<PAGE>   1
 
================================================================================
 
                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
 
                                   FORM 10-K
 
<TABLE>
<C>               <S>
   (MARK ONE)
      [X]         ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                  THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
                                      OR
      [ ]         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                  THE SECURITIES EXCHANGE ACT OF 1934
                  FOR THE TRANSITION PERIOD FROM          TO
</TABLE>
 
                         COMMISSION FILE NUMBER 1-3187
 
                        HOUSTON INDUSTRIES INCORPORATED
             (Exact name of registrant as specified in its charter)
 
<TABLE>
<S>                                                               <C>
                           TEXAS
     (State or other jurisdiction of incorporation or                                     74-0694415
                        organization)                                       (I.R.S. employer identification number)
                      1111 LOUISIANA
                   HOUSTON, TEXAS 77002                                                 (713) 207-3000
   (Address and zip code of principal executive offices)             (Registrant's telephone number, including area code)
</TABLE>
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
<TABLE>
<S>                                                               <C>
                    TITLE OF EACH CLASS                                    NAME OF EACH EXCHANGE ON WHICH REGISTERED
             Common Stock, without par value,                                       New York Stock Exchange
    and associated rights to purchase preference stock                              Chicago Stock Exchange
               7% Automatic Common Exchange                                         New York Stock Exchange
                Securities due July 1, 2000
             HL&P Capital Trust I 8.125% Trust
              Preferred Securities, Series A                                        New York Stock Exchange
</TABLE>
 
  SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Preferred Stock,
                        cumulative, no par -- $4 series
 
                         COMMISSION FILE NUMBER 1-13265
 
                               NORAM ENERGY CORP.
             (Exact name of registrant as specified in its charter)
 
<TABLE>
<S>                                                               <C>
                         DELAWARE
     (State or other jurisdiction of incorporation or                                     76-0511406
                        organization)                                       (I.R.S. employer identification number)
                      1111 LOUISIANA
                   HOUSTON, TEXAS 77002                                                 (713) 207-3000
   (Address and zip code of principal executive offices)             (Registrant's telephone number, including area code)
</TABLE>
 
          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
 
<TABLE>
<S>                                                               <C>
                    TITLE OF EACH CLASS                                    NAME OF EACH EXCHANGE ON WHICH REGISTERED
                 NorAm Financing I 6 1/4%                                           New York Stock Exchange
     Convertible Trust Originated Preferred Securities
      6% Convertible Subordinated Debentures due 2012                               New York Stock Exchange
</TABLE>
 
        SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
 
    NORAM ENERGY CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION
I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K WITH THE
REDUCED DISCLOSURE FORMAT.
 
    Indicate by check mark whether each of the registrants: (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 reports), 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 is not contained herein, and will not be contained, to the
best of each of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
 
    The aggregate market value of the voting stock held by non-affiliates of
Houston Industries Incorporated was $7,598,982,925 as of March 2, 1998, using
the definition of beneficial ownership contained in Rule 13d-3 promulgated
pursuant to the Securities Exchange Act of 1934 and excluding shares held by
directors and executive officers. As of March 2, 1998, Houston Industries
Incorporated had 295,698,228 shares of Common Stock outstanding, including
12,138,551 ESOP shares not deemed outstanding for financial statement purposes.
Excluded from the number of shares of Common Stock outstanding are 98,866 shares
held by Houston Industries Incorporated as treasury stock. As of March 2, 1998,
all 1,000 outstanding shares of NorAm Energy Corp.'s Common Stock were held by
Houston Industries Incorporated.
 
    Portions of the definitive proxy statement relating to the 1998 Annual
Meeting of Shareholders of Houston Industries Incorporated, which will be filed
within 120 days of December 31, 1997, are incorporated by reference in Item 10,
Item 11, Item 12 and Item 13 of Part III of this Form 10-K.
================================================================================
<PAGE>   2
 
     THIS COMBINED ANNUAL REPORT ON FORM 10-K IS SEPARATELY FILED BY HOUSTON
INDUSTRIES INCORPORATED (COMPANY) AND NORAM ENERGY CORP. (NORAM). INFORMATION
CONTAINED HEREIN RELATING TO NORAM IS FILED BY THE COMPANY AND SEPARATELY BY
NORAM ON ITS OWN BEHALF. NORAM MAKES NO REPRESENTATION AS TO INFORMATION
RELATING TO THE COMPANY (EXCEPT AS IT MAY RELATE TO NORAM AND ITS SUBSIDIARIES),
HOUSTON INDUSTRIES ENERGY, INC., HOUSTON INDUSTRIES POWER GENERATION, INC. OR
ANY OTHER AFFILIATE OR SUBSIDIARY OF THE COMPANY.
 
                        HOUSTON INDUSTRIES INCORPORATED
                                      AND
                               NORAM ENERGY CORP.
                 FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1997
 
                               TABLE OF CONTENTS
 
<TABLE>
<CAPTION>
                                                                          PAGE NO.
                                                                          --------
<S>         <C>                                                           <C>
PART I
Item 1.     Business....................................................      1
Item 2.     Properties..................................................     22
Item 3.     Legal Proceedings...........................................     23
Item 4.     Submission of Matters to a Vote of Security Holders.........     24
PART II
Item 5.     Market for the Company's Common Equity and Related
            Stockholder Matters.........................................     25
Item 6.     Selected Financial Data of the Company......................     26
            COMPANY
            Item 7. Management's Discussion and Analysis of Financial
            Condition and Results of Operations of the Company..........     28
            Item 7A. Quantitative and Qualitative Disclosures About
            Market Risk.................................................     50
            Item 8. Financial Statements and Supplementary Data of the
            Company.....................................................     53
            NORAM
            Item 7. Management's Narrative Analysis of the Results of
            Operations
            of NorAm Energy Corp. and Consolidated Subsidiaries.........    101
            Item 7A. Quantitative and Qualitative Disclosure About
            Market Risk.................................................     50
            Item 8. Financial Statements and Supplementary Data of
            NorAm.......................................................    109
Item 9.     Changes in and Disagreements with Accountants on Accounting
            and Financial Disclosure....................................    141
PART III
Item 10.    Directors and Executive Officers of the Company and NorAm...    141
Item 11.    Executive Compensation......................................    141
Item 12.    Security Ownership of Certain Beneficial Owners and
            Management..................................................    141
Item 13.    Certain Relationships and Related Transactions..............    141
PART IV
Item 14.    Exhibits, Financial Statement Schedules and Reports on Form
            8-K.........................................................    142
</TABLE>
 
                                       (i)
<PAGE>   3
 
                                     PART I
 
ITEM 1. BUSINESS.
 
     Houston Industries Incorporated (Company) is a diversified international
energy services company. Its Houston Lighting & Power Company division is an
electric utility serving approximately 1.6 million customers in the City of
Houston, Texas, and surrounding areas on the Texas Gulf Coast. NorAm Energy
Corp., the Company's largest subsidiary (NorAm), is a natural gas utility
serving over 2.8 million customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas. NorAm, through its subsidiaries, is also a
major interstate natural gas pipeline company and a provider of energy marketing
services.
 
     The Company's other principal subsidiaries include Houston Industries
Energy, Inc. (HI Energy), which participates in the privatization of foreign
generating and distribution facilities and the development and acquisition of
foreign independent power projects, and Houston Industries Power Generation,
Inc. (HIPG), which participates in the acquisition, development and operation of
domestic non-rate regulated power generation facilities.
 
     The Company acquired NorAm in August 1997 in a transaction (Merger)
involving the merger of the Company's former parent corporation, Houston
Industries Incorporated (Former HI), into the Company, and the merger of NorAm's
predecessor corporation (Former NorAm) into a newly formed subsidiary of Former
HI. As a result of the Merger, the Company's operating activities include the
following segments: Electric Operations, Natural Gas Distribution, Interstate
Pipeline, Energy Marketing, International and Corporate. Information regarding
these segments is set forth in "Management's Discussion and Analysis of
Financial Condition and Results of Operations of the Company -- Results of
Operations by Business Segment" and Note 15 to the Company's Consolidated
Financial Statements, which note is incorporated herein by reference. NorAm's
principal operating segments include Natural Gas Distribution, Interstate
Pipeline and Energy Marketing.
 
     The Company, subject to certain limited exceptions, is exempt from
regulation as a public utility holding company pursuant to Section 3(a)(2) of
the Public Utility Holding Company Act of 1935, as amended (1935 Act). For
additional information regarding the Company's status under the 1935 Act, see
"-- Regulation -- Public Utility Holding Company Act."
 
     The Company, incorporated in 1906, is a Texas corporation. NorAm,
incorporated in 1996, is a Delaware corporation. The executive offices of the
Company and NorAm are located at Houston Industries Plaza, 1111 Louisiana,
Houston, Texas 77002 (telephone number: 713-207-3000).
 
CERTAIN FACTORS AFFECTING THE ENERGY SERVICES INDUSTRY
 
     Various factors are currently affecting the energy services industry,
including increasing levels of competition, legislative and regulatory changes,
stringent environmental regulations, contingencies associated with nuclear plant
ownership, and diversification into businesses outside of traditional
rate-regulated utility operations. The effects of these and other factors on the
business and operations of Company and its subsidiaries are described in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Certain Factors Affecting Future Earnings of the
Company and its Subsidiaries."
 
FORWARD-LOOKING STATEMENTS
 
     Statements contained in this Form 10-K that are not historical facts are
forward-looking statements as defined in the Private Securities Litigation
Reform Act of 1995. Forward-looking statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. Because such statements are based on assumptions as to future
economic performance and are not statements of fact, actual results may differ
materially from those projected. Important factors that could cause future
results to differ include (i) the effects of competition in the electric power
and natural gas industries, (ii) legislative and regulatory changes, (iii)
fluctuations in the weather, (iv) fluctuations in energy commodity
 
                                        1
<PAGE>   4
 
prices, (v) environmental liabilities, (vi) changes in the economy and (vii)
other factors discussed in this and other filings by the Company and NorAm with
the Securities and Exchange Commission. When used in the Company's or NorAm's
documents or oral presentations, the words "anticipate," "estimate," "expect,"
"intend," "objective," "projection," "forecast," "goal" or similar words are
intended to identify forward-looking statements.
 
     The following sections of this Form 10-K contain forward-looking
statements: "Business -- Electric Operations -- System Capability,"
"Business -- Electric Operations -- Capital Expenditures," "Business -- Electric
Operations -- Fuel," "Business -- Energy Marketing -- Energy Marketing and Risk
Management -- Electric Power Marketing," "Business -- International,"
"Business -- Corporate," "Business -- Regulation" and "Business -- Environmental
Matters" in Item 1 of the Form 10-K; "Legal Proceedings" in Item 3 of this Form
10-K; "Management's Discussion and Analysis of Financial Condition and Results
of Operations of the Company -- Results of Operations by Business
Segment -- Energy Marketing," "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- Results of Operations by
Business Segment -- Corporate," "Management's Discussion and Analysis of
Financial Condition and Results of Operations of the Company -- Certain Factors
Affecting Future Earnings of the Company and its Subsidiaries," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Liquidity and Capital Resources -- Company
Consolidated Capital Requirements" in Item 7 of this Form 10-K and "Quantitative
and Qualitative Disclosures about Market Risk" in Item 7A of this Form 10-K.
 
                              ELECTRIC OPERATIONS
 
     The Company generates, purchases, transmits and distributes electricity to
approximately 1.6 million residential, commercial and industrial customers in a
5,000 square-mile service area on the Texas Gulf Coast, including the City of
Houston, Texas, the nation's fourth largest city. The Company's electric utility
operations are conducted through an unincorporated division of the Company known
as "Houston Lighting & Power Company" or "HL&P" (HL&P). All references in this
Form 10-K to "Electric Operations" refer to the electric utility operations
conducted by HL&P. Electric Operations does not include the development,
acquisition and operation of independent power generation facilities by HIPG.
These activities are discussed in "Corporate" below.
 
     For the year ended December 31, 1997, Electric Operations represented
approximately 62% of the Company's total consolidated revenues and 93% of its
operating income. For additional financial and operating data regarding Electric
Operations, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations of the Company -- Results of Operations by Business
Segment -- Electric Operations" and Note 15 to the Company's Consolidated
Financial Statements, which information is incorporated herein by reference.
 
     All projections and other forward looking data set forth under "Electric
Operations," including projections regarding System Capability and Capital
Expenditures, assume the continued existence of a cost-based regulatory system.
 
SERVICE AREA
 
     Houston's economy is centered primarily on energy sector industries, such
as oil companies, petrochemical and refining complexes, industrial and
petrochemical construction firms and natural gas distribution and processing
centers. During the year ended December 31, 1997, energy sector industries
accounted for approximately 34% of Electric Operations' industrial electric base
revenues and 8% of its total electric base revenues. Other important sectors of
Houston's economy include the Port of Houston, the Johnson Space Center and the
Texas Medical Center.
 
     The Company is a member of the Electric Reliability Council of Texas, Inc.
(ERCOT) and is interconnected to a transmission grid encompassing most of the
State of Texas.
 
                                        2
<PAGE>   5
 
ELECTRIC UTILITY ASSETS
 
     All of the electric generating stations and other operating properties used
in the business of Electric Operations are located in the State of Texas.
 
     The Company owns and operates (i)12 electric generating stations with a
combined turbine nameplate rating of 13,554,608 kilowatts (KW) and (ii) 213
major substations having a total installed rated transformer capacity of 59,407
megavolts (Mva). The Company is also one of four co-owners of the South Texas
Project Electric Generating Station (South Texas Project), a nuclear generating
plant consisting of two 1,250 megawatt (MW) nuclear generating units in which
the Company has a 30.8% ownership interest. For additional information regarding
the assets used in Electric Operations' business, see "Properties" in Item 2 of
this Report.
 
SYSTEM CAPABILITY
 
     The following table sets forth information regarding the system capability
of Electric Operations:
 
<TABLE>
<CAPTION>
                                                                  MAXIMUM HOURLY FIRM DEMAND
                       INSTALLED                                -------------------------------
                          NET        PURCHASED    TOTAL NET                           % CHANGE     RESERVE
                       CAPABILITY      POWER      CAPABILITY                            FROM       MARGIN
        YEAR              (MW)        (MW)(1)        (MW)        DATE      MW(2)     PRIOR YEAR      (%)
        ----           ----------    ---------    ----------    -------    ------    ----------    -------
<S>                    <C>           <C>          <C>           <C>        <C>       <C>           <C>
1993.................    13,679         945         14,624      Aug. 19    11,336        5.1        29.0
1994.................    13,666         720         14,386      Jun. 28    11,126       (1.9)       29.3
1995.................    13,921         445         14,366      Jul. 27    11,452        2.9        25.4
1996.................    13,960         445         14,405      Jul. 23    11,694        2.1        23.2
1997.................    14,040         445         14,485      Aug. 21    12,194        4.3        18.1
</TABLE>
 
---------------
 
(1) Reflects firm capacity purchased. For additional information on purchased
    power commitments, see "-- Fuel -- Purchased Power" below.
 
(2) Excludes loads on interruptible service tariffs, residential direct load
    control and commercial/industrial load cooperative capability. Including
    these loads, the maximum hourly demand served in 1997 was 13,407 MW compared
    to 12,667 MW in 1996.
 
     Based on present trends, the Company estimates that the maximum hourly firm
demand for electricity in the service area of Electric Operations will grow at a
compound annual rate of approximately 1.6% over the next ten years. Assuming
average weather conditions and including the net effects of demand-side
management programs, the Company projects that the reserve margin of Electric
Operations will decrease to an estimated 15% by 2001. For long-term planning
purposes, the Company intends to maintain the reserve margin for Electric
Operations at approximately 15% in excess of maximum hourly firm demand load
requirements.
 
     Electric Operations experiences significant seasonal variation in its sales
of electricity. Sales during the summer months are higher than sales during
other months of the year due to the reliance on air conditioning in the service
territory of Electric Operations.
 
CAPITAL EXPENDITURES
 
     The Company has an ongoing program to maintain the existing production,
transmission and distribution facilities of Electric Operations and to expand
its physical plant in response to customer needs. Assuming a target reserve
margin of 15%, the Company does not currently forecast a need for additional
capacity until 2002.
 
