President Arkansas Division, Arkansas
Louisiana Gas Company from at least
1/90 to 10/91
Charles M. Oglesby 44 President of NorAm Trading and
Transportation Group, Inc., 3/95 to
present, Vice President of Coastal
Corporation and President and Chief
Executive Officer of Coastal Gas
Services Company
Gary N. Petersen 44 President and Chief Operating Officer
of Minnegasco 9/91 to present
Rick L. Spurlock 51 Senior Vice President, Human Resources
of the Company, 12/90 to present
</TABLE>
17
<PAGE> 21
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The common stock of the Company is listed for trading on the New York Stock
Exchange under the symbol "NAE". At December 31, 1996, there were 42,251
common stockholders of record. The pending merger with Houston Industries
will, if consummated, result in the Company's common stock being wholly owned
by Houston Industries, see "Business" elsewhere herein. See "Management
Analysis - Net Cash Flows from Financing Activities" for a discussion of
dividend limitations. Following is selected data concerning the Company's
common stock price and cash dividends paid:
<TABLE>
<CAPTION>
COMMON CASH DIVIDENDS
1996 STOCK PRICE PER SHARE
============================================================================
Quarter High Low Common Preferred
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1st $ 9 3/8 $ 7 7/8 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
2nd $ 11 1/8 $ 8 3/8 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
3rd $ 14 7/8 $ 10 1/4 $ 0.07 $ -- (1)
- ----------------------------------------------------------------------------
4th $ 15 1/2 $ 14 3/4 $ 0.07 $ -- (1)
- ----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
COMMON CASH DIVIDENDS
1995 STOCK PRICE PER SHARE
============================================================================
Quarter High Low Common Preferred
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1st $ 6 $ 5 1/8 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
2nd $ 6 3/4 $ 5 1/4 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
3rd $ 8 1/8 $ 6 1/4 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
4th $ 9 $ 7 5/8 $ 0.07 $ 0.75
- ----------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
COMMON CASH DIVIDENDS
STOCK PRICE PER SHARE
===========================================================================
High Low Common Preferred
- ---------------------------------------------------------------------------
<C> <C> <C> <C> <C>
1994 $ 9 $ 5 1/4 $ 0.28 $ 3.00
- ---------------------------------------------------------------------------
1993 $ 10 5/8 $ 7 3/8 $ 0.28 $ 3.00
- ---------------------------------------------------------------------------
1992 $ 12 3/8 $ 6 7/8 $ 0.48 $ 3.00
- ---------------------------------------------------------------------------
</TABLE>
(1) The Company's Convertible Exchangeable Preferred Stock, Series A was
exchanged for its 6% Convertible Subordinated Debentures due 2012 in June
1996, see "Management Analysis - Net Cash Flows from Financing
Activities".
18
<PAGE> 22
ITEM 6. 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. In June 1993, the Company completed the sale of its
intrastate pipeline business as conducted by Louisiana Intrastate Gas
Corporation ("LIG") to Equitable Resources, Inc. for $191 million in cash,
recognizing a pre-tax gain of approximately $17.7 million (the associated tax
expense was approximately $14.3 million). LIG's transactions and balances,
representing operating income of $25.1 million and $5.6 million for 1992 and
the six months ended June 30, 1993, respectively, are included with those of
the Company until its sale. In December 1993, the Company recorded a $34.2
million pre-tax charge (the associated tax benefit was approximately $13.4
million) resulting from a comprehensive settlement which terminated or modified
a number of contractual arrangements with a gas supplier. The Company had
significant sales of distribution properties during 1993 and 1994, and had a
significant charge for early retirement and severance during 1996, see "Natural
Gas Distribution" and "Interstate Pipelines" under "Management Analysis"
elsewhere herein.
In August 1996, the Company signed a definitive agreement which is
expected to result in the merger of the Company with and into a wholly owned
subsidiary of Houston Industries Incorporated, see "Merger With Houston
Industries" under "Management Analysis" elsewhere herein.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------
(millions of dollars, except per share amounts) 1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues (1) $ 4,788.5 $ 2,964.7 $ 2,857.9 $ 2,988.3 $ 2,782.2
- ---------------------------------------------------------------------------------------------------------------
Income from continuing operations $ 95.1 $ 65.5 $ 51.3 $ 39.9 $ 6.2
- ---------------------------------------------------------------------------------------------------------------
Income (loss) from continuing operations
per common share (2) $ 0.70 $ 0.47 $ 0.36 $ 0.26 $ (0.01)
- ---------------------------------------------------------------------------------------------------------------
Total assets $ 4,017.5 $ 3,666.0 $ 3,561.5 $ 3,727.8 $ 4,059.0
- ---------------------------------------------------------------------------------------------------------------
Long-term debt, less current maturities $ 1,054.2 $ 1,474.9 $ 1,414.4 $ 1,629.4 $ 1,783.1
- ---------------------------------------------------------------------------------------------------------------
Trust preferred (3) $ 167,768 $ -- $ -- $ -- $ --
- ---------------------------------------------------------------------------------------------------------------
Dividends per common share $ 0.28 $ 0.28 $ 0.28 $ 0.28 $ 0.48
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
(1) The increase in operating revenues from 1995 to 1996 was principally due
to an increased level of natural gas marketing activities and, to a
lesser extent, increased sales prices and volumes in natural gas
distribution, see "Wholesale Energy Marketing", "Retail Energy
Marketing" and "Natural Gas Distribution" under "Material Changes in the
Results of Continuing Operations" included in "Management Analysis"
elsewhere herein.
(2) Computed after reduction for the preferred dividend requirement of $7.8
million in each year prior to 1996. Approximately $3.6 million of
preferred dividends were recorded during 1996 prior to the June 1996
exchange of the Company's Convertible Exchangeable Preferred Stock,
Series A for its 6% Convertible Subordinated Debentures due 2012, see
"Net Cash Flows from Financing Activities" under "Management Analysis"
elsewhere herein. In 1996, the only year in which the calculation is
relevant, fully diluted earnings per share from continuing operations
was $0.66 per share, see "Earnings per Share" included in Note 1 of the
accompanying Notes to Consolidated Financial Statements.
(3) Issued in June 1996, see "Net Cash Flows from Financing Activities"
under "Management Analysis" elsewhere herein.
ITEM 7. MANAGEMENT ANALYSIS
MERGER WITH HOUSTON INDUSTRIES
On August 11, 1996, the Company entered into an Agreement and Plan of Merger
(the "Merger Agreement") with Houston Industries Incorporated ("Houston
Industries" or "HI"), Houston Lighting & Power Company ("HL&P") and a newly
formed Delaware subsidiary of Houston Industries ("HI Merger, Inc."). Under the
Merger Agreement, the Company would merge with and into HI Merger, Inc. and
would become a wholly owned subsidiary of HII (as defined following). Houston
Industries would merge with and into HL&P, which would be renamed Houston
Industries Incorporated ("HII") (the term "Transaction" refers to the business
combination between Houston Industries and the Company). Consideration for the
purchase of the Company's common stock would be a combination of cash and
shares of HI common stock, valued at approximately $3.8 billion, consisting of
approximately $2.4 billion for the Company's common stock and equivalents and
approximately $1.4 billion in assumption of the Company's debt. Additional
information concerning the Merger Agreement is contained in the Joint
19
<PAGE> 23
Proxy Statement/Prospectus of Houston Industries, HL&P and the Company dated
October 29, 1996 ("the Proxy/Prospectus").
The Merger Agreement was approved and adopted at Special Meetings of
Houston Industries' and the Company's stockholders held on December 17, 1996.
The Company and HI proceeded to obtain required state and municipal regulatory
approvals, all of which have been obtained, and to request an exemption from
the Securities and Exchange Commission ("the SEC") which would allow the
Transaction to take place under its preferred structure without subjecting
post-merger HII to the requirements of the Public Utility Holding Company Act.
It is HI's and the Company's intention to defer the closing of the Transaction
until the SEC issues its ruling on the exemption request although, as set forth
in the Proxy/Prospectus, there are two alternative structures, one of which
would not require SEC approval. Adoption of either of these structures,
however, would require that the Company and HI make new filings to obtain the
various state and municipal regulatory approvals.
In early February 1997, the Federal Energy Regulatory Commission ("the
FERC" or "the Commission") issued an order ("the Order") advising the Company
that the Transaction "...may require Commission approval pursuant to section
203 of the FPA" ( the "FPA" refers to the Federal Power Act), and directing the
Company to file a response within 30 days of the Order either "...(1) providing
arguments as to why the transaction does not require Commission authorization
under section 203 or (2) an application under section 203". In early March
1997, the Company filed a response to the Order stating its view that the FERC
does not have jurisdiction over the Transaction. Although such response
disclaimed any FERC jurisdiction over the Transaction, it also indicated that
one option being considered was to file an application with the FERC for
approval of the Transaction in anticipation of an expedited review under the
FERC's newly-issued merger policy guidelines. On March 27, 1997, the Company
filed an application under section 203 of the FPA seeking FERC approval of the
Transaction, although continuing to assert its position that such approval is
not required.
The Company continues to believe that the Transaction will be completed
as contemplated although, in light of the pending regulatory issues as set
forth preceding, the Company cannot predict with any degree of certainty when
the Transaction will be consummated.
ORGANIZATION AND ACCOUNTING POLICIES
NorAm Energy Corp., referred to herein together with its consolidated
subsidiaries and divisions (all of which are wholly owned) as "NorAm" or "the
Company", principally conducts activities in the natural gas industry,
including gathering, transmission, marketing, storage and distribution which,
collectively, comprise in excess of 90% of the Company's total revenues, income
or loss and identifiable assets. The Company also makes certain non-energy
sales and provides certain non-energy services, principally to certain of its
retail natural gas distribution customers, see "Retail Energy Marketing" under
"Material Changes in the Results of Continuing Operations" elsewhere herein.
The Company's activities historically have been limited to the 48 contiguous
states, principally Texas, Louisiana, Mississippi, Arkansas, Oklahoma, Missouri
and Minnesota, although the Company has made sales in Mexico and Canada and is
investigating opportunities for international investment, as discussed
following. A significant portion of the Company's activities are subject to
rate regulation, see "Regulatory Matters" elsewhere herein. The Company
previously conducted operations in the oil and gas exploration and production
and radio communications businesses which were discontinued in 1992 and 1991,
respectively. In recent years, the Company has engaged in several transactions
with respect to its distribution properties and completed the sale of Louisiana
Intrastate Gas Corporation on June 30, 1993. For additional information on
these matters, see "Discontinued Operations" and the discussions by business
unit under "Material Changes in the Results of Continuing Operations"
following.
The reader is directed to Note 1 of the accompanying Notes to
Consolidated Financial Statements for a discussion of the Company's significant
accounting policies.
20
<PAGE> 24
MATERIAL CHANGES IN THE RESULTS
OF CONTINUING OPERATIONS
GENERAL
In recognition of the manner in which the Company manages its portfolio of
businesses, and in order to facilitate a more detailed understanding of the
various activities in which the Company engages, the Company has segregated its
results of operations into (1) Natural Gas Distribution, (2) Interstate
Pipelines, (3) Wholesale Energy Marketing, (4) Natural Gas Gathering, (5)
Retail Energy Marketing and (6) Corporate and Other. The Company's results of
operations are seasonal due to weather-related fluctuations in the demand for
and price of natural gas although, as discussed following and elsewhere herein,
(1) the Company has obtained rate design changes in its rate-regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to seasonal weather patterns (further such changes may occur) and (2)
the Company is seeking to derive a larger portion of its earnings from
businesses which exhibit less earnings seasonality.
Since the Company's December 1992 sale of its oil and gas exploration
and production business, the substantial majority of the Company's earnings
have been attributable to operations which are rate regulated. While these
businesses have been subjected to varying levels of competition through changes
in the form of regulation (further such changes may occur), in general, they
continue to be regulated on a cost-of-service basis and the potential for
growth in earnings and increased rates of return is limited. The Company seeks
to improve its returns from these businesses through increased efficiency,
aggressive marketing and by rate initiatives which allow these businesses to
compete more effectively and retain more of the value added through improved
operations and expanded services.
The Company continues to believe that its greatest potential for
significant increases in overall profitability lies in those businesses which
are, in some instances, subject to regulation as to the nature of services
offered, the manner in which services are provided or the allocation of joint
costs between cost-of-service regulated and other operations, but generally are
not subject to direct regulation as to the rates which may be charged. Such
operations are sometimes referred to herein for convenience as "unregulated".
The Company has separated its strategically significant unregulated activities
into discrete management units and formulated plans for increasing the future
financial contribution from these businesses. The Company has and expects to
continue to (1) expand both the range of products and services offered by these
businesses and the geographic areas served and (2) increase the percentage of
the Company's overall earnings derived from these activities.
In addition, the Company is investigating opportunities for
international investment. To date, the Company's efforts have focused on
opportunities emerging in Latin America due to privatization initiatives
currently underway in a number of countries, as well as broad-based efforts to
encourage international investment. While such investments involve increased
risks such as political, economic or regulatory instability and foreign
currency exchange rate fluctuations, the Company believes that, together with
carefully selected partners (both within the target countries and otherwise),
it can effectively apply its natural gas industry expertise to selected
projects in Latin America, thereby increasing its overall returns on invested
capital while keeping the increased risk within acceptable limits. In general,
the international investment is expected to build up gradually over a period of
years as the Company (1) identifies and creates working relationships with
strategic business partners, (2) selects projects which meet its risk/return
requirements, (3) develops specific country experience and (4) in some cases,
increases its investment in specific projects as facilities are constructed,
see the following discussion and "Capital Expenditures - Continuing Operations"
under "Net Cash Flows from Investing Activities" elsewhere herein.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160
21
<PAGE> 25
million, with construction expected to begin no later than the fourth quarter
of 1997. The Company's ownership interest in the Consortiums, while subject to
change through continuing negotiations with its existing and potential partners
ranges from 15% to approximately 33% and, based on the expected number of
customers, represents a weighted average ownership interest of approximately
23%. Depending upon, among other factors, its ownership percentage and success
in finalizing financing arrangements at estimated levels and with expected
terms (see the discussion following), the Company currently estimates that the
net cash outflows to support its investment in the Concessions will not exceed
approximately $4 million in any year, and that its investment in the
Concessions will become a net source of cash in approximately year four.
Debt is currently expected to make up a significant portion of the
financing for the Concessions in the early years of the project, reaching a
maximum level of approximately $90 million and declining thereafter. While such
debt is expected to be without direct recourse to members of the Consortiums
("the Partners"), the terms of the debt will likely require that each Partner
enter into an agreement which commits it to make pro rata capital contributions
as funds are borrowed to finance construction, and that lenders will be granted
a security interest in such agreements. The Company is considering extending an
offer of support to its Partners such that, in the event that any Partner fails
to make capital contributions as required, the Company would make such
contributions and assume the underlying ownership interest. The Company
currently estimates that, in the event this arrangement is agreed to by all
parties and finalized, and the Company is required to assume all such
interests, the Company's maximum investment in the Concessions will not exceed
$50 million and its net cash outflows in support of the Concessions will not
exceed $18 million in any year.
In January 1997, the Company participated in a bid for a permit
authorizing the construction, ownership and operation of a natural gas
distribution system for the geographic area that includes the cities of
Chihuahua, Delicias and Cuauchtemoc/Anahuac in North Central Mexico. In March
1997, the Company learned that its group was not the successful bidder. The
Company had previously announced its intention to participate in a similar
bidding process for a permit to provide natural gas distribution service to all
or a portion of Mexico City, although no date has yet been set for submission
of bids.
REGULATORY MATTERS
In general, the Company's interstate pipelines are subject to regulation by the
FERC, while its natural gas distribution operations are subject to regulation
at the state or municipal level. Historically, all of the Company's rate-
regulated businesses have followed the accounting guidance contained in
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation" ("SFAS 71"). The Company discontinued
application of SFAS 71 to its NorAm Gas Transmission Company subsidiary ("NGT")
effective with year-end 1992 reporting, see "Interstate Pipelines" elsewhere
herein. As a result of the continued application of SFAS 71 to Mississippi
River Transmission Corporation ("MRT") and the Company's natural gas
distribution operations, the Company's consolidated financial statements
contain certain assets and liabilities which would not be recognized by
unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions, the Company's only other
significant regulatory asset is related to anticipated environmental
remediation costs, see Note 5 of the accompanying Notes to Consolidated
Financial Statements and "Environmental Matters" under "Commitments and
Contingencies" elsewhere herein. Following are recent significant regulatory
actions and developments.
NGT's Negotiated Rate Filing (Docket No. RP96-200), accepted by the FERC
on April 25, 1996, allowed NGT's rates to exceed the maximum cost-based rates
set forth in its filed tariff and/or to deviate from the current FERC-mandated
rate design. NGT has negotiated certain transactions which provide for
shippers' rates to be based on various factors such as gas price differentials
between the east and west sides of the NGT system. Therefore, in some
instances, NGT will charge and collect a negotiated rate which exceeds its
then-current maximum filed tariff rate. Appeals of the FERC's negotiated rate
policy, as well as the specific authorization granted to NGT to charge
negotiated rates, have been filed with the U.S. Court of Appeals, D.C. Circuit.
Until such time as these appeals are resolved, some uncertainty will exist as
to whether the Company may be required to refund any amounts associated with
transactions billed at above the maximum tariff rate. The Company currently
believes that any such refund will not be material. The FERC accepted NGT's 4th
annual FERC Order 528 filing (Docket No. RP96-167) effective April 1,
22
<PAGE> 26
1996, which retained the $0.03 per MMBtu commodity surcharge for continued
recovery of 75% of eligible take-or-pay costs, to the extent that collection of
such costs is supported by market conditions. The recovery of these costs,
which commenced in 1992, will continue through the year 2002 although, as a
result of the discontinuance of the application of SFAS 71 to NGT as described
preceding, no asset has been recorded in anticipation of recovery.
Additionally, in April 1996, the FERC issued certificate orders granting (1)
abandonment of NGT's Collinson Storage Facility and associated facilities and
equipment (Docket No. CP95-250), which will not result in a material gain or
loss upon abandonment and will not be abandoned until all gas has been
recovered and (2) abandonment and transfer of NGT's Line O West facilities to
NorAm Field Services Corp. ("NFS") (Docket No. RP96-105), allowing NGT to
divest itself of certain non-core facilities which supported the gas supply
function in a time when NGT was principally a merchant of natural gas.
NGT's certificated Line F Project, constructed at a total cost of
approximately $17 million, replaced a 30 mile section of the existing Line F
from Ruston to Sterlington, Louisiana, and upgraded the maximum allowed
operating pressure of the line to 1200 psig. This replacement project was
placed in service on October 31, 1996 and allows NGT to receive gas from an
interconnect with MRT located near NGT's Ruston Compressor Station. Finally, on
November 1, 1996, both MRT and NGT filed to revise their FERC tariffs,
incorporating the Gas Industry Standards Board standards in compliance with
FERC Order 587 (Docket No. RM96-1). These filings set forth each company's
standard procedures for business practices supporting nominations, allocations,
balancing, measurement, invoicing, capacity release, and standardization of
electronic communications between pipelines and their customers. Pursuant to a
FERC acceptance order, both NGT and MRT revised and refiled specified sections
of these tariffs in February 1997.
In April 1996, MRT filed a FERC Section 4 rate case (Docket No. RP96-
199) pursuant to the settlement entered into in MRT's last rate case (Docket
No. RP93-4). MRT's proposed tariff rates would increase revenues derived from
jurisdictional service by $14.7 million annually. Motion rates, subject to
refund, were implemented October 1, 1996. As a result of a prehearing
conference in December 1996, another procedural schedule was established,
setting a hearing date of July 29, 1997.
MRT filed an application (Docket No. CP95-376) requesting spindown of
all of its gathering facilities. In May 1996, the FERC issued an order
approving MRT's abandonment of its off-system gathering facilities to NFS and
further declaring such facilities exempt from FERC jurisdiction. In March 1996,
MRT filed a second application (Docket No. CP96-268), which is now pending,
seeking (1) FERC approval to abandon its remaining gathering facilities by
transfer and sale to NFS and (2) a FERC declaration that these facilities are
exempt from FERC jurisdiction.
Entex was granted annualized rate increases totaling $5.4 million during
1996. In addition to annual cost-of-service adjustments in three Texas
operating divisions (approximately $0.6 million on an annualized basis),
performance-based rates were approved and implemented in Louisiana
(approximately $2.7 million on an annualized basis, effective in June ) and
Mississippi (approximately $2.1 million on an annualized basis, effective in
October). In both Louisiana and Mississippi, Entex will be allowed to earn a
return on equity ("ROE") within an approved range. Earnings will be monitored
by the public service commissions of the respective states and, while the
provisions in each state differ slightly, to the extent that Entex's ROE falls
below the lower bounds or exceeds the upper bounds of the approved range,
adjustments will be made to either adjust rates upward or refund excess
earnings to customers.
In April 1996, the Minnesota Public Utilities Commission (the "MPUC")
voted to approve Minnegasco's Performance-Based Gas Purchasing Plan (the
"PBR"), effective from September 1, 1995 to June 30, 1998. To the extent that
Minnegasco's actual purchased gas cost is either significantly higher or lower
than specified benchmarks, the PBR will require that Minnegasco and its
customers share in the savings or additional cost, resulting in a maximum
reward or penalty of up to 2% of annual gas cost (e.g. approximately $10
million using Minnegasco's 1996 gas cost) for Minnegasco during any year.
Minnegasco made a compliance filing with the MPUC on November 1, 1996, the
first year of the PBR, which filing was approved for approximately $1 million
in March 1997.
In June 1996, the MPUC issued its order in Minnegasco's August 1995 rate
case. The MPUC granted an annual increase of $12.9 million as compared to the
requested increase of $24.3 million. Interim rates reflecting an increase of
$17.8 million had been put into effect in October 1995 subject to refund. As a
part of its decision, the MPUC granted Minnegasco full recovery of its ongoing
net
23
<PAGE> 27
environmental costs through the use of a true-up mechanism whereby any amounts
collected in rates which differ from actual costs incurred, plus carrying
charges, will be deferred for recovery or refund in the next rate case.
Minnegasco requested reconsideration on several issues. Among them were (1) a
request to give effect, in this rate case, to the Minnesota Supreme Court's
(the "Court") recent rulings (see the discussion following), and (2) a request
to deduct from any interim rate refund the additional amount that Minnegasco
would have realized from its 1993 rate case by applying the Court's ruling to
that case, which remained on appeal.
The MPUC decided in Minnegasco's 1993 rate case that (1) Minnegasco's
unregulated appliance sales and service operations are required to pay the
regulated utility operations a fee for the use of Minnegasco's name, image and
reputation ("goodwill") and (2) a portion of the cost of responding to certain
gas leak calls not be allowed in rates. Minnegasco appealed those decisions to
the Court of Appeals. On June 13, 1996, in a case appealed prior to the 1993
rate case, the Court reversed the MPUC's decisions on these two issues, finding
in Minnegasco's favor and, in July, the Court denied the MPUC's request for
rehearing.
In its December 4, 1996 Order After Reconsideration, the MPUC determined
that Minnegasco was entitled to an annual rate increase of $13.3 million as
compared to the $12.9 million granted in June 1996. The MPUC decided that
Minnegasco's unregulated appliance sales and service operations should not pay
a fee for goodwill associated with the Minnegasco name, but refused to allow
Minnegasco to recover certain costs associated with gas leak check calls, and
did not approve Minnegasco's request with respect to the 1993 rate case costs.
An appeal related to the 1993 rate case is pending before the Court of Appeals.
Minnegasco requested and, on February 20, 1997, the MPUC voted to grant a stay
of the Commission's order pending Minnegasco's appeal of the gas leak issue in
the 1995 rate case. Minnegasco is accruing for any necessary interim rate
refunds should the Court deny Minnegasco's appeal.
CHANGE IN ESTIMATED SERVICE LIVES OF CERTAIN ASSETS
Pursuant to an updated study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas pipeline and gathering assets, see "Interstate Pipelines" and
"Natural Gas Gathering" elsewhere herein. This change had the effect of
increasing the Company's 1995 income before extraordinary item by approximately
$3.2 million ($0.03 per share) and represents an annualized increase of
approximately $6.5 million.
24
<PAGE> 28
OPERATING INCOME BY BUSINESS UNIT
Following is certain information concerning the Company's operating income by
business unit, followed by detailed discussions of year-to-year operating
results by individual business unit:
<TABLE>
<CAPTION>
OPERATING INCOME (LOSS) BY BUSINESS UNIT (1)
- ------------------------------------------------------------------------------
(millions of dollars) 1996 1995 1994
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural Gas Distribution $ 183.9(2) $ 158.0 $ 145.5
Interstate Pipelines (3) 124.4(2) 103.8 105.4
Wholesale Energy Marketing 12.1 4.2 (3.0)
Natural Gas Gathering (3) 13.9 8.7 5.6
Retail Energy Marketing 29.7 22.2 18.4
Corporate and Other (4) (27.2) (9.6) (7.0)
- ------------------------------------------------------------------------------
Subtotal 336.8 287.3 264.9
Early Retirement and Severance (5) (22.3) -- --
- ------------------------------------------------------------------------------
Consolidated $ 314.5 $ 287.3 $ 264.9
- ------------------------------------------------------------------------------
</TABLE>
(1) In general, transactions among business units are recorded at market
prices and material affiliate transactions within business units are
eliminated.
(2) Before the charge for early retirement and severance, see (5) following.
(3) Reflects a change in depreciation rates during 1995, see "Interstate
Pipelines" and "Natural Gas Gathering" following.
(4) Includes approximately $14.2 million of goodwill amortization during
each period presented, see "Investments and Other Assets" included in
Note 1 of the accompanying Notes to Consolidated Financial Statements.
(5) Costs associated with early retirement and severance at NGT, Entex and
Minnegasco, see "Natural Gas Distribution" and "Interstate Pipelines"
following.
NATURAL GAS DISTRIBUTION
The Company's natural gas distribution business, consisting principally of
natural gas sales to and transportation for residential, commercial and a
limited number of industrial customers, substantially all of which are located
behind the "city gate" and subject to cost-of-service rate regulation (see
"Regulatory Matters" elsewhere herein), is conducted by the Entex, Minnegasco
and Arkla divisions of NorAm Energy Corp. ("Natural Gas Distribution" or
"Distribution"). Entex provides service to approximately 1.4 million customers
in 502 communities across Texas, Louisiana and Mississippi, including Houston,
Texas, the fourth largest metropolitan area in the United States and NorAm's
single largest market, as well as major petrochemical and industrial complexes
located along the Gulf Coast. Minnegasco serves more than 639,000 customers in
245 communities solely within the state of Minnesota, including Minneapolis,
the nation's sixteenth largest city. Arkla provides distribution services to
more than 735,000 customers in 621 communities located in Arkansas, North
Louisiana, Oklahoma and East Texas, including its principal markets of Little
Rock, Arkansas and Shreveport, Louisiana.
In September 1994, the Company completed the sale of its Kansas
distribution properties (together with certain related pipeline assets) for
approximately $23 million in cash, with no material gain or loss recognized. In
September 1993, the Company completed the exchange of its South Dakota
distribution properties, serving approximately 45,000 customers in 18
communities, plus $38 million in cash for Midwest Gas's Minnesota distribution
properties, serving approximately 82,000 customers in 41 communities, with no
gain or loss recognized. In February 1993, the Company completed the sale of
its Nebraska distribution properties, serving approximately 124,000 customers
in 63 communities, for $93.1 million in cash, recognizing a pre-tax gain of
approximately $23.9 million (the associated tax expense was approximately $8.7
million).
During the first quarter of 1996, approximately 100 employees of Entex
accepted an early retirement program and approximately 25 positions were
eliminated at Minnegasco as a result of the reorganization of certain
functions, resulting in a total pre-tax charge of approximately $5.8 million
(the associated tax benefit was approximately $2.3 million), which amount is
included under the caption
25
<PAGE> 29
"Early retirement and severance" in the accompanying Statement of Consolidated
Income and in the following table. A portion of this expense was offset by
associated cost savings during 1996.
<TABLE>
<CAPTION>
NATURAL GAS DISTRIBUTION - FINANCIAL RESULTS
- ---------------------------------------------------------------------
(millions of dollars) 1996 1995 1994
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $ 2,074.1 $ 1,678.6 $ 1,769.9
Transportation revenue 16.0 19.1 17.6
Other revenue 23.5 21.7 23.1
- ---------------------------------------------------------------------
Total operating revenues 2,113.6 1,719.4 1,810.6
- ---------------------------------------------------------------------
Purchased gas cost
Unaffiliated 1,075.6 777.3 855.0
Affiliated 273.2 237.9 273.7
Operations and maintenance 388.6 366.3 360.3
Depreciation and amortization 94.9 90.4 86.9
Other operating expenses 97.4 89.5 89.2
- ---------------------------------------------------------------------
183.9 158.0 145.5
Early retirement and severance (1) 5.8 -- --
- ---------------------------------------------------------------------
Operating income $ 178.1 $ 158.0 $ 145.5
- ---------------------------------------------------------------------
Average invested capital $ 978.3 $ 940.7 $ 902.2
- ---------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
NATURAL GAS DISTRIBUTION - OPERATING STATISTICS
- -------------------------------------------------------------------------
(billions of cubic feet) 1996 1995 1994
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Residential sales 198.8 183.3 180.0
Commercial sales 133.7 123.3 119.1
Industrial sales 57.9 52.4 53.4
Transportation 42.0 49.4 44.9
- -------------------------------------------------------------------------
Total throughput 432.4 408.4 397.4
- -------------------------------------------------------------------------
Arkla actual degree days 3,045 2,830 2,806
Arkla normal degree days 3,012 2,999 3,038
- -------------------------------------------------------------------------
Entex actual degree days 1,586 1,331 1,348
Entex normal degree days 1,498 1,531 1,554
- -------------------------------------------------------------------------
Minnegasco actual degree days 8,717 7,836 7,617
Minnegasco normal degree days 7,801 7,821 7,786
- -------------------------------------------------------------------------
Average number of customers 2,761,672 2,722,306 2,683,175
- -------------------------------------------------------------------------
Number of employees at year end 5,314 5,538 5,617
- -------------------------------------------------------------------------
Average sales price ($/Mcf)
Residential $ 6.13 $ 5.52 $ 5.99
- -------------------------------------------------------------------------
Commercial $ 4.79 $ 4.17 $ 4.66
- -------------------------------------------------------------------------
Industrial $ 3.21 $ 2.65 $ 3.00
- -------------------------------------------------------------------------
Annual revenues per
residential customer $ 481.17 $ 405.59 $ 438.61
- -------------------------------------------------------------------------
Annual residential use
per customer (Mcf) 78.5 73.5 73.2
- -------------------------------------------------------------------------
</TABLE>
(1) See the discussion preceding.
26
<PAGE> 30
1996 vs. 1995
Distribution operating income improved from $158.0 million in 1995 to $183.9
million in 1996 (before the charge for early retirement and severance as
discussed preceding), an increase of $25.9 million (16.4%). This increase in
operating income reflected both increased operating revenues and increased
operating expenses as discussed following.
"Natural gas sales", representing approximately 98% of Distribution's
total operating revenues in each period presented, increased from $1,678.6
million in 1995 to $2,074.1 million in 1996, an increase of $395.5 million
(23.6%). Approximately $248.7 million (62.9%) of this favorable variance was
attributable to an increase in the average sales price in 1996, principally due
to (1) an increase in the average cost of gas in 1996 (a component of the sales
price) as discussed following and, to a lesser extent, (2) rate increases
obtained in certain jurisdictions (see "Regulatory Matters" elsewhere herein).
The remaining $146.8 million (37.1%) of the favorable variance was attributable
to increased 1996 sales volume, principally due to colder weather; 13,348 total
degree days in 1996 vs. 11,997 in 1995, an increase of 1,351 degree days
(11.3%). This colder weather, which increases demand for space heating, was
largely responsible for increases of 15.5 Bcf (8.5%) and 10.4 Bcf (8.4%) in
1996 residential and commercial sales volumes, respectively.
"Purchased gas cost" increased from $1,015.2 million in 1995 to $1,348.8
million in 1996, an increase of $333.6 million (32.9%), approximately $244.8
million (73.4%) of which is attributable to an increase in the average cost of
purchased gas in 1996 and approximately $88.8 million (26.6%) of which is
attributable to increased 1996 sales volume. The increased volume was
principally due to the colder weather and related increase in residential and
commercial demand as discussed preceding, while the increase in the weighted
average cost of gas from approximately $2.83 per Mcf in 1995 to approximately
$3.46 per Mcf in 1996, an increase of approximately $0.63 per Mcf (22.3%), was
reflective of an overall increase in the market price of gas.
The gross sales margin ("Natural gas sales" minus total purchased gas
cost) increased from $663.4 million in 1995 to $725.3 million in 1996, an
increase of $61.9 million (9.3%). This increase was principally due to the
largely weather-related 8.7% increase in total sales volume and, to a lesser
extent, the rate increases obtained in certain jurisdictions, each as discussed
preceding.
Operating expenses, exclusive of purchased gas cost and the 1996 charge
for early retirement and severance increased from $546.2 million in 1995 to
$580.9 million in 1996, an increase of $34.7 million (6.4%), principally due
to (1) increased environmental costs (which, as discussed in "Environmental
Matters" under "Commitments and Contingencies" elsewhere herein, are
substantially being recovered through the regulatory process), (2) increased
bad debt provisions largely resulting from weather-related increases in
customer bills and (3) increased depreciation expense due to increased
investment, including the transfer to Distribution of certain Corporate assets
during 1995.
1995 vs. 1994
Distribution operating income increased from $145.5 million in 1994 to $158.0
million in 1995, an increase of $12.5 million (8.6%). This increased operating
income reflected both decreased operating revenues and decreased operating
expenses as discussed following.
"Natural gas sales", representing approximately 98% of Distribution's
total operating revenues in both 1995 and 1994, decreased from $1,769.9 million
in 1994 to $1,678.6 million in 1995, a decrease of $91.3 million (5.2%). This
net decrease was composed of (1) an approximately $123.9 million decrease
attributable to a decline in the average natural gas sales price in 1995,
partially offset by (2) an increase of approximately $32.6 million attributable
to an increase of approximately 6.5 Bcf (1.8%) in 1995 sales volumes. The
decline of approximately $0.35 per Mcf (6.9%) in the average sales price from
1994 to 1995 was principally due to a decrease in the 1995 average cost of gas
(a component of the sales price) as discussed following, partially offset by
the favorable impact of rate increases obtained in certain jurisdictions. The
increase in 1995 sales volumes was principally due to increased demand
resulting from colder 1995 weather; 11,997 total degree days in 1995 vs. 11,771
in 1994, an increase of 226 degree days (1.9%), which was largely responsible
for increases of 3.3 Bcf and 4.2 Bcf (a combined increase of approximately
2.5%) in residential and commercial sales volumes, respectively. This increase
in residential and commercial sales volume was partially offset by an
approximately 1.0 Bcf (1.9%) decline in 1995 industrial sales.
27
<PAGE> 31
"Purchased gas cost" decreased from $1,128.7 million in 1994 to $1,015.2
million in 1995, a decrease of $113.5 million (10.1%). This net decrease was
composed of a decrease of approximately $134.3 million attributable to a
decline in the average cost of purchased gas in 1995, partially offset by an
approximately $20.8 million increase attributable to higher 1995 sales volume.
The increased 1995 volume was principally due to the colder weather and related
increased residential and commercial demand as discussed preceding, while the
decrease in the weighted average cost of purchased gas from approximately $3.20
per Mcf in 1994 to approximately $2.83 per Mcf in 1995, a decline of
approximately $0.37 per Mcf (11.6%), principally was reflective of an overall
decrease in the 1995 market price of gas.
The gross sales margin ("Natural gas sales" minus total purchased gas
cost) increased from $641.2 million in 1994 to $663.4 million in 1995, an
increase of $22.2 million (3.5%). Approximately $11.8 million (53.2%) of this
increase was attributable to the largely weather-related 1.8% increase in total
1995 sales volume as discussed preceding. The balance of the increase,
approximately $10.4 million (46.8%), was attributable to an increase in the
average 1995 sales margin, largely due to rate increases obtained in certain
jurisdictions as discussed preceding.
Operating expenses, exclusive of purchased gas cost, increased from
$536.4 million in 1994 to $546.2 million in 1995, an increase of $9.8 million
(1.8%), principally due to (1) increased 1995 operations and maintenance
expense due to increased costs for labor and related benefits and (2) increased
1995 depreciation expense due to increased investment, including the transfer
to Distribution of certain Corporate assets during 1995.
INTERSTATE PIPELINES
The Company's interstate pipeline business is conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), together with certain subsidiaries and affiliates (collectively,
"Pipeline"). NGT owns and operates an interstate natural gas pipeline system
consisting of approximately 6,200 miles of transmission lines located in
portions of Arkansas, Louisiana, Mississippi, Missouri, Kansas, Oklahoma,
Tennessee and Texas. The system utilizes three natural gas storage facilities
which are owned and operated by NGT and an additional facility in which NGT
owns an interest. In addition, the system previously utilized the Company's
Collinson Storage Facility, see "Regulatory Matters" elsewhere herein. MRT owns
and operates an interstate pipeline system consisting of approximately 2,000
miles of transmission lines serving principally the greater St. Louis area in
Missouri and Illinois, and which includes three natural gas storage facilities.
The Company has an agreement with ANR Pipeline Company for the lease of certain
transmission capacity, see "Transportation Agreement" under "Commitments and
Contingencies" elsewhere herein.
In recognition of the economic impact of ratemaking, the Company applies
the provisions of SFAS 71 to MRT, and also applied these provisions to NGT
until December 31, 1992. At December 31, 1992, the Company ceased to apply the
provisions of SFAS 71 to NGT and, pursuant to the provisions of Statement of
Financial Accounting Standards No. 101, "Regulated Enterprises - Accounting for
the Discontinuance of Application of FASB Statement No. 71", the Company
recorded a pre-tax charge of $314.5 million (the associated tax benefit was
approximately $119.5 million), included in the Company's 1992 Statement of
Consolidated Income under the caption "Extraordinary item, less taxes". This
charge had no effect on NGT's ability to include the underlying costs in its
regulated rates and did not affect its efforts to collect such rates from its
customers, see "Regulatory Matters" elsewhere herein.
As indicated in the accompanying table, Pipeline had revenues of $163.8
million, $160.9 million and $171.6 million in 1996, 1995 and 1994,
respectively, from sales to and transportation for Distribution, representing
approximately 47.2%, 46.4% and 42.8% of Pipeline's total operating revenues in
these respective years. Throughput associated with Distribution was
approximately 15% of Pipeline's total throughput in each year presented. These
services have been provided pursuant to contractual arrangements, some of which
expired in 1996, including the bundled sales contract pursuant to which most
sales to Distribution were made. The Company currently expects that services,
principally transportation, will continue to be provided by Pipeline to
Distribution in a manner which will not result in a material and continuing
decrease in Pipeline's earnings in comparison to the historical trend, although
negotiations are not yet completed and changes in these arrangements are
subject to regulatory approval. In addition, during 1996, Pipeline had revenues
of approximately $55 million, approximately 15.9% of Pipeline's total operating
revenues, from sales to and transportation for Laclede Gas Company
28
<PAGE> 32
(the local gas distribution company which serves the greater St. Louis,
Illinois area) pursuant to several long-term firm transportation and storage
agreements which currently are scheduled to expire in 1999.
In June 1993, the Company completed the sale of its intrastate pipeline
business as conducted by Louisiana Intrastate Gas Corporation ("LIG") to
Equitable Resources, Inc. ("Equitable") for $191 million in cash, and agreed to
indemnify Equitable against certain exposures, for which the Company has
established a reserve equal to expected claims under the indemnity. This
reserve is included under the caption "Estimated obligations under
indemnification provisions of sale agreements" in the accompanying Consolidated
Balance Sheet.
In February 1996, Pipeline announced a reorganization plan which
resulted in the elimination of a total of approximately 275 positions at NGT
and MRT. The reorganization plan, designed to allow Pipeline to operate more
efficiently and improve its ability to compete in its market areas, resulted in
a first-quarter 1996 pre-tax charge of approximately $16.5 million (the
associated tax benefit was approximately $6.6 million). This pre-tax charge,
included under the caption "Early retirement and severance" in the accompanying
Statement of Consolidated Income and in the following table, was partially
offset by the associated cost savings during 1996 as discussed following.
29
<PAGE> 33
<TABLE>
<CAPTION>
INTERSTATE PIPELINES - FINANCIAL RESULTS
- -------------------------------------------------------------------------
(millions of dollars) 1996 1995 1994
- -------------------------------------------------------------------------
<S> <C> <C> <C>
Gas sales revenue
Sales to Distribution $ 60.4 $ 64.9 $ 71.5
Sales for resale and other 26.0 35.9 90.9
- -------------------------------------------------------------------------
Total gas sales revenue 86.4 100.8 162.4
- -------------------------------------------------------------------------
Transportation revenue
Distribution 103.4 96.0 100.1
Unaffiliated 157.0 149.9 138.1
- -------------------------------------------------------------------------
Total transportation
revenue 260.4 245.9 238.2
- -------------------------------------------------------------------------
Total operating revenue 346.8 346.7 400.6
- -------------------------------------------------------------------------
Purchased gas cost 74.3 87.5 148.1
Operations and maintenance 50.3 61.8 52.7
Depreciation and amortization 29.2 33.7 36.7
General, administrative and other 68.6 59.9 57.7
- -------------------------------------------------------------------------
124.4 103.8 105.4
Early retirement and severance (1) 16.5 -- --
- -------------------------------------------------------------------------
Operating income $ 107.9 $ 103.8 $ 105.4
=========================================================================
Average invested capital $ 761.2 $ 832.7 $ 931.0
=========================================================================
</TABLE>
<TABLE>
<CAPTION>
INTERSTATE PIPELINES - OPERATING STATISTICS
- ---------------------------------------------------------------------------
(million MMBtu) 1996 1995 1994
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Sales to Distribution 22.9 29.6 28.3
Sales for resale and other 10.3 22.1 17.6
- ---------------------------------------------------------------------------
Total sales 33.2 51.7 45.9
- ---------------------------------------------------------------------------
Transportation
Distribution 115.0 111.3 99.3
Other 837.0 863.0 732.5
- ---------------------------------------------------------------------------
Total transportation 952.0 974.3 831.8
Elimination (2) (31.3) (49.7) (42.6)
- ---------------------------------------------------------------------------
Total throughput 953.9 976.3 835.1
===========================================================================
Average transportation margin
($/MMBtu) $ 0.286 $ 0.268 $ 0.305
===========================================================================
</TABLE>
(1) See the discussion preceding.
(2) When sold volumes are also transported by Pipeline, the throughput
statistics will include the same physical volumes in both the sales and
transportation categories, requiring an elimination to prevent the
overstatement of actual total throughput. No elimination is made for
volumes of 204.2 million MMBtu, 196.6 million MMBtu and 145.8 million
MMBtu in 1996, 1995 and 1994, respectively, which were transported on
both the NGT and MRT systems.
1996 vs. 1995
Pipeline operating income for 1996 was $107.9 million, an increase of $4.1
million (3.9%) from the $103.8 million earned in 1995. Excluding the $16.5
million pre-tax charge related to the Pipeline reorganization (see the
discussion preceding), 1996 operating income was $124.4 million, an increase of
$20.6 million (19.8%). This increase, which reflected essentially static
operating revenues and decreased operating expenses, was primarily attributable
to increased transportation margins and decreased operating expenses as
discussed following.
30
<PAGE> 34
"Total gas sales revenue" decreased from $100.8 million in 1995 to $86.4
million in 1996, a decrease of $14.4 million (14.3%). This net decrease was
composed of a $36.1 million decrease related to lower 1996 sales volumes,
partially offset by a $21.7 million increase related to a higher average sales
price in 1996, each as discussed following. "Sales for resale and other"
decreased by $9.9 million (27.6%) from 1995 to 1996 principally due to an 11.8
million MMBtu (53.4%) decrease in 1996 resale volumes, primarily due to certain
1995 sales to Wholesale Energy Marketing which did not continue during 1996.
"Sales to Distribution" for 1996 decreased by $4.5 million (6.9%) from 1995, as
a $14.7 million decrease related to reduced 1996 sales volumes was partially
offset by a $10.2 million increase related to an increased average sales price
in 1996. The reduced Distribution sales volumes were primarily attributable to
the expiration, in September 1996, of the bundled sales contract with a
distribution affiliate as discussed preceding. The increase in the average
sales price to Distribution from 1995 to 1996 was primarily due to an increase
in the average cost of purchased gas during 1996. Such increases in the average
cost of purchased gas, in general, increase the commodity component of the
overall sales price (and purchased gas cost) without necessarily increasing
total sales margins.
Mid-Continent spot market prices averaged approximately $2.16 per MMBtu
and $1.45 per MMBtu during 1996 and 1995, respectively, an increase of
approximately $0.71 per MMBtu (49%), which was largely responsible for the
increased purchased gas cost and average sales prices discussed preceding.
Additionally, 1995 results include the following favorable adjustments (which
did not recur in 1996) to purchased gas cost: (1) approximately $2.5 million
resulting from the securing of supplies of gas at lower than expected prices
for delivery to Distribution under a fixed-price sales commitment, see "Credit
Risk and Off-Balance-Sheet Risk" under "Commitments and Contingencies"
elsewhere herein and (2) approximately $3.5 million related to the resolution
of certain take-or-pay and FERC Order 636 issues. The unfavorable impact of
these items on the comparison of 1995 to 1996 was partially offset by 1996
recoveries of fuel usage in excess of tariff-allowed recoveries experienced
during 1995. Under the current rate structure, the fuel recovery percentage is
adjusted on a six-month interval and includes a provision for over or under
recoveries of fuel used in the previous six-month period. While the average
cost of purchased gas in 1996 increased significantly from 1995, "Total
purchased gas cost" decreased by $13.2 million (15.1%) from 1995. This net
decrease was due to reduced 1996 sales and related purchased gas volumes,
resulting in a reduction of $31.3 million, partially offset by a $18.1 million
increase related to higher average gas prices in 1996 as discussed preceding.
The gross margin on sales ("Total gas sales revenue" minus "Purchased
gas cost") decreased from $13.3 million in 1995 to $12.1 million in 1996, a
decline of $1.2 million (9.0%). This net decrease was composed of an
unfavorable variance of $4.8 million related to decreased 1996 sales volumes,
largely due to the expiration of the sales contract with a distribution
affiliate as discussed preceding, partially offset by a $3.6 million favorable
price variance. The favorable price variance was primarily due to (1) increases
in 1996 spot market gas prices which had a favorable impact on margins due to
purchases under contracts with fixed-price provisions which allowed purchases
at below the spot market rate and (2) 1996 recoveries of excess fuel usage
experienced during 1995, each as discussed preceding. Principally due to the
September 1996 expiration of the bundled sales contract with a distribution
affiliate as discussed preceding, Pipeline expects no significant sales margins
in the future.
"Total transportation revenue" increased by $14.5 million (5.9%) from
1995 to 1996 due to several factors including (1) the positive impact of NGT's
rate case which became effective in February 1995, (2) a change in the relative
pricing of Mid-Continent gas supplies as discussed following and (3) the
expiration, in September 1996, of certain contractual pricing provisions
related to transportation for Distribution which had placed a rate "cap" on
transportation rates for deliveries at certain points on the Pipeline system.
The relative pricing of Mid-Continent gas supplies has an impact (positive or
negative) on Pipeline's transportation rates which are covered under contracts
with market-sensitive pricing provisions. When prices of Gulf Coast gas
increase significantly over Mid-Continent gas (Pipeline's primary supply area),
competitive pressure on transportation prices are reduced, allowing average
transportation rates to increase. During 1996, the average price differential
between Mid-Continent and Gulf Coast gas was $0.37 per MMBtu compared to an
average of $0.14 per MMBtu during 1995. These positive variances in
transportation revenue were partially offset by a $3.8 million reduction in
revenues related to lower surcharges for Gas Supply Realignment ("GSR") costs,
as discussed following. During 1996, Pipeline continued to utilize the
Company's risk management program to mitigate the market risk,
31
<PAGE> 35
associated with certain of Pipeline's transportation agreements which contain
market-sensitive pricing provisions, arising from movement in certain basin
pricing differentials, see "Regulatory Matters" and "Wholesale Energy
Marketing" elsewhere herein.
"Total transportation volumes" decreased by 22.3 million MMBtu (2.3%)
from 1995 to 1996, primarily due to reduced 1996 east side deliveries. However,
decreases in transportation volumes tend to have a less than proportionate
impact on transportation revenues because, under the straight-fixed-variable
rate design generally applicable to Pipeline, a significant portion of the
overall transportation rate is represented by a "demand" charge based on the
contract volume. Pipeline receives a fixed demand fee for these volumes
regardless of whether the volumes are physically moved on the system.
Therefore, only a relatively small portion of the overall transportation rate
varies directly with the volume transported.
"Operations and maintenance" ("O&M") decreased from $61.8 million in
1995 to $50.3 million in 1996, a decrease of $11.5 million (18.6%) due to
several factors including: (1) a $3.8 million reduction related to lower GSR
costs as discussed following, (2) a $2.7 million unfavorable 1995 adjustment
resulting from a FERC compliance audit, (3) a $0.9 million favorable variance
related to the completion, in March 1996, of the amortization period for
certain PCB remediation costs as required by a previous rate proceeding and (4)
changes in cost allocations which shifted certain data processing costs from
"O&M" to "General, administrative and other". The remainder of the reduction is
attributable to cost savings associated with the early-1996 Pipeline
reorganization (as discussed preceding), partially offset by a reduction in
capitalized labor related to a change in company policy which has resulted in
the use of contract personnel rather than company personnel for many of its
capital projects. The reduction in GSR-related revenues mentioned preceding was
primarily due to reduced GSR costs eligible for recovery in 1996. GSR costs
result from Pipeline's buy-out of certain gas supply contracts in order to "re-
align" its portfolio of contracts toward transportation services and away from
commodity sales. Pursuant to the terms of a FERC settlement, Pipeline is
allowed to obtain recovery of a portion of this cost through a transportation
surcharge, with the unrecoverable portion having been expensed. In order to
match the GSR recoveries with the associated cost, Pipeline recognizes the
additional cost as the recoveries are generated through the surcharge. The
deferred GSR costs at December 31, 1996, which were related only to MRT, were
not material.
"Depreciation and amortization" for 1996 decreased by $4.5 million
(13.4%) primarily due to a July 1995 change in the depreciation rates
associated with certain Pipeline assets, see the discussion under "1995 vs.
1994" following and "Change in Estimated Service Lives of Certain Assets"
elsewhere herein.
"General, administrative and other" increased by $8.7 million (14.5%)
from 1995 to 1996 due to several factors, including: (1) $2.8 million related
to increased 1996 relocation and consulting cost associated with the Pipeline
reorganization, (2) $1.9 million of non-recurring favorable adjustments in 1995
which reduced medical expenses, (3) $0.9 million of favorable 1995 adjustments
related to a FERC Compliance audit which did not recur in 1996, (4) $1.6
million related to increased 1996 accruals for certain incentive compensation,
(5) $0.9 million associated with changes in allocation methods which re-
classified certain data processing cost from "O&M" to this expense category and
(6) $1.0 million associated with a change in method of recording payments to
the Gas Research Institute ("GRI"). During 1995, payments to GRI were recorded
as "flow-through", with no effect on income or expense. During 1996, these
payments resulted in both expense and revenue in equal amounts. These
unfavorable variances were partially offset by a reduction in 1996 costs due to
the Pipeline reorganization.
1995 vs. 1994
Pipeline operating income for 1995 was $103.8 million, a decrease of $1.6
million (1.5%) from the $105.4 million earned in 1994. This decrease reflected
both decreased operating revenues and decreased operating expenses as discussed
following.
"Total gas sales revenue" decreased from $162.4 million in 1994 to
$100.8 million in 1995, a decrease of $61.6 million (37.9%). This net decrease
was composed of an approximately $82.1 million decrease attributable to a lower
average sales price in 1995, partially offset by a $20.5 million increase
attributable to higher 1995 sales volume, each as discussed following. "Sales
to Distribution" for 1995 decreased by $6.6 million (9.2%) from 1994,
reflecting an approximately $9.9 million decrease attributable to a decreased
average sale price in 1995, partially offset by an increase of approximately
$3.3 million attributable to increased 1995 sales volumes. The lower average
sale price in 1995 was principally
32
<PAGE> 36
due to decreased 1995 average purchased gas cost as discussed following. This
reduction in the average cost of purchased gas, in general, decreases the
commodity component of the overall sales price (and purchased gas cost), thus
decreasing total revenues without necessarily decreasing total margins. The
increased 1995 sales volume was principally due to sales made to Wholesale
Energy Marketing in 1995 which were not made in 1994 and, to a lesser extent,
increased demand resulting from the relatively colder 1995 weather in
Distribution's service areas. "Sales for resale and other" decreased by $55.0
million (60.5%) from 1994 to 1995, primarily due to the sale in 1994, at cost,
of approximately $50.5 million of gas in storage inventory by MRT to its
customers in conjunction with implementation of services under FERC Order 636.
"Total transportation revenue" increased by $7.7 million (3.2%) from
1994 to 1995 principally due to increased volume as discussed following. The
increase of 12.0 million MMBtu (12.1%) in 1995 transportation for Distribution
was principally due to colder 1995 weather and the related increased demand in
Distribution's service area, partially offset by the inclusion, in 1994
results, of volumes associated with Distribution's Kansas properties which were
sold in September 1994. The increase of approximately 130.5 million MMBtu
(17.8%) from 1994 to 1995 in transportation volumes for third parties was
principally due to (1) increased 1995 transportation for resale customers due,
in part, to the filling of customer-owned storage which previously was owned by
Pipeline, (2) increased southbound volumes on the MRT system reflecting full
implementation of FERC Order 636 and (3) Distribution volumes subject to
"capacity release" programs pursuant to which volumes dedicated to a
Distribution affiliate are released (and billed) to third-party shippers,
resulting in a corresponding movement of these volumes from "Distribution" to
"Unaffiliated". These increases in transportation volume tend to have a less
than proportionate impact on transportation revenues due to straight-fixed-
variable rate design as discussed preceding. The decrease of approximately
$0.03 per MMBtu (11.9%) in the average transportation unit revenue from 1994 to
1995 was principally due to (1) the acceptance of lower margin transportation
transactions (subject to increased competition) as marketing activities were
intensified in 1995 and (2) the inclusion, in 1994 results, of a favorable rate
case adjustment of approximately $4.0 million. During 1995, Pipeline utilized
the Company's risk management program to mitigate the market risk, associated
with certain of Pipeline's transportation agreements which contain market-
sensitive pricing provisions, arising from movement in certain basin pricing
differentials, see "Regulatory Matters" and "Wholesale Energy Marketing"
elsewhere herein.
"Purchased gas cost" decreased from $148.1 million in 1994 to $87.5
million in 1995, a decrease of $60.6 million (40.9%). This net decrease was
composed of an approximately $79.3 million decrease attributable to a reduction
of approximately $1.53 per MMBtu in the average cost of purchased gas in 1995,
partially offset by an increase of approximately $18.7 million attributable to
an increase in the 1995 volume of gas purchased in support of increased sales
volumes as discussed preceding. The decrease of approximately $1.53 per MMBtu
(47.5%) in the average cost of purchased gas during 1995 was principally due to
(1) the transfer of gas storage inventory to customers in 1994 as discussed
preceding, (2) a general decrease in the 1995 market price of natural gas as
discussed preceding and (3) the inclusion, in 1995 results, of a favorable
adjustment of approximately $2.5 million resulting from the securing of
supplies of gas at lower than expected prices for delivery to Distribution
under a fixed-price sales commitment, see "Credit Risk and Off-Balance-Sheet
Risk" under "Commitments and Contingencies" elsewhere herein. These favorable
impacts were partially offset by the inclusion, in 1995 purchased gas cost, of
approximately $2.0 million of fuel usage in excess of tariff-allowed recoveries
from customers. Under subsequent rate cases, the fuel recovery percentage is
adjusted each May and November, including a provision for over or under
recoveries of fuel used in the previous six-month period.
The gross margin on sales ("Total gas sales revenue" minus "Purchased
gas cost") decreased from $14.3 million in 1994 to $13.3 million in 1995, a
decline of $1.0 million (7.0%). This net decrease was composed of an
unfavorable variance of approximately $2.8 million attributable to a decrease
in the average margin on gas sales during 1995, partially offset by an increase
of approximately $1.8 million attributable to the increased 1995 sales volume
as discussed preceding. The decrease of approximately $0.05 per MMBtu (17.4%)
in the average sales margin from 1994 to 1995 was principally due to (1) the
decrease in 1995 spot market gas prices which adversely affected 1995 margins
due to purchases under certain contracts which did not vary directly with spot
market prices and (2) the 1995 fuel usage in excess of recoveries, each as
discussed preceding.
33
<PAGE> 37
O&M increased from $52.7 million in 1994 to $61.8 million in 1995, an
increase of $9.1 million (17.3%) due to a number of factors including a $5.7
million increase in transportation expense. Approximately $2.1 million of this
increase in transportation expense was related to transportation fees paid to
NFS. The gathering assets of NGT were transferred to NFS effective February 1,
1995 (see "Natural Gas Gathering" elsewhere herein) and, subsequent to this
date, a transportation fee was paid to NFS for gas purchased by NGT at the
wellhead and delivered to NGT through NFS's gathering systems. The remainder of
the variance in transportation expense principally related to payments to the
Gas Research Institute, which amounts are collected from customers through a
surcharge, thereby offsetting the expense through increased transportation
revenues. Prior to mid-1995, these payments were recorded as a "flow through",
with no effect on revenue or expense. Other factors contributing to the
unfavorable variance in O&M from 1994 to 1995 included (1) a non-recurring 1994
transfer to inventory of approximately $1.6 million of costs previously
expensed, (2) approximately $2.7 million of 1995 expense resulting from a FERC
compliance audit, (3) increased 1995 labor cost, principally due to a reduction
in labor charged to capital projects and (4) the 1995 write-off of certain
clearing account balances. These unfavorable variances were partially offset by
reduced 1995 bad debts expense.
"Depreciation and amortization" decreased by $3.0 million (8.2%) from
1994 to 1995 principally due to a change in the estimated service lives of NGT
assets as discussed preceding and under "Change in Estimated Service Lives of
Certain Assets" elsewhere herein. This change, effective in July 1995, reduced
1995 depreciation expense by approximately $3.4 million and represents an
annualized expense decrease of approximately $6.8 million.
"General, administrative and other" increased by $2.2 million (3.8%)
from 1994 to 1995. Increased general and administrative expense represented
$1.0 million (45.5%) of the increase, with the balance principally due to
increased 1995 property taxes reflecting higher 1995 millage rates in certain
taxing jurisdictions.
WHOLESALE ENERGY MARKETING
The Company's marketing of natural gas and risk management services to natural
gas resellers and certain large volume industrial consumers is principally
conducted by NorAm Energy Services, Inc., together with certain affiliates
(collectively, "NES"). NES historically has operated primarily in those states
served by the NGT and MRT systems but recently has had significant sales in
various other states, Canada and Mexico, as it seeks to extend its activities
throughout North America. During the second quarter of 1996, NES opened
regional offices in Boulder, Colorado, Williamsburg, Virginia and Midland,
Michigan, and had opened offices in Miami, Florida and St. Louis, Missouri
during 1995. Additional offices may be opened as markets in other areas of the
United States are developed. In addition, in recent periods, NES has begun to
market electricity in wholesale markets.
To minimize the risk from market fluctuations in the price of natural
gas and transportation, the Company, generally through NES, enters into futures
transactions, swaps and options (collectively, "financial instruments") in
order to hedge certain commitments to buy, sell and transport natural gas, as
well as existing gas in storage inventory and certain anticipated transactions.
Some of these financial instruments carry off-balance-sheet risk, see "Credit
Risk and Off-Balance-Sheet Risk" under "Commitments and Contingencies"
elsewhere herein.
In general, NES does not seek to take significant commodity risk for the
purpose of generating margins in the ordinary course of its trading activities.
NES is not, however, able to completely avoid inter-month or intra-month price
or basis risk, and does not fully and at all times hedge its gas in storage
inventory. As a result, to the extent that NES has unhedged inventory which is
sold in a period of declining prices, losses (or reductions in margins) may
occur. NES estimates that it incurred pre-tax losses of $3-$5 million in
connection with the early 1997 sale of gas in storage inventory which was not
hedged at December 31, 1996. At December 31, 1996, NES had approximately $11.9
million of deferred pre-tax losses associated with hedges of anticipated
transactions, see "Credit Risk and Off-Balance-Sheet Risk" under "Commitments
and Contingencies" elsewhere herein. Gains and losses resulting from changes in
the market value of the various financial instruments utilized as hedges are
recognized as a component of expense when the associated physical volumes are
purchased, sold or transported under the relevant contracts, see "Accounting
for Price Risk Management Activities" included in Note 1 of the accompanying
Notes to Consolidated Financial Statements.
34
<PAGE> 38
As discussed following, total operating margins for NES increased by
159.6% and 107.4% from 1994 to 1995 and from 1995 to 1996, respectively. While
the Company believes that NES has the potential to continue to increase its
operating margins, the percentage increase for 1997, if any, may be less than
that suggested by the historical trend as shown following due to, among other
factors, (1) increasing competition (with attendant potential for decreased
unit margins) in natural gas and electric power markets due, in part, to the
creation, through business combinations and otherwise, of competitors
significantly larger than NES, (2) the uncertain regulatory environment with
respect to "unbundling" of natural gas markets and "deregulation" of wholesale
electric power markets and (3) the early-1997 losses associated with the sale
of gas in storage inventory as discussed preceding, and sales under "peaking
contracts" with certain customers, see "Credit Risk and Off-Balance-Sheet Risk"
under "Commitments and Contingencies" elsewhere herein.