                                        3
<PAGE>   6
 
     In 1997, Electric Operations' capital expenditures were approximately $234
million, excluding Allowance for Funds Used During Construction (AFUDC).
Electric Operations' capital program (excluding AFUDC) is currently estimated to
be approximately $331 million in 1998, $343 million in 1999 and $308 million in
2000. These expenditures relate primarily to improvements to Electric
Operations' existing electric generating, distribution and general plant
facilities. For the three-year period ending December 31, 2000, the aggregate
capital program for Electric Operations is estimated to be:
 
<TABLE>
<CAPTION>
                                                               AMOUNT      PERCENT OF TOTAL
                                                             (MILLIONS)      EXPENDITURES
                                                             ----------    ----------------
<S>                                                          <C>           <C>
Generating facilities......................................     $207              21%
Transmission facilities....................................       34               4%
Distribution facilities....................................      443              45%
Substation facilities......................................       65               7%
General plant facilities...................................      161              16%
Nuclear fuel...............................................       72               7%
                                                                ----             ---
          Total............................................     $982             100%
                                                                ====             ===
</TABLE>
 
     Actual capital expenditures will vary from estimates as a result of
numerous factors, including, but not limited to, changes in the rate of
inflation, availability and relative cost of fuels and purchased power, changes
in environmental laws, regulatory and legislative changes and the effect of
regulatory proceedings. For information regarding expenditures associated with
nuclear fuel costs and environmental programs, see "-- Fuel -- Nuclear Fuel
Supply" and "-- Environmental Matters" below.
 
     Under the Public Utility Regulatory Act of 1995 (PURA) and the integrated
resource planning rules adopted in 1996 by the Public Utility Commission of
Texas (Texas Utility Commission), Texas electric utilities are required to
conduct public solicitations for all resources (e.g., generating capacity,
demand-side management programs, etc.) to satisfy future capacity needs. In May
1998, Electric Operations will file a preliminary integrated resource plan as
required under the rules.
 
FUEL
 
     Based upon current assumptions regarding fuel (cost and availability),
plant operation schedules, load growth, load management and environmental
protection requirements, the projected future energy mix to be used by Electric
Operations in the generation of electricity is as follows:
 
<TABLE>
<CAPTION>
                                                                    ENERGY MIX (%)
                                                              --------------------------
                                                                             ESTIMATED
                                                              HISTORICAL    ------------
                                                                 1997       1998    2001
                                                              ----------    ----    ----
<S>                                                           <C>           <C>     <C>
Gas.........................................................      30         30      29
Coal and Lignite............................................      41         42      43
Nuclear.....................................................       9          8       8
Purchased Power.............................................      20         20      20
                                                                 ---        ---     ---
          Total.............................................     100        100     100
                                                                 ===        ===     ===
</TABLE>
 
     For information regarding current and historical fuel costs, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Results of Operations by Business
Segment -- Electric Operations -- Fuel and Purchased Power Expense" in Item 7 of
this Report, which information is incorporated herein by reference.
 
     Natural Gas Supply. During 1997, Electric Operations purchased
approximately 46% of its natural gas requirements pursuant to long-term
contracts with two suppliers (Midcon Texas Pipeline Company and Tejas Gas
Corporation). Electric Operations purchased an additional 23% of its natural gas
requirements under long-term contracts with other suppliers, and the remaining
31% of natural gas requirements on the spot
 
                                        4
<PAGE>   7
 
market. Substantially all of Electric Operations' natural gas contracts contain
pricing provisions based on fluctuating spot market prices.
 
     Based on the current market for and availability of natural gas, the
Company believes that Electric Operations will be able to replace the supplies
of natural gas covered under any expiring long-term contracts with (i) gas
purchased on the spot market or (ii) under long-term or short-term contracts.
The average daily gas consumption of Electric Operations during 1997 was 601
billion British thermal units (BBtu) with peak daily consumption of 1,349 BBtu.
Electric Operations' average cost of natural gas was $2.60 per million British
thermal units (MMBtu) in 1997, $2.31 per MMBtu in 1996 and $1.69 per MMBtu in
1995.
 
     Although natural gas has been relatively plentiful in recent years,
available supplies are vulnerable to disruption due to weather conditions,
transportation constraints and other events. As a result of these factors,
supplies of natural gas may become unavailable from time to time, or prices may
increase rapidly in response to temporary supply constraints or other factors.
 
     Coal and Lignite Supply. Electric Operations purchases approximately 80% of
the coal required to operate its four coal-fired units at the W. A. Parish
Electric Generating Station (W. A. Parish) under two long-term contracts from
mines in the Powder River Basin area of Wyoming. The first of these contracts
expires in 2010, and the other expires in 2011. Electric Operations obtains the
remaining coal required to operate these units under short-term contracts. The
majority of the coal purchased for W. A. Parish is currently transported under
an existing long-term rail transportation contract with Burlington Northern
Santa Fe Railroad. In 1997, Electric Operations completed construction of a
10-mile rail line to connect its W. A. Parish coal-handling facilities to Union
Pacific Railroad Company. During 1997 and 1998, Union Pacific Railroad Company
experienced significant delays in completing shipments of materials in and
through the City of Houston. To date, these delays have not had a material
adverse impact on Electric Operations' generation capability or its financial
results of operations. However, delays in rail shipments have reduced Electric
Operations' coal inventories below customary levels.
 
     Electric Operations obtains the lignite used to fuel the two units of its
Limestone Electric Generating Station (Limestone) from a surface mine adjacent
to the plant. The Company owns the mining equipment, facilities and a portion of
the lignite reserves. The lignite reserves currently under lease and contract
are expected to be sufficient to provide substantially all of the lignite
requirements for Limestone through 2013.
 
     Nuclear Fuel Supply. Fuel supply requirements for the South Texas Project
consist of (i) the acquisition of uranium concentrates, (ii) the conversion of
such concentrates into uranium hexafluoride, (iii) the enrichment of uranium
hexafluoride and (iv) the fabrication of nuclear fuel assemblies. The South
Texas Project has contracted for the raw materials and services necessary to
operate the plant through at least the following years:
 
<TABLE>
<CAPTION>
 
<S>                                                           <C>
Uranium.....................................................  2002(1)
Conversion..................................................  2002
Enrichment..................................................  2014(2)
Fabrication.................................................  2005
</TABLE>
 
---------------
 
(1) Contracts provide for over 50% of the uranium concentrates required. The
    balance of uranium concentrates requirements is expected to be provided by
    future spot and medium-term contracts.
 
(2) The South Texas Project has suspended its enrichment services contract for
    the period between October 2000 and September 2007 pursuant to an option
    available under such contract. During this period, the Company understands
    that the South Texas Project intends to obtain enrichment services through a
    competitive bidding process. At present, the South Texas Project has
    obtained competitive bids and is finalizing contracts for enrichment
    services through 2004.
 
     Although the Company and the other South Texas Project owners cannot
predict the future availability of uranium and related services, it is not
anticipated, based on current market conditions, that the South Texas Project
will have difficulty in obtaining fuel requirements for its remaining years of
operation. For information
 
                                        5
<PAGE>   8
 
regarding assessments for spent fuel disposal, decontamination and
decommissioning costs, see Note 4 to the Company's Consolidated Financial
Statements.
 
     Purchased Power. At December 31, 1997, Electric Operations had contracts
covering 445 MW of firm capacity and associated energy. These contracts expire
as follows: 1998 -- 125 MW and 2005 -- 320 MW. Capacity payments under firm
purchased power commitments for the next three years are approximately $22
million per year. For additional information, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations of the
Company -- Results of Operations by Business Segment -- Electric
Operations -- Fuel and Purchased Power Expense" and Note 12(b) to the Company's
Consolidated Financial Statements.
 
     Recovery of Fuel Costs. Texas Utility Commission rules provide for the
recovery of certain fuel and purchased power energy costs through a fixed fuel
factor included in electric rates. For information on recovery of fuel costs,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Results of Operations by Business
Segment -- Electric Operations -- Operating Revenues." The Company's two
principal firm capacity contracts (covering 320 MW of firm capacity) contain
provisions allowing Electric Operations to suspend or reduce purchased power
payments in the event that the Texas Utility Commission disallows future
recovery of these costs through Electric Operations' rates for electric service.
 
COMPETITION AND REGULATORY MATTERS
 
     The electric utility industry historically has been composed of vertically
integrated companies providing electric service on an exclusive basis within
governmentally defined geographic areas. Prices for electric service typically
have been set by governmental authorities under principles designed to provide
the utility with an opportunity to recover its cost of providing electric
service plus a reasonable return on its invested capital. In recent years,
federal legislation as well as legislative and regulatory initiatives in various
states have encouraged competition among electric utility and non-utility owned
power generators. These developments, combined with increasing demand for
lower-priced electricity and technological advances in electric generation, are
accelerating the electric utility industry's movement toward more competition.
These issues, as they affect the Company, including without limitation, the
Company's ability to recover its existing investment in certain electric utility
facilities, are discussed in "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- Certain Factors Affecting
Future Earnings of the Company and its Subsidiaries -- Competition -- Electric
Operations," which section is incorporated herein by reference.
 
     For information regarding regulatory matters affecting Electric Operations,
see "-- Regulation -- Public Utility Holding Company Act",
"-- Regulation -- State and Local Utility Regulations -- Electric Operations,"
"-- Regulation -- Nuclear Regulatory Commission," "-- Environmental Matters"
below, "Management's Discussion and Analysis of Financial Condition and Results
of Operations of the Company -- Certain Factors Affecting Future Earnings of the
Company and its Subsidiaries -- Rate Proceedings -- Electric Operations" and
Note 3 to the Company's Consolidated Financial Statements.
 
                                        6
<PAGE>   9
 
OPERATING STATISTICS OF ELECTRIC OPERATIONS
 
<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31,
                                                              ------------------------------------
                                                                 1997         1996         1995
                                                              ----------   ----------   ----------
<S>                                                           <C>          <C>          <C>
Electric Energy Generated and Purchased (Megawatt-Hours
  (MWH)):
  Generated -- Net Station Output...........................  56,066,845   55,170,841   53,447,128
  Purchased.................................................  14,008,452   12,540,172   10,452,818
  Net Interchange...........................................         841        1,486       (1,488)
                                                              ----------   ----------   ----------
         Total..............................................  70,076,138   67,712,499   63,898,458
  Company Use, Lost and Unaccounted for Energy..............  (3,075,143)  (3,350,400)  (2,822,876)
                                                              ----------   ----------   ----------
         Total Energy Sold..................................  67,000,995   64,362,099   61,075,582
                                                              ==========   ==========   ==========
Electric Sales (MWH):
  Residential...............................................  19,365,892   19,048,238   18,103,209
  Commercial................................................  15,474,761   14,640,762   14,233,413
  Small Industrial(1).......................................  11,439,753   11,727,500   11,174,404
  Large Industrial(1).......................................  14,380,499   13,519,845   12,493,029
  Street Lighting -- Government and Municipal...............     127,761      119,339      117,253
                                                              ----------   ----------   ----------
         Total Firm Retail Sales............................  60,788,666   59,055,684   56,121,308
  Other Electric Utilities..................................     190,878      205,463      169,750
                                                              ----------   ----------   ----------
         Total Firm Sales...................................  60,979,544   59,261,147   56,291,058
  Interruptible.............................................   4,278,458    4,038,277    4,093,385
  Off-System................................................   1,742,993    1,062,675      691,139
                                                              ----------   ----------   ----------
         Total..............................................  67,000,995   64,362,099   61,075,582
                                                              ==========   ==========   ==========
Number of Customers (End of Period):(2)
  Residential...............................................   1,378,658    1,353,631    1,327,168
  Commercial................................................     190,437      185,031      175,998
  Small Industrial(1).......................................       1,526        1,692        1,543
  Large Industrial (Including Interruptible)(1).............         132          126          127
  Street Lighting -- Government and Municipal...............          86           83           82
  Other Electric Utilities (Including Off-System)...........          20           15           11
                                                              ----------   ----------   ----------
         Total..............................................   1,570,859    1,540,578    1,504,929
                                                              ==========   ==========   ==========
Operating Revenue (Thousands of Dollars):
  Residential...............................................  $1,662,177   $1,603,591   $1,471,702
  Commercial................................................   1,065,917      986,591      923,223
  Small Industrial(1).......................................     616,419      611,495      564,609
  Large Industrial(1).......................................     529,718      473,451      431,499
  Street Lighting -- Government and Municipal...............      24,868       22,125       20,679
                                                              ----------   ----------   ----------
         Total Electric Revenue -- Firm Retail Sales........   3,899,099    3,697,253    3,411,712
  Other Electric Utilities..................................      11,330       18,841       22,207
                                                              ----------   ----------   ----------
         Total Electric Revenue -- Firm Sales...............   3,910,429    3,716,094    3,433,919
  Interruptible.............................................     108,053       97,164       81,707
  Off-System................................................      36,798       25,995       12,250
                                                              ----------   ----------   ----------
         Total Electric Revenue.............................   4,055,280    3,839,253    3,527,876
  Miscellaneous Electric Revenues...........................     195,963      185,774      152,421
                                                              ----------   ----------   ----------
         Total..............................................  $4,251,243   $4,025,027   $3,680,297
                                                              ==========   ==========   ==========
Installed Net Generating Capability (Kilowatts (KW)) (End of
  Period)...................................................  14,040,370   13,960,370   13,921,370
Cost of Fuel (Cents per MMBtu):
  Gas.......................................................       259.9        231.3        168.5
  Coal......................................................       201.8        210.8        202.5
  Lignite...................................................       108.4        111.1        124.8
  Nuclear...................................................        54.2         61.6         58.2
         Average............................................       186.8        181.6        159.3
</TABLE>
 
---------------
 
(1) For reporting purposes, customers of Electric Operations with an electric
    demand in excess of 600 kilovolt-amperes are classified as industrial. Small
    industrial customers typically are retail stores, office buildings,
    universities and other customers not associated with large industrial
    plants.
 
(2) In 1996, the Company began calculating the number of customers based on the
    number of active customers at month-end (as opposed to the number of billing
    transactions). This change had the effect of increasing the number of
    customers (primarily commercial) reported in 1996 by approximately 4,400.
    Prior periods have not been restated.
 
                                        7
<PAGE>   10
 
                            NATURAL GAS DISTRIBUTION
 
     NorAm, through its natural gas distribution division (Natural Gas
Distribution), purchases, transports, stores and distributes natural gas and
provides natural gas utility services to over 2.8 million residential,
commercial and industrial customers in six states, including the metropolitan
areas of Minneapolis, Minnesota; Houston, Texas; Little Rock, Arkansas; and
Shreveport, Louisiana.
 
     Financial and operating data regarding Natural Gas Distribution are
discussed in "Management's Discussion and Analysis of Financial Condition and
Results of Operations of the Company -- Results of Operations by Business
Segment -- Natural Gas Distribution," in Note 15 to the Company's Consolidated
Financial Statements, in NorAm's "Management's Narrative Analysis of the Results
of Operations -- Results of Operations by Business Unit -- Natural Gas
Distribution" and in Note 9 to NorAm's Consolidated Financial Statements, which
information is incorporated herein by reference.
 
LOCAL DISTRIBUTION DIVISIONS
 
     The natural gas utility operations of NorAm are conducted through three of
its unincorporated divisions: Arkla, Entex and Minnegasco.
 
     Arkla. Arkla provides natural gas distribution services in approximately
621 communities in the States of Arkansas, Louisiana, Oklahoma and Texas. The
largest metropolitan areas served by Arkla are Little Rock, Arkansas and
Shreveport, Louisiana. In 1997, approximately 72% of Arkla's total throughput
was composed of retail sales of gas and approximately 28% was attributable to
transportation services. Sales to residential and commercial customers in 1997
accounted for approximately 91% of Arkla's total gas revenues and 64% of natural
gas volumes sold or transported.
 
     Entex. Entex provides natural gas distribution services in approximately
502 communities in the States of Louisiana, Mississippi and Texas. The largest
metropolitan area served by Entex is Houston, Texas. In 1997, approximately 97%
of Entex's total throughput was composed of retail sales of gas and
approximately 3% was attributable to transportation services. Sales to
residential and commercial customers in 1997 accounted for approximately 83% of
Entex's total gas revenues and 81% of natural gas volumes sold.
 
     Minnegasco. Minnegasco provides natural gas distribution services in
approximately 243 communities in the State of Minnesota. The largest
metropolitan area served by Minnegasco is Minneapolis, Minnesota. In 1997,
approximately 98% of Minnegasco's total throughput was composed of retail sales
of gas and approximately 2% was attributable to transportation services. Sales
to residential and commercial customers in 1997 accounted for approximately 89%
of Minnegasco's total gas revenues and 87% of natural gas volumes sold.
 
     The demand for natural gas distribution services is seasonal in nature. In
1997, approximately 67%, 70% and 54%, respectively, of Arkla's, Minnegasco's and
Entex's revenues were reported in the months of January, February, March,
November and December. In each case, these patterns reflect the higher demand
for natural gas for use in heating during winter months.
 