<TABLE>
<CAPTION>
WHOLESALE ENERGY MARKETING - FINANCIAL AND OPERATING RESULTS
- -----------------------------------------------------------------------------------
(millions of dollars, except as noted) 1996 1995 1994
- -----------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales
Unaffiliated sales $ 1,892.8 $ 747.3 $ 537.4
Sales to Distribution 112.3 72.1 75.0
Sales to Pipeline 37.9 57.4 29.3
Other affiliated sales 24.0 16.5 5.7
- -----------------------------------------------------------------------------------
Total gas sales revenue 2,067.0 893.3 647.4
- -----------------------------------------------------------------------------------
Electricity sales 63.4 12.2 0.8
Other operating revenues -- 0.9 1.2
- -----------------------------------------------------------------------------------
Total operating revenues 2,130.4 906.4 649.4
- -----------------------------------------------------------------------------------
Purchased gas costs
Unaffiliated 1,877.6 765.2 574.5
Affiliated 115.4 70.1 31.0
Transportation and storage expense 46.3 46.1 38.0
Electricity purchases and transmission costs 63.1 11.5 0.7
- -----------------------------------------------------------------------------------
Operating margin 28.0 13.5 5.2
General and administrative 15.9 9.3 8.2
- -----------------------------------------------------------------------------------
Operating income(loss) $ 12.1 $ 4.2 $ (3.0)
- -----------------------------------------------------------------------------------
Natural gas sales volume (Bcf) 877.1 543.7 338.3
Average sales margin ($/Mcf) $ 0.032 $ 0.022 $ 0.012
- -----------------------------------------------------------------------------------
</TABLE>
1996 vs. 1995
Operating income for NES in 1996 was $12.1 million, an increase of $7.9 million
(188.1%) from the $4.2 million earned in 1995. This improvement reflected both
increased operating revenues and increased operating expenses as discussed
following.
"Total gas sales revenue" increased from $893.3 million in 1995 to
$2,067.0 million in 1996, an increase of $1,173.7 million (131.4%).
Approximately $625.9 million (53.3%) of this increase was attributable to an
increase in the average sales price in 1996, and the balance of approximately
$547.8 million (46.7%) was attributable to an increase in 1996 natural gas
sales volume. The increase of approximately $0.71 per Mcf (43.4%) in the
average sales price of natural gas during 1996 principally was reflective of
market conditions during 1996 which produced a general increase in the cost of
spot market natural gas purchases as discussed following (the cost of gas is a
component of the overall sales rate). The increase of approximately 333.4 Bcf
(61.3%) in 1996 natural gas sales volume was principally due to the expansion
of NES's marketing efforts. Utilizing an increased staff of marketers and
additional office locations as discussed preceding, NES continued to increase
its efforts toward becoming a nationwide marketing company with an emphasis on
increasing market share, principally targeting end-use customers in the
industrial, local gas distribution and electric generation sectors.
Total purchased gas costs were $1,993.0 million in 1996, an increase of
$1,157.7 million (138.6%) from 1995. Approximately $645.5 million (55.8%) of
this increase was attributable to an increase of approximately $0.74 per Mcf
(47.9%) in the average cost of purchased gas in 1996, and the
35
<PAGE> 39
balance of approximately $512.2 million (44.2%) was attributable to the
increased 1996 sales volume, each as discussed preceding. "Transportation and
storage expense" increased from $46.1 million in 1995 to $46.3 million in 1996,
an increase of $0.2 million (0.4%). This net increase was composed of an
increase of approximately $28.3 million due to the increased 1996 sales volume
as discussed preceding, substantially offset by a decrease of approximately
$28.1 million due to a decrease of approximately $0.032 per Mcf (37.7%) in the
unit cost of transportation and storage in 1996. The decrease in the unit cost
of transportation and storage in 1996 was principally due to increased 1996
usage of interruptible and capacity release transportation in lieu of firm
transportation arrangements. "Electricity sales" and "Electricity purchases and
transmission costs" of $63.4 million and $63.1 million, respectively, in 1996
represented significant increases over the corresponding amounts for 1995,
although the gross margin from power marketing declined from approximately $0.7
million in 1995 to approximately $0.3 million in 1996, as the significant
increase in volume was more than offset by a decrease in unit margins. During
1996, NES continued to increase both its emphasis on electricity sales and its
electricity marketing staff in anticipation of increased access to electric
power markets. The decrease in 1996 unit margins from power marketing was
principally attributable to the volatility and limited liquidity in wholesale
electric power markets which increase the intra-month price risk associated
with such activities.
The operating margin for 1996 was $28.0 million, an increase of $14.5
million (107.4%) from 1995. The 1996 margin on gas sales was $27.7 million, an
increase of $15.8 million (132.8%) from the $11.9 million earned in 1995. Of
this total increase in gas sales margin, approximately $8.5 million (53.8%) was
attributable to an approximately $0.01 per Mcf increase in the average margin
per unit of sales in 1996, principally due to the more intense and focused
marketing efforts in 1996 as discussed preceding, together with the increased
use of risk management capabilities and expanded use of cyclable storage. The
remainder of the increase, approximately $7.3 million (46.2%) was principally
attributable to the increased 1996 sales volume as discussed preceding.
The increase of $6.6 million (71.0%) in "General and administrative"
from 1995 to 1996 was principally due to costs associated with staffing
increases made in support of the increased sales and expanded marketing efforts
as described preceding.
1995 vs. 1994
Operating income for NES in 1995 was $4.2 million, an increase of $7.2 million
from the $(3.0) million loss reported in 1994. This improvement reflected both
increased operating revenues and increased operating expenses as discussed
following.
"Total gas sales revenue" increased from $647.4 million in 1994 to
$893.3 million in 1995, an increase of $245.9 million (38.0%). This net
increase was composed of an approximately $393.1 million increase due to
increased natural gas sales volume in 1995, partially offset by a decrease of
approximately $147.2 million attributable to a decreased 1995 average sales
price. The increase of approximately 205.4 Bcf (60.7%) in 1995 natural gas
sales volume was principally due to the expansion of NES's marketing efforts.
The decrease of approximately $0.27 per Mcf (14.1%) in the average sales price
of natural gas during 1995 principally was reflective of market conditions
during 1995 which produced a general decline in the cost of spot market natural
gas purchases (the cost of gas is a component of the overall sales rate).
Total purchased gas costs were $835.3 million in 1995, an increase of
$229.8 million (38.0%) from 1994. This net increase was composed of an
approximately $367.6 million increase attributable to the increased 1995 sales
volume as discussed preceding, partially offset by an approximately $137.8
million decrease attributable to an approximately $0.254 per Mcf (14.2%)
decrease in the average cost of purchased gas in 1995. This decrease in the
1995 average cost of purchased gas reflected the decreased 1995 spot market
price of natural gas as discussed preceding and, to a lesser extent, the
increased 1995 usage of risk management strategies to obtain lower-cost term
natural gas supplies. "Transportation and storage expense" increased from $38.0
million in 1994 to $46.1 million in 1995, an increase of $8.1 million (21.3%).
This net increase was composed of an increase of approximately $23.1 million
due to the increased sales volume in 1995 as discussed preceding, partially
offset by a decrease of approximately $15.0 million due to a decrease of
approximately $0.028 per Mcf (24.5%) in the 1995 unit cost of transportation
and storage. The decrease in the unit cost of transportation and storage in
1995 was principally due to increased 1995 usage of interruptible and capacity
release transportation in lieu of firm transportation arrangements.
"Electricity sales" and "Electricity purchases and transmission costs" of
36
<PAGE> 40
$12.2 million and $11.5 million, respectively, in 1995 represented significant
increases over the corresponding amounts for 1994. During 1995, NES increased
both its emphasis on electricity sales and its electricity marketing staff in
anticipation of increased access to electric power markets.
The operating margin for 1995 was $13.5 million, an increase of $8.3
million (159.6%) from 1994. The 1995 margin on gas sales was $11.9 million, an
increase of $8.0 million (205.1%) from the $3.9 million earned in 1994. Of this
total increase, approximately $2.4 million (30.0%) was attributable to the
increased sales volume in 1995 as discussed preceding, and approximately $5.6
million (70.0%) was attributable to an approximately $0.01 per Mcf increase in
the 1995 average margin per unit of sales, principally due to the more intense
and focused marketing efforts in 1995 as discussed preceding, together with the
increased use of risk management capabilities and expanded use of cyclable
storage.
The increase of $1.1 million (13.4%) in "General and administrative"
from 1994 to 1995 was principally due to costs associated with staffing
increases made in support of the increased sales and expanded marketing efforts
as described preceding.
NATURAL GAS GATHERING
The Company's natural gas gathering business, including related liquids
extraction and marketing activities, is conducted by NorAm Field Services Corp.
together with certain affiliates, collectively referred to herein as "NFS" or
"Natural Gas Gathering". Prior to 1994, a substantial portion of these
activities were billed as part of Interstate Pipelines' sales rate and not
separately identified. Accordingly, the Company's gathering activities prior to
1994 are included with Interstate Pipelines. NFS operates more than 3,600 miles
of gathering pipelines which collect gas from more than 200 separate gathering
systems located in major producing fields in Oklahoma, Louisiana, Arkansas and
Texas. In addition, NFS engages in liquids extraction activities, principally
through a joint venture with NGC Corp. (an affiliate of Natural Gas
Clearinghouse).
On February 1, 1995, pursuant to a "spindown" order from the FERC, the
Company transferred NGT's natural gas gathering assets to NFS, which is not
generally subject to cost-of-service rate regulation. Despite the fact that
competition remains high in many of its activities, the Company expects that
efforts will be made in certain states to enact legislation to regulate
gathering rates and services, although the Company currently expects that any
such efforts will be successful only to the extent of providing for complaint-
type proceedings alleging undue discrimination or similar "light-handed"
regulatory approaches.
In general, the level of NFS's throughput is subject to variability
resulting from, among other factors, (1) changes in the rate of producer
drilling, (2) production curtailments due to state allowables, (3) capacity
constraints on downstream pipelines and (4) shut-ins by producers due to
natural gas sales price levels. In addition, well freeze-offs occur in
extremely cold weather. NFS attempts to minimize the negative impact of these
factors through a strategy of aggressively connecting new wells and offering
additional value-added services.
37
<PAGE> 41
<TABLE>
<CAPTION>
NATURAL GAS GATHERING - FINANCIAL AND OPERATING RESULTS
- -----------------------------------------------------------------------------
(millions of dollars, except as noted) 1996 1995 1994
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Gathering revenue $ 25.4 $ 27.3 $ 22.6
Natural gas sales 63.2 20.2 --
Products extraction 8.9 7.6 7.9
Other operating revenue 3.2 1.2 2.2
- -----------------------------------------------------------------------------
Total operating revenues 100.7 56.3 32.7
- -----------------------------------------------------------------------------
Gas purchased, net 61.2 20.0 --
Cost of sales 4.8 4.7 4.7
Operation and maintenance 12.5 13.0 11.1
Administrative expense 5.3 4.5 3.9
Depreciation 2.1 4.1 6.2
Taxes other than income 0.9 1.3 1.2
- -----------------------------------------------------------------------------
Operating income $ 13.9 $ 8.7 $ 5.6
=============================================================================
Average invested capital $ 117.6 $ 97.8 $ 102.1(1)
=============================================================================
Total throughput (Bcf) 230.5 232.3 229.7
Margin/unit of throughput ($/MMBtu) $ 0.151 $ 0.136 $ 0.122
Number of receipt points 3,183 2,987 2,871
- -----------------------------------------------------------------------------
</TABLE>
(1) Balance as of December 31, 1994; the December 31, 1993 balance is not
available for the computation of an average.
1996 vs. 1995
Operating income for NFS in 1996 was $13.9 million, an increase of $5.2 million
(59.8%) from the $8.7 million earned in 1995. This increase reflected both
increased operating margins and reduced expenses as discussed following.
Total operating revenues increased from $56.3 million in 1995 to $100.7
million in 1996, an increase of $44.4 million (78.9%). Approximately $43.0
million (96.8%) of this favorable variance was due to an increase in NFS's gas
marketing and balancing activities performed in support of its gathering
customers, which activities yield very low margins. Excluding the revenues
associated with these marketing and balancing activities, operating revenues
increased approximately $1.4 million (3.9%) from $36.1 million in 1995 to $37.5
million in 1996. This net increase was composed of an approximately $1.7
million increase attributable to an increase in the average unit revenue in
1996, partially offset by a decrease of approximately $0.3 million attributable
to decreased 1996 throughput. The increase in the average unit revenue in 1996
was principally due to new compression, nomination and balancing services
provided to customers in 1996, in addition to higher 1996 liquid prices. The
net decrease of approximately 1.8 Bcf (0.8%) in 1996 throughput reflected
producer shut-ins, freeze-offs, curtailments and increased capacity constraints
in comparison to the prior year, partially offset by increased throughput from
approximately 200 new well connections and the addition of gathering assets
previously owned by Interstate Pipelines.
The gross margin ("Total operating revenues" less "Gas purchased, net"
and "Cost of sales") increased from $31.6 million in 1995 to $34.7 million in
1996, an increase of $3.1 million (9.8%). This net favorable variance was
composed of a $3.3 million favorable variance due to the increase in the 1996
average unit revenue, partially offset by a $0.2 million unfavorable variance
attributable to the reduced 1996 throughput, each as discussed preceding.
Pursuant to a review of the natural gas reserves connected and proximate
to NFS's gathering systems, in July 1995, NFS reduced the depreciation rates
associated with certain of its assets. This reduction in depreciation rates was
responsible for substantially all of the $2.0 million (48.8%) decrease in
depreciation expense from 1995 to 1996.
Despite an increased level of services during 1996, primarily from the
installation of compression and new well connections, other expenses (exclusive
of "Gas purchased, net", "Cost of sales" and "Depreciation") decreased by $0.1
million (0.5%) from 1995 to 1996, primarily due to (1) reduced 1996 labor costs
in the field which more than offset increased administrative staffing costs to
support the additional services as described preceding and (2) reduced 1996 ad
valorem taxes.
38
<PAGE> 42
1995 VS. 1994
Operating income for NFS in 1995 was $8.7 million, an increase of $3.1 million
(55.4%) from the $5.6 million earned in 1994. This increase reflected both
increased operating revenues and increased operating expenses as discussed
following.
Total operating revenues increased from $32.7 million in 1994 to $56.3
million in 1995, an increase of $23.6 million (72.2%). Approximately $20.2
million (85.6%) of this favorable variance was due to NFS's 1995 gas marketing
and balancing activities performed in support of its gathering customers, which
activities yield very low margins and were not performed in 1994. After removal
of revenues associated with these 1995 marketing and balancing activities,
operating revenues increased from $32.7 million in 1994 to $36.1 million in
1995, an increase of $3.4 million (10.4%). Approximately $3.0 million (88.2%)
of this increase was attributable to an increase in the average unit revenue in
1995, and approximately $0.4 million (11.8%) was attributable to increased 1995
throughput. The increase in the average 1995 unit revenue was principally due
to new compression and nomination services provided to customers in 1995. The
increase of approximately 2.6 Bcf (1.1%) in 1995 throughput reflected the
implementation of low pressure projects and other enhanced gathering services
during 1995, partially offset by approximately 6.5 Bcf of gas which was shut in
by producers during 1995 due to relatively low spot market gas prices.
The gross margin ("Total operating revenues" less "Gas purchased, net"
and "Cost of sales") increased from $28.0 million in 1994 to $31.6 million in
1995, an increase of $3.6 million (12.9%). Approximately $3.3 million (91.7%)
of this variance was due to the increase in the 1995 average unit revenue and
the remaining $0.3 million (8.3%) was attributable to the increased 1995
throughput, each as discussed preceding.
Pursuant to a review of the natural gas reserves connected and proximate
to NFS's gathering systems, in July 1995, NFS reduced the depreciation rates
associated with certain of its assets. This decrease in depreciation rates was
responsible for substantially all of the $2.1 million (33.9%) decrease in
depreciation expense from 1994 to 1995.
Other expenses (exclusive of "Gas purchased, net", "Cost of sales" and
"Depreciation") increased by approximately $2.6 million (16.0%) from 1994 to
1995, largely due to a $2.2 million increase in 1995 compression rental and
related supplies and expenses incurred in support of projects to lower pressure
and increase deliverability, together with incremental 1995 staffing costs
incurred to support the additional services as described preceding.
RETAIL ENERGY MARKETING
The Company's marketing of natural gas and related services to those industrial
and commercial customers located behind the "city gate" of local gas
distribution companies but not utilizing traditional "bundled" utility service,
as well as certain industrial customers served by third-party pipelines on
which the Company holds capacity, is principally carried out by NorAm Energy
Management, Inc., together with certain affiliates (collectively, "NEM").
Certain of NEM's activities, while not subject to traditional cost-of-service
rate determination, are subject to the jurisdiction of various regulatory
bodies as to the allocation of joint costs between such activities and certain
of the Company's regulated activities. In the fourth quarter of 1996, NEM
opened offices in Ohio and New Jersey in order to expand the scope of its
marketing efforts and provide for increased customer contact. NEM had sales to
six facilities, operated by its largest customer, which represented
approximately 38.4 Bcf (19.3%), 38.3 Bcf (22.6%) and 11.9 Bcf (10.2%) of NEM's
total gas sales volumes in 1996, 1995, and 1994, respectively. In general, the
contracts pursuant to which these sales are made extend to June 1999.
Results of operations for Retail Energy Marketing ("REM") as presented
following also include the Company's home care service activities ("HCS"),
including (1) appliance sales and service, (2) home security services and (3)
resale of long distance telephone service, the latter two of which businesses
are essentially in a "start-up" mode. HCS's activities contributed operating
income (loss) of approximately $3.0 million, $(0.5) million and $(0.7) million
to REM's overall operating results in 1996, 1995 and 1994, respectively.
Appliance sales and service had operating revenues of $52.2 million, $45.6
million and $43.6 million during 1996, 1995 and 1994, respectively,
representing in excess of 97% of HCS's operating revenues during each period.
39
<PAGE> 43
<TABLE>
<CAPTION>
RETAIL ENERGY MARKETING - FINANCIAL AND OPERATING RESULTS
- --------------------------------------------------------------------------------------------
(millions of dollars, except as noted) 1996 1995 1994
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas sales $ 495.5 $ 295.8 $ 242.2
Transportation 3.7 3.5 3.6
Other, principally home care services 54.2 46.6 44.7
- --------------------------------------------------------------------------------------------
Total operating revenues 553.4 345.9 290.5
- --------------------------------------------------------------------------------------------
Purchased gas cost 459.6 270.5 220.9
Operations, maintenance, cost of
sales and other, principally home care services 53.1 46.6 45.7
General and administrative 7.2 3.3 2.3
Depreciation and amortization 1.8 1.9 1.9
Taxes other than income 2.0 1.4 1.3
- --------------------------------------------------------------------------------------------
Operating income $ 29.7 $ 22.2 $ 18.4
- --------------------------------------------------------------------------------------------
Natural gas sales volume (Bcf) 198.7 169.7 116.6
Average sales margin ($/Mcf) $ 0.181 $ 0.149 $ 0.183
Transportation volume (Bcf) 26.2 25.3 27.7
- --------------------------------------------------------------------------------------------
</TABLE>
1996 vs. 1995
Operating income for REM increased from $22.2 million in 1995 to $29.7 million
in 1996, an increase of $7.5 million (33.8%). This overall increase reflected
(1) an increase of approximately $7.0 million attributable to improved results
from NEM's gas marketing activities (operating income for 1996 was $29.7
million) and (2) an increase of approximately $3.6 million attributable to
improved results from HCS (operating income for 1996 was approximately $3.0
million). The improved results from HCS were principally due to increased
margin from appliance sales and service, reflecting (1) increased contracts and
options, (2) a basic contract price increase and (3) increased technician
productivity. These favorable variances were partially offset by (1) a decrease
of approximately $2.3 million associated with the start-up of NorAm Consumer
Services in 1996, principally the initial offering of appliance services in
Denver, Colorado and (2) a decrease of approximately $0.8 million attributable
to the start-up of Arkla Long Distance, a reseller of long distance telephone
service. The improved results from NEM's activities reflected both increased
operating revenues and increased operating expenses as discussed following.
Natural gas sales revenues increased from $295.8 million in 1995 to
$495.5 million in 1996, an increase of $199.7 million (67.5%). Approximately
$149.2 million (74.7%) of this increase was attributable to an increase in the
average sales price in 1996 and approximately $50.5 million (25.3%) of the
increase was attributable to increased 1996 sales volumes. The increase of
approximately $0.75 per Mcf (43.1%) in the average sales price in 1996 was
principally due to (1) an increase of approximately $0.72 per Mcf (45.1%) in
the average cost of purchased gas in 1996 (a component of the sales rate) and
(2) an increase in the average sales margin as discussed following. The
increase of 29.0 Bcf (17.1%) in sales volumes during 1996 was principally due
to (1) increased 1996 marketing efforts by an expanded staff and (2) weather-
related 1996 increases in swing sales to commercial and industrial customers
(principally during the first quarter). In addition, the weather-related
increased demand for firm supplies of gas created opportunities to serve
customers outside NEM's traditional service area who were unable to obtain
supplies under their usual arrangements.
"Purchased gas cost" increased from $270.5 million in 1995 to $459.6
million in 1996, an increase of $189.1 million (69.9%). This increase was
principally due to the increase in the 1996 average cost of gas and the
increased 1996 sales volume as discussed preceding, which were responsible for
$142.9 million (75.6%) and $46.2 million (24.4%), respectively, of the total
increase.
The average sales margin increased from $0.149 per Mcf in 1995 to $0.181
per Mcf in 1996, an increase of $0.032 per Mcf (21.5%), principally due to the
relatively colder 1996 weather and resulting decreased availability of pipeline
capacity at various locations. This decreased availability of gas and
associated transportation resulted in the payment of significant premiums by
certain customers in certain circumstances in order to avoid interruption of
supply.
40
<PAGE> 44
The increase of $6.5 million (13.9%) in "Operating, maintenance, cost of
sales and other, principally Home Care Services" from 1995 to 1996 was
principally due to (1) the 1996 costs associated with the start-up businesses
as discussed preceding and (2) increased 1996 cost of sales, marketing expenses
and vehicles in the appliance sales and service business. The increase of $3.9
million (118.2%) in "General and administrative" was principally due to
increased staffing costs incurred in support of the increased marketing efforts
and sales as discussed preceding.
1995 vs. 1994
Operating income for REM increased from $18.4 million in 1994 to $22.2 million
in 1995, an increase of $3.8 million (20.7%). Approximately $0.2 million of
this increase was attributable to a decreased operating loss at HCS, with the
balance attributable to NEM's natural gas sales and marketing activities,
reflecting both increased operating revenues and increased operating expenses
as discussed following.
Natural gas sales revenues increased from $242.2 million in 1994 to
$295.8 million in 1995, an increase of $53.6 million (22.1%). This net increase
was composed of an approximately $110.3 million increase attributable to higher
1995 sales volume, partially offset by a decrease of approximately $56.7
million attributable to a decrease in the average natural gas sales price
during 1995. The increase of approximately 53.1 Bcf (45.5%) in natural gas
sales volume during 1995 was principally due to the addition of several new
industrial customers whose operations are affiliated with those of NEM's
largest customer, brought about by its acquisition of four large chemical
plants along the Texas Gulf Coast. The decrease of approximately $0.33 per Mcf
(16.1%) in the average natural gas sales price in 1995 was principally due to a
decrease of approximately $0.30 per Mcf (15.9%) in the average cost of
purchased gas in 1995 (a component of the sales rate) as discussed following.
"Purchased gas cost" increased from $220.9 million in 1994 to $270.5
million in 1995, an increase of $49.6 million (22.5%). This net increase was
composed of an increase of approximately $100.6 million attributable to the
increase in 1995 natural gas sales volume as discussed preceding, partially
offset by a decrease of approximately $51.0 million attributable to a decrease
in the 1995 average cost of purchased gas. This decrease in the average cost of
purchased gas was directly reflective of the decline in spot market natural gas
prices from 1994 to 1995.
The gross margin on gas sales increased from $21.3 million in 1994 to
$25.3 million in 1995, an increase of $4.0 million (18.8%). This net increase
was composed of an increase of approximately $9.7 million attributable to the
increased 1995 natural gas sales volume as discussed preceding, partially
offset by a decrease of approximately $5.7 million attributable to a decrease
in the average sales margin in 1995. The average sales margin decreased from
approximately $0.183 per Mcf in 1994 to approximately $0.149 per Mcf in 1995, a
decrease of approximately $0.034 per Mcf (18.6%). This decrease was principally
due to competitive pressures in NEM's market area which frequently require that
NEM accept lower margins in order to remain competitive in existing markets
and/or acquire incremental business.
The increase of $0.9 million (2.0%) in "Operating, maintenance, cost of
sales and other, principally Home Care Services" from 1994 to 1995 was
principally due to increased costs associated with appliance service
activities. The increase of $1.0 million (43.5%) in "General and
administrative" from 1994 to 1995 was principally due to increased staffing
costs incurred in support of the increased natural gas sales as discussed
preceding.
CORPORATE AND OTHER
The $17.6 million increase in the operating loss from $(9.6) million in 1995 to
$(27.2) million in 1996, was principally due to (1) approximately $4.5 million
of 1996 costs associated with the pending merger with Houston Industries, see
"Merger With Houston Industries" elsewhere herein, (2) approximately $2.8
million of incremental 1996 losses associated with NorAm Damage Prevention, a
start-up business principally engaged in line locating services, (3)
approximately $2.8 million of incremental 1996 costs associated with general
business development activities, (4) a decrease of approximately $1.8 million
in the 1996 favorable consolidation adjustment associated with certain benefit
plans, (5) approximately $1.6 million of incremental 1996 expense associated
with international activities, (6) approximately $1.5 million of incremental
1996 costs not allocated to business units during 1996, (7) approximately $1.0
million of 1995 operating income associated with a forward oil sale agreement
which terminated in mid-
41
<PAGE> 45
1995 and (8) approximately $1.6 million of incremental 1996 costs for
information services and certain miscellaneous activities.
The $2.6 million increase in the operating loss from 1994 to 1995 was
principally due to (1) the expiration of a forward oil sale agreement in June
1995, pursuant to which $1.9 million of operating income was recognized in 1994
but only $1.0 million in 1995, (2) 1995 expenditures associated with the
Company's investigation of international investment opportunities and (3)
incremental 1995 expenditures for miscellaneous activities. These unfavorable
variances were partially offset by a decline in 1995 depreciation expense due
to the transfer of certain Corporate assets to another business unit in early
1995.
NON-OPERATING INCOME AND EXPENSE
Consolidated net income for 1996 was approximately $90.9 million, an
improvement of approximately $25.4 million (38.8%) from the $65.5 million
earned in 1995 while, as discussed preceding, operating income increased by
approximately $27.2 million (9.5%) during the same period. The principal
reasons for this increase of $1.8 million (0.8%) in net expense below the
operating income line were as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
(dollars in millions) Year Ended
December 31, Increase(Decrease)
1996 1995 $ %
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Interest expense, net $ 132.6 $ 158.0 $ (25.4) / (16.1%)(1)(2)
Dividend on Trust Preferred (3) 5.8 -- 5.8 / N/A
Loss on sale of accounts receivable (2) 11.5 9.8 1.7 / 17.3% (4)
Other, net 3.1 (1.4) 4.5 / 321.4%
Income tax provision 66.4 55.4 11.0 / 19.9% (5)
Extraordinary item (6) 4.3 0.1 4.2 / N/M
- ----------------------------------------------------------------------------------------------
Total $ 223.7 $ 221.9 $ 1.8 / 0.8%
- ----------------------------------------------------------------------------------------------
</TABLE>
(1) Approximately $18.3 million (72.0%) of this favorable variance was
attributable to a decrease in the average level of debt during 1996 and
the balance of approximately $7.1 million (28.0%) was attributable to a
decrease in the average interest rate in 1996, see "Net Cash Flows from
Financing Activities" elsewhere herein.
(2) Beginning with January 1, 1997, amounts previously reported as "Loss on
sale of accounts receivable" will be included as a component of interest
expense, see "Net Cash Flows from Operating Activities" elsewhere herein.
(3) The Trust Preferred was issued in June 1996, see "Net Cash Flows from
Financing Activities" elsewhere herein.
(4) This net unfavorable variance was composed of a $3.5 million unfavorable
variance attributable to increased 1996 utilization of the facility,
partially offset by a $1.8 million favorable variance attributable to a
lower average interest rate in 1996.
(5) This net unfavorable variance was composed of an unfavorable variance of
approximately $18.6 million attributable to an increase in 1996 pre-tax
income, partially offset by a decrease of approximately $7.6 million
attributable to a decrease in the effective tax rate in 1996, see Note 2
of the accompanying Notes to Consolidated Financial Statements.
(6) Loss on early retirement of debt, less taxes, see "Retirements and
Reacquisitions of Long-Term Debt" included in Note 3 of the accompanying
Notes to Consolidated Financial Statements.
Consolidated net income for 1995 was approximately $65.5 million, an
improvement of approximately $17.4 million (36.2%) from the $48.1 million
earned in 1994 while, as discussed preceding, operating income increased by
$22.4 million during the same period. The principal reasons for this increase
of $5.0 million (2.3%) in net expense below the operating income line were as
follows:
42
<PAGE> 46
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
(dollars in millions) Year Ended
December 31, Increase(Decrease)
1995 1994 $ %
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Interest expense, net $ 158.0 $ 169.4 $ (11.4) / (6.7%) (1)(2)
Loss on sale of accounts receivable (2) 9.8 7.1 2.7) / 38.0% (3)
Other, net (1.4) 2.8 (4.2) / (150.0%)
Income tax provision 55.4 34.4 21.0 / 61.0% (4)
Discontinued operations 0.0 2.1(5) (2.1) / (100.0%)
Extraordinary item (6) 0.1 1.1 (1.0) / (90.9%)
- -------------------------------------------------------------------------------------------------------------
Total $ 221.9 $ 216.9 $ 5.0 / 2.3%
=============================================================================================================
</TABLE>
(1) Approximately $8.1 million (71.1%) of this favorable variance was
attributable to a decrease in the average level of debt during 1995 and
the balance of approximately $3.3 million (28.9%) was attributable to a
decrease in the average interest rate in 1995, see "Net Cash Flows from
Financing Activities" elsewhere herein.
(2) Beginning with January 1, 1997, amounts previously reported as "Loss on
sale of accounts receivable" will be included as a component of interest
expense, see "Net Cash Flows from Operating Activities" elsewhere
herein.
(3) Approximately $2.2 million (81.5%) of this unfavorable variance was
attributable to an increase in the average interest rate in 1995 and the
balance of approximately $0.5 million (18.5%) was attributable to
increased 1995 utilization of the facility.