SUPPLY AND TRANSPORTATION
 
     Arkla. In 1997, Arkla purchased approximately 13% of its natural gas supply
from a NorAm subsidiary, NorAm Energy Services, Inc. (NES), 17% pursuant to
third party contracts and 70% on the spot market. Arkla transports its natural
gas supplies by interstate and intrastate pipelines under long-term contracts
with terms varying from five to sixteen years.
 
     Entex. In 1997, Entex purchased approximately 80% of its natural gas supply
pursuant to term contracts (having terms varying from one to five years) and 20%
on the spot market. During 1997, Entex's major natural gas suppliers were Enron
Corp. (29.4%), Tejas Gas Corporation (29.0%), Cokinos Natural Gas Company Inc.
(9.1%) and Midcon Texas Pipeline Company (7.6%). Entex transports its natural
gas supplies on both interstate and intrastate pipelines under long-term
contracts with terms varying from one to five years.
 
                                        8
<PAGE>   11
 
     Minnegasco. In 1997, Minnegasco purchased approximately 73% of its natural
gas supply pursuant to term contracts (having terms varying from one to ten
years) with 17 different suppliers and 27% on the spot market. Most of the
natural gas volumes under long-term contracts are committed under terms
providing for delivery during the winter heating season, November through March.
During 1997, Minnegasco purchased approximately 50% of its natural gas
requirements from three suppliers, Pan-Alberta Gas Ltd., TransCanada Gas
Services Inc. and NES. Minnegasco transports its natural gas supplies on various
interstate pipelines under long-term contracts with terms varying from five to
ten years.
 
     Each of Arkla and Minnegasco makes use of various leased and owned natural
gas storage facilities to meet peak-day requirements and to manage the daily
changes in demand due to changes in weather. Contracted supplies and storage for
Minnegasco are also supplemented from time to time with stored liquefied natural
gas and propane-air plant production.
 
     Although natural gas supplies have been relatively plentiful in recent
years, available supplies are vulnerable to disruption due to weather
conditions, transportation constraints and other events. As a result of these
factors, supplies of natural gas may become unavailable from time to time or
prices may increase rapidly in response to temporary supply constraints or other
factors.
 
CAPITAL EXPENDITURES
 
     For information regarding Natural Gas Distribution's historical and
projected capital expenditures, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations of the Company -- Liquidity and
Capital Resources -- Company Consolidated Capital Requirements."
 
COMPETITION AND REGULATORY MATTERS
 
     For information regarding the impact of competition on Natural Gas
Distribution, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations of the Company -- Certain Factors Affecting Future
Earnings of the Company and its Subsidiaries -- Competition -- Other
Operations," which section is incorporated herein by reference.
 
     For information regarding regulatory matters affecting Natural Gas
Distribution, see " -- Regulation -- State and Local Utility
Regulations -- Natural Gas Distribution Operations" and " -- Environmental
Matters" below.
 
                              INTERSTATE PIPELINE
 
     NorAm's interstate natural gas pipeline business is conducted through two
wholly-owned subsidiaries of NorAm, NorAm Gas Transmission Company (NGT) and
Mississippi River Transmission Corporation (MRT). The business and operations of
NGT and MRT are collectively referred to in this Form 10-K as "Interstate
Pipeline."
 
     Financial and operating data regarding Interstate Pipeline are discussed in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Results of Operations by Business
Segment -- Interstate Pipeline," in Note 15 to the Company's Consolidated
Financial Statements and in "Management's Narrative Analysis of the Results of
Operations of NorAm -- Results of Operations by Business Unit -- Interstate
Pipeline" and in Note 9 to NorAm's Consolidated Financial Statements, which
information is incorporated herein by reference.
 
     Interstate Pipeline owns and operates approximately 8,200 miles of
transmission lines and six natural gas storage facilities located across the
following eight states in the south-central United States: Arkansas, Kansas,
Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas. Interstate
Pipeline transports and delivers natural gas on behalf of various shippers
primarily to utilities, industrial customers, and third party pipeline
interconnects.
 
     In 1997, approximately 41% of Interstate Pipeline's total operating
revenues was attributable to services provided by NGT and MRT to Arkla,
approximately 13% of its operating revenues was attributable to services
                                        9
<PAGE>   12
 
provided by MRT to Laclede Gas Company (Laclede), a local distribution company
that provides natural gas utility service to the greater St. Louis metropolitan
area in Illinois and Missouri, and approximately 9% was attributable to gas
marketed by NES to other parties. Interstate Pipeline provides service to Arkla
and Laclede under several long-term firm storage and transportation agreements.
The expiration dates for the service agreements with Laclede range from October
1999 through May 2000. These agreements are currently under negotiation for
renewal. The service agreement with Arkla is for a term of five and one-half
years and is scheduled to expire in March 2002.
 
     The business and operations of Interstate Pipeline are affected by seasonal
changes in the demand for natural gas, the relative price of natural gas in the
Mid-Continent and Gulf Coast Natural Gas supply regions and, to a lesser extent,
general economic conditions.
 
CAPITAL EXPENDITURES
 
     For information regarding Interstate Pipeline's historical and projected
capital expenditures, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- Liquidity and Capital
Resources -- Company Consolidated Capital Requirements."
 
COMPETITION AND REGULATORY MATTERS
 
     For information regarding the impact of competition on Interstate
Pipeline's operations, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- Certain Factors Affecting
Future Earnings of the Company and Its Subsidiaries -- Competition -- Other
Operations," which section is incorporated herein by reference.
 
     Interstate Pipeline is subject to regulation by the Federal Energy
Regulatory Commission (FERC). For information regarding regulatory matters
affecting Interstate Pipeline, see " -- Regulation -- Federal Energy Regulatory
Commission" below.
 
                                ENERGY MARKETING
 
     NorAm's Energy Marketing and Gathering division (Energy Marketing) markets
natural gas and electric power and provides price risk management services to
various energy sector customers. In addition, the division provides natural gas
gathering services and retail energy marketing services. The division's energy
marketing and risk management services are conducted by NES. The division's
natural gas gathering operations are conducted by NorAm Field Services Corp.
(NFS), and its retail energy marketing services are conducted by NorAm Energy
Management, Inc. (NEM).
 
     Financial and operating data regarding Energy Marketing are discussed in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Results of Operations by Business Segment -- Energy
Marketing," in Note 15 to the Company's Consolidated Financial Statements and in
"Management's Narrative Analysis of the Results of Operations of
NorAm -- Results of Operations by Business Unit -- Energy Marketing" and in Note
9 to NorAm's Consolidated Financial Statements, which information is
incorporated herein by reference.
 
ENERGY MARKETING AND RISK MANAGEMENT
 
     NES, a wholly owned subsidiary of NorAm, supplies, markets and trades
natural gas and electricity. In addition, it offers physical and financial
wholesale energy marketing products and services to a variety of customers,
including natural gas distribution companies, municipalities, power plants,
marketers, aggregators and large volume industrial customers. The operations of
NES are not subject to traditional cost of service rate regulation.
 
     Natural Gas Marketing. NES' natural gas marketing activities consist of
contracting to buy specified volumes of natural gas from suppliers at various
points of receipt to be supplied over a specified period of time; aggregating
natural gas supplies and arranging for their transportation; negotiating the
sale of specific volumes
 
                                       10
<PAGE>   13
 
of natural gas over a specified period of time; and matching natural gas
receipts and deliveries based on volumes required by customers.
 
     NES purchases natural gas from a variety of suppliers under daily, monthly,
variable load and base load and term contracts that include either market
sensitive or fixed pricing provisions. NES sells natural gas under sales
agreements that have varying terms and conditions intended to match seasonal and
other changes in demand. In 1997, NES sold 958 Bcf of natural gas, substantially
all of which sales were to non-affiliates.
 
     NES also enters into various short-term and long-term firm and
interruptible agreements for natural gas storage in order to offer peak delivery
services to satisfy winter heating and summer electric generating demands. Such
services are also intended to provide an additional level of performance
security and backup services to NES' customers.
 
     NES from time to time arranges for the transportation of the natural gas it
markets from the supplier receipt point to the delivery point requested by the
purchasers. Transportation arrangements are made with affiliated and
non-affiliated interstate and intrastate pipelines through a variety of means,
including short-term and long-term firm and interruptible agreements with
pipelines. NES generally retains title to the natural gas it transports from the
receipt point to the delivery point.
 
     Electric Power Marketing. NES sold over 25 million megawatt-hours of
electric power in 1997 and 2.7 million megawatt-hours of electric power in 1996.
NES sells electric power primarily to electric utilities and other marketing
companies. NES intends to participate in the California power market upon the
deregulation of wholesale and retail electric power sales in such state, which
is anticipated to occur in the spring of 1998. NES will seek to supply natural
gas to, and purchase electricity for resale from, non-regulated power plants in
the California market, including generating plants to be developed, acquired or
operated by HIPG.
 
     Price Risk Management. In 1997, NES invested in personnel, software and
trading systems in order to expand its capacity to trade in fixed-price forward
purchase and sales contracts (involving the physical delivery of energy
commodities), swap agreements, futures and option contracts traded on securities
and commodities exchanges and in the over-the-counter financial markets.
 
     NES uses derivative financial instruments to manage and hedge its
fixed-price purchase and sale commitments, to provide fixed-price commitments as
a service to its customers and suppliers, to reduce its exposure relative to the
volatility of the cash market prices and to protect its investment in storage
inventories. Although NES generally attempts to balance its fixed-price physical
and financial purchase and sale obligations, commodity price exposure often
exists or is created due to the origination of new transactions and the
assessment of, and response to, changing market conditions. NES is accordingly
exposed in such transactions to the risk that fluctuating market prices may
adversely affect its, the Company's and NorAm's financial position or results of
operations. For additional information with respect to the Company's and NorAm's
financial exposure to derivative financial instruments, see Item 7A of this Form
10-K, Note 2 to the Company's Consolidated Financial Statements and Note 2 to
NorAm's Consolidated Financial Statements.
 
     In addition to the risk associated with price movements, credit risk is
also inherent in NES' risk management activities. Credit risk relates to the
risk of loss resulting from the nonperformance of contractual obligations by a
counterparty. NES maintains credit policies intended to minimize overall credit
risk with regard to its counterparties.
 
     The Company has established a Risk Oversight Committee to oversee all
corporate price and credit risks, including NES' risk management and trading
activities. The Risk Oversight Committee's responsibilities include reviewing
the Company's and its subsidiaries' overall risk management strategy and
monitoring risk management activities to ensure compliance with the Company's
risk management limitations, policies and procedures. For additional information
regarding risk management accounting policies, see Note 2 to the Company's
Consolidated Financial Statements and Note 2 to NorAm's Consolidated Financial
Statements.
 
                                       11
<PAGE>   14
 
NATURAL GAS GATHERING
 
     NFS, a wholly owned subsidiary of NorAm, provides natural gas gathering
services, including related liquids extraction and marketing activities. NFS
operates approximately 4,000 miles of gathering pipelines which collect natural
gas from more than 200 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas. NFS is not subject to traditional
cost-of-service regulation.
 
RETAIL ENERGY MARKETING
 
     NEM, a wholly owned subsidiary of NorAm, markets natural gas and related
energy services to industrial customers served by large local distribution
companies and connected to interstate and intrastate pipelines offering
unbundled transportation services. Included in NEM's retail marketing operations
are three intrastate pipeline subsidiaries of NorAm that market and deliver
natural gas to large volume customers at market-based rates.
 
CAPITAL EXPENDITURES
 
     For information regarding Energy Marketing's capital expenditures, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Liquidity and Capital Resources -- Company
Consolidated Capital Requirements."
 
COMPETITION AND REGULATORY MATTERS
 
     For information regarding the impact of competition on Energy Marketing's
operations, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations of the Company -- Certain Factors Affecting Future
Earnings of the Company and its Subsidiaries -- Competition -- Other
Operations," which section is incorporated herein by reference.
 
     For information regarding regulatory matters affecting Energy Marketing,
see "-- Regulation -- Federal Energy Regulatory Commission" below.
 
                                 INTERNATIONAL
 
     The Company's international operations (International) are conducted
through HI Energy, a subsidiary of the Company that participates in the
privatization of foreign generating and distribution facilities and the
development and acquisition of foreign independent power projects. International
includes the international operations of NorAm, which are managed by HI Energy.
 
     As of December 31, 1997, the Company's Consolidated Balance Sheets
reflected $803 million of foreign investments, a substantial portion of which
represent equity investments in foreign utility companies. Financial and
operating data regarding International are discussed in "Management's Discussion
and Analysis of Financial Condition and Results of Operations of the
Company -- Results of Operations by Business Segment -- International" and Notes
5 and 15 to the Company's Consolidated Financial Statements, which information
is incorporated herein by reference. The international operations of NorAm were
not material to NorAm's 1997 results of operations.
 
     For a discussion of certain risks associated with overseas operations, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations of the Company -- Certain Factors Affecting Future Earnings of the
Company and its Subsidiaries -- Risks of Overseas Operations."
 
MAJOR FOREIGN INVESTMENTS
 
     Argentina. As of December 31, 1997, approximately 26% of International's
foreign investments were located in Argentina. HI Energy owns, through its
subsidiaries, interests in two Argentine electric distribution companies and a
100% ownership interest in a 160-MW cogeneration facility. The electric
distribution company investments consist of (i) a 63% ownership interest in the
electric utility company serving La Plata, Argentina and (ii) a 90% ownership
interest in an electric utility in north-central Argentina (EDESE).
                                       12
<PAGE>   15
 
     A subsidiary of HI Energy had expected to complete development of the
160-MW cogeneration facility in late 1997 at an estimated cost of $100 million.
The commercial operation date for the project has been significantly delayed
because of major damage to the turbine blade during pre-operational testing.
Based on the representations by the project contractor as to the projected
completion date for repairs, it is not anticipated that such delay will have a
material adverse financial impact on HI Energy or the Company.
 
     Brazil. As of December 31, 1997, approximately 52% of International's
foreign investments were located in Brazil. In May 1996, a subsidiary of HI
Energy acquired 11.35% of the common stock of Light -- Servicos de Eletricidade
S.A., a publicly held Brazilian corporation (Light) for $393 million (which
includes the direct costs of the acquisition) in a government-sponsored auction
of 60% of Light's outstanding shares. Light is the operator of an integrated
electric power and distribution system that serves a portion of the state of Rio
de Janeiro, Brazil, including the City of Rio de Janeiro. The winning bidders in
the government-sponsored auction of Light, including a subsidiary of HI Energy,
formed a consortium whose aggregate ownership interest of 50.44% represents a
controlling interest in Light. In November 1997, another subsidiary of HI Energy
purchased approximately $7 million of Light shares (less than 1% of outstanding
Light shares) on the open market.
 
     Colombia. As of December 31, 1997, approximately 20% of International's
foreign investments were located in Colombia. In June 1997, a consortium of
investors which included a subsidiary of HI Energy acquired for $496 million a
56.7% controlling ownership interest in Empresa de Energia del Pacifico
S.A.E.S.P., (EPSA) an electric utility system serving the Valle de Cauca region
of Colombia, including the area surrounding the City of Cali. EPSA was the first
electric distribution system to be privatized by the Colombian government. HI
Energy contributed $152 million of the purchase price for a 28% ownership
interest in EPSA. In addition to its distribution facilities, EPSA owns 850 MW
of electric generation capacity. HI Energy's co-investor in this project is
Electricidad de Caracas, the electric utility serving Caracas, Venezuela.
 
     In February 1997, a subsidiary of NorAm acquired interests in four natural
gas distribution concessions in Colombia. As of December 31, 1997, aggregate
expenditures incurred with respect to these concessions were approximately $3
million. Based on current projections, total additional expenditures for these
systems over the next four years are estimated to be approximately $11 million.
 
     Mexico and India. In January 1998, a subsidiary of NorAm and a local
investor accepted an award of a 30-year concession from the Mexican government
to build, operate and maintain a natural gas distribution system in northeastern
Mexico. Based on current projections, International will invest approximately
$18 million in the project through 2002.
 
     In 1998, a subsidiary of HI Energy, together with various other investors,
expects to complete development of a coke calcining and power generation
facility in India. Based on current projections, it is estimated that
International's total investment in this project through 1998 will be
approximately $11 million.
 
CAPITAL EXPENDITURES
 
     For information regarding International's capital expenditures, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Company Consolidated Capital
Requirements."
 
COMPETITION AND REGULATION
 
     For information regarding the impact of competition on International's
operations, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations of the Company -- Certain Factors Affecting Future
Earnings of the Company and Its Subsidiaries -- Competition -- Other
Operations," which section is incorporated herein by reference.
 