(4) Approximately $14.1 million (67.1%) of this unfavorable variance was
attributable to an increase in 1995 pre-tax income and the balance of
approximately $6.9 million (32.9%) was attributable to an increase in
the effective tax rate in 1995, see Note 2 of the accompanying Notes to
Consolidated Financial Statements.
(5) Costs associated with the discontinued operations of University Savings
Association, see "Discontinued Operations" included in Note 1 of the
accompanying Notes to Consolidated Financial Statements.
(6) Loss on early retirement of debt, less taxes, see "Retirements and
Reacquisitions of Long-Term Debt" included in Note 3 of the accompanying
Notes to Consolidated Financial Statements.
DISCONTINUED OPERATIONS
EXPLORATION AND PRODUCTION
On December 31, 1992, the Company completed the sale of Arkla Exploration
Company, the Company's former subsidiary engaged in oil and gas exploration and
production activities, to Seagull Energy Corporation ("Seagull") for
approximately $397 million in cash. In conjunction with the sale, the Company
agreed to indemnify Seagull against certain exposures, for which the Company
has established reserves equal to anticipated claims under the indemnity. In
conjunction with its 1991 sale of Dyco Petroleum Company, the Company
established a reserve equal to its expected exposure under the limited
indemnity provisions of the sale agreement. These reserves are included under
the caption "Estimated obligations under indemnification provisions of sale
agreements" in the accompanying Consolidated Balance Sheet.
RADIO COMMUNICATIONS AND ENERGY MEASUREMENT
In conjunction with the purchase of Diversified Energies, Inc. in November
1990, the Company acquired business units that conducted operations in radio
communications ("Johnson") and energy measurement products and systems
("EnScan"). In 1992, the Company sold Johnson, and EnScan merged with Itron,
Inc. ("Itron") of Spokane, Washington, a company which manufactures equipment
and provides services similar and complementary to those of EnScan, resulting
in an exchange of the Company's EnScan common stock for shares of Itron common
stock (the "Itron Shares"). After the Company's 1994 sale of 400,000 Itron
Shares and its 1995 sale of 80,000 Itron Shares, each at approximately book
value (yielding cash proceeds of approximately $7.2 million and $1.4 million,
respectively), at December 31, 1996, the Company's remaining Itron Shares
(approximately 1.5 million) represented ownership of approximately 11.2% of the
combined enterprise, which is managed by Itron. Based on price quotations on
the NASDAQ, the market value (and carrying value) of the Company's investment
at December 31, 1996 was approximately $26.7 million, approximately the
Company's cost basis. The market value of the Itron shares was approximately
$29.3 million at March 14, 1997, representing an unrealized gain of $1.7
million (net of tax benefit of $1.0 million). Any unrealized gain or loss, net
of related tax effect, is reported as a separate component of stockholders'
equity. During 1996, the market value of the
43
<PAGE> 47
Company's Itron investment (based on closing share prices on the NASDAQ) varied
from a high of approximately $88.3 million to a low of approximately $22.5
million. While there are other ways in which the Company could monetize its
investment in the Itron Shares, in general, the market for the Itron Shares on
the NASDAQ is not sufficiently liquid to allow the Company to dispose of a
significant portion of its investment in a single transaction without accepting
a significant discount from the quoted price.
UNIVERSITY SAVINGS ASSOCIATION
University Savings Association was a wholly owned subsidiary of Entex, Inc.
until its sale to a private group in May 1987, prior to the Company's February
1988 merger with Entex, see "Discontinued Operations" included in Note 1 of the
accompanying Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
The table below illustrates the sources of the Company's invested capital
during the last five years (see also "Sale of Receivables" under "Net Cash
Flows from Operating Activities" elsewhere herein). The Company engaged in
several significant financing transactions during 1996, see "Net Cash Flows
from Financing Activities" elsewhere herein.
<TABLE>
<CAPTION>
INVESTED CAPITAL
- -------------------------------------------------------------------------------------------
(dollars in millions) December 31,
1996 1995 1994 1993 1992
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Long-term debt $1,054.2 $1,474.9 $1,414.4 $1,629.4 $1,783.1
Trust preferred (1) 167.8 -- -- -- --
Common equity (2) 800.5 637.3 587.4 578.0 582.9
Preferred stock (3) -- 130.0 130.0 130.0 130.0
- -------------------------------------------------------------------------------------------
Total capitalization 2,022.5 2,242.2 2,131.8 2,337.4 2,496.0
Short-term debt 392.0 128.8 274.6 192.4 120.0
- -------------------------------------------------------------------------------------------
Total invested capital $2,414.5 $2,371.0 $2,406.4 $2,529.8 $2,616.0
===========================================================================================
TOTAL CAPITALIZATION:
Long-term debt 52.1% 65.8% 66.3% 69.7% 71.4%
Trust preferred (1) 8.3% -- -- -- --
Common equity 39.6% 28.4% 27.6% 24.7% 23.4%
Preferred stock -- 5.8% 6.1% 5.6% 5.2%
- -------------------------------------------------------------------------------------------
TOTAL INVESTED CAPITAL:
Senior debt (4) 54.8% 67.6% 70.2% 72.0% 72.7%
Total debt
Without receivables sold (5) 59.9% 67.6% 70.2% 72.0% 72.7%
With receivables sold (5) 63.5% 70.6% 72.4% 74.3% 74.8%
- -------------------------------------------------------------------------------------------
</TABLE>
(1) Company-Obligated Mandatorily Redeemable Convertible Preferred
Securities of Subsidiary Trust Holding Solely $177.8 Million Principal
Amount of 6.25% Convertible Subordinated Debentures due 2026 of NorAm
Energy Corp., see "Net Cash Flows from Financing Activities" elsewhere
herein.
(2) Includes unrealized gains on the Company's investment in Itron, net of
tax of $15.3 million and $2.6 million at December 31, 1995 and 1994,
respectively. The unrealized gain was not material at December 31, 1996.
See also "Radio Communications and Energy Measurement" under
"Discontinued Operations" elsewhere herein.
(3) Exchanged for the Company's 6% Convertible Subordinated Debentures due
2012 in June 1996, see "Net Cash Flows From Financing Activities"
elsewhere herein.
(4) Excludes the Company's 6% Convertible Subordinated Debentures due 2012
outstanding beginning with June 1996, and of which $122.7 million were
outstanding at December 31, 1996, see "Net Cash Flows From Financing
Activities" elsewhere herein.
(5) See "Sale of Receivables" under "Net Cash Flows From Operating
Activities" elsewhere herein.
44
<PAGE> 48
CASH FLOW ANALYSIS
The following discussion of cash flows should be read in conjunction with the
Company's Statement of Consolidated Cash Flows and the additional cash flow
information provided under "Supplemental Cash Flow Information" in Note 1 of
the accompanying Notes to Consolidated Financial Statements.
NET CASH FLOWS FROM OPERATING ACTIVITIES
1996 VS. 1995
As indicated in the accompanying Statement of Consolidated Cash Flows, "Net
cash provided by operating activities" decreased from approximately $338.9
million in 1995 to $228.2 million in 1996. This decrease of approximately
$110.7 million (32.7%) was principally attributable to:
- -- A decrease of approximately $130.0 million (304.4%) in 1996 cash
provided from the net of accounts receivable and accounts payable,
principally due to the build-up of accounts receivable at year-end 1996
reflecting (1) the relatively colder weather and resultant increased
sales in Distribution and (2) increased sales volumes at the Company's
marketing units, partially offset by the related build-up of accounts
payable for purchases of natural gas, transportation and storage
services.
- -- A decrease of approximately $40.0 million (159.4%) in cash provided by
inventories during 1996 principally due to (1) reduced 1996 proceeds
from sales of inventory existing at December 31, 1995 in comparison to
1995 proceeds from sales of inventory existing at December 31, 1994,
principally due to the relatively larger December 31, 1994 balance and
(2) the increase in the December 31, 1996 inventory balance (largely
paid for in 1996) over the December 31, 1995 balance (largely paid for
in 1995).
- -- A decrease of approximately $13.3 million in cash provided in 1996 from
recoveries under settlements of gas contracts disputes as the underlying
agreements continue to expire.
These unfavorable impacts were partially offset by:
- -- An increase of approximately $31.8 million in 1996 income before non-
cash charges and credits, see "Material Changes in the Results of
Continuing Operations" elsewhere herein.
- -- An increase of approximately $32.6 million in 1996 cash provided by
deferred gas costs, principally due to the relatively larger December
31, 1995 balance which was collected during 1996.
- -- An increase of approximately $5.8 million in 1996 cash provided by
income taxes payable, inclusive of the utilization of tax loss
carryforwards, principally due to increased 1996 current tax expense net
of cash income tax payments.
- -- An increase of approximately $2.4 million in 1996 cash provided by
miscellaneous working capital items.
1995 VS. 1994
As indicated in the accompanying Statement of Consolidated Cash Flows, "Net
cash provided by operating activities" increased from approximately $302.3
million in 1994 to approximately $338.9 million in 1995. This increase of
approximately $36.6 million (12.1%) was principally attributable to:
- -- An increase of $22.6 million in cash provided by other current
liabilities in 1995, principally due to the relatively larger December
31, 1993 balance in other current liabilities which was paid in 1994.
- -- An increase of $18.3 million in cash provided by other current assets in
1995 principally due to the relatively larger December 31, 1994 balance
in other current assets which was collected in 1995.
- -- An increase of $13.5 million in 1995 income before depreciation,
amortization and deferred taxes, see "Material Changes in the Results of
Continuing Operations" elsewhere herein.
- -- An increase of $8.9 million in 1995 cash provided by income taxes
payable, inclusive of the utilization of tax loss carryforwards,
principally due to increased 1995 current tax expense and the relatively
larger December 31, 1993 balance in income taxes payable which was paid
in 1994.
45
<PAGE> 49
- -- An increase of $8.2 million in 1995 cash provided by miscellaneous
working capital items, including a $2.9 million increase in cash
provided from recoveries under gas contract disputes.
- -- An increase of approximately $3.4 million in 1995 cash provided by the
net of discontinued operations, extraordinary items and other
miscellaneous items.
These favorable impacts were partially offset by:
- -- An increase of $19.8 million in cash used for deferred gas costs in 1995
principally due to an increase in purchases of gas in advance of
collections from customers.
- -- A decrease of $17.5 million in 1995 cash provided by inventories,
principally due to the 1994 sale of the majority of MRT's gas in storage
to its customers in conjunction with implementation of FERC Order 636.
- -- A decrease of $1.0 million in 1995 cash provided from the net of
accounts receivable and accounts payable, principally due to the
seasonality of the Company's businesses.
Under an August 1996 agreement ("the Receivables Facility") which
expires in August 1997 (although the Company currently expects to renew the
facility), the Company sells, with limited recourse and subject to a floating
interest rate provision which varies with the buyer's A1/P1 commercial paper
rate, an undivided interest (limited to a maximum of $235 million) in a
designated pool of accounts receivable. Certain of the Company's remaining
receivables serve as collateral for receivables sold, which collateral
represents the maximum exposure to the Company should all receivables sold
prove ultimately uncollectible. The Company has retained servicing
responsibility under the Receivables Facility for which it is paid a fee which
does not differ materially from a normal servicing fee and, to the extent that
the Company utilizes this facility more or less during a given period, it will
experience a net cash inflow or outflow. These cash flows have been included
with "Cash Flows from Operating Activities" in the Company's Statement of
Consolidated Cash Flows, and losses realized upon sales of receivables under
the Receivables Facility have been reported in the Company's Statement of
Consolidated Income under the caption "Loss on sale of accounts receivable",
which accounting will change beginning January 1, 1997 as described following
the tabular data. Following is certain information concerning the utilization
of this facility:
<TABLE>
<CAPTION>
SALE OF RECEIVABLES
- -------------------------------------------------------------------------------------------------------------------------
(dollars in millions) Year Ended
December 31, December 31,
---------------------------------- ---------------------------------------------------------------------
Amount Net Pre-tax Average Weighted
Sold and Inflows Loss Receivables Average
Uncollected Collateral (Outflows) on Sale Sold (1) Rate (1)(2)
---------------- ---------------- ---------------- ---------------- --------------- ---------------
<S> <C> <C> <C> <C> <C>
1996 $ 235.0 $ 34.2 -- $ (11.5) $ 186.9 5.41%
1995 235.0 35.0 $ 42.2 (9.8) 136.8 6.02%
1994 $ 192.8 $ 48.7 $ (33.6) $ (7.1) $ 115.2 4.43%
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Based on daily balances.
(2) Exclusive of a facility fee payable on the full commitment of $235
million, which fee was 22 basis points at December 31, 1996. The rate in
effect at December 31, 1996 (exclusive of the facility fee) was 5.65%.
Statement of Financial Accounting Standards No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities"
("SFAS 125") is required to be adopted for transfers and servicing of financial
assets and extinguishments of liabilities occurring after December 31, 1996.
The effect of the adoption of SFAS 125 on the Company's financial statements
will be to treat amounts transferred pursuant to the Receivables Facility as
collateralized borrowings rather than as sales. Therefore, beginning January 1,
1997, (1) receivables which previously would have been reported as sold
pursuant to the Receivables Facility will remain as assets on the Company's
consolidated balance sheet, (2) amounts received by the Company pursuant to
this facility will be recorded as debt, (3) amounts previously reported as
"Loss on sale of accounts receivable" will be reported as a component of
interest
46
<PAGE> 50
expense and (4) cash flows associated with the utilization of this facility
will be included with "Cash Flows from Financing Activities" in the Company's
Statement of Consolidated Cash Flows.
In accordance with authoritative accounting guidelines, income tax
payments and refunds are reported as cash flows from operating activities. The
Company has net operating loss carryforwards and alternative minimum tax credit
carryforwards which may reduce its future income tax payments, see Note 2 of
the accompanying Notes to Consolidated Financial Statements.
NET CASH FLOWS FROM INVESTING ACTIVITIES
In 1994, the Company generated cash of approximately $23.2 million through the
sale of distribution properties, see "Natural Gas Distribution" under "Material
Changes in the Results of Continuing Operations" elsewhere herein. Also in
1994, the Company generated approximately $12.3 million in cash from the sale
of certain gas prepayments. The Company terminated virtually all of its
"corporate-owned life insurance" policies during 1995, receiving cash proceeds
of approximately $12.3 million. The Company generated approximately $1.4
million and $7.2 million in cash from sales of Itron common stock in 1995 and
1994, respectively, see "Radio Communications and Energy Measurement" under
"Discontinued Operations" elsewhere herein. Following is certain information
concerning the Company's capital expenditures:
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES - CONTINUING OPERATIONS
- -------------------------------------------------------------------------------------------------------------------------
(millions of dollars) Budgeted
1997(1) 1996 1995 1994 1993 1992
- --------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Distribution $ 128.0 $ 116.4 $ 128.4 $ 120.4 $ 111.4 $ 105.0
Interstate Pipelines 60.5 39.9 37.5 41.7 30.3 21.5
Wholesale Energy Marketing -- -- -- -- -- --
Natural Gas Gathering (2) 16.9 10.2 6.0 5.8 -- --
Retail Energy Marketing 9.8 2.1 0.8 0.8 1.5 1.2
Corporate and Other 2.5 3.6 0.9 1.7 1.1 2.1
- --------------------------------------------------------------------------------------
Subtotal 217.7 172.2 173.6 170.4 144.3 129.8
LIG (3) -- -- -- -- 1.9 5.1
- --------------------------------------------------------------------------------------
Total $ 217.7 $ 172.2 $ 173.6 $ 170.4 $ 146.2 $ 134.9
- --------------------------------------------------------------------------------------
</TABLE>
(1) Does not include expenditures for international projects which the
Company expects, on average, will not exceed $25-30 million per year
over the next 3-5 years, see also "General" under "Material Changes in
the Results of Continuing Operations" elsewhere herein.
(2) Natural Gas Gathering expenditures are included with Interstate
Pipelines in 1993 and 1992, see "Natural Gas Gathering" under "Material
Changes in the Results of Continuing Operations" elsewhere herein.
(3) LIG's capital expenditures are included until its sale in June 1993, see
"Interstate Pipelines" under "Material Changes in the Results of
Continuing Operations" elsewhere herein.
The Company's total capital expenditures did not change materially from 1995 to
1996, as a decrease of approximately $12.0 million (9.3%) at Natural Gas
Distribution was largely offset by increases of approximately $4.2 million
(70.0%), $2.7 million (300.0%), $2.4 million (6.4%) and $1.3 million (162.5%)
at Natural Gas Gathering, Corporate and Other, Interstate Pipelines and Retail
Energy Marketing, respectively. The decrease in capital spending for
Distribution was spread approximately equally across the Company's three
distribution divisions and principally represented reduced expenditures for new
construction, expansion and transportation equipment. While each of these
changes is within the normal range of variance in the Company's capital
spending programs, (1) the increase in Natural Gas Gathering was principally
due to the purchase of field compression equipment to increase deliverability,
which equipment had formerly been leased, (2) the increase in Corporate and
Other was principally due to the replacement of a corporate aircraft, and (3)
the increase in Interstate Pipelines was principally due to increased
expenditures for new construction/expansion (principally Line F, see
"Regulatory Matters" elsewhere herein), partially offset by decreased
expenditures for replacements.
The Company's total capital expenditures did not change significantly
from 1994 to 1995, as an increase of $8.0 million (6.6%) at Distribution was
partially offset by a decrease of $4.2 million (10.1%) at Pipeline. These
variances are within the normal range of variation in the Company's capital
spending
47
<PAGE> 51
program, although Pipeline's capital spending was significantly lower than
originally budgeted for 1995 due, in large part, to a return of transmission
capacity by ANR Pipeline Company, see "Transportation Agreement" under
"Commitments and Contingencies" elsewhere herein. This increased capacity
allowed Pipeline to cancel or postpone certain expenditures budgeted to
increase throughput capacity at facilities near Perryville, Louisiana.
The Company's capital expenditures for 1997 are budgeted at $217.7
million, an increase of $45.5 million (26.4%) over 1996 actual expenditures,
reflecting increases of $20.6 million (51.6%), $11.6 million (10.0%), $7.7
million and $6.7 million (65.7%) at Pipeline, Distribution, Retail Energy
Marketing, and Natural Gas Gathering, respectively. The increase for Pipeline
reflects a significant increase in projected expenditures for "market-driven"
projects which are expected to be undertaken to meet increased demand,
principally for incremental west-to-east capacity across the NGT and MRT
systems. The increase for Distribution principally reflects projected
incremental expenditures for new service extensions, as market opportunities
are aggressively pursued. The increase for Retail Energy Marketing is
principally attributable to projected expenditures for the purchase of winter-
peaking facilities to expand its ability to provide firm service in periods of
peak demand. The increase for Natural Gas Gathering is principally due to
projected expenditures for projects to (1) lower pressure and increase
deliverability, (2) install electronic flow measurement equipment needed to
support certain wellhead services and (3) provide for multiple pipeline
connects from the outlet of the Waskom gas processing facility. At December 31,
1996, the Company had committed to spend only a small portion of projected 1997
capital expenditures (see "Commitments and Contingencies" and "General" under
"Material Changes in the Results of Continuing Operations" elsewhere herein),
and the Company expects that its capital spending will be funded through
internally generated funds and, if necessary, through incremental borrowing.
NET CASH FLOWS FROM FINANCING ACTIVITIES
The Company meets its needs for short-term financing through its revolving
credit facility which includes a major money center bank as agent and various
other commercial banks, through informal lines of credit and through a sale of
receivables facility, see "Net Cash Flows from Operating Activities" elsewhere
herein.
The Company's principal short-term credit facility ("the Credit
Facility") with Citibank, N.A. as Agent and a group of 18 other commercial
banks provides a $400 million commitment to the Company through December 11,
1998. Borrowings under the Credit Facility are unsecured and, at the option of
the Company, bear interest at various Eurodollar and domestic rates plus a
credit spread, which credit spread is subject to adjustment based on the rating
of the Company's senior debt securities. The Company pays a facility fee on the
total commitment to each bank each year, currently .14% and subject to decrease
based on the Company's debt rating, and is required to pay incremental rates of
1/8% to 1/4% on outstanding borrowings in excess of $200 million.
The Company had $80.0 million in borrowings under the Credit Facility at
December 31, 1996 and $35.0 million in borrowings under informal lines of
credit. The Company had no borrowings under the Credit Facility at December 31,
1995, and had $10 million of borrowings under informal lines of credit. The
Company had $175.0 million in borrowings under the Credit Facility at March 3,
1997. The Company had, therefore, $225 million in capacity under the Facility
at March 3, 1997, which capacity is expected to be adequate to cover the
Company's current and projected needs for short-term financing. For additional
information on interest rates and amounts borrowed under short-term financing
agreements, see "Short-Term Credit Facilities" included in Note 3 of the
accompanying Notes to Consolidated Financial Statements.
The Credit Facility contains a provision which requires the Company to
maintain a minimum level of total stockholders' equity, initially set at $700
million at December 31, 1995, and increased annually thereafter by (1) 50% of
positive consolidated net income and (2) 50% of the proceeds from any
incremental equity offering made after June 30, 1996. The Credit Facility also
places a limitation of $2,055 million on total debt (unless the ratio of total
debt to total capitalization is less than or equal to 60%) and a limitation of
$200 million on the amount of outstanding long-term debt which may be
reacquired, retired or otherwise prepaid prior to its maturity. Certain of the
Company's other financial arrangements contain similar provisions. Based on
these restrictions, the Company had incremental
48
<PAGE> 52
capacity for debt issuance, dividends and debt reacquisitions of $561.7
million, $220.2 million and $200.0 million, respectively, at December 31, 1996.
As further discussed following, the Company's recent long-term debt
financing has been obtained through the issuance of debentures and notes and
through a bank term loan. The issuance of additional mortgage bonds is
precluded by the Company's unsecured indenture dated as of December 1, 1986
with Citibank, N.A. The Company expects that as its long-term debt matures, it
will be able to fund these debt retirements through additional borrowings
and/or from cash provided by operations. For additional information on the
Company's outstanding long-term debt securities, see "Long-Term Debt" included
in Note 3 of the accompanying Notes to Consolidated Financial Statements. In
addition to long-term debt issuance, the Company has obtained long-term
financing through the issuance of common stock, preferred stock and, more
recently, trust originated preferred securities. Following is a discussion of
the Company's recent significant financing activities.
In June 1996, the Company issued 11,500,000 shares of NorAm Energy Corp.
common stock (the "Common Stock") to the public at a price of $9.875 per share,
yielding net cash proceeds of approximately $109.0 million after deducting an
underwriting discount of 4.05% and before deducting expenses of approximately
$0.1 million. The net proceeds from the offering principally were used to
retire debt as described following.
In June 1996, the Company issued $177.8 million of 6.25% Convertible
Junior Subordinated Debentures due 2026 (unless extended by the Company) (the
"Trust Debentures") to NorAm Financing I (the "Trust"), a statutory business
trust under Delaware law, wholly owned by the Company. The Trust Debentures
were purchased by the Trust using the proceeds from (1) the public issuance by
the Trust of 3,450,000 shares of 6.25% Convertible Preferred Securities (the
"Trust Preferred") at $50 per share, a total of $172.5 million and (2) the sale
of approximately $5.3 million of the Trust's common stock (106,720 shares,
representing 100% of the Trust's common equity) to the Company. The sole assets
of the Trust are and will be the Trust Debentures. The interest and other
payment dates on the Trust Debentures correspond to the interest and other
payment dates on the Trust Preferred, and the Company has guaranteed amounts
due on the Trust Preferred. In conjunction with the issuance of the Trust
Preferred, the Company paid an underwriting commission of $1.375 per share and
expenses of approximately $0.1 million in view of the fact that the proceeds
from such issuance would be invested in the Trust Debentures. Under existing
law, interest payments made by the Company for the Trust Debentures are
deductible for federal income tax purposes. For additional information
concerning the Trust Preferred and the Trust Debentures, including conversion
rates, redemption provisions and the ability of the Company to (1) defer
interest payments and (2) extend the stated maturity date, see "Other Long-Term
Financing" included in Note 3 of the accompanying Notes to Consolidated
Financial Statements. The net proceeds from these transactions principally were
used to retire debt as described following.
The Trust is consolidated with the Company for financial reporting
purposes and, therefore, the Trust Debentures are eliminated in consolidation
and the Trust Preferred appears on the Company's Consolidated Balance Sheet
under the caption "Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of Subsidiary Trust Holding Solely $177.8 Million
Principal Amount of 6.25% Convertible Junior Subordinated Debentures due 2026
of NorAm Energy Corp." The dividend on the Trust Preferred is reported in the
accompanying Statement of Consolidated Income under the caption "Dividend
requirement on preferred securities of subsidiary trust".
Utilizing, in large part, the proceeds from the offerings discussed
preceding, in June 1996, the Company (1) retired the $109.0 million principal
amount then outstanding of its 9.875% Debentures due 2018 at a price equal to
105.93% of face value, recognizing an extraordinary pre-tax loss of
approximately $6.5 million (approximately $3.9 million or $0.03 per share
after-tax) and (2) retired its $150 million bank term loan due 2000 at face
value. The Company also made certain other debt reacquisitions and scheduled
debt retirements during 1996, see "Retirements and Reacquisitions of Long-Term
Debt" included in Note 3 of the accompanying Notes to Consolidated Financial
Statements. 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.
49
<PAGE> 53
In June 1996, the Company exercised its right to exchange the $130
million principal amount of its $3.00 Convertible Exchangeable Preferred Stock,
Series A (the "Preferred") for its 6% Convertible Subordinated Debentures due
2012 (the "Subordinated Debentures"). The holders of the Subordinated
Debentures will receive interest quarterly at 6% and have the right at any time
on or before the maturity date thereof to convert the Subordinated Debentures
into Common Stock, initially at the conversion rate in effect for the Preferred
at the date of the exchange, which conversion rate of approximately 1.7467
shares of the Common Stock for each $50 principal amount of the Subordinated
Debentures is subject to adjustment should certain events occur. The Company is
required to make annual sinking fund payments of $6.5 million on the
Subordinated Debentures beginning on March 15, 1997 and on each succeeding
March 15 to and including March 15, 2011. The Company (1) may credit against
the sinking fund requirements (i) any Subordinated Debentures redeemed by the
Company and (ii) Subordinated Debentures which have been converted at the
option of the holder and (2) may deliver outstanding Subordinated Debentures in
satisfaction of the sinking fund requirements, see "Other Long-Term Financing"
included in Note 3 of the accompanying Notes to Consolidated Financial
Statements.
The Company has entered into interest rate swaps for the purposes of (1)
increasing or decreasing the amount of the Company's debt portfolio which is
subject to market interest rate fluctuations and (2) effectively fixing the
interest rate on debt expected to be issued in the future for refunding
purposes (see "Long-Term Debt" included in Note 3 of the accompanying Notes to
Consolidated Financial Statements for the maturities of the Company's various
debt issues), and may enter into additional such swaps in the future. In
general, these swaps are entered into with commercial banks and require that
one party pay a fixed rate on the notional amount of the swap while the
counterparty pays a LIBOR-based rate. Following is information on the Company's
recent interest rate swap activity and on its portfolio of interest rate swaps
at December 31, 1996:
<TABLE>
<CAPTION>
INTEREST RATE SWAPS
- ------------------------------------------------------------------------------------------------
(dollars in millions)
Notional
Amount Unrealized Deferred Interest Rate
Outstanding Gain(Loss) (1) Gains (2) Fixed/Floating
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
December 31, 1993 $ 200.0 $ (2.6) $ 5.0 5.1/% 4.5%
Additions 75.0 -- -- --
Closed out -- -- -- --
- ------------------------------------------------------------------------------------------------
December 31, 1994 275.0 (18.0) 2.5 5.1/% 6.7%
Additions 100.0 -- -- --
Closed out (25.0) -- -- --
- ------------------------------------------------------------------------------------------------
December 31, 1995 350.0 (0.8) 0.8 5.1/% 6.6% (3)
Additions 200.0 -- -- --
Closed out (250.0) -- -- --
- ------------------------------------------------------------------------------------------------
December 31, 1996 $ 300.0 $ 6.7 $ 0.1 4.7/% 5.6% (3)
- ------------------------------------------------------------------------------------------------
</TABLE>
(1) Market value of swaps at date indicated.
(2) The economic value which transfers between the parties to these swaps is
reported as an adjustment to the effective interest rate on the underlying
debt securities and, when positions are closed prior to expiration, any
material gain or loss is deferred and amortized over the period remaining
in the original term of the swap. The effect of these swaps was to
increase (decrease) interest expense by approximately $(1.6) million,
$(0.2) million and $0.5 million in 1996, 1995 and 1994, respectively.
(3) These interest rates do not include swaps which are hedges of anticipated
debt issuance as described following.
50
<PAGE> 54
<TABLE>
<CAPTION>
INTEREST RATE SWAP PORTFOLIO AT DECEMBER 31, 1996 (1) (2)
- -----------------------------------------------------------------------------------------
(dollars in millions)
Estimated
Notional Period Interest Rate Market
Initiated Amount Covered Fixed/Floating (3) Value (4)
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 1995 $ 50.0 Apr.1997-Apr.2002 (5) 5.92% /6.55% $ 1.3
December 1995 50.0 Apr.1997-Apr.2002 (5) 5.92% /6.55% 1.3
January 1996 50.0 Apr.1997-Apr.2002 (5) 5.80% /6.55% 1.6
February 1996 50.0 Apr.1997-Apr.2002 (5) 5.77% /6.55% 1.6
February 1996 50.0 Mar.1996-Jan.1998 (6) 4.76% /5.65% 0.5
February 1996 50.0 Jun.1996-Dec.1997 (6) 4.71% /5.63% 0.4
- -----------------------------------------------------------------------------------------
Total $ 300.0 $ 6.7
=========================================================================================
</TABLE>
(1) None of these swaps are "leveraged" and, accordingly, do not represent
exposure in excess of that suggested by the notional amounts and interest
rates. Off-balance-sheet credit risk exists to the extent that
counterparties to these swaps may fail to perform, although all
counterparties are commercial banks which are participants in the
Company's revolving credit facility. The Company routinely reviews the
financial condition of these banks (utilizing independent monitoring
services and otherwise) and believes that the probability of default by
any of these counterparties is minimal.
(2) In March 1997, the Company closed out the $200 million of swaps which were
serving as hedges of its anticipated April 1997 debt refinancing (see (5)
following), receiving cash proceeds of approximately $8.7 million. Based
on its revised plan for a smaller, shorter-term debt issuance (principally
due to the pending merger with Houston Industries, see "Merger With
Houston Industries" elsewhere herein), approximately $1.0 million will
serve to reduce the effective interest rate on the debt to be issued and
the balance will be credited to March 1997 earnings.
(3) In each case, the Company is the fixed-price payor. The floating (LIBOR-
based) rate is estimated as of December 31, 1996.
(4) Represents the estimated amount which would have been realized upon
termination of the swap at December 31, 1996.
(5) Swaps entered into for the purpose of effectively fixing the interest rate
on debt expected to be issued in 1997 for refunding purposes.
(6) Swaps entered into for the purpose of reducing the Company's exposure to
fluctuations in market interest rates.