     For information regarding regulatory matters affecting International, see
"-- Regulation -- Public Utility Holding Company Act -- Regulation of Foreign
Utility Company Investments."
 
                                       13
<PAGE>   16
 
                                   CORPORATE
 
     Corporate. The Company's corporate business segment (Corporate) includes
(i) the operations of HIPG, which is engaged in the acquisition, development and
operation of domestic non-rate regulated power generation facilities; (ii)
various office buildings and other real estate used in the Company's and its
subsidiaries' business operations; (iii) corporate costs, and (iv) inter-unit
eliminations. Corporate also includes the Company's retail marketing operations,
which offer energy products and services to customers in and outside the
Company's and NorAm's regulated service areas.
 
     HIPG was formed in March 1997 to pursue the acquisition, development and
operation of domestic non-rate regulated power generation facilities. Since its
formation, HIPG has participated in a number of bid processes involving electric
utility generation plants. In November 1997, HIPG was awarded the right to
purchase four generating stations (2,276 MW of generating capacity) located in
southern California for $237 million. The closing of this acquisition is
anticipated to occur in the spring of 1998, subject to the commencement of
operations of the California Independent System Operator and Power Exchange for
the California market.
 
     HIPG is participating in the development of several non-rate regulated
power generation facilities, including among others, (i) a 480 MW gas-fired
power plant located in Boulder City, Nevada (El Dorado Project), which is being
developed jointly by HIPG and the parent company of San Diego Gas & Electric
Co., and (ii) a 100 MW cogeneration plant located in southeast Texas. Upon
completion of construction and subject to the successful negotiation of various
project development agreements, it is expected that the output of these projects
will be sold on the wholesale market. Based on current projections, it is
anticipated that HIPG will spend in connection with these facilities
approximately $59.4 million in 1998 and an additional $26.2 million in 1999.
 
     HIPG intends to evaluate and possibly participate in a wide range of
non-rate regulated power generation projects. In February 1998, HIPG made an
offer, subject to completion of due diligence and the satisfaction of certain
other conditions, to purchase another independent power generation facility. If
HIPG elects to pursue the offer, the project is expected to result in additional
expenditures during 1998 of approximately $43 million.
 
     The Company believes HIPG's efforts to develop or acquire generation assets
will complement the Company's other operations, including the trading and
marketing activities of NES. For example, it is currently anticipated that NES
will supply approximately 50% of the gas requirements of the El Dorado Project
and will purchase approximately 50% of the electric output of the project for
resale and that NES will manage the fuel procurement and power trading and
marketing for the generating assets to be acquired by HIPG in southern
California.
 
                                       14
<PAGE>   17
 
                                   REGULATION
 
     The Company and NorAm and their respective subsidiaries are subject to
regulation by various federal, state, local and, in the case of HI Energy,
foreign governmental agencies, including those regulations described below.
 
PUBLIC UTILITY HOLDING COMPANY ACT
 
     Holding Company Status. The Company is both a holding company and an
electric utility as defined in the 1935 Act; however, it is exempt from
regulation as a holding company based upon an order granted in July 1997 by the
Securities and Exchange Commission (SEC) under Section 3(a)(2) of the 1935 Act.
Although NorAm is a natural gas utility company as defined under the 1935 Act,
it is not a holding company within the meaning of the 1935 Act. The Company and
NorAm remain subject to regulation under the 1935 Act with respect to the
acquisition of certain voting securities of other domestic public utility
companies and utility holding companies.
 
     Regulation of Investments in Exempt Wholesale Power Generation
Facilities. Companies, like HIPG, which own facilities used exclusively for the
generation of electricity for sale at wholesale are not deemed electric utility
companies under the 1935 Act, provided certain conditions are met.
 
     Regulation of Foreign Utility Company Investments. Section 33(a)(1) of the
1935 Act exempts foreign utility company affiliates of the Company and NorAm
from regulation as "public utility companies," thereby permitting the Company
and NorAm to invest in foreign utility companies without registration under the
1935 Act as a holding company. The exemption, however, is subject to the SEC's
having received from each state commission having jurisdiction over the retail
rates of any electric or gas utility company affiliated with the Company or
NorAm, a certification to the effect that such commission has the authority and
resources to protect ratepayers subject to its jurisdiction and that such
commission intends to exercise its authority. The Texas Utility Commission and
the state regulatory commissions exercising jurisdiction over NorAm (Arkansas,
Louisiana, Minnesota, Mississippi, Oklahoma and Texas) have provided such a
certification to the SEC subject, however, to the right of such commissions to
revise or withdraw their certifications as to any future acquisition of a
foreign utility company.
 
     Subject to certain limited exceptions, Section 33(f)(1) of the 1935 Act
also prohibits any public utility (such as the Company or NorAm) from issuing
any security for the purpose of financing the acquisition, ownership or
operation of a foreign utility company, or assuming any obligation or liability
with respect to a foreign utility company.
 
     Proposals to Repeal the 1935 Act. Several bills have been introduced in
Congress that would repeal the 1935 Act. Repeal or significant modification to
the 1935 Act could have a significant impact on the Company and the electric
utility industry. At this time, however, the Company is not able to predict the
outcome of bills to repeal the 1935 Act or the outlook for additional
legislation in 1998.
 
FEDERAL ENERGY REGULATORY COMMISSION
 
     The transportation and sale for resale of natural gas in interstate
commerce is subject to regulation by the Federal Energy Regulatory Commission
(FERC) under the Natural Gas Act (NGA) and, to a lesser extent, the Natural Gas
Policy Act of 1978, as amended (NGPA). Interstate transportation and storage
services by interstate pipelines, and the rates charged for such services, are
regulated by the FERC. The FERC also has jurisdiction over, among other things,
the construction of pipeline and related facilities used in the transportation,
storage and sale of natural gas in interstate commerce, including the extension,
expansion or abandonment of such facilities.
 
     NGT and MRT periodically file applications with the FERC for changes in
their rates and charges designed to allow them to recover their costs of
providing service to customers (to the extent allowed by prevailing market
conditions), including a reasonable rate of return. These rates are normally
allowed to become effective after a suspension period, and in certain cases are
subject to refund under applicable law, until such time as FERC issues an order
on the allowable level of rates. NGT is currently operating under
                                       15
<PAGE>   18
 
rates approved by the FERC and effective in February 1995, and MRT is currently
providing services pursuant to a negotiated rate settlement approved by the FERC
in October 1997.
 
     Historically, NGT and MRT, like most other interstate pipelines, operated
primarily as merchants of natural gas. Commencing in 1985, the FERC issued a
series of orders and regulations that significantly altered the business of
transporting and marketing natural gas by fostering competition. Pursuant to
those Orders, NGT and MRT are now primarily engaged in the transportation and
storage of natural gas and no longer serve a bundled merchant function.
 
     The FERC regulates NES under both the NGA and the Federal Power Act. As a
gas marketer, NES makes sales of natural gas in interstate commerce at wholesale
pursuant to a blanket certificate issued by the FERC, but the FERC does not
otherwise regulate the rates, terms or conditions of these gas sales. NES is
deemed to be a "public utility" under the Federal Power Act, and its wholesale
sales of electricity in interstate commerce are subject to a FERC-filed rate
schedule that authorizes NES to make sales at negotiated, market-based rates.
NES market-based rate tariffs are filed with the FERC. The FERC also imposes
certain restrictions on NES' transactions with Electric Operations, including a
prohibition on the receipt of goods or services on a preferential basis. Similar
restrictions apply to transactions between NES and Electric Operations under
PURA.
 
STATE AND LOCAL UTILITY REGULATIONS
 
     Electric Operations. The Company conducts its electric utility operations
under a certificate of convenience and necessity granted by the Texas Utility
Commission. The certificate of convenience and necessity covers the present
service area and facilities of Electric Operations. In addition, the Company
holds non-exclusive franchises to provide electric service within the
incorporated municipalities in the service territory of Electric Operations.
None of these franchises expires before 2007.
 
     Under PURA, the Texas Utility Commission has original jurisdiction over
electric rates and services in unincorporated areas of the State of Texas and in
the incorporated municipalities that have relinquished original jurisdiction.
Original jurisdiction over electric rates and services in the remaining
incorporated municipalities served by Electric Operations is exercised by such
municipalities, including the City of Houston, but the Texas Utility Commission
has appellate jurisdiction over electric rates and services within those
incorporated municipalities. For additional information, including information
about current rate proceedings, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations of the Company -- Certain Factors
Affecting Future Earnings of the Company and its Subsidiaries -- Rate
Proceedings -- Electric Operations" and Note 3 to the Company's Consolidated
Financial Statements.
 
     Natural Gas Distribution Operations. In almost all communities in which
Natural Gas Distribution provides service, NorAm operates under franchises,
certificates or licenses obtained from state and local authorities. The terms of
the franchises, with various expiration dates, typically range from ten to
thirty years. None of Natural Gas Distribution's material franchises expires
before 2005. In most cases, franchises to provide natural gas utility services
are not exclusive.
 
     Substantially all of Natural Gas Distribution's retail sales are subject to
traditional cost-of-service regulation at rates regulated by the relevant state
public service commissions and, in Texas, by municipalities served by Natural
Gas Distribution. None of Natural Gas Distribution's local distribution
companies is currently a party to any pending rate proceeding.
 
     The Oklahoma Corporation Commission recently approved natural gas utility
rules that, if implemented, would require the separation of integrated gas
delivery services, currently provided by natural gas utilities, into individual
components of gas supply, gathering, transmission, distribution and storage
services. The rules would also require gas utilities to buy natural gas through
a competitive bidding process administered by the Oklahoma commission and to set
a time table for implementing retail competition. Final implementation of the
rule is dependent on action by the Oklahoma legislature. The Company and NorAm
are not able at this time to predict the ultimate outcome of this legislation or
the likelihood of adoption of similar proposals by governmental agencies or
legislatures exercising jurisdiction in the service area of Natural Gas
Distribution.
 
                                       16
<PAGE>   19
 
NUCLEAR REGULATORY COMMISSION
 
     Under the 1954 Atomic Energy Act and the 1974 Energy Reorganization Act,
operation of nuclear plants is extensively regulated by the United States
Nuclear Regulatory Commission (NRC), which has broad power to impose licensing
and safety requirements. In the event of non-compliance, NRC has the authority
to impose fines or shut down nuclear plants, or both, depending upon its
assessment of the severity of the situation, until compliance is achieved.
 
     The 1980 Federal Low-Level Radioactive Waste Policy Act directed states to
assume responsibility for the disposal of low-level nuclear waste generated
within their borders. Under this Act, states may combine with other states and
seek consent from the U.S. Congress for regional compacts to construct and
operate low-level nuclear waste sites. Only two sites (the Envirocare facility
in Utah and the Barnwell facility in South Carolina) are currently licensed and
available to the South Texas Project for low-level waste disposal. The South
Texas Project has entered into a contract with the operator of the Barnwell
facility to dispose of all of the South Texas Project's low-level nuclear waste
through December 1998.
 
     The Texas Low-Level Radioactive Waste Disposal Authority (Waste Disposal
Authority) is currently seeking authority to build and operate a low-level waste
disposal facility in Hudspeth County, Texas. A bill that establishes an
interstate compact among Texas, Maine and Vermont has been approved by the U.S.
Senate and is expected to be considered by the House of Representatives in 1998.
Ratification of the compact would limit access to the proposed facility to the
three compact members. Although lack of Congressional action would not prohibit
the Waste Disposal Authority from constructing the site unilaterally, failure to
ratify the compact would result in the loss of contributions from Maine and
Vermont toward the construction of the facility.
 
     The Waste Disposal Authority is authorized to assess a planning and
implementation fee upon waste generators to fund development of the proposed
Texas disposal facility. For the authority's fiscal year commencing in September
1998, the Company's share of this assessment fee is expected to be approximately
$2.5 million. Licensing hearings are currently underway and, subject to receipt
of the license, construction is expected to commence in late 1998. The Waste
Disposal Authority estimates that the Texas site could begin receiving waste in
late 1999. In the event the Barnwell facility stops accepting waste before the
Texas site is opened, the South Texas Project would store its waste in an
interim storage facility located at the nuclear plant. The plant currently has
storage capacity for at least five years of low-level nuclear waste generated by
the project.
 
                             ENVIRONMENTAL MATTERS
 
     The Company and its subsidiaries are subject to a number of federal, state
and local environmental requirements that govern the discharge of emissions into
the air and water and regulate the handling of solid and hazardous waste. The
Company and its subsidiaries have incurred substantial expenditures in the past
to comply with these requirements and anticipate that further expenditures will
be incurred in the future.
 
     Air Quality. A provision of the Federal Clean Air Act (Clean Air Act)
affecting electric power producers is the Acid Rain Program, which is designed
to reduce emissions of sulfur dioxide (SO2) from generating units. The program
requires that after a certain date an electric power producer must have been
granted a regulatory "allowance" for each ton of SO2 emitted from its
facilities. Allowances have been distributed to utilities by the Environmental
Protection Agency (EPA) based on their historical operations. If a utility is
not allocated sufficient allowances to cover its future SO2 emissions, it must
either purchase allowances or reduce its emissions of SO2. The Company believes
it holds sufficient allowances for continued operations of its facilities for
the foreseeable future, including the Phase II (2000 and later) portion of the
Clean Air Act.
 
     Provisions of the Clean Air Act dealing with urban air pollution require
establishing new emission limitations for oxides of nitrogen (NOx) from existing
sources. Initial limitations were established by the Texas Natural Resources
Conservation Commission (TNRCC) applicable to the Company's generating units in
the Houston, Texas area. Implementation of these limitations have been delayed
until 1999. In addition,
                                       17
<PAGE>   20
 
Governor Bush of Texas has proposed that all "grandfathered" emission units
(units constructed prior to permitting requirements) voluntarily secure permits
from the TNRCC and accomplish emission reductions. The Company has voluntarily
committed to seek permits for three such units, and will reduce NOx emissions
from these units accordingly.
 
     Although the Company did not incur additional NOx reduction costs in 1997,
the Company estimates that, based on the new regulations and its voluntary
commitments, it will expend up to $10 million between 1998 and 1999 for NOx
reductions. Current TNRCC analyses indicate that even further NOx reductions
will be required after 1999 to attain the prescribed ozone standard in the
Houston area. However, neither the timing nor the magnitude of possible future
reduction requirements has been identified at this time.
 
     The Ozone Transport Assessment Group (OTAG) was established in 1995. It is
composed of state air directors from 37 states, including some of the states in
which the Company and NorAm have facilities. OTAG is responsible for (i)
evaluation of long-range transport of pollutants related to ozone formation,
which includes NOx, and for (ii) identification of NOx emission reductions
deemed necessary for attainment of the current standard. Based on the results of
the OTAG effort, EPA has issued proposed regulations for State Implementation
Plan (SIP) development to implement NOx reductions in 22 of the 37 states
represented in the OTAG evaluation. The states from which a NOx reduction plan
is proposed to be required by EPA include Missouri and Illinois; however, it is
not anticipated that implementation of these plans would have a material impact
on the Company's or NorAm's facilities.
 
     The Clean Air Act also required a study to determine if additional
regulations are needed to improve visibility in the southwestern United States.
It is not anticipated, however, that this study will require the installation of
additional pollution controls on the Company's and its subsidiaries' generating
units, including the generating units to be acquired by HIPG in the southern
California area, the El Dorado Energy project and HIPG's cogeneration project in
southeast Texas.
 
     The Clean Air Act also requires the EPA to perform a study of the risk to
public health from emissions of toxic air pollutants from power plants, and to
regulate such emissions as necessary. The EPA issued a report to Congress in
February 1998. The report makes no determination as to the need to issue
regulations applicable to the utility industry, but states an intent to make
such a determination at a later but unspecified date. It is, therefore, not
possible to make any determination as to the potential need for additional
controls on emissions from the Company's or NorAm's facilities.
 
     The Company and NorAm have obtained or applied for all necessary permits,
registrations and authorizations necessary for operation of their facilities
under the various federal, state and local statutes regulating the discharge of
pollutants into surface water, and for the handling and disposal of solid
wastes. The expenditures associated with these programs have not been, and are
not expected to be material.
 
     The issue of whether exposure to electric and magnetic fields (EMFs) may
result in adverse health effects or damage to the environment is currently being
debated. EMFs are produced by all devices which carry or use electricity,
including home appliances as well as electric transmission and distribution
lines. Results of studies concerning the effect of EMFs have been inconclusive
and EMFs are not the subject of any regulations affecting the Company or NorAm
or their respective subsidiaries. However, lawsuits have arisen in several
states (including Texas) against electric utilities and others alleging that the
presence or use of electric power transmission and distribution lines has an
adverse effect on health and/or property values.
 
     For a discussion of specific environmental contingencies, projected
expenditures in connection with environmental matters and a quantification of
costs associated with these matters, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations of the Company -- Certain
Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Environmental Expenditures" and Note 8(g) to NorAm's
Consolidated Financial Statements.
 
                                       18
<PAGE>   21
 
                                   EMPLOYEES
 
     As of December 31, 1997, the Company and its subsidiaries had 12,711
full-time employees. The following table sets forth information about the
Company's and NorAm's employees by business segment as of such date:
 
<TABLE>
<S>                                                           <C>
Electric Operations.........................................   6,131
Natural Gas Distribution....................................   5,220
Interstate Pipeline.........................................     600
International...............................................      64
Energy Marketing............................................     318
Corporate...................................................     378
          Total.............................................  12,711
</TABLE>
 
     The number of employees of the Company and its subsidiaries who are
represented by unions or other collective bargaining groups include (i) Electric
Operations, 2,696; (ii) Natural Gas Distribution, 1,538; and (iii) Corporate,
12.
 
                                       19
<PAGE>   22
 
                      EXECUTIVE OFFICERS OF THE COMPANY(1)
                              AS OF MARCH 2, 1998
 
<TABLE>
<CAPTION>
                                       OFFICER
            NAME              AGE(2)    SINCE    BUSINESS EXPERIENCE AND POSITIONS 1993-1998
            ----              ------   -------   --------------------------------------------
<S>                           <C>      <C>       <C>                                           <C>
Don D. Jordan...............    65      1971     Chairman and Chief Executive Officer and      1997-
                                                   Director
                                                 Chairman and Chief Executive Officer and      1997
                                                   Director -- Former HI
                                                 Chairman, Chief Executive Officer and         1996-1997
                                                   President and Director -- Former HI
                                                 Chairman and Chief Executive Officer and      1993-1996
                                                   Director -- Former HI
                                                 Chairman, President and Chief Executive       1993
                                                   Officer and Director -- Former HI
                                                 Chairman and Chief Executive Officer and      1993-1997
                                                   Director -- Former HL&P
R. Steve Letbetter..........    49      1978     President and Chief Operating Officer and     1997-
                                                   Director
                                                 President and Chief Operating Officer and     1997
                                                   Director -- Former HI
                                                 Senior Vice President and Director -- Former  1996-1997
                                                   HI
                                                 Vice President and Director -- Former HI      1995-1996
                                                 Vice President -- Former HI                   1993-1995
                                                 President and Chief Operating                 1993-1997
                                                   Officer -- Former HL&P
                                                 Group Vice President -- Finance and           1993
                                                   Regulatory Relations -- Former HL&P
Lee W. Hogan................    53      1990     Executive Vice President and Director         1997-
                                                 Executive Vice President and Director --      1997
                                                   Former HI
                                                 Senior Vice President and Director -- Former  1996-1997
                                                   HI
                                                 Vice President and Director -- Former HI      1995-1996
                                                 Vice President -- Former HI                   1993-1995
                                                 President and Chief Operating Officer -- HI   1993-1997
                                                   Energy
                                                 Group Vice President -- External Affairs --   1993
                                                   Former HL&P
Hugh Rice Kelly.............    55      1984     Executive Vice President, General Counsel     1997-
                                                 and Corporate Secretary
                                                 Executive Vice President, General Counsel     1997
                                                   and Corporate Secretary -- Former HI
                                                 Senior Vice President, General Counsel and    1994-1997
                                                   Corporate Secretary -- Former HI
                                                 Vice President, General Counsel and           1993-1994
                                                   Corporate Secretary -- Former HI
                                                 Executive Vice President, General Counsel     1997
                                                   and Corporate Secretary -- Former HL&P
                                                 Senior Vice President, General Counsel and    1993-1997
                                                   Corporate Secretary -- Former HL&P
</TABLE>
 
                                       20
<PAGE>   23
 
<TABLE>
<CAPTION>
                                       OFFICER
            NAME              AGE(2)    SINCE    BUSINESS EXPERIENCE AND POSITIONS 1993-1998
            ----              ------   -------   --------------------------------------------
<S>                           <C>      <C>       <C>                                           <C>
Stephen W. Naeve............    50      1988     Executive Vice President and Chief Financial  1997-
                                                   Officer
                                                 Executive Vice President and Chief Financial  1997
                                                   Officer -- Former HI
                                                 Senior Vice President and Chief Financial     1996-1997
                                                   Officer -- Former HI
                                                 Vice President -- Strategic Planning and      1993-1996
                                                   Administration -- Former HI
                                                 Vice President -- Corporate Planning and      1993
                                                   Treasurer -- Former HL&P
Charles M. Oglesby..........    44      1997     Senior Vice President                         1997-
                                                 President -- NorAm Trading and                1995-1997
                                                   Transportation Group, Inc.
                                                 Vice President of Coastal Corporation and     1993-1995
                                                   President and Chief Executive Officer of
                                                   Coastal Gas Services Company
Bruce Gibson................    44      1994     Senior Vice President -- Governmental         1997-
                                                 Affairs
                                                 Senior Vice President -- Governmental         1997
                                                   Affairs -- Former HI
                                                 Vice President -- Government and Regulatory   1996-1997
                                                   Affairs -- Former HI
                                                 Vice President -- Government and Regulatory   1996-1997
                                                   Affairs -- Former HL&P
                                                 Vice President -- Governmental Relations --   1994-1996
                                                   Former HI
                                                 President and CEO, Texas Chamber of Commerce  1994
                                                 Executive Assistant to the Texas Lt.          1993-1994
                                                   Governor
Robert L. Waldrop...........    50      1988     Senior Vice President -- Communications       1997-
                                                 Senior Vice President -- Communications --    1997
                                                   Former HI
                                                 Senior Vice President -- External Affairs --  1996-1997
                                                   Former HL&P
                                                 Senior Vice President -- Marketing and        1996
                                                   Customer Service -- Former HL&P
                                                 Group Vice President -- External Affairs --   1993-1996
                                                   Former HL&P
                                                 Vice President -- Public and Customer         1993
                                                   Relations -- Former HL&P
Mary P. Ricciardello........    42      1993     Vice President and Comptroller                1997-
                                                 Vice President and Comptroller -- Former HI   1996-1997
                                                 Vice President and Comptroller -- Former      1996-1997
                                                   HL&P
                                                 Comptroller -- Former HI                      1993-1996
                                                 Assistant Corporate Secretary and Assistant   1993
                                                   Treasurer -- Former HL&P
</TABLE>
 
---------------
 
(1) Executive officer list includes the Comptroller of the Company and all other
    officers of the Company holding the title of Senior Vice President,
    Executive Vice President and above. On August 6, 1997, the directors and
    officers of Former HI became by operation of the Merger the initial
    directors and officers of the Company and will serve in such capacities
    until their successors are elected and qualify at the annual meeting of the
    shareholders and Board of Directors of the Company on May 6, 1998.
 
(2) At December 31, 1997.
 
                                       21
<PAGE>   24
 
ITEM 2. PROPERTIES.
 
CHARACTER OF OWNERSHIP
 
     The principal properties of the Company, NorAm and their respective
subsidiaries are owned in fee, except that most electric lines and gas mains are
located, pursuant to easements and other rights, in public roads or on land
owned by others.
 
     Substantially all of the real estate, electric distribution system
properties, buildings and franchises owned directly by the Company (excluding
real estate and other properties of subsidiaries of the Company) are subject to
a lien created under a Mortgage and Deed of Trust dated as of November 1, 1944
(as supplemented, Mortgage) between the Company and South Texas Commercial
National Bank of Houston (Chase Bank of Texas, National Association, as
Successor Trustee). The lien of the Mortgage excludes cash, stock in
subsidiaries and certain other assets. Substantially all properties of the
subsidiaries of HI Energy and HIPG that own interests in operating plants are
subject to liens of creditors of the respective subsidiaries.
 
ELECTRIC OPERATIONS
 
     All of the electric generating stations and other operating properties of
Electric Operations are located in the State of Texas.
 
     Electric Generating Stations. As of December 31, 1997, the Company owned 12
electric generating stations (62 generating units) with a combined turbine
nameplate rating of 13,554,608 KW, including a 30.8% interest in one nuclear
generating station (two units) with a combined turbine nameplate rating of
2,623,676 KW.
 
     Substations. As of December 31, 1997, the Company owned 213 major
substations (with capacities of at least 5 megavolt amperes (Mva)) having a
total installed rated transformer capacity of 59,407 Mva (exclusive of spare
transformers), including a 30.8% interest in one major substation with an
installed rated transformer capacity of 3,080 Mva.
 
     Electric Lines -- Overhead. As of December 31, 1997, the Company owned
25,541 pole miles of overhead distribution lines and 3,567 circuit miles of
overhead transmission lines, including 502 circuit miles operated at 69,000
volts, 2,021 circuit miles operated at 138,000 volts and 1,044 circuit miles
operated at 345,000 volts.
 
     Electric Lines -- Underground. As of December 31, 1997, the Company owned
10,198 circuit miles of underground distribution lines and 12.6 circuit miles of
underground transmission lines, including 4.5 circuit miles operated at 69,000
volts and 8.1 circuit miles operated at 138,000 volts.
 
     For additional information regarding the properties of Electric Operations,
see "Business -- Electric Operations -- Electric Utility Assets" in Item 1 of
this Form 10-K.
 
NATURAL GAS DISTRIBUTION
 
     NorAm's approximately 55,000 linear miles of gas distribution mains vary in
size from one-half inch to 24 inches in diameter. Generally, in each of the
cities, towns and rural areas served by Natural Gas Distribution, NorAm 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
NorAm receives gas from its suppliers are owned, operated and maintained by
others, and the distribution facilities of NorAm begin at the outlet of the
measuring equipment. These facilities, including odorizing equipment, are
usually located on the land owned by suppliers and district regulator
installations.
 
INTERSTATE PIPELINE
 
     Interstate Pipeline owns and operates, through NGT and MRT, approximately
8,200 miles of transmission lines and transportation service to various shippers
across eight states in the south-central United States.
 
                                       22
<PAGE>   25
 
Interstate Pipeline also owns and operates six storage fields with a combined
daily deliverability of approximately 1.2 billion cubic feet (BCF) per day and a
combined working gas capacity of approximately 51.8 BCF. Most of Interstate
Pipeline's storage operations are in north Louisiana and Oklahoma.
 
ENERGY MARKETING
 
     Energy Marketing owns and operates gathering pipelines which collect gas
from more than 200 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.
 
INTERNATIONAL
 
     For information regarding the properties of HI Energy, see
"Business -- International" in Item 1 of this Form 10-K.
 
OTHER
 
     For information regarding the properties of Corporate (including HIPG), see
"Business -- Corporate" in Item 1 of this Form 10-K.
 
ITEM 3. LEGAL PROCEEDINGS.
 
     (a) Company and NorAm.
 
          NorAm Merger Lawsuit. In August 1996, a purported NorAm stockholder
     filed a lawsuit, Shaw v. NorAm Energy Corp., et al., in the District Court
     of Harris County, Texas, against NorAm, certain of its officers and
     directors and the Company to enjoin the Merger or to rescind the Merger
     and/or to recover damages in the event that the Merger was consummated. In
     February 1998, the plaintiffs withdrew their lawsuit and the court issued
     an order of non-suit dismissing the litigation.
 
     (b) Company.
 
          Environmental. The Company is a defendant in litigation arising out of
     the environmental remediation of a site in Corpus Christi, Texas. The site
     was operated by third parties as a metals reclaiming operation. Although
     the Company neither operated nor owned the site, certain transformers and
     other equipment originally sold by the Company may have been delivered to
     the site by third parties. The Company and others have remediated the site
     pursuant to a plan approved by appropriate state agencies and a federal
     court. To date, the Company has recovered or has commitments to recover
     from other responsible parties $2.2 million of the more than $3 million it
     has spent on remediation.
 
          In Dumes, et al. v. Company, et al. (filed in December 1991 and
     pending in the U.S. District Court for the Southern District of Texas,
     Corpus Christi Division), landowners near the Corpus Christi site have
     asserted claims that their property has been contaminated as a result of
     the remediation effort and are seeking approximately $70 million in
     compensatory damages, in addition to punitive damages of $51 million. The
     Dumes case is currently scheduled for trial in June 1998. Although the
     ultimate outcome of this case cannot be predicted at this time, the Company
     does not believe that this case will have a material adverse effect on the
     Company's financial condition, liquidity or results of operations.
 
          Notification of PRP Status. In 1992, the EPA (i) identified the
     Company, along with several other parties, as "potentially responsible
     parties" (PRP) under the Comprehensive Environmental Response, Compensation
     and Liability Act (CERCLA) for the costs of cleaning up a site located
     adjacent to one of the Company's transmission lines and (ii) issued an
     administrative order for the remediation of the site. The Company believes
     that the EPA took this action solely on the basis of information indicating
     that the Company in the 1950s acquired record title to a portion of the
     land on which the site is located. The Company does not believe that it now
     or previously has held any ownership interest in the site covered by the
     order and has obtained a judgment to that effect from a court in Galveston
     County, Texas. Based on this judgment and other defenses that the Company
     believes to be meritorious, the Company has elected not to adhere to the
     EPA's administrative order, even though the Company understands that other
     PRPs
 
                                       23
<PAGE>   26
 
     are proceeding with site remediation. To date, neither the EPA nor any
     other PRP has instituted a claim against the Company for any share of the
     remediation costs for the site. However, if the Company was determined to
     be a responsible party, the Company could be jointly and severally liable
     along with the other PRPs for the aggregate remediation costs of the site
     (which the Company currently estimates to be approximately $80 million in
     the aggregate) and could be assessed substantial fines and damage claims.
     Although the ultimate outcome of this matter cannot currently be predicted
     at the time, the Company does not believe that this case will have a
     material adverse effect on the Company's financial condition, liquidity or
     results of operations.
 
          For a description of certain other legal and regulatory proceedings
     affecting the Company, see Notes 3, 5 and 12(h) to the Company's
     Consolidated Financial Statements, which notes are incorporated herein by
     reference.
 
     (c) NorAm.
 
          For a description of certain other legal and regulatory proceedings
     affecting NorAm, see Note 12(h) of the Notes to the Company's Consolidated
     Financial Statements and Note 8 to NorAm's Consolidated Financial
     Statements, which notes are incorporated herein by reference.
 
          Although the ultimate outcome of the foregoing matters cannot
     currently be predicted, the Company and NorAm believe that none of these
     matters will have a material adverse effect on their respective financial
     positions or results of operations.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
 
     None.
 
                                       24
<PAGE>   27
 
                                    PART II
 
ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
 
     The Company's Common Stock, which at March 2, 1998 was held of record by
approximately 89,330 shareholders, is listed on the New York and Chicago Stock
Exchanges (symbol: HOU). All of NorAm's common stock is held by the Company.
 
     The following table sets forth the high and low sales prices of the
Company's Common Stock on the composite tape during the periods indicated, as
reported by The Wall Street Journal, and the dividends declared for such
periods. Dividend payout was $1.50 per share for 1997 and 1996, respectively.
The dividend declared during the fourth quarter of 1997 is payable in March
1998.
 
<TABLE>
<CAPTION>
                                                      MARKET PRICE
                                                     --------------    DIVIDEND DECLARED
                                                     HIGH      LOW         PER SHARE
                                                     -----    -----    -----------------
<S>                                                  <C>      <C>      <C>
1997
First Quarter......................................                         $0.375
  February 25......................................  $23 5/8
  March 21.........................................           $20 5/8
Second Quarter.....................................                         $0.375
  April 18.........................................           $18 7/8
  May 6............................................  $23 5/8
Third Quarter......................................                         $0.375
  August 7.........................................  $22 1/8
  August 28........................................           $20 1/8
Fourth Quarter.....................................                         $0.375
  December 31......................................  $27 1/4
  October 28.......................................           $20 3/4
1996
First Quarter......................................                         $0.375
  January 17.......................................           $21 1/2
  March 15.........................................  $25 5/8
Second Quarter.....................................                         $0.375
  April 19.........................................           $20 1/2
  June 25..........................................  $24 3/4
Third Quarter......................................                         $0.375
  September 5......................................           $21 1/8
  July 1...........................................  $24 3/4
Fourth Quarter.....................................                         $0.375
  December 6.......................................           $20 3/4
  November 11......................................  $24 1/8
</TABLE>
 
     The closing market price of the Company's Common Stock on December 31, 1997
was $26 3/4 per share.
 