The Company has equipment funding agreements ("EFA's") with affiliates
of major banks which provide for the purchase of vehicles, major work equipment
and, to a lesser extent, computers and other office equipment. For accounting
purposes, assets subject to these EFA's receive operating lease treatment, with
an initial non-cancelable term of one year, see "Lease Commitments" included in
Note 7 of the accompanying Notes to Consolidated Financial Statements. At
December 31, 1996, the Company had $3.5 million of available capacity under
these EFA's. The Company currently expects to finalize an agreement by April
1997 which will increase the available capacity by an additional $10 million.
The EFA's extend through July 1997 unless renewed through mutual agreement of
the parties.
Since late 1994, the Company has offered a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP") which affords customers and other
interested parties the opportunity to (1) purchase the Company's common stock
("the Common Stock") directly from the Company, avoiding brokerage fees and
commissions and (2) automatically reinvest their dividends in shares of Common
Stock. Sales of Common Stock under the DSPP were immaterial in 1994 and, during
1996 and 1995, the Company received approximately $10.3 million and $9.8
million, respectively, from such sales. Sales of Common Stock under the DSPP
(although not dividend reinvestment) have been suspended as a result of the
pending Houston Industries transaction, see "Merger With Houston Industries"
elsewhere herein. The Company also has several programs pursuant to which
shares of Common Stock may be issued or sold to employees or directors, see
Notes 5 and 6 of the accompanying Notes to Consolidated Financial Statements.
During 1995, the Company refunded $50 million in conjunction with the
revision of an agreement for sale of an interest in certain pipeline facilities
and will be required to refund additional amounts, see "Transportation
Agreement" under "Commitments and Contingencies" elsewhere herein.
During 1996, 1995 and 1994, the Company paid common dividends of $0.07
per share each quarter, resulting in total cash expenditures of $36.7 million,
$34.5 million and $34.3 million, respectively. The Company paid preferred
dividends of $0.75 per share during each quarter of 1995 and 1994, resulting in
total cash expenditures of $7.8 million in each year, and $3.6 million in
preferred
51
<PAGE> 55
dividends in 1996 prior to the June 1996 conversion of the Company's $3.00
Convertible Exchangeable Preferred Stock, Series A to convertible subordinated
debentures as discussed preceding.
COMMITMENTS AND CONTINGENCIES
CAPITAL SPENDING
At December 31, 1996, the Company had capital commitments of less than $15
million which are expected to be funded through cash provided by operations
and/or incremental borrowings. The Company's other planned capital projects
require no substantial capital commitment in advance of the actual
expenditures, although certain of such expenditures are not discretionary due
to the nature of the Company's utility businesses. See also "General" under
"Material Changes in the Results of Continuing Operations" and "Capital
Expenditures - Continuing Operations" under "Net Cash Flows from Financing
Activities" elsewhere herein.
DEBT RETIREMENTS AND LEASE OBLIGATIONS
The Company's debt retirement schedule for the years 1997-2001 and all years
thereafter is $277.0 million, $81.8 million, $207.1 million, $228.0 million,
$150.6 million and $386.7 million, respectively, see "Long-Term Debt" included
in Note 3 of the accompanying Notes to Consolidated Financial Statements. The
Company has obligations under certain of its leasing arrangements, see "Lease
Commitments" included in Note 7 of the accompanying Notes to Consolidated
Financial Statements. The Company expects that, in general, its lease
obligations and miscellaneous accrued liabilities will be settled with
internally generated cash and that, as its long-term debt matures, it will
generally be replaced with newly-issued debt of a similar tenor, although
certain of such debt retirements may be funded through the issuance of equity,
or by short-term borrowings on an interim basis until permanent refinancing is
obtained.
LETTERS OF CREDIT
At December 31, 1996, the Company was obligated under letters of credit
incidental to its ordinary business operations totaling approximately $21.7
million.
INDEMNITY OBLIGATIONS
The Company has obligations under indemnification provisions of certain sale
agreements, see "Interstate Pipelines" under "Material Changes in the Results
of Continuing Operations" and "Discontinued Operations" elsewhere herein.
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been transferred pursuant to a sale of receivables facility, see "Sale of
Receivables" under "Net Cash Flows from Operating Activities" elsewhere herein.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has
prepaid for certain volumes of gas, which prepayments have been recorded at
their net realizable value and, to the extent that the Company is unable to
realize at least the carrying amount as the gas is delivered and sold, the
Company's earnings will be adversely affected, although such impact is not
expected to be material. In addition to these prepayments, the Company is a
party to a number of agreements which require it to either purchase or sell gas
in the future at prices which may differ from then-prevailing market prices or
which require it to deliver gas at a point other than the expected receipt
point for volumes to be purchased. The Company operates an ongoing risk
management program designed to limit the Company's exposure from its
obligations under these purchase/sale commitments, see the discussion under
"Credit Risk and Off-Balance-Sheet Risk" following. To the extent that the
Company expects that these commitments will result in losses over the contract
term, the Company has established reserves equal to such expected losses.
52
<PAGE> 56
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250 MMcf/day,
and pursuant to which ANR had advanced $125 million to the Company. The ANR
Agreement has been restructured as a lease of capacity and, after refunds of
$50 million and $34 million in 1995 and 1993, respectively, the Company
currently retains $41 million (recorded as a liability) in exchange for ANR's
use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in 2003
with a refund of $5 million to ANR and the ANR Agreement will terminate in 2005
with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company operates in various phases of the natural gas industry, making
sales to resellers such as pipeline companies and local distribution companies
as well as to end-users such as commercial businesses, industrial concerns and
residential consumers. While certain of these customers are affected by
periodic downturns in the economy in general or in their specific segment of
the natural gas industry, the Company believes that its level of credit-related
losses due to such economic fluctuations has been adequately reserved for and
will remain relatively stable in the long-term.
The Company has entered into a number of interest rate swaps which carry
off-balance-sheet risk, see "Net Cash Flows from Financing Activities"
elsewhere herein.
The Company's gas supply, marketing, gathering and transportation
activities subject the Company's earnings to variability based on fluctuations
in both the market price of natural gas and the value of transportation as
measured by changes in the delivered price of natural gas at various points in
the nation's natural gas grid. In order to mitigate the financial risk
associated with these activities both for itself and for certain customers who
have requested the Company's assistance in managing similar exposures, the
Company routinely enters into natural gas swaps, futures contracts and options,
collectively referred to in this discussion as "derivatives". The use of
derivatives for the purpose of reducing exposure to risk is generally referred
to as hedging and, through deferral accounting, results in matching the
financial impact of these derivative transactions with the cash impact
resulting from consummation of the transactions being hedged, see "Accounting
for Price Risk Management Activities" included in Note 1 of the accompanying
Notes to Consolidated Financial Statements.
The futures contracts are purchased and sold on the NYMEX and generally
are used to hedge a portion of the Company's storage gas, manage intra-month
and inter-month actual and anticipated short or long commodity positions and
provide risk management assistance to certain customers, to whom the cost of
the derivative activity is generally passed on as a component of the sales
price of the service being provided. Futures contracts are also utilized to fix
the price of compressor fuel or other future operational gas requirements,
although usage to date for this purpose has not been significant. The options
are entered into with various third parties and principally consist of options
which serve to limit the year-to-year escalation from January 1998 to April
1999 in the purchase price of gas which the Company is committed to deliver to
a distribution affiliate. These options covered 2.4 Bcf, 13.2 Bcf and 30.5 Bcf
at December 31, 1996, 1995 and 1994, respectively and, due to their nature and
term, have no readily determinable fair market value. The Company has
established a reserve equal to its projected maximum exposure to losses during
the term of this commitment and, accordingly, no impact on future earnings is
expected. The Company also utilizes options in conjunction with meeting
customers' needs for custom risk management services and for other limited
purposes. The Company had an immaterial amount of such options outstanding at
December 31, 1996. The impact of such options was to decrease 1996 earnings by
approximately $2.6 million and the effect on prior periods was not material.
The swaps, also entered into with various third parties, are principally
associated with the Company's marketing and transportation activities and
generally require that one party pay either a fixed price or fixed differential
from the NYMEX price per MMBtu of gas, while the other party pays a price based
on a published index. These swaps allow the Company to (1) commit to purchase
gas at one location and sell it at another location without assuming
unacceptable risk with respect to changes in the cost of the intervening
transportation, (2) effectively set the value to be received for transportation
of certain volumes of gas on the Company's facilities in the future and (3)
effectively fix the base price for gas to be delivered in conjunction with the
53
<PAGE> 57
commitment described preceding. None of these derivatives are held for
speculative purposes and the Company's risk management policy requires that
positions taken in derivatives be offset by positions in physical transactions
(actual or anticipated) or in other derivatives.
In the table which follows, the term "notional amount" refers to the
contract unit price times the contract volume for the relevant derivative
category and, in general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative of the Company's level of activity in such derivatives,
although the amounts at risk are significantly smaller because, in view of the
price movement correlation required for hedge accounting, changes in the market
value of these derivatives generally are offset by changes in the value
associated with the underlying physical transactions or in other derivatives.
When derivative positions are closed out in advance of the underlying
commitment or anticipated transaction, however, the market value changes may
not offset due to the fact that price movement correlation ceases to exist when
the positions are closed. Under such circumstances, gains or losses are
deferred and recognized when the underlying commitment or anticipated
transaction was scheduled to occur. Following is certain information concerning
the Company's derivative activities:
54
<PAGE> 58
<TABLE>
<CAPTION>
SWAPS(1)
- --------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Volume Volume Estimated Fair
As Fixed As Fixed Market Value
Price Payor Price Receiver Loss (2)
----------- -------------- --------
<S> <C> <C> <C>
December 31, 1993 101.2 82.2 $ (6.6)
Additions 137.1 170.9 --
Maturities (106.4) (139.0) --
- --------------------------------------------------------------------------
December 31, 1994 131.9 114.1 (16.7)
Additions 300.9 253.4 --
Maturities (221.7) (226.3) --
- --------------------------------------------------------------------------
December 31, 1995 211.1 141.2 (5.0)
Additions 309.2 281.8 --
Maturities (393.7) (370.1) --
- --------------------------------------------------------------------------
December 31, 1996 126.6 52.9 $ 9.7
===========================================================================
</TABLE>
<TABLE>
<CAPTION>
FUTURES CONTRACTS (3)
- -----------------------------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Purchased Sold
-------------------------- -------------------- Estimated Fair
Notional Notional Market Value
Volume Amount Volume Amount Gain(Loss) (2)
---------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1993 N/M (4) $ N/M N/M $ N/M $ N/M
- -----------------------------------------------------------------------------------------------
December 31, 1994 6.7 13.8 1.7 2.8 (2.9)
Additions 119.2 198.6 117.3 198.9 --
Maturities (110.8) (182.8) (110.8) (182.8) --
- -----------------------------------------------------------------------------------------------
December 31, 1995 15.1 29.6 8.2 18.9 3.3
Additions 359.8 989.7 356.6 976.3 --
Maturities (351.2) (955.2) (351.2) (955.2) --
- -----------------------------------------------------------------------------------------------
December 31, 1996 23.7 $ 64.1 13.6 $ 40.0 $ 0.1
- -----------------------------------------------------------------------------------------------
</TABLE>
(1) The financial impact of these swaps was to increase(decrease) earnings by
$(1.0) million, $1.0 million and $2.8 million during 1996, 1995 and 1994,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The
amount which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the
case of certain commitments described preceding, no earnings impact is
expected due to existing accruals. Swaps associated with these commitments
had fair market values of $2.8 million, $(1.0) million and $(17.6) million
at December 31, 1996, 1995 and 1994, respectively.
(3) There was no material financial impact from these futures contracts in
1994 and the effect during 1996 and 1995 was to decrease earnings by $9.3
million and $4.1 million, respectively, as futures transactions were
matched with the hedged transactions. At December 31, 1996, the Company
had deferred losses of approximately $11.9 million associated with
anticipated sales under "peaking" contracts with certain customers which,
in effect, give the customer a "call" on certain volumes of gas. All such
losses were recognized in January 1997 when the anticipated transactions
were scheduled to occur.
(4) Indicates that the item is not material.
While, as yet, the Company has experienced no significant losses due to
the credit risk associated with these arrangements, the Company has off-
balance-sheet risk to the extent that the counterparties to these transactions
may fail to perform as required by the terms of each such contract. In order to
minimize this risk, the Company enters into such transactions solely with firms
of acceptable financial strength, in the majority of 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
55
<PAGE> 59
achieving the Company's objectives. Should the counterparties to these
arrangements fail to perform, the Company would seek to compel performance at
law or otherwise, or to obtain compensatory damages in lieu thereof, but the
Company might be forced to acquire alternative hedging arrangements or be
required to honor the underlying commitment at then-current market prices. In
such event, the Company might incur additional loss to the extent of amounts,
if any, already paid to the counterparties. In view of its criteria for
selecting counterparties, its process for monitoring the financial strength of
these counterparties and its experience to date in successfully completing
these transactions, the Company believes that the risk of incurring a
significant loss due to the nonperformance of counterparties to these
transactions is minimal.
LITIGATION
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the merger between the Company and Houston
Industries (see "Merger With Houston Industries) elsewhere herein or to rescind
such merger and/or to recover damages in the event that the Transaction is
consummated. The complaint alleges, among other things, that the merger
consideration is inadequate, that the Company's Board of Directors breached its
fiduciary duties and that Houston Industries aided and abetted such breaches of
fiduciary duties. In addition, the plaintiff seeks certification as a class
action. The Company believes that the claims are without merit and intends to
vigorously defend against the lawsuit. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of this matter will not be material.
The Company is a party to litigation (other than that specifically
noted) which arises in the normal course of business. Management regularly
analyzes current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
adjacent to the Mississippi River in Minnesota known as the former Minneapolis
Gas Works ("FMGW") until 1960. The Company is working with the Minnesota
Pollution Control Agency to implement an appropriate remediation plan. There
are six other former MGP sites in the Company's Minnesota service territory. Of
the six sites, the Company believes that two were neither owned nor operated by
the Company; two were owned at one time but were operated by others and are
currently owned by others; and one was operated by the Company and is now owned
by others. The Company believes it has no liability with respect to the sites
it neither owned nor operated.
At December 31, 1996, the Company has estimated a range of $10 million
to $170 million for possible remediation of the Minnesota sites. The low end of
the range was determined using only those sites presently owned or known to
have been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned
by the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to
recover amortization of previously deferred and ongoing clean-up costs. Any
amounts in excess of $2.1 million annually were deferred for future recovery.
In its 1995 rate case, Minnegasco asked that the annual allowed recovery be
increased to approximately $7 million and that such costs be subject to a true-
up mechanism whereby any over or under recovered amounts, net of certain
insurance recoveries as described following, plus carrying charges, would be
deferred for recovery or refund in the next rate case. Such accounting was
approved by the Minnesota Public Utilities Commission ("MPUC") and was
implemented effective October 1, 1995. The amount of insurance recoveries to be
flowed back to ratepayers is determined by multiplying insurance recoveries
received by the ratio of total costs incurred to-date as a percentage of the
probable total costs of environmental remediation. At December 31, 1996 and
1995, the Company had under-
56
<PAGE> 60
collected, through rates, net environmental clean-up costs of $1.4 million and
$1.3 million, respectively. In addition, at December 31, 1996 and 1995, the
Company had received insurance proceeds that will be refunded through rates in
the future as clean-up expenditures are made of $4.3 million and $3.3 million,
respectively. At December 31, 1996 and 1995, the Company had recorded a
liability of $35.9 million and $45.2 million, respectively, to cover the cost
of future remediation. In addition, the Company has receivables from insurance
settlements of $5.2 million at December 31, 1996. These insurance settlements
will be collected through 1999. The Company expects that the majority of its
accrual as of December 31, 1996 will be expended within the next five years. In
accordance with the provisions of SFAS 71, a regulatory asset has been recorded
equal to the liability accrued. The Company is continuing to pursue recovery of
at least a portion of these costs from insurers. The Company believes the
difference between any cash expenditures for these costs and the amounts
recovered in rates during any year will not be material to the Company's
overall cash requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites
in the service territories of the distribution divisions. At the present time,
the Company is aware of some plant sites in addition to the Minnesota sites and
is investigating certain other locations. While the Company's evaluation of
these other MGP sites remains 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 its financial position, results of
operations or cash flows.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company that the Company, through one of its subsidiaries and
together with several other unaffiliated entities, had been named under state
law as a potentially responsible party with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any, of the site. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on its financial position, results of operations or
cash flows.
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
remains in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
At December 31, 1996 and 1995, the Company had recorded an accrual of
$3.3 million (with a maximum estimated exposure of approximately $18 million)
and an offsetting regulatory asset for environmental matters in connection with
a former fire training facility and a landfill for which future remediation may
be required. This accrual is in addition to the accrual for MGP sites as
discussed preceding.
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.
EARNINGS PER SHARE
In February 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"),
which is required to be implemented for fiscal years ending after December 15,
1997 and earlier application is not permitted. SFAS 128 replaces the current
"primary earnings per share" ("primary EPS") and "fully diluted earnings per
share" ("fully
57
<PAGE> 61
diluted EPS") with "basic earnings per share" ("basic EPS") and "diluted
earnings per share" ("diluted EPS"). Unlike the calculation of primary EPS
which includes, in its denominator, the sum of (1) actual weighted shares
outstanding and (2) "common stock equivalents" as that term is defined in the
authoritative accounting literature, basic EPS is calculated using only the
actual weighted average shares outstanding during the relevant periods. Diluted
EPS is very similar to fully diluted EPS, differing only in technical ways
which do not currently affect the Company.
RATIO OF EARNINGS TO FIXED CHARGES
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------
Year Ended December 31,
1996 1995 1994 1993 1992
- -------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
2.12 1.69 1.47 1.47 1.10
- -------------------------------------------------------------------------
</TABLE>
DEBT RETIREMENT SCHEDULE
The debt retirement schedule at December 31, 1996 is as follows (see also
"Long-Term Debt" included in Note 3 of the accompanying Notes to Consolidated
Financial Statements):
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
(millions of dollars)
1997 1998 1999 2000 2001 Beyond 2001
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$277.0 $81.8 $207.1 $228.0 $150.6 $386.7
- -------------------------------------------------------------------------------------------
</TABLE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
58
<PAGE> 62
NORAM ENERGY CORP. AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
(thousands of dollars, except per share amounts)
Year Ended December 31,
1996 1995 1994
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas sales $ 4,513,697 $ 2,725,927 $ 2,593,665
Natural gas transportation, including storage 181,367 159,142 184,219
Appliance sales and service 52,192 45,581 43,598
Other 41,206 34,029 36,420
- -----------------------------------------------------------------------------------------------------
4,788,462 2,964,679 2,857,902
- -----------------------------------------------------------------------------------------------------
OPERATING EXPENSES
Cost of natural gas purchased, net 3,667,954 1,857,166 1,779,481
Operation, maintenance, cost of sales and other 524,736 564,790 553,289
Depreciation and amortization 142,362 147,109 153,035
Taxes other than income taxes 116,600 108,309 107,173
Early retirement and severance (Note 1) 22,344 -- --
- -----------------------------------------------------------------------------------------------------
4,473,996 2,677,374 2,592,978
- -----------------------------------------------------------------------------------------------------
OPERATING INCOME 314,466 287,305 264,924
- -----------------------------------------------------------------------------------------------------
OTHER (INCOME) AND DEDUCTIONS
Interest expense, net 132,557 157,959 169,365
Loss on sale of accounts receivable (Note 3) 11,499 9,771 7,139
Dividend requirement on preferred securities of
subsidiary trust (Note 3) 5,842 -- --
Other, net 3,078 (1,333) 2,757
- -----------------------------------------------------------------------------------------------------
152,976 166,397 179,261
- -----------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 161,490 120,908 85,663
PROVISION FOR INCOME TAXES 66,352 55,379 34,372
- -----------------------------------------------------------------------------------------------------
INCOME FROM CONTINUING OPERATIONS 95,138 65,529 51,291
Loss from discontinued operations, less taxes -- -- (2,102)
- -----------------------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM 95,138 65,529 49,189
Extraordinary item, less taxes (Note 3) (4,280) (52) (1,123)
- -----------------------------------------------------------------------------------------------------
NET INCOME 90,858 65,477 48,066
Preferred dividend requirement (Note 3) 3,597 7,800 7,800
- -----------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE TO COMMON STOCK $ 87,261 $ 57,677 $ 40,266
- -----------------------------------------------------------------------------------------------------
EARNINGS (LOSS) PER COMMON SHARE
PRIMARY:
Continuing operations (1) $ 0.70 $ 0.47 $ 0.36
Discontinued operations, less taxes -- -- (0.02)
Extraordinary item, less taxes (0.03) 0.00 (0.01)
- -----------------------------------------------------------------------------------------------------
PRIMARY EARNINGS PER COMMON SHARE $ 0.67 $ 0.47 $ 0.33
- -----------------------------------------------------------------------------------------------------
Fully Diluted:
Continuing operations (1) $ 0.68 $ 0.47 $ 0.36
Discontinued operations, less taxes -- -- (0.02)
Extraordinary item, less taxes (0.03) 0.00 (0.01)
- -----------------------------------------------------------------------------------------------------
FULLY DILUTED EARNINGS PER COMMON SHARE $ 0.65 $ 0.47 $ 0.33
- -----------------------------------------------------------------------------------------------------
Weighted average common shares outstanding (in thousands)
Primary 131,648 123,868 122,424
Fully Diluted 139,345 123,868 122,424
- -----------------------------------------------------------------------------------------------------
</TABLE>
(1) Earnings per common share from continuing operations is computed after
reduction for the preferred dividend requirement.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
59
<PAGE> 63
NORAM ENERGY CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
(thousands of dollars) December 31,
1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT
Natural Gas Distribution $2,158,013 $2,059,376
Interstate Pipelines 1,685,959 1,666,017
Natural Gas Gathering 232,815 208,989
Other 39,844 35,157
- ----------------------------------------------------------------------------------
4,116,631 3,969,539
Less: Accumulated depreciation and amortization 1,675,576 1,561,764
- ----------------------------------------------------------------------------------
2,441,055 2,407,775
INVESTMENTS AND OTHER ASSETS
Goodwill, net 466,938 481,125
Prepaid pension asset 45,390 57,965
Investment in Itron, Inc. 26,670 50,711
Regulatory asset for environmental costs 39,152 48,500
Gas purchased in advance of delivery 34,895 24,284
Other 32,200 21,324
- ----------------------------------------------------------------------------------
645,245 683,909
CURRENT ASSETS
Cash and cash equivalents 27,981 13,311
Accounts and notes receivable, principally customer 696,982 335,779
Deferred income taxes 10,495 13,601
Inventories
Gas in underground storage 70,651 53,183
Materials and supplies 30,595 33,354
Other 631 445
Deferred gas costs 231 13,019
Gas purchased in advance of delivery 6,200 23,440
Other current assets 14,561 25,496
- ----------------------------------------------------------------------------------
858,327 511,628
- ----------------------------------------------------------------------------------
DEFERRED CHARGES 72,850 62,671
- ----------------------------------------------------------------------------------
TOTAL ASSETS $4,017,477 $3,665,983
==================================================================================
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
60
<PAGE> 64
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
STOCKHOLDERS' EQUITY
Preferred stock (Note 3) $ -- $ 130,000
Common stock 86,193 78,002
Paid-in capital 1,001,053 880,885
Accumulated deficit (286,703) (336,940)
Unrealized gain on Itron investment, net of tax 5 15,316
- ----------------------------------------------------------------------------------------
800,548 767,263
- ----------------------------------------------------------------------------------------
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
CONVERTIBLE PREFERRED SECURITIES OF SUBSIDIARY
TRUST HOLDING SOLELY $177.8 MILLION PRINCIPAL
AMOUNT OF 6.25% CONVERTIBLE JUNIOR SUBORDINATED
DEBENTURES DUE 2026 OF NORAM ENERGY CORP.(Note 3) 167,768 --
LONG-TERM DEBT, LESS CURRENT MATURITIES 1,054,221 1,474,924
CURRENT LIABILITIES
Current maturities of long-term debt 277,000 118,750
Notes payable to banks 115,000 10,000
Accounts payable, principally trade 762,164 472,374
Income taxes payable 11,684 5,337
Interest payable 31,928 38,730
General taxes 51,082 48,320
Customers' deposits 35,711 35,651
Other current liabilities 113,628 96,645
- ----------------------------------------------------------------------------------------
1,398,197 825,807
- ----------------------------------------------------------------------------------------
OTHER LIABILITIES AND DEFERRED CREDITS
Accumulated deferred income taxes 320,506 303,445
Estimated environmental remediation costs 39,152 48,500
Payable under capacity lease agreement 41,000 41,000
Supplemental retirement and deferred compensation 39,640 40,869
Estimated obligations under indemnification provisions
of sale agreements 29,098 34,207
Refundable excess deferred income taxes 17,946 26,599
Other 109,401 103,369
- ----------------------------------------------------------------------------------------
596,743 597,989
- ----------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Note 7)
- ----------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 4,017,477 $ 3,665,983
========================================================================================
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
61
<PAGE> 65
NORAM ENERGY CORP. AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) Year Ended December 31,
1996 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
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 liquidation preference), cumulative,
non-voting; authorized 10,000,000 shares
Balance at beginning of year 2,600,000 $ 130,000 2,600,000 $ 130,000 2,600,000 $ 130,000
Conversion to subordinated
debentures (Note 3) (2,600,000) (130,000) -- -- -- --
- -----------------------------------------------------------------------------------------------------------------------------
Balance at end of year -- -- 2,600,000 130,000 2,600,000 130,000
- -----------------------------------------------------------------------------------------------------------------------------
Common, $.625 par, authorized
250,000,000 shares
Balance at beginning of year 124,803,693 78,002 122,530,248 76,581 122,361,578 76,476
Public issuance (Note 3) 11,500,000 7,188 -- -- -- --
Issuance under Direct Stock
Purchase Plan, net 937,193 586 1,610,148 1,006 48,968 30
Other issuance 667,287 417 663,297 415 119,702 75
- -----------------------------------------------------------------------------------------------------------------------------
Balance at end of year 137,908,173 86,193 124,803,693 78,002 122,530,248 76,581
- -----------------------------------------------------------------------------------------------------------------------------
Paid-In Capital
Balance at beginning of year 880,885 868,289 867,641
Public issuance (Note 3) 101,775 - --
Issuance under Direct Stock
Purchase Plan 9,668 8,795 (153)
Other issuance 8,725 3,801 801
- -----------------------------------------------------------------------------------------------------------------------------
Balance at end of year 1,001,053 880,885 868,289
- -----------------------------------------------------------------------------------------------------------------------------
Retained Deficit
Balance at beginning of year (336,940) (360,079) (366,080)
Net income 90,858 65,477 48,066
Cash dividends
Preferred stock - $3.00 per share
in 1994 and 1995; $1.50 per share
in 1996 (Note 3) (3,900) (7,800) (7,800)
Common stock - $0.28 per share (36,721) (34,538) (34,265)
- -----------------------------------------------------------------------------------------------------------------------------
Balance at end of year (286,703) (336,940) (360,079)
- -----------------------------------------------------------------------------------------------------------------------------
Unrealized gain on Itron investment, net 5 15,316 2,586
- -----------------------------------------------------------------------------------------------------------------------------
Total Stockholders' Equity $ 800,548 $ 767,263 $ 717,377
- -----------------------------------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
62
<PAGE> 66
NORAM ENERGY CORP. AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
- -------------------------------------------------------------------------------------------------------
(thousands of dollars)
Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 90,858 $ 65,477 $ 48,066
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization 142,362 147,109 153,035
Deferred income taxes 28,809 34,883 32,855
Early retirement and severance, less cash costs 12,941 -- --
Discontinued operations -- -- 2,102
Extraordinary item, less taxes (Note 3) 4,280 52 1,123
Utilization of tax loss carryforwards (2,405) (19,797) (6)
Other 3,582 3,483 (3,065)
Changes in certain assets and liabilities,
net of non-cash transactions (Note 1) (52,274) 107,702 68,167
- -------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 228,153 338,909 302,277
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (172,200) (173,600) (170,371)
Sale of distribution properties -- -- 23,172
Cash surrender value of life insurance -- 12,276 --
Other asset sales -- -- 12,315
Sales of Itron stock -- 1,441 7,204
Other, net (4,957) (5,844) 5,898
- -------------------------------------------------------------------------------------------------------
Net cash used in investing activities (177,157) (165,727) (121,782)
- -------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of 7 1/2% notes due 2000 -- 200,000 --
Public issuance of common stock (Note 3) 108,963 -- --
Public issuance of convertible preferred
securities by subsidiary trust (Note 3) 167,756 -- --
Bank term loan, due 2000 -- 150,000 --
Common and preferred stock dividends (40,621) (42,338) (42,065)
Retirements and reacquisitions of long-term debt (Note 3) (396,733) (335,352) (148,913)
Other interim borrowings (repayments) 105,000 (100,000) 15,000
Return of advance received under contingent sales agreement -- (50,000) --
Issuance of common stock under direct stock purchase plan, net 10,254 9,801 (123)
Increase (decrease) in overdrafts 9,055 (9,614) (1,672)
- -------------------------------------------------------------------------------------------------------
Net cash used in financing activities (36,326) (177,503) (177,773)
- -------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash 14,670 (4,321) 2,722
- -------------------------------------------------------------------------------------------------------
Cash and cash equivalents - beginning of year 13,311 17,632 14,910
- -------------------------------------------------------------------------------------------------------
Cash and cash equivalents - end of year $ 27,981 $ 13,311 $ 17,632
- -------------------------------------------------------------------------------------------------------
</TABLE>
For supplemental cash flow information, see Note 1.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
63
<PAGE> 67
1. ACCOUNTING POLICIES AND COMPONENTS OF
CERTAIN FINANCIAL STATEMENT LINE ITEMS
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of
NorAm Energy Corp. and its subsidiaries, all of which are wholly owned, and all
significant affiliated transactions and balances have been eliminated. As used
herein, "NorAm" and "the Company" refer to NorAm Energy Corp. and its
consolidated subsidiaries. Certain prior period amounts have been reclassified
to conform to current presentation.
MERGER WITH HOUSTON INDUSTRIES
On August 11, 1996, the Company entered into an Agreement and Plan of Merger
(the "Merger Agreement") with Houston Industries Incorporated ("Houston
Industries" or "HI"), Houston Lighting & Power Company ("HL&P") and a newly
formed Delaware subsidiary of Houston Industries ("HI Merger, Inc."). Under the
Merger Agreement, the Company would merge with and into HI Merger, Inc. and
would become a wholly owned subsidiary of HII (as defined following). Houston
Industries would merge with and into HL&P, which would be renamed Houston
Industries Incorporated ("HII") (the term "Transaction" refers to the business
combination between Houston Industries and the Company). Consideration for the
purchase of the Company's common stock would be a combination of cash and
shares of HI common stock, valued at approximately $3.8 billion, consisting of
approximately $2.4 billion for the Company's common stock and equivalents and
approximately $1.4 billion in assumption of the Company's debt. Additional
information concerning the Merger Agreement is contained in the Joint Proxy
Statement/Prospectus of Houston Industries, HL&P and the Company dated October
29, 1996 ("the Proxy/Prospectus").
The Merger Agreement was approved and adopted at Special Meetings of
Houston Industries' and the Company's stockholders held on December 17, 1996.
The Company and HI proceeded to obtain required state and municipal regulatory
approvals, all of which have been obtained, and to request an exemption from
the Securities and Exchange Commission ("the SEC") which would allow the
Transaction to take place under its preferred structure without subjecting
post-merger HII to the requirements of the Public Utility Holding Company Act.
It is HI's and the Company's intention to defer the closing of the Transaction
until the SEC issues its ruling on the exemption request although, as set forth
in the Proxy/Prospectus, there are two alternative structures, one of which
would not require SEC approval. Adoption of either of these structures,
however, would require that the Company and HI make new filings to obtain the
various state and municipal regulatory approvals.
In early February 1997, the Federal Energy Regulatory Commission ("the
FERC" or "the Commission") issued an order ("the Order") advising the Company
that the Transaction "...may require Commission approval pursuant to section
203 of the FPA" ( the "FPA" refers to the Federal Power Act), and directing the
Company to file a response within 30 days of the Order either "...(1) providing
arguments as to why the transaction does not require Commission authorization
under section 203 or (2) an application under section 203". In early March
1997, the Company filed a response to the Order stating its view that the FERC
does not have jurisdiction over the Transaction. Although such response
disclaimed any FERC jurisdiction over the Transaction, it also indicated that
one option being considered was to file an application with the FERC for
approval of the Transaction in anticipation of an expedited review under the
FERC's newly-issued merger policy guidelines. On March 27, 1997, the Company
filed an application under section 203 of the FPA seeking FERC approval of the
Transaction, although continuing to assert its position that such approval is
not required.
The Company continues to believe that the Transaction will be completed
as contemplated although, in light of the pending regulatory issues as set
forth preceding, the Company cannot predict with any degree of certainty when
the Transaction will be consummated.
64
<PAGE> 68
NATURE OF OPERATIONS
The Company's principal activities are in the natural gas industry
(representing in excess of 90% of the Company's total revenues, income or loss
and identifiable assets), primarily in the contiguous 48 states,
with principal operations in Texas, Louisiana, Mississippi, Arkansas, Oklahoma,
Missouri and Minnesota. The Company has operations in various phases of the
natural gas industry, including distribution, transmission, marketing and
gathering which, during 1996, provided approximately 50.5%, 34.2%, 11.5% and
3.8%, respectively, of the Company's consolidated operating income (exclusive
of the net operating loss attributable to Corporate and certain miscellaneous
activities). The Company's distribution operations are conducted by its Entex,
Minnegasco and Arkla divisions, its interstate pipeline operations are
conducted by NorAm Gas Transmission Company ("NGT") and Mississippi River
Transmission Corporation ("MRT"), its marketing activities are conducted by
NorAm Energy Services, Inc. ("NES") and NorAm Energy Management, Inc. ("NEM"),
and its gathering activities are conducted by NorAm Field Services Corp.
("NFS"), in each case also including certain subsidiaries and affiliates. The
Company's miscellaneous activities, whose collective results of operations
currently are not material, principally consist of home care services,
including (1) appliance sales and service, (2) home security services, (3)
utility services, principally line locating and (4) resale of long distance
telephone service. The Company expects to make an investment in international
activities as discussed following.
During 1996, the Company had revenues of $55 million, approximately 1%
of consolidated operating revenues, from sales to and transportation for
Laclede Gas Company (the local natural gas distribution company which serves
the greater St. Louis, Illinois area) pursuant to several long-term firm
transportation and storage agreements which expire in 1999. The Company's
interstate pipelines received revenues of approximately $163.8 million in 1996
from services provided to the Company's Arkla distribution division pursuant to
several agreements, representing approximately 3.4% of consolidated operating
revenues and approximately 47.2% of NGT's and MRT's combined operating
revenues. With respect to services provided to Arkla in (1) Arkansas, the
current service agreement is scheduled to expire in April 2002 and (2)
Louisiana, Oklahoma and East Texas, the process of negotiation and regulatory
approval has not yet been completed, but the Company currently expects to
obtain revised agreements with a term similar to that currently in effect for
Arkansas.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160 million, with construction expected to begin no
later than the fourth quarter of 1997. The Company's ownership interest in the
Consortiums, while subject to change through continuing negotiations with its
existing and potential partners ranges from 15% to approximately 33% and, based
on the expected number of customers, represents a weighted average ownership
interest of approximately 23%.
In January 1997, the Company participated in a bid for a permit
authorizing the construction, ownership and operation of a natural gas
distribution system for the geographic area that includes the cities of
Chihuahua, Delicias and Cuauchtemoc/Anahuac in North Central Mexico. In March
1997, the Company learned that its group was not the successful bidder. The
Company had previously announced its intention to participate in a similar
bidding process for a permit to provide natural gas distribution service to all
or a portion of Mexico City, although no date has yet been set for submission
of bids.
65
<PAGE> 69
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 periods.
Actual results could differ from those estimates.
RATE REGULATION
Methods of allocating costs to accounting periods in the portion of the
Company's business subject to federal, state or local rate regulation may
differ from methods generally applied by unregulated companies. However, when
accounting allocations prescribed by regulatory authorities are used for rate-
making, the resultant accounting follows the concept of matching costs with
related revenues. The Company's rate-regulated divisions/subsidiaries bill
customers on a monthly cycle billing basis. Revenues are recorded on an accrual
basis, including an estimate for gas delivered but unbilled at the end of each
accounting period.
All of the Company's rate-regulated businesses historically have
followed the accounting guidance contained in Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
("SFAS 71"). The Company discontinued application of SFAS 71 to NGT effective
with year-end 1992 reporting. As a result of the continued application of SFAS
71 to MRT and the Company's distribution divisions, the accompanying
consolidated financial statements contain certain assets and liabilities which
would not be recognized by unregulated entities. In addition to regulatory
assets related to postretirement benefits other than pensions (see Note 5), the
Company's only other significant regulatory asset is related to anticipated
environmental remediation costs, see "Accounting for Remediation Costs"
following and "Environmental Matters" included in Note 7.
CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas gathering and pipeline assets. This change had the effect of
increasing 1995 "Income before extraordinary item" and "Net income" by
approximately $3.2 million ($0.03 per share).
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
To reduce the risk from market fluctuations in the price of natural gas and
related transportation, the Company enters into futures transactions, swaps and
options (collectively, "financial instruments") in order to hedge certain
natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas, a portion of which are firm commitments at the
inception of the hedge. Some of these financial instruments carry off-balance-
sheet risk, see "Credit Risk and Off-Balance-Sheet Risk" included in Note 7.
Changes in the market value of these financial instruments utilized as hedges
are (1) recognized as an adjustment of the carrying value in the case of
existing assets and liabilities, (2) included in the measurement of the
transaction that satisfies the commitment in the case of firm commitments and
(3) included in the measurement of the subsequent transaction in the case of
anticipated transactions, whether or not the hedge is closed out before the
date of the anticipated transaction. In cases where anticipated transactions do
not occur, deferred gains and losses are recognized when such transactions were
scheduled to occur.
66
<PAGE> 70
ACCOUNTING FOR REMEDIATION COSTS
Environmental remediation costs are accrued when the Company determines that it
is probable that it will incur such costs and the amount is reasonably
estimable. To the extent that potential environmental remediation 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. In determining the amount of the liability,
future costs are not discounted to their present value and the liability is not
offset by expected insurance recoveries. If justified by circumstances within
the Company's business subject to SFAS 71, corresponding regulatory assets are
recorded in anticipation of recovery through the ratemaking process, see
"Environmental Matters" included in Note 7.
EARLY RETIREMENT AND SEVERANCE
During the first quarter of 1996, the Company instituted a reorganization plan
affecting its NGT and MRT subsidiaries, pursuant to which a total of
approximately 275 positions were eliminated, resulting in expense for severance
payments and enhanced retirement benefits. Also during the first quarter of
1996, (1) the Company's Entex division instituted an early retirement program
which was accepted by approximately 100 employees and (2) the Company's
Minnegasco division reorganized certain functions, resulting in the elimination
of approximately 25 positions. Collectively, these programs resulted in a non-
recurring pre-tax charge of approximately $22.3 million (approximately $13.4
million or $0.10 per share after tax), which pre-tax amount is reported in the
accompanying Statement of Consolidated Income as "Early retirement and
severance".
INTEREST EXPENSE
Interest expense includes, where applicable, amortization of debt issuance cost
and amortization of gains and losses on interest rate hedging transactions
related to the Company's debt financing activities, see Note 3. "Interest
expense, net" as presented in the accompanying Statement of Consolidated Income
is net of an allowance for borrowed funds used during construction of $1.6
million, $1.1 million and $1.3 million in 1996, 1995 and 1994, respectively.
Beginning in 1997, amounts previously reported as "Loss on sale of receivables"
will be reported as a component of interest expense, see "Sale of Receivables"
included in Note 3.
DISCONTINUED OPERATIONS
"Loss from discontinued operations, less taxes" as presented in the
accompanying Statement of Consolidated Income for 1994 represents a pre-tax
loss of $3.3 million (the associated tax benefit was $1.2 million) resulting
from litigation associated with the discontinued operations of University
Savings Association, a former subsidiary of Entex.
EARNINGS PER SHARE
Primary earnings per share is computed using the weighted average number of
shares of the Company's Common Stock ("Common Stock") actually outstanding
during each period presented. Outstanding options for purchase of Common Stock,
the Company's only "common stock equivalent" as that term is defined in the
authoritative accounting literature, have been excluded due to either (1) the
fact that the options would have been anti-dilutive if exercised or (2) the
immaterial impact which would result from the exercise of those options which
are currently exercisable and would be dilutive if exercised. Fully diluted
earnings per share, in addition to the actual weighted average common shares
outstanding, assumes the conversion, as of its issuance date of June 17, 1996,
of the 3,450,000 shares of the Trust Preferred (see Note 3) at a conversion
rate of 4.1237 shares of Common Stock for each share of the Trust Preferred
(resulting in the assumed issuance of a total of 14,226,765 shares of Common
Stock), and reflects the increase in earnings from the cessation of the
dividends on the Trust Preferred (net of the related tax benefit) which would
result from such assumed conversion. For 1996, this assumed earnings increase
was approximately $3.5 million, net of related tax benefits of approximately
$2.3 million. The Company's 6% Convertible Subordinated Debentures due 2012
(see "Other Long-Term Financing" included in Note 3) and the Company's $3.00
Series A Preferred Stock (prior to its June 1996 exchange, see "Other Long-Term
Financing" included in Note 3), due to their exchange rates, are anti-dilutive
and are therefore excluded from all earnings per share calculations. During the
periods in which the
67
<PAGE> 71
Company's $3.00 Convertible Exchangeable Preferred Stock, Series A was
outstanding, earnings per share from continuing operations is calculated after
reduction for the preferred stock dividend requirement associated with such
security.
In February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share"
("SFAS 128"), which is required to be implemented for fiscal years ending after
December 15, 1997 and earlier application is not permitted. SFAS 128 replaces
the current "primary earnings per share" ("primary EPS") and "fully diluted
earnings per share" ("fully diluted EPS") with "basic earnings per share"
("basic EPS") and "diluted earnings per share" ("diluted EPS"). Unlike the
calculation of primary EPS which includes, in its denominator, the sum of (1)
actual weighted shares outstanding and (2) "common stock equivalents" as that
term is defined in the authoritative literature, basic EPS is calculated using
only the actual weighted average shares outstanding during the relevant
periods. Diluted EPS is very similar to fully diluted EPS, differing only in
technical ways which do not currently affect the Company.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, in general, is carried at cost and depreciated
or amortized on a straight-line basis over its estimated useful life. Additions
to and betterments of utility property are charged to property accounts at
cost, while the costs of maintenance, repairs and minor replacements are
charged to expense as incurred. Upon normal retirement of units of utility
property, plant and equipment, the cost of such property, together with cost of
removal less salvage, is charged to accumulated depreciation. Costs of
individually significant internally developed and purchased computer software
systems are capitalized and amortized over their expected useful life.
INVESTMENTS AND OTHER ASSETS
Goodwill, none of which is being recovered in regulated service rates, is
amortized on a straight-line basis over 40 years. Approximately $14.2 million
of goodwill was amortized each year during 1996, 1995 and 1994. Accumulated
amortization of goodwill was $103.4 million and $89.2 million at December 31,
1996 and 1995, 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.
Itron, Inc. ("Itron") is a publicly-traded Spokane, Washington company
which manufactures and markets automated meter-reading devices and provides
related services. The Company accounts for its investment in Itron utilizing
the cost method (its ownership of approximately 1.5 million Itron common shares
at December 31, 1996 represented an ownership interest of approximately 11.2%),
revalues its investment to market value as of each balance sheet date and
reports any unrealized gain or loss, net of tax, as a separate component of
stockholders' equity, which unrealized gain was immaterial at December 31,
1996. During 1996, the market value of the Company's Itron investment (based on
closing share prices on the NASDAQ) varied from a high of approximately $88.3
million to a low of approximately $22.5 million. At March 14, 1997, the market
value of the Company's investment in Itron was approximately $29.3 million and
the unrealized gain was approximately $1.7 million (net of tax benefit of $1.0
million).
ALLOWANCE FOR DOUBTFUL ACCOUNTS
"Accounts and notes receivable, principally customer" as presented in the
accompanying Consolidated Balance Sheet are net of an allowance for doubtful
accounts of $13.0 million and $11.1 million at December 31, 1996 and 1995,
respectively.
INVENTORIES
Inventories principally follow the average cost method and all non-utility
inventories held for resale are valued at the lower of cost or market.
ACCOUNTS PAYABLE
Certain of the Company's cash balances reflect credit balances to the extent
that checks written have not yet been presented for payment. Such balances
included in "Accounts payable, principally trade" in the
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<PAGE> 72
accompanying Consolidated Balance Sheet were approximately $53.5 million and
$44.4 million at December 31, 1996 and 1995, respectively.
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 September 1994, the Company sold all of its Kansas distribution
properties, serving approximately 23,000 customers in 14 communities, together
with certain related pipeline assets, for approximately $23 million in cash,
approximately its carrying value, shown in the accompanying Statement of
Consolidated Cash Flows as "Sale of distribution properties".
In June 1996, the Company exercised its right to exchange its $3.00
Convertible Exchangeable Preferred Stock, Series A for its 6% Convertible
Subordinated Debentures due 2012 in a non-cash transaction. The Company issues
its common stock in conjunction with certain compensation plans. For additional
information on these matters, see Note 6 and "Other Long-Term Financing"
included in Note 3. Following is certain supplemental cash flow information:
<TABLE>
<CAPTION>
SUPPLEMENTAL CASH FLOW INFORMATION
- -------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash interest payments, net
of capitalized interest $ 140,751 $ 154,866 $ 162,743
- -------------------------------------------------------------------------------------
Cash income tax
payments, net $ 29,657 $ 19,970 $ 6,477
- -------------------------------------------------------------------------------------
</TABLE>
The caption "Changes in certain asset and liabilities, net of noncash
transactions" as shown in the accompanying Statement of Consolidated Cash Flows
includes the following:
<TABLE>
<CAPTION>
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
- -------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------------------
<S> <C> <C> <C>
Accounts and notes receivable,
principally customer (1) $ (353,703) $ (119,933) $ 98,641
Inventories (14,895) 25,112 42,626
Deferred gas costs 12,788 (19,831) (78)
Other current assets 10,935 10,661 (7,637)
Accounts payable, principally trade 266,446 162,595 (54,871)
Income taxes payable 8,752 20,444 (8,216)
Interest payable (6,802) (3,450) (2,497)
General taxes 2,762 2,603 (4,394)
Customers' deposits 60 150 734
Other current liabilities 10,483 5,151 (17,441)
Settlement of gas
contract disputes 10,900 24,200 21,300
- -------------------------------------------------------------------------------------
$ (52,274) $ 107,702 $ 68,167
=====================================================================================
</TABLE>
(1) Beginning with January 1, 1997, cash flows associated with the Company's
sale of receivables facility will be included with "Cash Flows from
Financing Activities", see "Sale of Receivables" included in Note 3.
69
<PAGE> 73
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. If the pending merger with Houston Industries is
consummated, the Company will be consolidated into Houston Industries'
consolidated U.S. Federal income tax return beginning as of the merger date,
see "Merger With Houston Industries" included in Note 1. Following are the
components of the Company's income tax provision:
<TABLE>
<CAPTION>
PROVISION FOR INCOME TAXES
- --------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
Expense (Benefit) 1996 1995 1994
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal
Current $ 33,654 $ 18,760 $ 41
Deferred 25,760 24,377 38,965
Investment Tax Credit (636) (639) (641)
State
Current 4,525 2,375 2,117
Deferred 3,049 10,506 (6,110)
- --------------------------------------------------------------------------------
$ 66,352 $ 55,379 $ 34,372
- --------------------------------------------------------------------------------
</TABLE>
The provision for income taxes differs from the amount computed by
applying the statutory federal income tax rate of 35% to income from continuing
operations before income taxes. The reasons for this difference are as follows:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1996 1995 1994
- ------------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed "expected" federal
income tax $ 56,522 $ 42,318 $ 29,982
Increase (decrease) in tax
resulting from:
State income taxes, net of
federal income tax benefit (1) 4,923 8,373 (2,596)
Investment tax credit (636) (639) (641)
Research and experimentation credit (188) (375) (1,500)
Adjustments to prior
year accruals 301 510 1,492
Goodwill amortization 4,163 4,163 4,167
Other, net 1,267 1,029 3,468
- ------------------------------------------------------------------------------------
Provision for income taxes $ 66,352 $ 55,379 $ 34,372
- ------------------------------------------------------------------------------------
</TABLE>
(1) Calculation of the accrual for state income taxes at the end of each
year requires that the Company estimate the manner in which its income
for that year will be allocated and/or apportioned among the various
states in which it conducts business, which states have widely differing
tax rules and rates. These allocation/apportionment factors change from
year to year and the amount of taxes ultimately payable may differ from
that estimated as a part of the accrual process. For these reasons, the
amount of state income tax expense may vary significantly from year-to-
year, even absent significant changes to state income tax valuation
allowances or changes in individual state income tax rates.
70
<PAGE> 74
The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities at December 31, 1996 and
1995, were as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
(thousands of dollars) December 31,
1996 1995
- ----------------------------------------------------------------------------------
<S> <C> <C>
Deferred Tax Assets
Employee benefit accruals $ 27,282 $ 25,153
Inventory revaluation and capitalization 552 1,101
Gas purchase contract accruals 15,495 21,972
Regulatory obligations 7,469 10,806
Indemnifications and other reserves 9,332 9,714
Deferred state income taxes 13,799 12,915
Miscellaneous 29,295 30,797
Operating and capital loss carryforwards 28,517 30,547
Alternative minimum tax and general
business credit carryforwards 76,089 78,233
Valuation allowance (6,761) (6,188)
- ----------------------------------------------------------------------------------
Total deferred tax assets 201,069 215,050
- ----------------------------------------------------------------------------------
Deferred Tax Liabilities
Property, plant and equipment,
principally due to depreciation
methods and lives 458,506 450,312
Deferred gas costs 25,043 15,431
Employee benefit accruals 5,807 10,354
Miscellaneous 21,724 28,797
- ----------------------------------------------------------------------------------
Total deferred tax liabilities 511,080 504,894
- ----------------------------------------------------------------------------------
Net deferred tax liabilities $ 310,011 $ 289,844
==================================================================================
</TABLE>
At December 31, 1996, the Company had approximately $398 million of
state net operating losses available to offset future state taxable income
through the year 2011, and approximately $2 million of federal net operating
losses available to offset future federal taxable income through the year 2001.
In addition, at December 31, 1996, the Company had approximately $4 million of
general business credit carryforwards which expire between 1998-2010, and
approximately $69 million of federal alternative minimum tax credits which are
available to reduce future federal income taxes payable, if any, over an
indefinite period (although not below the tentative minimum tax otherwise due
in any year). The Company also has approximately $3 million of state
alternative minimum tax credits which are available to reduce future state
income taxes payable, if any, through the year 2001.
3. FINANCING
The Company meets its needs for short-term financing through utilization of
both formal and informal lines of credit with commercial banks and through a
sale of receivables facility as discussed following. The Company obtains long-
term financing through the issuance of common stock in public offerings and
pursuant to a number of plans (see Notes 5 and 6 and "Other Long-Term
Financing" following), through public offerings of unsecured debt (the Company
is prohibited under an indenture from issuing mortgage debt), through a bank
term loan (which has been retired as discussed following), has issued $130
million
71
<PAGE> 75
of preferred stock (which has been exchanged as discussed following) and has
issued trust originated preferred securities, also as described following.
In late 1995, the Company renewed, revised and extended its principal
short-term credit facility ("the Credit Facility"), an arrangement with
Citibank, N.A. as agent and a group of 18 other commercial banks, which now
provides a $400 million commitment to the Company through December 11, 1998.
Borrowings under the Credit Facility are unsecured and, at the option of the
Company, bear interest at various Eurodollar and domestic rates plus a credit
spread, which credit spread is subject to adjustment based on the rating of the
Company's senior debt securities. The Company pays a facility fee on the total
commitment to each bank each year, currently .14% and subject to decrease based
on the Company's debt rating, and will pay incremental rates of 1/8% to 1/4% on
outstanding borrowings in excess of $200 million. Following is certain
information concerning the Company's short-term borrowings:
<TABLE>
<CAPTION>
SHORT-TERM CREDIT FACILITIES (1)
- ---------------------------------------------------------------------------------------------------
(dollars in millions) Borrowings at Year Ended
December 31, (2) December 31,
-------------------------- --------------------------------------------
Borrowed Wtg. Avg. Wtg. Avg. Wtg. Avg. Max. Amt.
Amount Int. Rate Borrowed (3) Rate (3) Borrowed
----------- ------------- -------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
1996 $ 115.0 6.29% $ 26.9 5.96% $ 115.0
1995 10.0 6.68% 56.5 6.73% 135.0
1994 $ 110.0 7.04% $ 55.9 5.85% $ 170.0
- ---------------------------------------------------------------------------------------------------
</TABLE>
(1) Includes both formal and informal facilities.
(2) There were $175 million in borrowings under the Credit Facility (and
$225 million of remaining capacity) at March 3, 1997.
(3) Based on daily balances.
Under an August 1996 agreement (the "Receivables Facility") which
expires in August 1997 (although the Company currently expects to renew the
facility), the Company sells, with limited recourse and subject to a floating
interest rate provision which varies with the buyer's A1/P1 commercial paper
rate, an undivided interest (limited to a maximum of $235 million) in a
designated pool of accounts receivable. The receivables sold have been deducted
from "Accounts and notes receivable, principally customer" in the accompanying
Consolidated Balance Sheet, although this accounting will change beginning in
1997 as discussed following the tabular data. Certain of the Company's
remaining receivables serve as collateral for receivables sold and represent
the maximum exposure to the Company should all receivables sold prove
ultimately uncollectible. The Company has retained servicing responsibility
under the Receivables Facility for which it is paid a fee which does not differ
materially from a normal servicing fee and, to the extent that the Company
utilizes this facility more or less during a given period, it will experience
net cash inflows or outflows. Following is certain information concerning the
utilization of this facility:
<TABLE>
<CAPTION>
SALE OF RECEIVABLES
- -------------------------------------------------------------------------------------------------------------------------
(dollars in millions) Year Ended
December 31, December 31,
---------------------------------- ---------------------------------------------------------------------
Amount Net Pre-tax Average Weighted
Sold and Inflows Loss Receivables Average
Uncollected Collateral (Outflows) on Sale Sold (1) Rate (1)(2)
---------------- ---------------- ---------------- ---------------- --------------- ---------------
<S> <C> <C> <C> <C> <C>
1996 $ 235.0 $ 34.2 - $ (11.5) $ 186.9 5.41%
1995 235.0 35.0 $ 42.2 (9.8) 136.8 6.02%
1994 $ 192.8 $ 48.7 $ (33.6) $ (7.1) $ 115.2 4.43%
- -------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Based on daily balances.
(2) Exclusive of a facility fee payable on the full commitment of $235
million, which fee was 22 basis points at December 31, 1996.
The rate in effect at December 31, 1996 (exclusive of the facility fee)
was 5.65%.
72
<PAGE> 76
Statement of Financial Accounting Standards No. 125, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities"
("SFAS 125") is required to be adopted for transfers and servicing of financial
assets and extinguishments of liabilities occurring after December 31, 1996.
The effect of the adoption of SFAS 125 on the Company's financial statements
will be to treat amounts transferred pursuant to the Receivables Facility as
collateralized borrowings rather than as sales. Therefore, beginning January 1,
1997, (1) receivables which previously would have been reported as sold
pursuant to the Receivables Facility will remain as assets on the Company's
consolidated balance sheet, (2) amounts received by the Company pursuant to
this facility will be recorded as debt, (3) amounts previously reported as
"Loss on sale of receivables" will be reported as a component of interest
expense and (4) cash flows associated with utilization of this facility will be
included with "Cash Flows from Financing Activities" in the Company's statement
of consolidated cash flows.
Following is certain information concerning the Company's long-term
debt:
<TABLE>
<CAPTION>
LONG-TERM DEBT (1)
- -----------------------------------------------------------------------------------
(millions of dollars) December 31, 1996 (2) December 31, 1995
------------------ --------------------
Due in Due in
Long-Term One Year Long-Term One Year
--------- -------- --------- ----------
<S> <C> <C> <C> <C>
Medium-term notes, Series A and B due
through 2001, weighted average rate
of 8.96% at December 31, 1996 $ 241.6 $ 52.0 $ 293.6 $ 118.8
9.875% Series due 1997 -- 225.0 225.0 --
8.875% Series due 1999 200.0 -- 200.0 --
7 1/2% Series due 2000 200.0 -- 200.0 --
Bank Term Loan due 2000 (3) -- -- 150.0 --
8.90% Series due 2006 145.1 -- 145.1 --
6% Convertible Subordinated
Debentures due 2012 (4) 122.7 -- -- --
9.875% Series due 2018 -- -- 116.4 --
10% Series due 2019 (5) 144.2 -- 144.2 --
Other 0.6 -- 0.6 --
- -----------------------------------------------------------------------------------
$1,054.2 $ 277.0 $1,474.9 $ 118.8
- -----------------------------------------------------------------------------------
</TABLE>
(1) Noncallable and without sinking fund requirements except as noted.
(2) The aggregate amount of long-term debt maturities (excluding certain
scheduled sinking fund requirements, see (4) following) for each of the
five years following December 31, 1996 and thereafter is: 1997 - $277.0
million; 1998 - $81.8 million; 1999 - $207.1 million; 2000 - $228.0
million; 2001 - $150.6 million and $386.7 million.
(3) In December 1995, the Company entered into a $150 million term loan
agreement ("the Loan") with a group of 18 commercial banks, bearing
interest at LIBOR + 87 1/2 basis points, with the rate reset each 30, 60,
90 or 180 days at the option of the Company. This loan was retired without
premium during 1996, see "Other Long-Term Financing" following.
(4) In June 1996, the Company exchanged its Convertible Exchangeable Preferred
Stock, Series A for its 6% Convertible Subordinated Debentures due 2012.
See "Other Long-Term Financing" following for additional information
concerning these debentures. Mandatory sinking fund payments of $6.5
million are payable beginning March 15, 1997 and each succeeding March 15
to and including March 15, 2011. At December 31, 1996, the Company had
reacquired and retired $7.2 million principal amount of these debentures
which may, at the Company's option, be credited against the sinking fund
requirements.
(5) Callable beginning in 1999 at redemption prices beginning at 105.0% and
declining to par in November 2009. Mandatory sinking fund payments of $10
million (which may be increased by up to an additional $20 million at the
option of the Company) are payable beginning in November 2005 and each
year thereafter, and $55.8 million principal amount previously reacquired
and retired by the Company may, at its option, be credited against the
sinking fund requirements.
73
<PAGE> 77
<TABLE>
<CAPTION>
RETIREMENTS AND REACQUISITIONS OF LONG-TERM DEBT (1)
- -------------------------------------------------------------------------------
(millions of dollars) Year Ended December 31,
1996 1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Reacquisition of 8% Series Due 1997 -- $ 150.0 --
Reacquisition of 8.9% Debentures due 2006 -- -- $ 1.9
Reacquisition of 9.23% Medium Term Notes due 2001 -- -- 10.0
Reacquisition of 9.875% Debentures due 2018 $ 7.4 5.7 12.2
Reacquisition of 10% Debentures due 2019 -- 15.0 26.3
Reacquisition of 6% Convertible Subordinated
Debentures due 2012 (2) 7.2 -- --
Retirement, at maturity, of Medium Term Notes (3) 118.8 1.0 77.0
Retirement of Bank Term Loan due 2000 150.0 -- --
Retirement of 9.45% Series due 1995 -- 150.0 --
Retirement of 9.875% Debentures due 2018 109.0 -- --
Retirement of Note Payable to Gas Supplier -- 13.6 20.4
Net loss on reacquisition of debt, less taxes 4.3 0.1 1.1
- -------------------------------------------------------------------------------
$ 396.7 $ 335.4 $ 148.9
- -------------------------------------------------------------------------------
</TABLE>
(1) In cases where premiums were paid or discounts were realized in
association with these reacquisitions and retirements, such amounts are
reported in the accompanying Statement of Consolidated Income as
"Extraordinary item, less taxes", and are net of tax benefits of $2.5
million, $0.03 million and $0.7 million in 1996, 1995 and 1994,
respectively.
(2) These reacquired debentures may be credited against sinking fund
requirements, see "Other Long-Term Financing" following.
(3) Weighted average interest rate of approximately 9.06%, 9.0% and 9.15% in
1996, 1995 and 1994 respectively.
The Company has entered into interest rate swaps for the purposes of (1)
increasing or decreasing the amount of the Company's debt portfolio which is
subject to market interest rate fluctuations and (2) effectively fixing the
interest rate on debt expected to be issued in the future for refunding
purposes, and may enter into additional such swaps in the future. In general,
these swaps are entered into with commercial banks and require that one party
pay a fixed rate on the notional amount of the swap while the counterparty pays
a LIBOR-based rate. Following is information on the Company's recent interest
rate swap activity and on its portfolio of interest rate swaps at December 31,
1996:
<TABLE>
<CAPTION>
INTEREST RATE SWAPS
- ---------------------------------------------------------------------------------------------
(dollars in millions)
Notional Unrealized
Amount Gain Deferred Interest Rate
Outstanding (Loss) (1) Gains (2) Fixed/Floating
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
December 31, 1993 $ 200.0 $ (2.6) $ 5.0 5.1% / 4.5%
Additions 75.0 -- -- --
Terminations -- -- -- --
- ---------------------------------------------------------------------------------------------
December 31, 1994 275.0 (18.0) 2.5 5.1% / 6.7%
Additions 100.0 -- -- --
Terminations (25.0) -- -- --
- ---------------------------------------------------------------------------------------------
December 31, 1995 350.0 (0.8) 0.8 5.1% / 6.6% (3)
Additions 200.0 -- -- --
Terminations (250.0) -- -- --
- ---------------------------------------------------------------------------------------------
December 31, 1996 $ 300.0 $ 6.7 $ 0.1 4.7% / 5.6% (3)
- ---------------------------------------------------------------------------------------------
</TABLE>
(1) Market value of swaps at date indicated.