     Future dividends will be subject to determination based upon the results of
operations and financial condition of the Company, the Company's future business
prospects, any applicable contractual restrictions and such other factors as the
Company's Board of Directors considers relevant. For information regarding
restrictions on the payment of dividends in the Company's credit agreements, see
Note 8(c) of the Notes to the Company's Consolidated Financial Statements.
 
                                       25
<PAGE>   28
 
ITEM 6. SELECTED FINANCIAL DATA OF THE COMPANY.
 
     The following table sets forth selected financial data with respect to the
Company's consolidated financial condition and results of consolidated
operations and should be read in conjunction with the Company's Consolidated
Financial Statements and the related notes in Item 8 of this Report. Certain
amounts from prior years have been reclassified to conform with the 1997
presentation. Such reclassifications do not affect earnings. On July 6, 1995,
the Company closed the sale of its cable television operations. The operations
of the Company's former cable television subsidiary (KBLCOM) have been accounted
for as discontinued operations.
 
<TABLE>
<CAPTION>
                                                                         YEAR ENDED DECEMBER 31,
                                                   -------------------------------------------------------------------
                                                     1997(1)        1996          1995          1994          1993
                                                   -----------   -----------   -----------   -----------   -----------
                                                            (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S>                                                <C>           <C>           <C>           <C>           <C>
Revenues.........................................  $ 6,873,385   $ 4,095,277   $ 3,729,271   $ 3,752,573   $ 4,083,238
                                                   -----------   -----------   -----------   -----------   -----------
Income from continuing operations before
  cumulative effect of change in accounting(2)...  $   421,110   $   404,944   $   397,400   $   423,985   $   440,531
Gain on sale of cable television subsidiary......                                  708,124
Loss from discontinued operations................                                                (16,524)      (24,495)
Cumulative effect of change in accounting(3).....                                                 (8,200)
Preferred Dividends..............................          162
                                                   -----------   -----------   -----------   -----------   -----------
Net income(2)....................................  $   420,948   $   404,944   $ 1,105,524   $   399,261   $   416,036
                                                   ===========   ===========   ===========   ===========   ===========
Earnings per common share(4):
  Continuing operations before cumulative effect
    of change in accounting(2)...................  $      1.66   $      1.66   $      1.60   $      1.72   $      1.69
  Gain on sale of cable television subsidiary....                                     2.86
  Loss from discontinued operations..............                                                   (.07)         (.09)
  Cumulative effect of change in accounting(3)...                                                   (.03)
                                                   -----------   -----------   -----------   -----------   -----------
Basic Earnings per common share(2)...............  $      1.66   $      1.66   $      4.46   $      1.62   $      1.60
Diluted Earnings per common share(2).............         1.66          1.66          4.46          1.62          1.60
Cash dividends declared per common share(4)(5)...  $      1.50   $      1.50   $      1.50   $      1.50   $     1.875
Dividend pay-out ratio from continuing
  operations.....................................           96%           89%           94%           87%           89%
Return on average common equity(6)...............          9.7%         10.2%         29.5%         12.0%        12.71%
Ratio of earnings from continuing operations to
  fixed charges before cumulative effect of
  change in accounting...........................         2.41          2.76          2.71          2.89          2.78
At year-end:
  Book value per common share(2)(4)..............  $     17.28   $     16.41   $     16.61   $     13.64   $     12.53
  Market price per common share(4)...............  $     26.75   $     22.63   $     24.25   $     17.82   $     23.82
  Market price as a percent of book value(2).....          155%          138%          146%          131%          190%
At year-end:
  Total assets of continuing operations..........  $18,414,555   $12,287,857   $11,819,606   $10,784,095   $10,867,581
  Net assets of discontinued operations..........                                                618,982       487,026
                                                   -----------   -----------   -----------   -----------   -----------
        Total assets.............................  $18,414,555   $12,287,857   $11,819,606   $11,403,077   $11,354,607
                                                   ===========   ===========   ===========   ===========   ===========
  Long-term obligations including current
    maturities -- continuing operations(7).......  $ 5,831,356   $ 3,280,113   $ 3,768,928   $ 3,905,518   $ 3,950,576
  Long-term obligations including current
    maturities included in net assets of
    discontinued operations......................                                                504,580       514,964
  Capitalization from continuing operations:
  Common stock equity............................           46%           53%           50%           44%           43%
  Cumulative preferred stock of HL&P (including
    current maturities)..........................                          2%            5%            7%            7%
  Long-term debt (including current
    maturities)..................................           54%           45%           45%           49%           50%
Capital expenditures:
  Purchase of NorAm, net of cash acquired........  $ 1,422,672
  HL&P electric capital and nuclear fuel
    expenditures (excluding AFUDC)(8)............      234,068   $   314,934   $   296,635   $   412,899   $   329,016
  Natural Gas Distribution.......................       61,078
  Interstate Pipeline............................       16,304
  Energy Marketing...............................       14,365
  International project expenditures and advances
    (excluding capitalized interest).............      223,807       493,179        49,835         7,087        35,796
  HIPG project expenditures......................        3,324
  Corporate (excluding HIPG).....................       20,247        13,446         4,643        13,562         5,295
  Cable television additions and other
    cable-related investments -- discontinued....                                   47,601        84,071        61,856
  Corporate headquarters expenditures (excluding
    capitalized interest)(8).....................                      5,308        89,627        44,250        26,034
</TABLE>
 
                                       26
<PAGE>   29
 
---------------
 
(1) Includes the results of NorAm since its August 1997 acquisition, which was
    accounted for under the purchase method. See Note 1(b) to the Company's
    Consolidated Financial Statements.
 
(2) The Company adopted Statement of Position (SOP) 93-6, "Employers' Accounting
    for Employee Stock Ownership Plans," effective January 1, 1994, which had
    the effect of reducing net income while increasing earnings per share. See
    Note 10(c) to the Company's Consolidated Financial Statements. SOP 93-6 is
    effective only with respect to financial statements for periods after
    January 1, 1994, and no restatement was permitted for prior periods.
 
(3) The 1994 cumulative effect relates to the change in accounting for
    postemployment benefits. See also Note 10(e) to the Company's Consolidated
    Financial Statements.
 
(4) All common share data reflect a two-for-one common stock dividend
    distribution in December 1995. Year ended December 31, 1993 includes five
    quarterly dividends of $.375 per share due to a change in the timing of the
    Company's Board of Directors' declaration of dividends. Dividend payout was
    $1.50 per share for 1993.
 
(6) The return on average common equity for 1995 includes the gain on the sale
    of the Company's cable television subsidiary. The return on average common
    equity excluding the gain was 11.7%.
 
(7) Includes Cumulative Preferred Stock subject to mandatory redemption and
    Company/NorAm obligated mandatorily redeemable preferred securities of
    subsidiary trusts holding solely junior subordinated debentures of
    Company/NorAm.
 
(8) During 1995 and 1996, Electric Operations made payments toward the purchase
    of its corporate headquarters building. Such payments are not reflected in
    the Company's electric capital and nuclear fuel expenditures because they
    are affiliate transactions eliminated upon consolidation.
 
                                       27
<PAGE>   30
 
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS OF THE COMPANY.
 
     The following discussion and analysis should be read in combination with
the Company's consolidated financial statements and notes contained in Item 8 of
this Form 10-K (Company's Consolidated Financial Statements).
 
                        HOUSTON INDUSTRIES INCORPORATED
 
     Houston Industries Incorporated (Company) is a diversified international
energy services company. It operates the nation's tenth largest electric utility
in terms of kilowatt-hour (KWH) sales, and its three natural gas distribution
divisions together form the nation's third largest natural gas distribution
operation in terms of customers served. The Company also invests in
international and domestic electric utility privatizations, gas distribution
projects and the development of unregulated power generation projects. The
Company is also a major interstate natural gas pipeline and energy services
company, providing gas transportation, supply, gathering and storage, and
wholesale natural gas and electric power marketing services.
 
     The Company is exempt from regulation as a public utility holding company
pursuant to Section 3(a)(2) of the Public Utility Holding Company Act of 1935,
as amended (1935 Act), except with respect to the acquisition of certain voting
securities of other domestic public utility companies and utility holding
companies.
 
                       CONSOLIDATED RESULTS OF OPERATIONS
 
     On August 6, 1997, the Company completed its acquisition (Merger) of NorAm
Energy Corp. (NorAm), a natural gas gathering, transmission, marketing and
distribution company. The Merger was accounted for as a purchase; accordingly,
the Company's results of operations for 1997 include NorAm's results of
operations beginning on August 6, 1997 (Acquisition Date).
 
     To enhance comparability between reporting periods, certain information
below is presented on a pro forma basis and reflects the acquisition of NorAm as
if it had occurred at the beginning of the 1996 and 1997 reporting periods
presented. Pro forma purchase-related adjustments include amortization of
goodwill and the revaluation on a preliminary basis of the fair value of certain
NorAm assets and liabilities. The pro forma results of operations are not
necessarily indicative of the combined results of operations that actually would
have occurred had the acquisition occurred on such dates. The Company, however,
believes that the presentation of pro forma data provides a more meaningful
comparative standard for assessing changes in the Company's consolidated
financial condition and results of operations during the years ended December
31, 1997 and 1996, since the pro forma presentation combines a full year of
results of the Company and its acquired NorAm operations.
 
     In general, the Company's 1997 results of operations and prior year pro
forma amounts reflect the effects of the acquisition of NorAm, which include (i)
significant increases in amortization attributable to purchase accounting, (ii)
increases in shares outstanding and interest expense, and (iii) the impact of
revenues and operating expenses attributable to the newly acquired NorAm
business units.
 
                                       28
<PAGE>   31
 
                       CONSOLIDATED RESULTS OF OPERATIONS
 
<TABLE>
<CAPTION>
                                                                               UNAUDITED
                                                   ACTUAL                      PRO FORMA
                                               ---------------              ----------------
                                                TWELVE MONTHS                TWELVE MONTHS
                                                    ENDED                        ENDED
                                                DECEMBER 31,                  DECEMBER 31,
                                               ---------------   PERCENT    ----------------   PERCENT
                                                1997     1996     CHANGE     1997      1996     CHANGE
                                               ------   ------   --------   -------   ------   --------
                                                         (IN MILLIONS, EXCEPT PER SHARE DATA)
<S>                                            <C>      <C>      <C>        <C>       <C>      <C>
Revenues.....................................  $6,873   $4,095      68%     $10,210   $8,884      15%
Operating Expenses...........................   5,809    3,105      87%       8,991    7,612      18%
Operating Income.............................   1,065      990       8%       1,219    1,272      (4%)
Other Expenses, Net(1).......................     437      385      14%         546      595      (8%)
Income Taxes.................................     206      200       3%         234      245      (4%)
Net Income(2)................................     421      405       4%         439      432       2%
Basic Earnings Per Share.....................    1.66     1.66                 1.56     1.48       5%
Diluted Earnings Per Share...................    1.66     1.66                 1.56     1.48       5%
</TABLE>
 
---------------
 
(1)  Includes a $121 million unrealized accounting loss incurred in the fourth
     quarter of 1997 relating to the Company's 7% Automatic Common Exchange
     Securities (ACES). See Note 1(n) to the Company's Consolidated Financial
     Statements.
 
(2)  Includes $37 million of interest income attributable to a tax refund in
     1997.
 
<TABLE>
<CAPTION>
                                                                  ACTUAL
                                                              ---------------
                                                               TWELVE MONTHS
                                                                   ENDED
                                                               DECEMBER 31,
                                                              ---------------   PERCENT
                                                               1996     1995     CHANGE
                                                              ------   ------   --------
<S>                                                           <C>      <C>      <C>
Revenues....................................................  $4,095   $3,729      10%
Operating Expenses..........................................   3,105    2,824      10%
Operating Income............................................     990      905       9%
Other Expenses, Net.........................................     385      308      25%
Income Taxes................................................     200      200
Income from Continuing Operations...........................     405      397       2%
Gain from Discontinued Operations...........................              708
Net Income..................................................     405    1,105     (63%)
Basic Earnings Per Share....................................    1.66     1.60       4%
Diluted Earnings Per Share..................................    1.66     1.60       4%
</TABLE>
 
     1997 Compared to 1996 (Actual). The Company's actual consolidated net
income from continuing operations for 1997 was $421 million ($1.66 per share)
compared to $405 million ($1.66 per share) in 1996. Although income increased by
$16 million, the Company's basic and diluted earnings per share remained the
same due to the issuance of approximately 47.8 million additional shares of the
Company's common stock as a portion of the consideration paid in connection with
the Merger. The Company's income from continuing operations reflects net
non-recurring and other after-tax charges amounting to $42 million in 1997 and
$67 million in 1996. Charges in 1997 included a non-cash, unrealized accounting
loss of $79 million on the ACES, which were issued in July 1997, partially
offset by $37 million of interest income related to a refund of federal income
taxes in 1997. For a discussion of the accounting loss in connection with the
ACES, see "-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Accounting Treatment of ACES." The non-recurring, after-tax
charges in 1996 included a $62 million charge taken in connection with the
settlement of South Texas Project Electric Generating Station (South Texas
Project) litigation claims and a $5 million loss associated with Houston
Industries Energy, Inc.'s (HI Energy) investment in two tire-to-energy plants in
Illinois.
 
                                       29
<PAGE>   32
 
     After adjusting for non-recurring and other charges in both years, income
from continuing operations for 1997 would have been $463 million ($1.83 per
share) compared to $472 million ($1.93 per share) in 1996. The decrease is due
in part to the additional amortization of certain lignite reserves by the
Company's electric operations division (Electric Operations), the amortization
of goodwill recorded upon the Merger and increased interest expense. The
increase in interest on long-term debt and other interest on the Company's
Statements of Consolidated Income reflect both (i) the $1.4 billion indebtedness
incurred by the Company to fund a portion of the cost of the Merger and (ii) the
consolidation of NorAm's existing indebtedness with that of the Company.
Partially offsetting these effects were increased Electric Operations' sales due
to customer growth, improved results at HI Energy and the additional operating
income generated by the new business units acquired in the Merger.
 
     1997 Compared to 1996 (Pro Forma). The Company's pro forma consolidated
earnings for 1997 were $439 million ($1.56 per share) compared with $432 million
($1.48 per share) in 1996.
 
     Excluding the non-recurring and other charges described above, the
Company's 1997 pro forma income from continuing operations would have been $481
million ($1.71 per share) compared to $499 million ($1.71 per share) in 1996.
This decrease in pro forma earnings, as adjusted for non-recurring and other
charges, is principally the result of (i) hedging-related losses incurred in the
first quarter of 1997 (prior to the Merger) by a subsidiary of NorAm, which
losses are not reflected in the Company's actual results of operations since
they were incurred prior to the Merger, (ii) a weather-related decline in sales
volumes from the natural gas distribution segment, and (iii) increased
administrative and general expenses associated with increased staffing and
marketing in connection with increasing the scope of energy marketing
activities.
 
     Pro forma consolidated net income for 1997 and 1996 exceeds actual
consolidated net income for such years because purchase-related costs were more
than offset on a pro forma basis by NorAm's earnings for the periods prior to
the Acquisition Date. Such earnings were not part of the reported actual
results.
 
     1996 Compared to 1995 (Actual). Consolidated income from continuing
operations was $405 million ($1.66 per share) for 1996, compared to income from
continuing operations of $397 million ($1.60 per share) in 1995. The Company's
1995 net income was $1.1 billion ($4.46 per share) including a one-time
after-tax gain of $708 million ($2.86 per share) recorded upon the sale of the
Company's cable television subsidiary.
 
     The Company's net income includes non-recurring, after-tax charges
amounting to $67 million described above in 1996 and $24 million primarily
related to the write-down of HI Energy's Illinois tire-to-energy plant
investment in 1995. After adjusting for non-recurring gains and charges in both
years, consolidated basic and diluted per share earnings from continuing
operations rose nearly 14% to $1.93 in 1996 from $1.70 in 1995, while income
from continuing operations rose to $472 million in 1996 from $422 million the
previous year. The improvement in earnings resulted from increased sales at
Electric Operations, improved results at HI Energy and a full year of after-tax
dividend income ($37 million in 1996 compared to $18 million in 1995) from the
Company's investment in Time Warner Inc. (Time Warner) securities.
 
                   RESULTS OF OPERATIONS BY BUSINESS SEGMENT
 
     In order to reflect the changes in the Company's business resulting from
the acquisition of NorAm, the Company has organized its financial reporting
segments into Electric Operations, Natural Gas Distribution, Interstate
Pipeline, Energy Marketing, International and Corporate. The business and
operations of each of these segments are described below and are shown for
comparative purposes on a pro forma basis.
 
     All business segment data (other than data relating to Electric Operations)
are presented on a pro forma basis as if the acquisition of NorAm had occurred
on January 1 of the period presented. Pro forma results of operations are not
necessarily indicative of the combined results of operations that actually would
have occurred had the acquisition occurred on such date. The Company, however,
believes that the presentation of pro forma data provides a more meaningful
comparative standard for assessing changes in the results of operations of the
business segments, because the pro forma presentation gives retroactive effect
to the purchase-related adjustments, including amortization of goodwill and the
revaluation on a preliminary basis of the fair market value of certain NorAm
assets and liabilities.
                                       30
<PAGE>   33
 
     The following table presents operating income on (i) an actual basis for
the year ended December 31, 1997 and (ii) a pro forma basis for each of the
Company's business segments for the years ended December 31, 1997 and 1996.
 
                  OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
 
<TABLE>
<CAPTION>
                                                                             UNAUDITED
                                                              ACTUAL         PRO FORMA
                                                            YEAR ENDED      YEAR ENDED
                                                           DECEMBER 31,    DECEMBER 31,
                                                           ------------   ---------------
                                                             1997(1)       1997     1996
                                                           ------------   ------   ------
                                                                   (IN MILLIONS)
<S>                                                        <C>            <C>      <C>
Electric Operations......................................     $  995      $  995   $  997
Natural Gas Distribution.................................         55         153      160
Interstate Pipeline......................................         32         100      109
Energy Marketing.........................................         16          15       49
International............................................         20          17       (1)
Corporate................................................        (53)        (61)     (42)
                                                              ------      ------   ------
Total Consolidated.......................................     $1,065      $1,219   $1,272
                                                              ======      ======   ======
</TABLE>
 
---------------
 
(1) Includes NorAm business segments beginning on the Acquisition Date.
 
ELECTRIC OPERATIONS
 
     Electric Operations are conducted under the name "Houston Lighting & Power
Company" or "HL&P" (HL&P), an unincorporated division of the Company. Electric
Operations provides electric generation, transmission, distribution and sales to
approximately 1.6 million customers in a 5,000 square mile area on the Texas
Gulf Coast, including Houston (the nation's fourth largest city). Electric
Operations constitutes the Company's largest business segment, representing 82%
of the Company's consolidated pro forma operating income for 1997.
 
     The following table provides summary data, before income taxes, regarding
the actual results of operations of Electric Operations for 1997, 1996 and 1995.
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                            ------------------      PERCENT
                                                             1997        1996       CHANGE
                                                            ------      ------      -------
                                                              (IN MILLIONS)
<S>                                                         <C>         <C>         <C>
Base Revenues(1)..........................................  $2,839      $2,743         3%
Reconcilable Fuel Revenues(2).............................   1,413       1,282        10%
Fuel and Purchased Power Expense..........................   1,477       1,347        10%
Operation Expense.........................................     737         640        15%
Maintenance Expense.......................................     228         249        (8%)
Depreciation and Amortization Expense.....................     569         546         4%
Other Operating Expenses..................................     246         246         --
                                                            ------      ------
Operating Income..........................................  $  995      $  997         --
                                                            ======      ======
</TABLE>
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                            ------------------      PERCENT
                                                             1996        1995        CHANGE
                                                            ------      ------      --------
                                                              (IN MILLIONS)
<S>                                                         <C>         <C>         <C>
Base Revenues(1)..........................................  $2,743      $2,645          4%
Reconcilable Fuel Revenues(2).............................   1,282       1,035         24%
Fuel and Purchased Power Expense..........................   1,347       1,113         21%
Operation Expense.........................................     640         616          4%
Maintenance Expense.......................................     249         250         --
Depreciation and Amortization Expense.....................     546         475         15%
Other Operating Expense...................................     246         246         --
                                                            ------      ------
Operating Income..........................................  $  997      $  980          2%
                                                            ======      ======
</TABLE>
 
                                       31
<PAGE>   34
 
---------------
 
(1) Includes miscellaneous revenues, certain non-reconcilable fuel revenues and
    certain purchased power-related revenues.
 
(2) Includes revenues collected through a fixed fuel factor net of adjustment
    for over/under recovery. See "-- Operating Revenues -- Electric Operations."
 
OPERATING INCOME -- ELECTRIC OPERATIONS
 
     1997 Compared to 1996. Electric Operations' operating income (before income
taxes) was $995 million in 1997 compared with $997 million the previous year.
The decrease in operating income was due to increases in operations expense and
depreciation and amortization expense, partially offset by increased revenues
from electric sales growth and decreases in maintenance expense, as described
below. Total KWH sales rose 3% during 1997, with increases of 1% in residential
sales, 6% in commercial sales and 2% in firm industrial sales.
 
     1996 Compared to 1995. Electric Operations' operating income (before income
taxes) was $997 million in 1996 compared with $980 million in 1995. Increased
sales resulting from favorable weather and economic conditions helped offset the
effects of the increases in operations expense and depreciation and amortization
expense discussed below. Total KWH sales rose 6% during 1996, with increases of
4% in residential sales, 3% in commercial sales and 7% in firm industrial sales.
 
OPERATING REVENUES -- ELECTRIC OPERATIONS
 
     1997 Compared to 1996. Electric Operations' 3% increase in base revenues
(which includes electric sales, miscellaneous revenues and certain
non-reconcilable fuel) is primarily the result of newly recorded transmission
revenues. Electric Operations' transmission revenues (which are considered
miscellaneous revenues) in 1997 were $86 million but were offset by related
transmission expenses of $88 million which are included in operation and
maintenance expenses. For information regarding these transmission revenues, see
"-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Competition -- Electric Operations -- Competition in Wholesale
Market" below.
 
     Electric Operations' 10% increase in reconcilable fuel revenue resulted
primarily from increased natural gas prices. The Public Utility Commission of
Texas (Texas Utility Commission) provides for recovery of certain fuel and
purchased power costs through a fixed fuel factor included in electric rates.
The fixed fuel factor is established during either a utility's general rate
proceeding or its fuel factor proceeding and is generally effective for a
minimum of six months. Revenues collected through such factor are adjusted
monthly to equal actual fuel costs; therefore, such revenues and expenses have
no effect on earnings unless fuel costs are determined not to be recoverable.
The adjusted over/under recovery of fuel costs is recorded on the Company's
Consolidated Balance Sheets as fuel-related credits or fuel-related debits,
respectively. Fuel costs are reviewed during periodic fuel reconciliation
proceedings, which are required at least every three years. Electric Operations
filed a fuel reconciliation proceeding with the Texas Utility Commission on
January 30, 1998 for the three year period ending July 31, 1997.
 
     In 1997, Electric Operations implemented (i) a $70 million temporary fuel
surcharge (inclusive of interest) effective for the first six months of 1997 and
(ii) a $62 million temporary fuel surcharge (inclusive of interest) effective
for the last six months of 1997. As of December 31, 1997, Electric Operations'
cumulative under-recovery of fuel costs was $172 million, including interest. In
December 1997, the Texas Utility Commission approved the implementation of a
$102 million (inclusive of interest) temporary fuel surcharge which was
implemented by Electric Operations on January 1, 1998, with recovery extending
from 8 months to 16 months depending on the customer class. Electric Operations
requested the surcharge in order to recover its under-recovery of fuel expenses
for the period March 1997 through August 1997.
 
FUEL AND PURCHASED POWER EXPENSE -- ELECTRIC OPERATIONS
 
     Fuel costs constitute the single largest expense for Electric Operations.
The mix of fuel sources for generation of electricity is determined primarily by
system load and the unit cost of fuel consumed. The average cost of fuel used by
Electric Operations in 1997 was $1.87 per million British Thermal Units
 
                                       32
<PAGE>   35
 
(MMBtu) ($2.60 for natural gas, $2.02 for coal, $1.08 for lignite and $0.54 for
nuclear). In 1996, the average cost of fuel was $1.82 per MMBtu ($2.31 for
natural gas, $2.11 for coal, $1.11 for lignite and $0.62 for nuclear). Fuel
costs are reconciled to fuel revenues resulting in no effect on earnings unless
fuel costs are determined not to be recoverable.
 
     1997 Compared to 1996. Fuel expenses in 1997 increased by $66 million or 6%
over 1996 expenses. The increase was driven by significant increases in the
average unit cost of natural gas, which rose to $2.60 per MMBtu in 1997 from
$2.31 per MMBtu in 1996. Purchased power expenses also increased in 1997 by $63
million or 20% over 1996 expenses. This change was primarily due to higher
prices paid to qualifying facilities for purchased electric energy principally
as a result of increases in gas prices, energy purchased under Electric
Operations' joint dispatching agreement with the City of San Antonio (See Note
12(c) to the Company's Consolidated Financial Statements), and Electric
Operations participating in the newly deregulated Texas wholesale energy market
in order to buy and sell energy at lower costs to its customers.
 
     1996 Compared to 1995. Fuel expenses in 1996 increased by $146 million or
17% over 1995 expenses. The increase was driven by significant increases in the
average unit cost of natural gas, which rose to $2.31 per MMBtu in 1996 from
$1.69 per MMBtu in 1995. Purchased power expenses also increased in 1996 by $89
million over 1995 expenses. This change was driven primarily by the unit cost
paid for purchased electric energy which rose as a result of the increase in
natural gas prices.
 
OPERATION AND MAINTENANCE EXPENSES, DEPRECIATION, AMORTIZATION AND
OTHER -- ELECTRIC OPERATIONS
 
     1997 Compared to 1996. Operation and maintenance expense increased $76
million in 1997, including $88 million due to transmission tariffs within the
Electric Reliability Council of Texas (ERCOT). These expenses are largely offset
by $86 million of revenue associated with wholesale transmission services. The
additional expenses do not reflect a significant increase in Electric
Operations' cost of providing transmission service, but only a change in the
pricing and billing of wholesale transmission services among providers in Texas.
 
     In 1997, Electric Operations incurred $17.4 million in work force severance
costs as a result of its efforts to streamline and improve certain business
activities. In 1996, Electric Operations incurred severance costs of $30
million.
 
     Depreciation and amortization expense increased $23 million in 1997
compared to 1996. The increase is primarily due to the additional accelerated
amortization of $16 million over 1996 of Electric Operations' investment in
lignite reserves. In 1996, Electric Operations began amortizing its $153 million
investment in these lignite reserves, which are associated with a canceled
generation project. The lignite reserves will be fully amortized no later than
2002. In each of 1997 and 1996, Electric Operations wrote down its investment in
the South Texas Project by $50 million in addition to ordinary depreciation
associated with the South Texas Project. The additional amortization of the
lignite reserves and the South Texas Project is allowed pursuant to Electric
Operations' most recent rate order. For additional information regarding these
amortizations, see Note 1(f) to the Company's Consolidated Financial Statements.
 
     1996 Compared to 1995. Operations and maintenance expense increased by $23
million or 3% in 1996. This increase is largely attributable to the
implementation of an employee incentive compensation program and an increase in
severance payments paid to former employees. A significant decline in employee
benefits-related expenses partially offset the other increases in operations and
maintenance expense.
 
     In 1995, Electric Operations incurred $15 million in work force severance
as a result of its efforts to streamline and improve certain business activities
as compared to $30 million in 1996.
 
NATURAL GAS DISTRIBUTION
 
     Domestic natural gas distribution operations (Natural Gas Distribution) are
conducted through the Arkla, Entex and Minnegasco divisions of NorAm and are
included in the Company's actual consolidated results of operations beginning on
the Acquisition Date. These operations consist of natural gas sales to, and
 
                                       33
<PAGE>   36
 
natural gas transportation for, residential, commercial and certain industrial
customers in six states: Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma
and Texas.
 
     The following table provides summary data regarding the unaudited pro forma
financial results of operations of Natural Gas Distribution, including operating
statistics, for 1997 and 1996. Results of operations data for prior periods are
not presented because the Company had no operations in this segment prior to the
Merger.
 
<TABLE>
<CAPTION>
                                                               UNAUDITED
                                                               PRO FORMA
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                            ----------------    PERCENT
                                                             1997      1996     CHANGE
                                                            ------    ------    -------
                                                            ($ IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Operating Revenues........................................  $2,202    $2,113       4%
Operating Expenses:
  Natural Gas.............................................   1,441     1,348       7%
  Operation and Maintenance...............................     247       250      (1%)
  Depreciation and Amortization...........................     123       120       3%
  Other Operating Expenses(1).............................     238       235       1%
                                                            ------    ------
     Total Operating Expenses.............................   2,049     1,953       5%
                                                            ------    ------
Operating Income..........................................  $  153    $  160      (4%)
                                                            ======    ======
Throughput Data (in Bcf):
  Residential and Commercial Sales........................     326       333      (2%)
  Industrial Sales........................................      59        58       2%
  Transportation..........................................      42        42       --
                                                            ------    ------
     Total Throughput.....................................     427       433      (1%)
                                                            ======    ======
</TABLE>
 
---------------
 
(1) Before a $6 million one-time charge incurred in 1996 for early retirement
    and severance costs.
 
     1997 Compared to 1996 (Pro Forma). The increase of approximately $89
million (4%) in pro forma Natural Gas Distribution operating revenue for the
year ended December 31, 1997 in comparison to the corresponding period of 1996
is principally due to the increase in purchased gas costs.
 
     Pro forma operating income was $153 million in 1997 compared with $160
million (before a one-time charge of $6 million for early retirement and
severance) in 1996. The decrease of approximately $7 million (4%) in 1997 pro
forma operating income was principally due to decreased Minnegasco customer
usage due to warmer weather and customer conservation, decreased Arkla customer
usage due to warmer weather (primarily in the first quarter of 1997) and Arkla's
charges associated with the applicable state regulatory commission's methodology
of calculating the price of gas charged to customers (the purchased gas
adjustment) primarily in Louisiana. Partially offsetting the decrease is an
increase in Minnegasco's performance based rate incentive recoveries and
customer growth and increased revenues from Entex due to rate relief granted in
1996 and fully reflected in 1997.
 
     The $93 million (7%) increase in gas purchased costs in 1997 compared to
1996 primarily reflects the increase in Natural Gas Distribution's average cost
of gas in 1997 (consistent with the overall increase in the market price of gas)
along with the purchased gas adjustment described above.
 
INTERSTATE PIPELINE
 
     Interstate natural gas pipeline operations (Interstate Pipeline) are
conducted through NorAm Gas Transmission Company (NGT) and Mississippi River
Transmission Corporation (MRT), two wholly owned subsidiaries of NorAm. The NGT
system consists of approximately 6,200 miles of natural gas transmission lines
located in portions of Arkansas, Kansas, Louisiana, Mississippi, Missouri,
Oklahoma, Tennessee and Texas. The MRT system consists of approximately 2,000
miles of pipeline serving principally the greater
 
                                       34
<PAGE>   37
 
St. Louis metropolitan area in Illinois and Missouri. The results of operations
of Interstate Pipeline are included in the Company's actual consolidated results
of operations beginning on the Acquisition Date.
 
     The following table provides summary data regarding the unaudited pro forma
results of operations of Interstate Pipeline including operating statistics for
1997 and 1996. Results of operations data for prior periods are not presented
because the Company had no operations in this segment prior to the Merger.
 
<TABLE>
<CAPTION>
                                                                 UNAUDITED
                                                                 PRO FORMA
                                                                 YEAR ENDED
                                                                DECEMBER 31,
                                                              ----------------    PERCENT
                                                               1997      1996     CHANGE
                                                              ------    ------    -------
                                                              ($ IN MILLIONS)
<S>                                                           <C>       <C>       <C>
Operating Revenues..........................................   $295      $347      (15%)
Operating Expenses:
  Natural Gas...............................................     42        76      (45%)
  Operation and Maintenance.................................     45        49       (8%)
  Depreciation and Amortization.............................     46        45        2%
  Other Operating Expenses(1)...............................     62        68       (9%)
                                                               ----      ----
          Total Operating Expenses..........................    195       238      (18%)
                                                               ----      ----
Operating Income............................................   $100      $109       (9%)
                                                               ====      ====
Throughput Data (in million MMBtu):
Natural Gas Sales...........................................     18        33      (45%)
Transportation..............................................    911       952       (4%)
     Elimination(2).........................................    (17)      (31)      45%
                                                               ----      ----
Total Throughput............................................    912       954       (4%)
                                                               ====      ====
</TABLE>
 
---------------
 
(1) Before a $17 million one-time charge incurred in 1996 for early retirement
    and severance costs.
 
(2) Elimination of volumes both transported and sold.
 
     1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for
Interstate Pipeline decreased by $52 million (15%) for the year ended December
31, 1997 in comparison to the corresponding period of 1996. The decrease in
revenues primarily reflects a decline in natural gas sales revenue resulting
from the expiration in 1996 of an unbundled natural gas sales contract between
Interstate Pipeline and Arkla. Natural gas sales to Natural Gas Distribution
were $60 million in 1996 and none in 1997. It is anticipated that substantially
all future revenues for Interstate Pipeline will be from natural gas
transportation only.
 