(2) The economic value which transfers between the parties to these swaps is
reported as an adjustment to the effective interest rate on the
underlying debt securities and, when positions are closed prior to
expiration, any material gain or loss is deferred and amortized over the
period remaining in the original term of the swap. The effect of these
swaps was to increase (decrease) interest expense by approximately
$(1.6) million, $(0.2) million and $0.5 million in 1996, 1995 and 1994,
respectively.
(3) Does not include swaps which are hedges of anticipated debt issuance as
discussed following.
74
<PAGE> 78
<TABLE>
<CAPTION>
INTEREST RATE SWAP PORTFOLIO AT DECEMBER 31, 1996 (1) (2)
- -----------------------------------------------------------------------------------------
(dollars in millions)
Estimated
Notional Period Interest Rate Market
Initiated Amount Covered Fixed/Floating (3) Value (4)
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
December 1995 $ 50.0 Apr.1997-Apr.2002 (5) 5.92% /6.55% $ 1.3
December 1995 50.0 Apr.1997-Apr.2002 (5) 5.92% /6.55% 1.3
January 1996 50.0 Apr.1997-Apr.2002 (5) 5.80% /6.55% 1.6
February 1996 50.0 Apr.1997-Apr.2002 (5) 5.77% /6.55% 1.6
February 1996 50.0 Mar.1996-Jan.1998 (6) 4.76% /5.65% 0.5
February 1996 50.0 Jun.1996-Dec.1997 (6) 4.71% /5.63% 0.4
- -----------------------------------------------------------------------------------------
Total $ 300.0 $ 6.7
=========================================================================================
</TABLE>
(1) None of these interest rate swaps are "leveraged" and, accordingly, do
not represent exposure in excess of that suggested by the reported
notional amounts and interest rates and, in general, the future cash
flows are measured as the notional amount times the interest rate. Off-
balance-sheet credit risk exists to the extent that counterparties to
these swaps may fail to perform, although all counterparties are
commercial banks which are participants in the Company's revolving
credit facility. The Company routinely reviews the financial condition
of these banks (utilizing independent monitoring services and otherwise)
and believes that the probability of default by any of these
counterparties is minimal.
(2) In March 1997, the Company closed out the $200 million of swaps which
were serving as hedges of its anticipated April 1997 debt refinancing
(see (5) following), receiving cash proceeds of approximately $8.7
million.
(3) In each case, the Company is the fixed-price payor. The floating (LIBOR-
based) rate is estimated as of December 31, 1996.
(4) Represents the estimated amount which would have been realized upon
termination of the swap at December 31, 1996.
(5) Swaps entered into for the purpose of effectively fixing the interest
rate on debt expected to be issued in 1997 for refunding purposes.
(6) Swaps entered into for the purpose of reducing the Company's exposure to
fluctuations in market interest rates.
OTHER LONG-TERM FINANCING
In June 1996, the Company issued 11,500,000 shares of NorAm Energy Corp. common
stock (the "Common Stock") to the public at a price of $9.875 per share,
yielding net cash proceeds of approximately $109.0 million after deducting an
underwriting discount of 4.05% and before deducting expenses of approximately
$0.1 million. The net proceeds from the offering principally were used to
retire debt as described following.
In June 1996, the Company issued $177.8 million of 6.25% Convertible
Junior Subordinated Debentures due 2026 (unless extended by the Company as
discussed following) (the "Trust Debentures") to NorAm Financing I (the
"Trust"), a statutory business trust under Delaware law, wholly owned by the
Company. The Trust Debentures were purchased by the Trust using the proceeds
from (1) the public issuance by the Trust of 3,450,000 shares of 6.25%
Convertible Preferred Securities (the "Trust Preferred") at $50 per share, a
total of $172.5 million and (2) the sale of approximately $5.3 million of the
Trust's common stock (106,720 shares, representing 100% of the Trust's common
equity) to the Company. The sole assets of the Trust are and will be the Trust
Debentures. The interest and other payment dates on the Trust Debentures
correspond to the interest and other payment dates on the Trust Preferred. In
conjunction with the issuance of the Trust Preferred, the Company paid an
underwriting commission of $1.375 per share and expenses of approximately $0.1
million in view of the fact that the proceeds from such issuance would be
invested in the Trust Debentures. The net proceeds from these transactions
principally were used to retire debt as described following.
The Trust Preferred accrues a dividend equal to 6.25% of the $50
liquidation amount, payable quarterly in arrears. The ability of the Trust to
pay distributions on the Trust Preferred is solely dependent on its receipt of
interest payments on the Trust Debentures. The Company has irrevocably
guaranteed, on a subordinated basis, distributions and other payments due on
the Trust Preferred (the "Guarantee"). The Guarantee, when taken together with
the Company's obligations under the Trust Debentures and in the indenture
pursuant to which the Trust Debentures were issued and the Company's
obligations under the Amended and Restated Declaration of Trust governing the
Trust, provides a full and unconditional guarantee by the Company of amounts
due on the Trust Preferred. The Company has the right to defer
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<PAGE> 79
interest payments on the Trust Debentures as discussed following. In the case
of such deferral, quarterly distributions on the Trust Preferred would be
deferred by the Trust but would continue to accumulate quarterly and would
accrue interest. Each share of Trust Preferred is convertible at the option of
the holder into shares of Common Stock at an initial conversion rate of 4.1237
shares of Common Stock for each share of the Trust Preferred, subject to
adjustment in certain circumstances. The Trust Preferred does not have a stated
maturity date, although it is subject to mandatory redemption upon maturity of
the Trust Debentures or, to the extent that the Trust Debentures are redeemed,
upon redemption of the Trust Debentures. The redemption price in either such
case will be $50 per share plus accrued and unpaid distributions to the date
fixed for redemption. In general, holders of the Trust Preferred do not have
any voting rights.
The Trust Debentures bear interest at 6.25% and are redeemable for cash
at the option of the Company, in whole or in part, from time to time on or
after June 30, 2000, if and only if for 20 trading days within any period of 30
consecutive days, including the last trading day of such period, the current
market price of the Common Stock equals or exceeds 125% of the then-applicable
conversion price of the Trust Debentures, or at any time in certain
circumstances upon the occurrence of a specified tax event. The Trust
Debentures will mature on June 30, 2026, although the maturity date may be
extended only once at the Company's election for up to an additional 19 years,
provided certain requirements and conditions are met. Under existing law,
interest payments made by the Company for the Trust Debentures are deductible
for federal income tax purposes. The Company has the right at any time and from
time to time to defer interest payments on the Trust Debentures for successive
periods not to exceed 20 consecutive quarters for each such extension period.
In such case, (1) quarterly distributions on the Trust Preferred would also be
deferred as discussed preceding and (2) the Company has agreed not to declare
or pay any dividend on any common or preferred stock, except in certain
instances.
The Trust is consolidated with the Company for financial reporting
purposes and, therefore, the Trust Debentures are eliminated in consolidation
and the Trust Preferred appears on the Company's Consolidated Balance Sheet
under the caption "Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of Subsidiary Trust Holding Solely $177.8 Million
Principal Amount of 6.25% Convertible Junior Subordinated Debentures due 2026
of NorAm Energy Corp." The dividend on the Trust Preferred is reported in the
accompanying Statement of Consolidated Income under the caption "Dividend
requirement on preferred securities of subsidiary trust".
Utilizing, in large part, the proceeds from the offerings discussed
preceding, in June 1996, the Company (1) retired the $109.0 million principal
amount then outstanding of its 9.875% Debentures due 2018 at a price equal to
105.93% of face value, recognizing an extraordinary pre-tax loss of
approximately $6.5 million (approximately $3.9 million or $0.03 per share
after-tax) and (2) retired its $150 million bank term loan due 2000 at face
value. The Company also made certain other debt reacquisitions and scheduled
debt retirements as set forth preceding.
Also in June 1996, the Company exercised its right to exchange the $130
million principal amount of its $3.00 Convertible Exchangeable Preferred Stock,
Series A (the "Preferred") for its 6% Convertible Subordinated Debentures due
2012 (the "Subordinated Debentures"). The holders of the Subordinated
Debentures will receive interest quarterly at 6% and have the right at any time
on or before the maturity date thereof to convert the Subordinated Debentures
into Common Stock, initially at the conversion rate in effect for the Preferred
at the date of the exchange, which conversion rate of approximately 1.7467
shares of the Common Stock for each $50 principal amount of the Subordinated
Debentures is subject to adjustment should certain events occur. The Company is
required to make annual sinking fund payments of $6.5 million on the
Subordinated Debentures beginning on March 15, 1997 and on each succeeding
March 15 to and including March 15, 2011. The Company (1) may credit against
the sinking fund requirements (i) any Subordinated Debentures redeemed by the
Company and (ii) Subordinated Debentures which have been converted at the
option of the holder and (2) may deliver outstanding Subordinated Debentures in
satisfaction of the sinking fund requirements.
The Company has equipment funding agreements ("EFA's") with affiliates
of major banks which provide for the purchase of vehicles, major work equipment
and, to a lesser extent, computers and other office equipment. For accounting
purposes, assets subject to these EFA's receive operating lease treatment, with
an initial non-cancelable term of one year. At December 31, 1996, the Company
had $3.5
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<PAGE> 80
million of available capacity under these EFA's. The EFA's extend through July
1997 unless renewed through mutual agreement of the parties.
Since late 1994, the Company has offered a Direct Stock Purchase and
Dividend Reinvestment Plan ("the DSPP") which affords customers and other
interested parties the opportunity to (1) purchase Common Stock directly from
the Company, avoiding brokerage fees and commissions and (2) automatically
reinvest their dividends in additional shares of Common Stock. Sales of Common
Stock under the DSPP were immaterial in 1994 and, in 1995 and 1996, the Company
received net proceeds of approximately $9.8 million and $10.3 million,
respectively, from such sales. Sales of Common Stock under the DSPP (although
not dividend reinvestment) have been suspended as a result of the pending
Houston Industries transaction, see "Merger With Houston Industries" included
in Note 1.
RESTRICTIONS ON STOCKHOLDERS' EQUITY AND DEBT
Under the provisions of the Company's revolving credit facility as described
preceding, and under similar provisions in certain of the Company's other
financial arrangements, the Company's total debt capacity is limited and it is
required to maintain a minimum level of stockholders' equity. In addition, the
Company's total debt is limited to $2,055 million (unless the ratio of total
debt to total capitalization is less than or equal to 60%) and the Company's
ability to reacquire, retire or otherwise prepay its long-term debt prior to
its maturity is limited to a total of $200 million. The required minimum level
of stockholders' equity was initially set at $700 million at December 31, 1995,
increasing annually thereafter by (1) 50% of positive consolidated net income
and (2) 50% of the proceeds from any incremental equity offering made after
June 30, 1996. Based on these restrictions, the Company had incremental
capacity for debt issuance, dividends and debt reacquisitions of $561.7
million, $220.2 million and $200.0 million, respectively, at December 31, 1996.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and fair values of certain of
the Company's financial instruments. Statement of Financial Accounting
Standards No. 107, "Disclosures about Fair Value of Financial Instruments",
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale. The estimated fair value amounts
have been determined by the Company using quoted market prices of the same or
similar securities when available or other estimation techniques. The items
presented below without a carrying value are off-balance-sheet financial
instruments and all of the Company's financial instruments are held for
purposes other than trading.
The carrying amounts of certain financial instruments employed by the
Company, including cash and cash equivalents, accounts and notes receivable and
payable, gas purchased in advance of delivery and other current assets and
liabilities, approximate fair value. The fair value of the Company's interest
rate swaps, natural gas swaps and futures contracts generally reflect the
estimated amounts that the Company would pay or receive to terminate the
contracts at the reporting date, thereby taking into account the unrealized
gains and losses on open contracts. There is no readily available market for
the natural gas options. Following is certain information concerning the
Company's significant financial assets and liabilities:
77
<PAGE> 81
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
(millions of dollars) December 31,
1996 1995
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
FINANCIAL ASSETS (LIABILITIES) Amount Value Amount Value
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Investment in Itron (Note 1) $ 26.7 $ 26.7 $ 50.7 $ 50.7
Natural gas options (Note 7) 0.8 -- 1.3 --
Natural gas futures (Note 7) -- 0.1 -- 3.3
Long-term debt (Note 3) (1,331.2) (1,389.5) $(1,593.7) (1,677.1)
Trust preferred (Note 3) $ (167.8) (219.1) -- --
Interest rate swaps (Note 3) -- 6.7 -- (0.8)
Natural gas swaps (Note 7) -- $ 9.7 -- $ (5.0)
- -------------------------------------------------------------------------------
</TABLE>
5. EMPLOYEE BENEFIT PLANS
The Company has two qualified pension plans ("the Qualified Plans") which cover
substantially all employees; (1) the plan which covers the Company's employees
other than Minnegasco employees and (2) the plan which covers Minnegasco
employees. The Qualified Plans provide benefits based on the participant's
years of service and highest average compensation. The funding policy for the
Qualified Plans is to contribute at least the minimum amount required to be
funded as determined by the Company's consulting actuaries. Plan assets are
made up of marketable equity and high-grade fixed income securities.
In addition to the Qualified Plans, the Company maintains certain non-
qualified plans which principally consist of (1) a retirement restoration plan
which allows participants to retain the benefit to which they would have been
entitled under the Qualified Plans except for the federally mandated limits on
such benefits or on the level of salary on which such benefits may be
calculated and (2) certain supplemental benefit plans which, in the past, were
entered into with individual employees or with small groups of employees.
Participants in these non-qualified plans are general creditors of the Company
with respect to these benefits, as these plans are not funded by the Company in
advance of the cash payment of benefits. Expense of approximately $2.0 million,
$2.1 million and $2.3 million associated with these non-qualified plans was
recorded during 1996, 1995 and 1994, respectively. Following is certain
information concerning the Company's pension plans:
78
<PAGE> 82
<TABLE>
<CAPTION>
PENSION PLAN STATUS
- -------------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1996 1995
------------------------- ----------------------
Qualified Non-Qualified Qualified Non-Qualified
Plans Plans Plans Plans
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Net assets available for benefits $ 500,452 -- $ 439,153 --
- -------------------------------------------------------------------------------------------
Actuarial present value of
accumulated plan benefits
Vested (assuming immediate
separation) 325,461 $ 30,554 304,361 $ 18,681
Non-vested 30,096 1,663 32,831 1,660
- -------------------------------------------------------------------------------------------
Accumulated benefit obligation 355,557 32,217 337,192 20,341
Additional amount related to
projected pay increases 79,933 712 75,713 845
- -------------------------------------------------------------------------------------------
Total projected benefit obligation 435,490 32,929 412,905 21,186
- -------------------------------------------------------------------------------------------
Funded status 64,962 (32,929) 26,248 (21,186)
Unrecognized net obligation at January 1 (8,290) -- (12,123) --
Unrecognized prior service costs (2,222) 5,004 -- 5,529
Unrecognized net loss (gain) from past
experience different from that
assumed and effects of changes
in actuarial assumptions (9,060) (1,506) 43,840 (1,654)
- -------------------------------------------------------------------------------------------
Pension prepaid asset (liability) $ 45,390 $ (29,431) $ 57,965 $ (17,311)
- -------------------------------------------------------------------------------------------
</TABLE>
The assumed rate of increase in future compensation levels and the
expected long-term rate of return on fund assets utilized in the above
calculations (and for 1994 which is not presented) were 4% and 10%,
respectively. The weighted average discount rate was 7.5%, 7.25% and 8.5% for
1996, 1995 and 1994, respectively.
<TABLE>
<CAPTION>
PERIODIC PENSION COST (QUALIFIED PLANS ONLY)
- -----------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1996 1995 1994
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 11,817 $ 9,900 $ 11,757
Interest cost on projected benefit obligation 29,946 27,097 25,633
Actual return on plan assets (41,800) (36,909) (3,067)
Amortization and deferral (641) (1,388) (33,774)
- -----------------------------------------------------------------------------------------------------
Net pension cost (credit) $ (678) $ (1,300) $ 549
=====================================================================================================
</TABLE>
The Company has an employee savings plan ("the ESP") which covers
substantially all employees other than Minnegasco employees. Under the terms of
the ESP, employees may contribute up to 12% of total compensation, which
contributions up to 6% are matched by the Company. Employer contributions to
the ESP of $8.9 million, $8.9 million and $8.8 million were expensed during
1996, 1995 and 1994, 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 $1.4 million, $1.4 million and $1.3 million
related to these plans was recorded during 1996, 1995 and 1994, respectively.
In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits to retired employees, collectively
referred to as "postretirement benefits", accounted for pursuant to Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other than Pensions". The Company provides these
benefits under a defined
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<PAGE> 83
benefit plan for all eligible former employees who retired prior to July 1,
1992, and under a defined contribution plan for all others. A substantial
number of the Company's employees may become eligible for postretirement
benefits if they are participating in such plans when they reach normal
retirement age. As of December 31, 1996, the Company had contributed a total of
$1.8 million to an external fund (associated with Minnegasco employees) to
provide for these benefits and contributed an additional $1.2 million in early
1997. The Company currently expects that it will fund these benefits utilizing
external funding techniques for additional employees in the future. Following
is certain information concerning the Company's postretirement benefit plans:
<TABLE>
<CAPTION>
POSTRETIREMENT BENEFIT PLAN STATUS
- ---------------------------------------------------------------------------------------
(thousands of dollars) December 31,
1996 1995
- ---------------------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation
Retirees $ 121,183 $ 129,425
Fully-eligible plan participants 3,711 4,929
Other active plan participants 4,487 5,574
- ---------------------------------------------------------------------------------------
Total 129,381 139,928
Fair value of plan assets 3,051 1,800
- ---------------------------------------------------------------------------------------
126,330 138,128
Unrecognized transition obligation (106,599) (113,261)
Unrecognized net actuarial gain 14,292 337
- ---------------------------------------------------------------------------------------
Accrued postretirement benefit liability $ 34,023 $ 25,204
- ---------------------------------------------------------------------------------------
</TABLE>
The weighted average discount rate used in determining the accumulated
benefit obligation for postretirement benefits was 7.5%, 7.25% and 8.5% for
1996, 1995 and 1994, respectively. The cost of covered health care benefits
(for those participants entitled to a defined benefit as a result of having
retired prior to July 1, 1992) is assumed to increase by 10% per year initially
and then increase at a decreasing rate to an annual and continuing increase of
4.5% after 11 years. Based on these assumptions, a one percentage point
increase in the assumed health care cost trend rate would increase the annual
net periodic postretirement benefit cost (before any deferral for regulatory
reasons) and the accumulated benefit obligation at December 31, 1996 by
approximately $0.9 million and $12.4 million, respectively.
<TABLE>
<CAPTION>
POSTRETIREMENT BENEFIT COST
- -----------------------------------------------------------------------------------------------------
(thousands of dollars) Year Ended December 31,
1996 1995 1994
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost $ 306 $ 291 $ 408
Interest cost on accumulated benefit obligation 9,234 10,183 10,436
Actual return on plan assets (108) - -
Amortization of transition obligation
on a straight line basis over 20 years 6,662 6,663 6,721
Amortization of actuarial loss 1,321 - -
Deferral of asset loss - (195) (87)
- -----------------------------------------------------------------------------------------------------
Net periodic cost $ 17,415 $ 16,942 $ 17,478
- -----------------------------------------------------------------------------------------------------
</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
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<PAGE> 84
not yet filed rate cases to seek recovery of the SFAS 106 calculated costs (as
opposed to the cash costs currently included in rates). In light of this
regulatory uncertainty and the guidance provided by authoritative accounting
pronouncements concerning the appropriate accounting treatment for the excess
of accrual SFAS 106 costs over the amount includable in rates prior to final
regulatory determination, at December 31, 1996, the Company had deferred
approximately $5.6 million of such costs in certain jurisdictions pending final
regulatory actions. This deferral will be subject to continuing review and may
require adjustment depending on the ultimate regulatory disposition of these
costs.
The Company has several plans which provide for the issuance of its
common stock to employees and directors or provide for the sale of the
Company's common stock to these individuals, see Note 6.
6. STOCK COMPENSATION/STOCK PURCHASE PLANS
The Company has an Incentive Equity Plan ("the IEP") intended to facilitate the
attraction and retention of key employees and to provide an incentive for
superior performance. The IEP provides for the issuance of up to 3.8 million
shares of the Company's common stock ("Shares"), no more than 2 million of
which may be issued or transferred as restricted stock, as well as stock
options ("options") and stock appreciation rights ("SAR's"). Options and SAR's
issued pursuant to the IEP are exercisable for a period of 10 years from the
date of issuance and vest (become exercisable and non-cancelable) at the rate
of 1/3 per year beginning with the year of issuance. Provisions of the IEP
determine the amount of these securities initially granted to employees, while
the amount ultimately retained by each employee is determined by the Company's
performance as measured by the Board of Directors during three-year performance
cycles. The charge (credit) to earnings associated with the IEP was $4.4
million, $0.5 million and $(0.2) million in 1996, 1995 and 1994, respectively.
The principal reason for the increase in IEP expense in 1996 was the
acceleration of certain IEP benefits resulting from the pending Houston
Industries transaction, see "Merger With Houston Industries" included in Note
1.
The Company has a Restricted Stock Plan for Non-Employee Directors ("the
DRSP") which is intended to assist in attracting and retaining highly qualified
individuals to serve as directors of the Company. Shares issued pursuant to the
DRSP will not exceed a total of 125,000 and may be Shares of original issuance,
treasury Shares or both. At December 31, 1996, a total of 57,984 Shares had
been issued pursuant to the DRSP.
The Company had an Employee Stock Purchase Plan ("the ESPP") which
provided employees with an incentive to increase their Share ownership by
affording them the opportunity to purchase Shares at a price equivalent to 85%
of fair market value. The ESPP provided for payment via payroll deduction and
was limited to a total of 2 million Shares. The ESPP terminated as of December
31, 1996.
While no additional options may be issued pursuant to either plan, and
no compensation expense has been or will be recorded, some stock options remain
outstanding pursuant to (1) a Non-Qualified Stock Option Plan adopted by the
Company in 1983, which options expire in 1997 and (2) a former Diversified
Energies Plan, which options expire at various times through the year 2000. In
addition, 114,000 options (with an exercise price of $21.84 per share and which
expire in July 1998) were issued to a former executive of the Company and are
included in the tabular data which follows.
Following is certain information concerning certain Shares, options and
SAR's issued pursuant to the foregoing arrangements:
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<PAGE> 85
<TABLE>
<CAPTION>
RESTRICTED STOCK, STOCK OPTIONS AND STOCK APPRECIATION RIGHTS
- ----------------------------------------------------------------------------------------------------------------------
Restricted Stock (1) Stock Options (2) SAR's (3)
---------------------------- ------------------------------------------- ---------------------
Weighted Weighted
Average Average Average Average
Grant Date Exercise Grant Date Exercise
Shares Fair Value (4) Shares Price/Shr. Fair Value (4) Shares Price/Shr.
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1993 929,689 -- 375,573 $ 18.39 -- 375,592 $ 12.92
Granted/Issued 162,284 $ 6.54 313,418 6.50 $ 1.84 -- --
Forfeited/Expired (149,404) -- (38,053) 14.49 -- (250,000) 12.00
Exercised -- -- -- -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------
December 31, 1994 942,569 -- 650,938 (5) 12.89 -- 125,592 14.75
Granted/Issued 262,461 5.48 546,550 5.54 1.64 -- --
Forfeited/Expired (103,894) -- (164,469) 14.05 -- (32,478) 18.44
Exercised -- -- -- -- -- -- --
- ----------------------------------------------------------------------------------------------------------------------
December 31, 1995 1,101,136 -- 1,033,019 (5) 8.82 -- 93,114 13.47
Granted/Issued 463,856 $ 11.86 579,749 8.69 $ 2.39 -- --
Forfeited/Expired (283,953) -- (76,821) 11.99 -- (15,743) 19.03
Exercised -- -- (28,019) 6.44 -- -- --
- ----------------------------------------------------------------------------------------------------------------------
December 31, 1996 1,281,039 -- 1,507,928 $ 8.65 -- 77,371 $ 12.34
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Shares are included when granted. Does not include restricted stock (i)
issued to the Company's Chairman in lieu of cash salary; 60,838 Shares
with a weighted average market price of $6.375 per share and 53,406
Shares with a weighted average market price of $11.28 per share in 1995
and 1996, respectively, or (ii) issued pursuant to the Restricted Stock
Plan for Non-Employee Directors as discussed preceding.
(2) The exercise price was equal to the fair market value at the grant date.
(3) The exercise price was greater than or equal to the fair market value at
the grant date.
(4) See the discussion following.
(5) At December 31, 1994 and 1995, 337,520 options and 431,615 options,
respectively, were exercisable at weighted average prices of $18.83 per
share and $16.14 per share.
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING AT DECEMBER 31, 1996
- -------------------------------------------------------------------------------------------------
Weighted Weighted
Average Exercise Average Remaining
Number of Options Price per Share Contractual Life
Exercise ----------------------- ----------------------- ------------------------
Price Range Exercisable Total Exercisable Total Exercisable Total
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
up to $7 per Share 484,557 726,449 $ 5.86 $ 5.78 7.8 years 7.8 years
$7 to $15 per Share 246,214 600,590 8.74 8.66 9.0 years 9.0 years
above $15 per Share 180,889 180,889 20.17 20.17 2.12 years 2.12 years
- -------------------------------------------------------------------------------------------------
Totals 911,660 1,507,928 $ 9.48 $ 8.65 7.0 years 7.6 years
- -------------------------------------------------------------------------------------------------
</TABLE>
In October, 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-
Based Compensation" ("SFAS 123"). SFAS 123 provides for the disclosure of
certain information concerning the "fair value" of securities issued pursuant
to stock-based employee compensation plans, and gives the Company the options
of calculating and recording compensation expense utilizing either (1) SFAS
123's "fair value" methodology which measures compensation expense as the "fair
value" of all securities at the date on which they are granted to the employee
or (2) the provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" ("APBO 25") which, in general, do
not require the recording of compensation expense for options and SAR's issued
pursuant to plans structured similarly to those of the Company. The Company has
elected to continue to apply the provisions of APBO 25 for the purpose of
computing compensation expense associated with the relevant plans, although
certain additional required disclosure has been made in accordance with the
provisions of SFAS 123.
In the preceding table, the term "fair value" as applied to restricted
stock represents the quoted NYSE closing market price of the Shares on the
grant date. The term "fair value" as applied to stock options (and which would
also be applicable to any future issuance of SAR's) is a statistical
calculation made utilizing a methodology generally referred to as the Black-
Scholes option pricing model ("the BS
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<PAGE> 86
model"). The BS model yields a value for each option which is dependent on a
number of variables which are inputs to the relevant calculations. For the
purposes of determining the "fair value" of stock options in the preceding
tables, the Company has assumed (1) a risk free interest rate (based on U.S.
Treasury strips with a remaining term of five years) of 5.24% to 7.84%, (2) an
expected option life (duration) of five years, (3) an expected volatility of
31.6% to 36.4% and (4) an expected dividend yield of 3.4%. To the extent that
actual conditions during the post-grant, pre-exercise period differ from these
assumptions (which is probable as described following), the actual value of the
options to the employee will differ from the calculated "fair value" at grant
date. Had compensation cost for the IEP been determined in accordance with the
provisions of SFAS 123, the impact on the Company's earnings for 1995 and 1996
would have been immaterial.
As described elsewhere herein and under "Merger With Houston Industries"
included in Note 1, the Company is expected to merge with Houston Industries
Incorporated. Should the merger be consummated, Houston Industries would become
the sole owner of NorAm common stock. In addition, in conjunction with
consummation of the acquisition, all of the Company's outstanding stock options
and SAR's would be either (1) exercised and the Shares obtained converted to
Houston Industries common stock, cash or a combination thereof, (2) converted
directly to cash or (3) exchanged for SAR's or options on Houston Industries
common stock.
7. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
Following is certain information concerning the Company's obligations under
operating leases:
<TABLE>
<CAPTION>
MINIMUM LEASE COMMITMENTS AT DECEMBER 31, 1996 (1)
- -------------------------------------------------------------
(thousands of dollars)
- -------------------------------------------------------------
<S> <C> <C>
1997 $ 36,500
1998 17,833
1999 15,453
2000 13,362
2001 12,436
2002 and beyond 27,492
- -------------------------------------------------------------
Subtotal 123,076
Less subleases (181)
- -------------------------------------------------------------
Net $ 122,895
- -------------------------------------------------------------
</TABLE>
(1) Principally consisting of rental agreements for building space, data
processing equipment and vehicles (including major work equipment).
Lease payments related to assets transferred under the Company's leasing
arrangements (see "Other Long-Term Financing" included in Note 3) are included
in the preceding table for only their primary (non-cancelable) term. Subsequent
to the primary term, the Company could terminate its obligations under these
arrangements by electing to purchase the relevant assets for an amount
approximating fair market value. Total rental expense for all leases was $33.4
million, $48.9 million and $36.8 million in 1996, 1995 and 1994, respectively.
LETTERS OF CREDIT
At December 31, 1996, the Company was obligated under letters of credit
incidental to its ordinary business operations totalling approximately $21.7
million.
INDEMNITY PROVISIONS
In June 1993, the Company completed the sale of Louisiana Intrastate Gas
Corporation ("LIG"), its former subsidiary engaged in the intrastate pipeline
and liquids extraction business, to Equitable Resources, Inc. In December 1992,
the Company completed the sale of Arkla Exploration Company
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<PAGE> 87
("AEC"), its former subsidiary engaged in oil and gas exploration and
production activities, to Seagull Energy Corporation. In June 1991, the Company
completed the sale of Dyco Petroleum Company ("Dyco"), the oil and gas
exploration and production company acquired in conjunction with the Company's
acquisition of Diversified Energies Inc., to Continental Drilling Company,
Inc., a subsidiary of Samson Investment Company. In each instance, the relevant
sale agreement required the Company to indemnify the purchaser against certain
exposures, for which the Company has established reserves based on, among other
factors, its estimates of potential claims. These reserves are included in the
Company's Consolidated Balance Sheet under the caption "Estimated obligations
under indemnification provisions of sale agreements".
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been transferred pursuant to a sale of receivables facility, see "Sale of
Receivables" included in Note 3.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has
prepaid for certain volumes of gas, which prepayments have been recorded at
their net realizable value and, to the extent that the Company is unable to
realize at least the carrying amount as the gas is delivered and sold, the
Company's earnings will be adversely affected, although such impact is not
expected to be material. In addition to these prepayments, the Company is a
party to a number of agreements which require it to either purchase or sell gas
in the future at prices which may differ from then-prevailing market prices or
which require it to deliver gas at a point other than the expected receipt
point for volumes to be purchased. As discussed under "Credit Risk and Off-
Balance-Sheet Risk" following, the Company operates an ongoing risk management
program designed to eliminate or limit the Company's exposure from its
obligations under these purchase/sale commitments. To the extent that the
Company expects that these commitments will result in losses over the contract
term, the Company has established reserves equal to such expected losses.
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250 MMcf/day,
and pursuant to which ANR had advanced $125 million to the Company. The ANR
Agreement has been restructured as a lease of capacity and, after refunds of
$50 million and $34 million in 1995 and 1993, respectively, the Company
currently retains $41 million (recorded as a liability) in exchange for ANR's
use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in the
year 2003 with a refund of $5 million to ANR and the ANR Agreement will
terminate in 2005 with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company's gas supply, marketing, gathering and transportation activities
subject the Company's earnings to variability based on fluctuations in both the
market price of natural gas and the value of transportation as measured by
changes in the delivered price of natural gas at various points in the nation's
natural gas grid. In order to mitigate the financial risk associated with these
activities both for itself and for certain customers who have requested the
Company's assistance in managing similar exposures, the Company routinely
enters into natural gas swaps, futures contracts and options, collectively
referred to in this discussion as "derivatives". The use of derivatives for the
purpose of reducing exposure to risk is generally referred to as hedging and,
through deferral accounting, results in matching the financial impact of these
derivative transactions with the cash impact resulting from consummation of the
transactions being hedged, see "Accounting for Price Risk Management
Activities" included in Note 1.
The futures contracts are purchased and sold on the NYMEX and generally
are used to hedge a portion of the Company's storage gas, manage intra-month
and inter-month actual and anticipated short or long commodity positions and
provide risk management assistance to certain customers, to whom the cost of
the derivative activity is generally passed on as a component of the sales
price of the service being
84
<PAGE> 88
provided. Futures contracts are also utilized to fix the price of compressor
fuel or other future operational gas requirements, although usage to date for
this purpose has not been material. The options are entered into with various
third parties and principally consist of options which serve to limit the year-
to-year escalation from January 1998 to April 1999 in the purchase price of gas
which the Company is committed to deliver to a distribution affiliate. These
options covered 2.4 Bcf, 13.2 Bcf and 30.5 Bcf at December 31, 1996, 1995 and
1994, respectively and, due to their nature and term, have no readily
determinable fair market value. The Company previously established a reserve
equal to its projected maximum exposure to losses during the term of this
commitment and, accordingly, no impact on earnings is expected. The Company
also utilizes options in conjunction with meeting customers' needs for custom
risk management services and for other limited purposes. The Company had an
immaterial amount of such options outstanding at December 31, 1996. The impact
of such options was to decrease 1996 earnings by approximately $2.6 million and
the effect on prior periods was not material. The swaps, also entered into with
various third parties, are principally associated with the Company's marketing
and transportation activities and generally require that one party pay either a
fixed price or fixed differential from the NYMEX price per MMBtu of gas while
the other party pays a price based on a published index. These swaps allow the
Company to (1) commit to purchase gas at one location and sell it at another
location without assuming unacceptable risk with respect to changes in the cost
of the intervening transportation, (2) effectively set the value to be received
for transportation of certain volumes on the Company's facilities in the future
and (3) effectively fix the base price for gas to be delivered in conjunction
with the commitment described preceding. None of these derivatives are held for
speculative purposes and the Company's risk management policy requires that
positions taken in derivatives be offset by positions in physical transactions
(actual or anticipated) or in other derivatives.
In the table which follows, the term "notional amount" refers to the
contract unit price times the contract volume for the relevant derivative
category and, in general, such amounts are not indicative of the cash
requirements associated with these derivatives. The notional amount is intended
to be indicative of the Company's level of activity in such derivatives,
although the amounts at risk are significantly smaller because, in view of the
price movement correlation required for hedge accounting, changes in the market
value of these derivatives generally are offset by changes in the value
associated with the underlying physical transactions or in other derivatives.
When derivative positions are closed out in advance of the underlying
commitment or anticipated transaction, however, the market value changes may
not offset due to the fact that price movement correlation ceases to exist when
the positions are closed. Under such circumstances, gains or losses are
deferred and recognized when the underlying commitment or anticipated
transaction was scheduled to occur. Following is certain information concerning
the Company's derivative activities:
85
<PAGE> 89
<TABLE>
<CAPTION>
SWAPS (1)
- --------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Volume Volume Estimated Fair
As Fixed As Fixed Market Value
December 31, Price Payor Price Receiver Gain (Loss) (2)
- --------------------------------------------------------------------------
<S> <C> <C> <C>
1996 126.6 52.9 $ 9.7
1995 211.1 141.2 (5.0)
1994 131.9 114.1 $ (16.7)
- --------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
FUTURES CONTRACTS (3)
- -----------------------------------------------------------------------------------------------
(Volumes in Bcf's, dollars in millions)
Purchased Sold
--------------------------- -------------------------- Estimated Fair
Notional Notional Market Value
December 31, Volume Amount Volume Amount Gain(Loss) (2)
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1996 23.7 $ 64.1 13.6 $ 40.0 $ 0.1
1995 15.1 29.6 8.2 18.9 3.3
1994 6.7 $ 13.8 1.7 $ 2.8 $ (2.9)
- -----------------------------------------------------------------------------------------------
</TABLE>
(1) The financial impact of these swaps was to increase(decrease) earnings by
$(1.0) million, $1.0 million and $2.8 million during 1996, 1995 and 1994,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The
amount which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the
case of certain commitments described preceding, no earnings impact is
expected due to existing accruals. Swaps associated with these commitments
and included in the above totals had fair market values of $2.8 million,
$(1.0) million and $(17.6) million at December 31, 1996, 1995 and 1994,
respectively.
(3) There was no material financial impact from these futures contracts in
1994 and the effect during 1996 and 1995 was to decrease earnings by $9.3
million and $4.1 million, respectively, as futures transactions were
matched with hedged transactions during these periods. At December 31,
1996, the Company had deferred losses of approximately $11.9 million
associated with expected sales under "peaking" contracts with certain
customers which, in effect, give the customer a "call" on certain volumes
of gas. All such losses were recognized in January 1997 when the
anticipated transactions were scheduled to occur.
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 the majority of cases limiting such
transactions to counterparties whose debt securities are rated "A" or better by
recognized rating agencies. For long-term arrangements, the Company
periodically reviews the financial condition of such firms in addition to
monitoring the effectiveness of these financial contracts in achieving the
Company's objectives. Should the counterparties to these arrangements fail to
perform, the Company would seek to compel performance at law or otherwise, or
to obtain compensatory damages in lieu thereof, but the Company might be forced
to acquire alternative hedging arrangements or be required to honor the
underlying commitment at then-current market prices. In such event, the Company
might incur additional loss to the extent of amounts, if any, already paid to
the counterparties. In view of its criteria for selecting counterparties, its
process for monitoring the financial strength of these counterparties and its
experience to date in successfully completing these transactions, the Company
believes that the risk of incurring a significant loss due to the
nonperformance of counterparties to these transactions is minimal.
86
<PAGE> 90
LITIGATION
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the merger between the Company and Houston
Industries (see "Merger With Houston Industries" included in Note 1) or to
rescind such merger and/or to recover damages in the event that the Transaction
is consummated. The complaint alleges, among other things, that the merger
consideration is inadequate, that the Company's Board of Directors breached its
fiduciary duties and that Houston Industries aided and abetted such breaches of
fiduciary duties. In addition, the plaintiff seeks certification as a class
action. The Company believes that the claims are without merit and intends to
vigorously defend against the lawsuit. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of this matter will not be material.
The Company is a party to litigation (other than that specifically
noted) which arises in the normal course of business. Management regularly
analyzes current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
adjacent to the Mississippi River in Minnesota known as the former Minneapolis
Gas Works ("FMGW") until 1960. The Company is working with the Minnesota
Pollution Control Agency to implement an appropriate remediation plan. There
are six other former MGP sites in the Company's Minnesota service territory. Of
the six sites, the Company believes that two were neither owned nor operated by
the Company; two were owned at one time but were operated by others and are
currently owned by others; and one was operated by the Company and is now owned
by others. The Company believes it has no liability with respect to the sites
it neither owned nor operated.
At December 31, 1996, the Company has estimated a range of $10 million
to $170 million for possible remediation of the Minnesota sites. The low end of
the range was determined using only those sites presently owned or known to
have been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned
by the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to
recover amortization of previously deferred and ongoing clean-up costs. Any
amounts in excess of $2.1 million annually were deferred for future recovery.
In its 1995 rate case, Minnegasco asked that the annual allowed recovery be
increased to approximately $7 million and that such costs be subject to a true-
up mechanism whereby any over or under recovered amounts, net of certain
insurance recoveries as described following, plus carrying charges, would be
deferred for recovery or refund in the next rate case. Such accounting was
approved by the Minnesota Public Utilities Commission ("MPUC") and was
implemented effective October 1, 1995. The amount of insurance recoveries to be
flowed back to ratepayers is determined by multiplying insurance recoveries
received by the ratio of total costs incurred to-date as a percentage of the
probable total costs of environmental remediation. At December 31, 1996 and
1995, the Company had under-collected, through rates, net environmental clean-
up costs of $1.4 million and $1.3 million, respectively. In addition, at
December 31, 1996 and 1995, the Company had received insurance proceeds that
will be refunded through rates in the future as clean-up expenditures are made
of $4.3 million and $3.3 million, respectively. At December 31, 1996 and 1995,
the Company had recorded a liability of $35.9 million and $45.2 million,
respectively, to cover the cost of future remediation. In addition, the Company
has receivables from insurance settlements of $5.2 million at December 31,
1996. These insurance settlements will be collected through 1999. The Company
expects that the majority of its accrual as of December 31, 1996 will be
expended within the next five years. In accordance with the provisions of SFAS
71, a regulatory asset has been recorded equal to the liability accrued. The
Company is continuing to pursue
87
<PAGE> 91
recovery of at least a portion of these costs from insurers. The Company
believes the difference between any cash expenditures for these costs and the
amounts recovered in rates during any year will not be material to the
Company's overall cash requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites
in the service territories of the distribution divisions. At the present time,
the Company is aware of some plant sites in addition to the Minnesota sites and
is investigating certain other locations. While the Company's evaluation of
these other MGP sites remains 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 its financial position, results of
operations or cash flows.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company that the Company, through one of its subsidiaries and
together with several other unaffiliated entities, had been named under state
law as a potentially responsible party with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any, of the site. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on its financial position, results of operations or
cash flows.
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
remains in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
At December 31, 1996 and 1995, the Company had recorded an accrual of
$3.3 million (with a maximum estimated exposure of approximately $18 million)
and an offsetting regulatory asset for environmental matters in connection with
a former fire training facility and a landfill for which future remediation may
be required. This accrual is in addition to the accrual for MGP sites as
discussed preceding.
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.
88
<PAGE> 92
REPORT OF INDEPENDENT ACCOUNTANTS
BOARD OF DIRECTORS AND STOCKHOLDERS
NORAM ENERGY CORP.
We have audited the consolidated financial statements and financial statement
schedule of NorAm Energy Corp. and Subsidiaries listed in Item 14(a) of this
Form 10-K. These financial statements and the financial statement schedule are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and the financial statement
schedule 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, 1996 and 1995, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. In addition, in our opinion, the financial
statement schedule referred to above, when considered in relation to the basic
financial statements taken as a whole, presents fairly, in all material
respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 25, 1997
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
Management is responsible for the preparation of the Company's financial
statements and associated data in conformity with generally accepted accounting
principles. Some of the amounts are estimates based on judgment of current
conditions and circumstances.
To provide reasonable assurance that assets are safeguarded against loss
from unauthorized use or disposition and that accounting records are reliable
for preparing financial statements, management maintains a system of internal
accounting and managerial controls, including review of these controls by our
independent accountants and internal audit department who have free access to
the Audit Committee of the Board of Directors composed of non-employee
directors.
Management continues to improve its controls in response to changes in
business conditions and to assure ethical business practices. The independent
accountants have been engaged to examine and express an opinion on the
Company's annual consolidated financial statements.
Management believes that the Company's system of internal accounting and
managerial controls, including policies and procedures, provides reasonable
assurance that in all material respects assets are safeguarded and financial
information is reliable. All information in the annual report is consistent
with the financial statements.
89
<PAGE> 93
QUARTERLY INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
(thousands of dollars) 1996 Quarter Ended
March 31 (1) June 30 Sept. 30 Dec. 31
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 1,417,663 $ 891,325 $ 899,283 $ 1,580,191
=========================================================================================================
Gross profit (2) $ 390,121 $ 206,328 $ 210,784 $ 313,275
=========================================================================================================
Operating income $ 146,582 $ 39,673 $ 18,634 $ 109,577
=========================================================================================================
Income (loss) before extraordinary item $ 61,197 $ 2,335 $ (8,183)$ 39,789
Extraordinary item, less taxes (3) (278) (4,455) 477 (24)
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 60,919 $ (2,120)$ (7,706)$ 39,765
=========================================================================================================
Per Share Data (4)
Primary:
Before extraordinary item $ 0.47 $ 0.01 $ (0.06)$ 0.29
Extraordinary item, less taxes 0.00 (0.04) 0.00 0.00
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.47 $ (0.03)$ (0.06)$ 0.29
=========================================================================================================
Fully Diluted:
Before extraordinary item $ 0.47 $ 0.01 $ (0.04)$ 0.27
Extraordinary item, less taxes 0.00 (0.04) 0.00 0.00
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.47 $ (0.03)$ (0.04)$ 0.27
=========================================================================================================
Weighted average shares outstanding
Primary 124,991 127,006 137,104 137,375
Fully Diluted 124,991 129,195 151,331 151,602
- ---------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------------
(thousands of dollars) 1995 Quarter Ended
March 31 June 30 Sept. 30 Dec. 31
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating revenues $ 888,148 $ 565,842 $ 542,611 $ 968,078
=========================================================================================================
Gross profit (2) $ 346,972 $ 219,129 $ 217,865 $ 323,547
=========================================================================================================
Operating income $ 134,719 $ 27,263 $ 16,119 $ 109,204
=========================================================================================================
Income (loss) before extraordinary item $ 51,996 $ (7,072)$ (14,284)$ 34,889
Extraordinary item, less taxes (3) (52) - - -
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 51,944 $ (7,072)$ (14,284)$ 34,889
Per Share Data (4)
Primary:
Before extraordinary item $ 0.41 $ (0.07)$ (0.13)$ 0.26
Extraordinary item, less taxes 0.00 - - -
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.41 $ (0.07)$ (0.13)$ 0.26
=========================================================================================================
Fully Diluted:
Before extraordinary item $ 0.41 $ (0.07)$ (0.13)$ 0.26
Extraordinary item, less taxes 0.00 - - -
- ---------------------------------------------------------------------------------------------------------
Net income (loss) $ 0.41 $ (0.07)$ (0.13)$ 0.26
=========================================================================================================
Weighted average shares outstanding
Primary 122,960 123,735 124,103 124,654
Fully Diluted 122,960 123,735 124,103 124,654
- ---------------------------------------------------------------------------------------------------------
</TABLE>
(1) Includes a pre-tax charge of $22.3 million associated with early
retirement and severance costs, see Note 1 of the accompanying Notes to
Consolidated Financial Statements.
(2) "Gross profit" is "Operating revenues" less "Cost of natural gas
purchased, net".
(3) Net loss on early retirement of debt less taxes, see Note 3 of the
accompanying Notes to Consolidated Financial Statements.
(4) Income (loss) from continuing operations per common share is reduced for
preferred dividend requirements in periods in which preferred stock was
outstanding. Primary earnings per share is computed using the weighted
average number of the Company's common shares outstanding during each
period. Fully diluted earnings per share, in addition to the weighted
average common shares actually outstanding, includes shares resulting
from the assumed conversion of the Company's Redeemable Preferred
Securities of Subsidiary Trust and the associated earnings increase
which would result from such assumed conversion. See also "Earnings per
Share" included in Note 1 and "Other Long-Term Financing" included in
Note 3 of the accompanying Notes to Consolidated Financial Statements.
90
<PAGE> 94
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 13, 1997, 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 13, 1997, 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 13, 1997 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 caption "Executive Compensation" set
forth in the Company's definitive proxy statement for the Annual Meeting of
Stockholders to be held on May 13, 1997 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
<TABLE>
<CAPTION>
(a)(1) FINANCIAL STATEMENTS Page
----
<S> <C>
Included under Item 8 are the following financial statements:
Statement of Consolidated Income for the years ended December 31, 1996, 1995
and 1994. 59
Consolidated Balance Sheet as of December 31, 1996 and 1995. 60
</TABLE>
91
<PAGE> 95
<TABLE>
<CAPTION>
Page
----
<S> <C>
Statement of Consolidated Stockholders' Equity for the years ended December 31,
1996, 1995 and 1994. 62
Statement of Consolidated Cash Flows for the years ended December 31, 1996, 1995
and 1994. 63
Notes to Consolidated Financial Statements. 64
Report of Independent Accountants. 89
(a)(2) FINANCIAL STATEMENT SCHEDULES
Schedule II - Valuation and Qualifying Accounts 95
</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.
(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.
*2.1 Agreement and Plan of Merger, dated August 11, 1996, as amended
among HI; HL&P; Merger Sub and the Company; incorporated herein
by reference to Appendix A of the Joint Proxy
Statement/Prospectus of HI, HL&P and the Company dated October
29, 1996.
*3.1 Restated Certificate of NorAm Energy Corp., dated May 31, 1995 as
amended, incorporated herein by reference to Exhibit 99.1 to the
Company's Quarterly Report on Form 10-Q for the Quarter ended
June 30, 1996.
*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).
92
<PAGE> 96
*4.4 Form of Indenture between the Company and The Bank of New York,
as trustee, incorporated herein by reference to Exhibit 4.8 to
the Company's Registration Statement on Form S-3 (33-64001)
*4.5 Form of First Supplemental Indenture, between the Company and The
Bank of New York, as trustee, incorporated by reference to
Exhibit 4.01 to the Company's Current Report on Form 8-K dated
June 10, 1996.
*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.
*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 Incentive Equity Plan, incorporated herein by reference to
Appendix B of Proxy Statement, Annual Meeting of Stockholders May
10, 1994.
*10.13 Non-Employee Director Restricted Stock Plan, incorporated here by
reference to Appendix D of Proxy Statement, Annual Meeting of
Stockholders May 10, 1994.
*10.14 Form of Severance Agreement for each of the Chief Executive
Officer and the four most highly compensated executive officers
of the Company (T. Milton Honea, Charles M. Oglesby, Michael B.
Bracy, William A. Kellstrom, Hubert Gentry, Jr.) and for 10 other
executive officers of the Company, incorporated herein by
reference to Exhibit 99.2 to the Company's Quarterly Report on
Form 10-Q for the quarter ended June 30, 1996.
93
<PAGE> 97
12 Computation of Ratio of Earnings to Fixed Charges.
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
(b) REPORTS ON FORM 8-K FILED DURING THE LAST QUARTER OF THE PERIOD
COVERED BY THIS REPORT
None
94
<PAGE> 98
NORAM ENERGY CORP.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
(IN THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
================================================================================================================
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ----------------------------------------------------------------------------------------------------------------
ADDITIONS
-----------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DESCRIPTION OF PERIOD
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Reserves which are deducted in the balance
sheet from assets to which they apply:
(a) Allowance for Doubtful Accounts
Receivable
Year ended December 31, 1996 $ 11,117 $ 12,364 $ 3,189 $ 13,647 $ 13,023
Year ended December 31, 1995 $ 12,604 $ 10,315 $ (470) $ 11,332 $ 11,117
Year ended December 31, 1994 $ 11,296 $ 11,957 $ 1,771 $ 12,420 $ 12,604
(b) Deferred Tax Asset Valuation
Allowance
Year ended December 31, 1996 $ 6,188 $ 573 $ -- $ -- $ 6,761
Year ended December 31, 1995 $ 5,974 $ 214 $ -- $ -- $ 6,188
Year ended December 31, 1994 $ 10,023 $ -- $ -- $ 4,049 $ 5,974
</TABLE>
95
<PAGE> 99
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 27, 1997
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.
Signature Title Date
--------- ----- ----
/s/ T. MILTON HONEA Director March 27, 1997
- -----------------------
(T. Milton Honea)
/s/ MICHAEL B. BRACY Director
- -----------------------
(Michael B. Bracy)
JOE E. CHENOWETH* Director
- -----------------------
(Joe E. Chenoweth)
O. HOLCOMBE CROSSWELL* Director
- -----------------------
(O. Holcombe Crosswell)
WALTER A. DeROECK* Director
- -----------------------
(Walter A. DeRoeck)
96
<PAGE> 100
MICKEY P. FORET* Director
- -----------------------
(Mickey P. Foret)
JOSEPH M. GRANT* Director
- -----------------------
(Joseph M. Grant)
ROBERT C. HANNA* Director
- -----------------------
(Robert C. Hanna)
W. JEFFREY HART* Director
- -----------------------
(W. Jeffrey Hart)
WELDON H. JOHNSON* Director
- -----------------------
(Weldon H. Johnson)
MYRA JONES* Director
- -----------------------
(Myra Jones)
BRUCE W. WILKINSON* Director
- -----------------------
(Bruce W. Wilkinson
*By /s/ T. MILTON HONEA March 27, 1997
---------------------------
(T. Milton Honea
Attorney-in-Fact)
97
<PAGE> 101
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, 1996
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, 32ND FLOOR, HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICE)
(713) 654-5699
(REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE)
EXHIBITS
<PAGE> 102
<TABLE>
<CAPTION>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER DESCRIPTION OF EXHIBITS PAGES
- ------ ----------------------- -----
<S> <C>
* (Asterisk indicates exhibits incorporated by reference herein).
*2.1 Agreement and Plan of Merger, dated August 11, 1996, as amended
among HI; HL&P; Merger Sub and the Company; incorporated herein
by reference to Appendix A of the Joint Proxy Statement/Prospectus
of HI, HL&P and the Company dated October 29, 1996.
*3.1 Restated Certificate of NorAm Energy Corp., dated May 31,
1995 as amended, incorporated herein by reference to Exhibit 99.1
to the Company's Quarterly Report on Form 10-Q for the Quarter
ended June 30, 1996.
*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).
*4.4 Form of Indenture between the Company and The Bank of
New York, as trustee, incorporated herein by reference to Exhibit
4.8 to the Company's Registration Statement on Form S-3 (33-64001).
*4.5 Form of First Supplemental Indenture, between the Company and
The Bank of New York, as trustee, incorporated by reference to
Exhibit 4.01 to the Company's Current Report on Form 8-K
dated June 10, 1996.
*10.1 Copy of Deferred Compensation Agreement incorporated herein by
reference to Exhibit 10.2 to the Company's Annual Report on
Form 10-K for the year 1988.
</TABLE>
<PAGE> 103
<TABLE>
<S> <C>
*10.2 Copy of Deferred Stock Appreciation Agreement incorporated
herein by reference to Exhibit 10.3 to the Company's Annual
Report on Form 10-K for the year 1988.
*10.3 Executive Supplemental Medical Plan (Page 13 of Proxy
Statement, Annual Meeting of Stockholders, May 12, 1987, and
incorporated herein by reference).
*10.4 1982 Nonqualified Stock Option Plan with Appreciation Rights
(Form S-8, Registration No. 2-84830, dated July 1, 1983,
and incorporated herein by reference).
*10.5 Nonqualified Executive Disability Income Plan incorporated
herein by reference to Exhibit 10.6 to the Company's Annual
Report on Form 10-K for the year 1988.
*10.6 Nonqualified Unfunded Executive Supplemental Income
Retirement Plan incorporated herein by reference to the
Company's Annual Report on Form 10-K for the year 1988.
*10.7 Unfunded Nonqualified Retirement Income Plan incorporated
herein by reference to Exhibit 10.10 to the Company's Form
10-K for the year 1985.
*10.8 Annual Incentive Award Plan incorporated herein by reference
as maintained in the files of the Commission, File No. 1-3751.
*10.9 Long-Term Incentive Compensation Plan (Form S-8,
Registration No. 33-10806, dated December 12, 1986, and
incorporated herein by reference).
*10.10 Service Agreement, by and between Mississippi River
Transmission Corporation and Laclede Gas Company,
dated August 22, 1989 incorporated herein by reference
to Exhibit 10.20 to the Company's Annual Report on Form
10-K for the year 1989.
*10.11 Agreement and Plan of Merger, dated as of July 30, 1990,
between NorAm Energy Corp., Diversified Energies,
Inc. and Minnegasco, Inc., incorporated by reference to
Exhibit A to the Company's Registration Statement on
Form S-4 (Reg. No. 33-27428).
*10.12 Incentive Equity Plan, incorporated herein by reference
to Appendix B of Proxy Statement, Annual Meeting of
Stockholders May 10, 1994.
*10.13 Non-Employee Director Restricted Stock Plan, incorporated
herein by reference to Appendix D of Proxy Statement, Annual
meeting of Stockholders May 10, 1994.
</TABLE>
<PAGE> 104
<TABLE>
<S> <C>
*10.14 Form of Severance Agreement for each of the Chief Executive
Officers and the four most highly compensated executive
officers of the Company (T. Milton Honea, Charles M.
Oglesby, Michael B. Bracy, William A. Kellstrom, Hubert
Gentry, Jr.) and for 10 other executive officers of the Company,
incorporated herein by reference to Exhibit 99.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended
June 30, 1996.
12 Computation of Ratio of Earnings to Fixed Charges.
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>
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Income from continuing operations
as set forth in Consolidated
Statement of Income $ 95,138 $ 65,529 $ 51,291 $ 39,935 $ 6,227
Add back:
Provision for income taxes 66,352 55,379 34,372 46,481 12,516
Less:
Non-utility interest capitalized 0 0 0 0 0
---------- ---------- ---------- ---------- ----------
161,490 120,908 85,663 86,416 18,743
---------- ---------- ---------- ---------- ----------
Fixed charges (from continuing
operations):
Interest 130,592 155,584 167,384 169,857 182,453
Amortization of debt discount
and expense 3,582 3,483 3,312 3,421 4,450
Portion of rents considered to
represent an interest factor 10,083 16,215 11,292 10,402 7,704
---------- ---------- ---------- ---------- ----------
Total fixed charges 144,257 175,282 181,988 183,680 194,607
---------- ---------- ---------- ---------- ----------
Earnings $ 305,747 $ 296,190 $ 267,651 $ 270,096 $ 213,350
========== ========== ========== ========== ==========
Ratio of earnings to fixed charges 2.12 1.69 1.47 1.47 1.10
========== ========== ========== ========== ==========
Interest Expense Reconciliation:
Interest expense above $ 130,592 $ 155,584 $ 167,384 $ 169,857 $ 182,453
Amort. of Debt Disc. & Exp. 3,582 3,483 3,312 3,421 4,450
AFUDC (1,617) (1,108) (1,331) (871) (1,675)
---------- ---------- ---------- ---------- ----------
Interest expense per financials $ 132,557 $ 157,959 $ 169,365 $ 172,407 $ 185,228
========== ========== ========== ========== ==========
</TABLE>
<PAGE> 1
EXHIBIT 21
NORAM ENERGY CORP.
DIVISIONS:
Arkla
Entex
Minnegasco
NorAm Trading & Transportation Group
SUBSIDIARIES:
AER - Arkansas Gas Transit Company
Subsidiaries: Blue Jay Gas Company
Raven Gas Company
ALG Gas Supply Company
Subsidiaries: ALG Gas Supply Company of Arkansas
ALG Gas Supply Company of Kansas
ALG Gas Supply Company of Louisiana
ALG Gas Supply Company of Oklahoma
ALG Gas Supply Company of Texas
Allied Materials Corporation
Arkansas Louisiana Finance Corporation
Arkla Finance Corporation
Arkla Industries Inc.
Arkla Products Company
Entex Coal Company
Entex Gas Marketing Company
Entex NGV, Inc.
Entex Oil Company
Entex Oil & Gas Co.
Industrial Gas Supply Corporation
Intex, Inc.
Louisiana Unit Gas Transmission Company
Minnesota Intrastate Pipeline Company
Mississippi River Transmission Corporation
Subsidiaries: MRT Services Company
National Furnace Company
NorAm Consumer Services, Inc.
NorAm Damage Prevention, Inc.
NorAm Energy Management, Inc.
NorAm Energy Services, Inc.
NorAm Field Services Corp.
NorAm Financing I (Trust)
NorAm Funds Management, Inc.
NorAm Gas Processing Company
NorAm Gas Transmission Company
NorAm Hub Services Inc.
NorAm Latin America, Inc.
Subsidiary: NorAm De Mexico S.A. de C.V.
NorAm Trading and Transportation Group, Inc.
NorAm Utility Services, Inc.
Unit Gas, Inc.
Unit Gas Transmission Company
United Gas, Inc.
<PAGE> 1
EXHIBIT 23
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration statements of
NorAm Energy Corp. and Subsidiaries (the "Company") on Form S-3 (File Nos.
33-64001, 33-41493, 33-52853 and 33-55071) and Form S-8 (File Nos. 2-61923,
33-10806, 33-20594, 33-38063, 33-38064, 33-54241, 33-54247, and 33-54253) of
our report dated March 25, 1997 on our audits of the consolidated financial
statements and financial statement schedule of the Company as of December 31,
1996 and 1995, and for the years ended December 31, 1996, 1995, and 1994, which
report is included in this Annual Report on Form 10-K.
COOPERS & LYBRAND L.L.P.
Houston, Texas
March 27, 1997
<PAGE> 1
EXHIBIT 24
POWER OF ATTORNEY
WHEREAS, NORAM ENERGY CORP., a Delaware corporation, (the "Company")
intends to file with the Securities and Exchange Commission its Annual Report
on Form 10-K pursuant to Section 13 or 15(d) of the Securities Exchange Act of
1934 for fiscal year ended December 31, 1996 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 14th day of March, 1997.
/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, 1996 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 14th day of March, 1997.
/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, 1996 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 14th day of March, 1997.
/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, 1996 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 14th day of March, 1997.
/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, 1996 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 14th day of March, 1997.
/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, 1996 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 14th day of March, 1997.
/s/ Joseph M. Grant
-------------------------
<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, 1996 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 14th day of March, 1997.
/s/ Robert C. Hanna
-------------------------
<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, 1996 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 14th day of March, 1997.
/s/ W. Jeffrey Hart
----------------------------
<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, 1996 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 14th day of March, 1997.
/s/ T. Milton Honea
---------------------------------
<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, 1996 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 14th day of March, 1997.
/s/ Myra Jones
----------------------------
<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, 1996 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 14th day of March, 1997.
/s/ Weldon H. Johnson
---------------------------
<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, 1996 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 14th day of March, 1997.
/s/ Bruce W. Wilkinson
----------------------------
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<FISCAL-YEAR-END> DEC-31-1996
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