     Pro forma operating income was $100 million in 1997 compared to $109
million (before a one-time charge of $17 million for early retirement and
severance) in 1996. This decrease of approximately $9 million (9%) in Interstate
Pipeline's pro forma operating income between 1997 and 1996 results primarily
from three factors: (i) a 6% decrease in transportation revenues, (ii) a 43%
decrease in natural gas sales revenue (as described above) and (iii) lower
demand for natural gas transportation as a result of lower natural gas
consumption (primarily weather-related) in the eastern markets served by the
segment. These factors were offset partially by an approximately 18% decline in
operating expenses primarily due to decreases in gas purchased.
 
     The decline in transportation revenues are largely attributable to price
differentials between the average spot price for Mid-continent natural gas
(Interstate Pipeline's primary supply area) and Gulf Coast natural gas in 1997.
When prices of Gulf Coast gas decrease significantly relative to Mid-continent
gas, downward pressure on transportation prices occurs when selling in west to
east markets like those of NGT. This competitive pressure, in turn, results in a
decline in average transportation rates under contracts that contain
market-sensitive pricing provisions.
 
                                       35
<PAGE>   38
 
     The $34 million (45%) decrease in gas purchased costs in 1997 compared to
1996 is largely attributable to the expiration of long-term supply contracts
entered into prior to unbundling, as discussed above. Other operating expenses
decreased $4 million (9%) in 1997 compared to 1996 primarily due to the
elimination of non-recurring costs combined with cost reductions related to the
1996 early retirement and severance program and reductions in costs allocated
from NorAm.
 
     During 1997, Interstate Pipeline's largest unaffiliated customer was a
natural gas utility that serves the greater St. Louis metropolitan area.
Revenues from this customer are generated pursuant to several long-term firm
transportation and storage contracts that currently are scheduled to expire at
various dates between October 1999 and May 2000. Interstate Pipeline is
currently negotiating with the natural gas utility to renew these agreements.
 
ENERGY MARKETING
 
     Energy marketing and gathering business (Energy Marketing) includes the
operations of the Company's wholesale and selected retail energy marketing
businesses and natural gas gathering activities conducted, respectively, by
NorAm Energy Services, Inc. (NES), NorAm Energy Management, Inc. (NEM) and NorAm
Field Services Corp. (NFS), three wholly owned subsidiaries of NorAm.
 
     The following table provides summary data regarding the unaudited pro forma
results of operations of Energy Marketing, including operating statistics for
1997 and 1996. Results of operations data for prior periods are not presented
because the Company had no operations in this segment prior to the Merger.
 
<TABLE>
<CAPTION>
                                                          UNAUDITED PRO FORMA
                                                              YEAR ENDED
                                                              DECEMBER 31
                                                          -------------------     PERCENT
                                                           1997        1996       CHANGE
                                                          -------     -------     -------
                                                             (IN MILLIONS)
<S>                                                       <C>         <C>         <C>
Operating Revenues......................................  $3,589      $2,645         36%
Operating Expenses:
  Natural Gas and Purchased Power, net..................   3,477       2,489         40%
  Operation and Maintenance.............................      46          68        (32%)
  Depreciation and Amortization.........................      11          10         10%
  Other Operating Expenses..............................      40          29         38%
                                                          ------      ------
          Total Operating Expenses......................   3,574       2,596         38%
                                                          ------      ------
Operating Income........................................  $   15      $   49        (69%)
                                                          ======      ======
Operations Data:
  Natural Gas (in Bcf):
     Sales..............................................   1,185       1,076         10%
     Transportation.....................................      24          26         (8%)
     Gathering..........................................     242         231          5%
                                                          ------      ------
          Total.........................................   1,451       1,333          9%
                                                          ======      ======
  Electricity (in thousand MWH):
     Wholesale Power Sales..............................  24,997       2,776        800%
                                                          ======      ======
</TABLE>
 
     1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for Energy
Marketing increased by $944 million (36%) for 1997 in comparison to 1996 due to
increased natural gas and electricity trading volumes. Increased volumes in 1997
had minimal effect on operating income due to low operating margins in both
periods.
 
     Pro forma operating income for 1997 was $15 million compared to $49 million
in 1996. This decrease of approximately $34 million (69%) was primarily
attributed to: (i) hedging losses associated with anticipated first quarter 1997
sales under peaking contracts and (ii) losses from the sale of natural gas held
in storage and
 
                                       36
<PAGE>   39
 
unhedged in the first quarter of 1997 totaling $17 million. In addition, other
operating expenses increased $11 million largely due to increased staffing and
marketing activities made in support of the increased sales and expanded
marketing efforts. Partially offsetting these unfavorable impacts were increased
margins from natural gas gathering activities.
 
     Natural gas and purchased power expense increased $988 million (40%) in
1997 compared to 1996 primarily due to increased gas and electricity marketing
activities but also included hedging losses and losses from the sale of natural
gas, as discussed above.
 
     To minimize fluctuations in the price of natural gas and transportation,
NorAm, primarily through NES, enters into futures transactions, swaps and
options in order to hedge against market price changes affecting (i) certain
commitments to buy, sell and transport natural gas, (ii) existing gas storage
inventory and (iii) certain anticipated transactions, some of which carry
off-balance sheet risk. NES also enters into natural gas derivatives for trading
purposes and electricity derivatives for hedging and trading purposes. For a
discussion about the Company's accounting treatment of derivative instruments,
see Note 2 to the Company's Consolidated Financial Statements and "Quantitative
and Qualitative Disclosures About Market Risk" in Item 7A of this report.
 
     The Company believes that NES' energy marketing and risk management
services have the potential of complementing the Company's strategy of
developing and/or acquiring unregulated generation assets in other markets. As a
result, the Company has made, and expects to continue to make, significant
investments in developing NES' internal software, trading and personnel
resources.
 
INTERNATIONAL
 
     The Company's international business segment (International) includes the
results of operations of HI Energy, a wholly owned subsidiary of the Company
that participates in the development and acquisition of foreign independent
power projects and the privatization of foreign generation and distribution
facilities, and of the international operations of NorAm. Substantially all of
the Company's International operations to date have been in Central and South
America.
 
     Results of operations data for International are presented in the following
table on an unaudited pro forma basis as if the Merger had occurred as of
January 1, 1997 and 1996, as applicable. The primary pro forma adjustment made
to this segment in connection with the Merger is to give effect to the
development costs and other expenditures incurred by certain NorAm subsidiaries
on international projects prior to the Acquisition Date. The adjustment had no
effect on operating revenues. Results of operations for International for the
years ended December 31, 1996 and 1995 are presented on an actual basis as the
related NorAm operations for such years were immaterial.
 
<TABLE>
<CAPTION>
                                                  UNAUDITED
                                                  PRO FORMA                    ACTUAL
                                                  YEAR ENDED                 YEAR ENDED
                                                 ------------   PERCENT     ------------   PERCENT
                                                 1997    1996   CHANGE      1996    1995   CHANGE
                                                 ----    ----   -------     ----    ----   -------
                                                     (IN                        (IN
                                                  MILLIONS)                  MILLIONS)
<S>                                              <C>     <C>    <C>         <C>     <C>    <C>
Operating Revenues.............................  $92     $62       48%      $62     $ 47      32%
Operating Expenses:(1)
  Fuel.........................................   21      19       11%       19       18       6%
  Operation and Maintenance....................   50      42       19%       39       76     (49%)
  Depreciation and Amortization................    4       2      100%        2        1     100%
                                                 ---     ---                ---     ----
          Total Operating Expenses.............   75      63       19%       60       95     (37%)
                                                 ---     ---                ---     ----
Operating Income (Loss)........................  $17     $(1)               $ 2     $(48)
                                                 ===     ===                ===     ====
</TABLE>
 
---------------
 
(1) International operating expenses are included in other operating expenses on
    the Company's Consolidated Statements of Income. The above detail is
    provided for informational purposes only.
 
                                       37
<PAGE>   40
 
     1997 Compared to 1996 (Pro Forma). Pro forma operating income for 1997 was
$17 million compared to an operating loss of approximately $1 million for the
same period in 1996. The first quarter of 1996 includes an $8 million pre-tax
non-recurring charge related to the write-off of a portion of HI Energy's
investment in two tire-to-energy plants in 1996. Excluding non-recurring
charges, International would have had operating income in 1996 of $7 million.
The increase in 1997 operating income is due to increased equity earnings of $32
million partially offset by higher operation expenses resulting from increased
corporate and project development costs. Equity earnings increased primarily due
to investments in Brazil and Colombia. Light Servicos de Eletricidade S.A.
(Light) reported enhanced results in 1997 and a full year of operations compared
to only eight months in 1996. HI Energy's investment in EPSA, a Colombian
electric utility, in which HI Energy acquired a 28% interest in June 1997, also
contributed to the increase in equity income.
 
     Excluding after-tax nonrecurring charges of $5 million for 1996,
International's pro forma net income was $23 million and $3 million for 1997 and
1996, respectively. Generally, HI Energy's net income exceeds its operating
income because of tax benefits and because equity income is reflected net of
tax. However, in 1996 net income did not exceed operating income primarily due
to lower equity earnings in 1996.
 
     1996 Compared to 1995 (Actual). Operating income for the year ended
December 31, 1996 was $2 million compared to an operating loss of $48 million
for the same period in 1995. The increase is primarily due to (i) equity
earnings of approximately $16 million from Light which was acquired in May 1996,
(ii) a $20 million reduction in non-recurring charges associated with the
investment in two tire-to-energy plants (included in operation and maintenance
expenses) and (iii) reduced project development costs (included in operation and
maintenance expenses). International's actual net income in 1996 was $.2 million
compared to a loss of $33 million in 1995.
 
     International intends to evaluate and consider a wide array of potential
business strategies, including possible acquisitions, restructurings,
reorganizations and/or dispositions of currently owned properties or
investments. Pursuit of any of the above strategies, or any combination thereof
could have a significant impact on the business operations and financial
condition of International.
 
     For additional information about the accounting treatment of certain of HI
Energy's foreign investments, see Note 5 to the Company's Consolidated Financial
Statements.
 
CORPORATE
 
     Corporate. The Company's corporate and other business segment (Corporate)
includes the operations of HI Power Generation, Inc. (HIPG), which is engaged in
the acquisition, development, and operation of domestic non-rate regulated power
generation facilities, the Company's unregulated retail electric services
business, certain real estate holdings of the Company, corporate costs and
inter-unit eliminations.
 
     In 1997, Corporate's pro forma operating loss of $61 million which reflects
an increase of $19 million when compared to 1996. The increase in pro forma
operating losses was primarily due to (i) losses associated with the Company's
non-regulated utility services business; (ii) consumer services business; (iii)
unregulated retail electric services business; and (iv) expenses related to the
development of domestic power generation projects.
 
     HIPG. HIPG was formed in March 1997 to pursue the acquisition of domestic
electric generation assets as well as the development of new domestic non-rate
regulated power generation facilities. The Company has invested approximately $3
million in HIPG development activities since its formation. HIPG currently has
entered into commitments associated with various generation projects amounting
to $338 million, including certain commitments that remain subject to due
diligence and other conditions. The Company currently expects to finance these
commitments primarily with the proceeds from bank borrowings obtained by one or
more subsidiaries of the Company. The Company expects that HIPG will continue to
participate as a bidder in future sales of generating assets. Depending on the
timing and success of HIPG's future bidding efforts resulting expenditures could
be substantial.
 
                                       38
<PAGE>   41
 
                   CERTAIN FACTORS AFFECTING FUTURE EARNINGS
                      OF THE COMPANY AND ITS SUBSIDIARIES
 
     Earnings for the past three years are not necessarily indicative of future
earnings and results. The level of future earnings depends on numerous factors
including (i) the Company's ability to successfully integrate the operations of
NorAm into the Company's operations; (ii) the future growth in the Company and
its subsidiaries' energy sales; (iii) weather; (iv) the success of the Company's
and its subsidiaries' entry into non-rate regulated businesses such as energy
marketing and international and domestic power projects; (v) the Company's and
its subsidiaries' ability to respond to rapid changes in a competitive
environment and in the legislative and regulatory framework under which it has
traditionally operated; (vi) rates of economic growth in the Company's and its
subsidiaries' service areas; (vii) the ability of the Company and its
subsidiaries to control costs and to maintain pricing structures that are both
attractive to customers and profitable; (viii) the outcome of future rate
proceedings; and (ix) future legislative initiatives.
 
     In order to adapt to the increasingly competitive environment in which the
Company and its subsidiaries operate, the Company intends to evaluate and
consider a wide array of potential business strategies. These may include
business combinations or acquisitions involving other utility or non-utility
businesses or properties, internal restructuring, and reorganizations or
dispositions of currently owned properties or currently operating business
units. Pursuit of any of the above strategies, or any combination thereof, may
significantly affect the business operations and financial condition of the
Company.
 
RATE PROCEEDINGS -- ELECTRIC OPERATIONS
 
     The Texas Utility Commission has jurisdiction (or, in some cases, appellate
jurisdiction) over the electric rates of Electric Operations and as such
monitors Electric Operations' earnings to ensure that Electric Operations is not
earning in excess of a reasonable rate of return.
 
     In 1997, the Texas legislature considered but did not pass legislation
intended to address various issues concerning the restructuring of the electric
utility industry, including proposals that would permit Texas retail electric
customers to choose their own electric suppliers beginning on December 31, 2001.
The legislative proposals included provisions relating to full stranded cost
recovery; rate reductions; rate freezes; the unbundling of generation
operations, transmission and distribution and customer service operations;
securitization of regulatory assets; and consumer protections. Although the
Company and certain other parties (including the Texas Utility Commission)
supported the bill, it was not enacted prior to the expiration of the
legislative session.
 
     In October 1997, the Company presented a proposed transition to competition
plan intended to address certain aspects of the proposals contained in the
legislation formerly pending before the Texas legislature. By mid-December 1997,
negotiations resulted in a settlement agreement (Settlement Agreement) among the
Company and representatives of the state's consumer and industrial groups, the
staffs of the City of Houston, the Texas Utility Commission and others that was
presented to the Texas Utility Commission, where it is currently under
consideration.
 
     Under the terms of the proposal, residential customers will receive a 4%
credit to the base cost of electricity in 1998, increasing to 6% in 1999. Small
and mid-sized businesses will receive a 2% credit to their base costs beginning
in 1998. The combined effect of these reductions is expected to be a $166
million decrease in base revenues over a two year period. In addition, the
Company (over the next two years) will be permitted to mitigate its potentially
stranded costs by (i) redirecting to production property all of its current
depreciation expenses that would otherwise be credited to accumulated
depreciation for transmission and distribution property, and (ii) applying any
and all earnings above a rate of return cap of 9.95% to additional depreciation
of production property. The Company estimates that redirected depreciation over
the two-year period of 1998 and 1999 will be approximately $364 million. As part
of the Settlement Agreement, the Company will support proposed legislation in
the 1999 Texas legislative session that includes provisions providing for retail
customer choice effective December 31, 2001 and other provisions consistent with
those in the 1997 proposed legislation.
 
                                       39
<PAGE>   42
 
     The Settlement Agreement is currently under consideration by the Texas
Utility Commission, the City of Houston and other cities served by HL&P. In
December 1997, the Texas Utility Commission approved the petition filed by the
Company to implement the requested base rate credits on a temporary basis
beginning January 1, 1998, pending final Texas Utility Commission consideration.
The approval also included the accounting order necessary to permit the Company
to begin redirecting depreciation from its transmission and distribution
facilities to production property on a temporary basis pending final Texas
Utility Commission consideration. A procedural schedule has been developed by
the Texas Utility Commission whereby a final decision regarding the Settlement
Agreement would be reached by the end of March 1998.
 
     Although the Company believes that the proposal has strong support from
many groups active in the debate over deregulation of the electric industry, it
is not in a position at this time to predict whether the proposal will be
adopted, and if adopted, what form it ultimately may take.
 
COMPETITION -- ELECTRIC OPERATIONS
 
     Due to changing government regulations, technological developments and the
availability of alternative energy sources, the U.S. electric utility industry
has become increasingly competitive.
 
     Long-Term Trends in Electric Utility Industry. Based on a strategic review
of the Company's business and of ongoing developments in the electric utility
and related industries regarding competition, regulation and consolidation, the
Company's management believes that the pace of change affecting the electric
utility industry is likely to accelerate, albeit on a state-by-state basis. As
of December 31, 1997, 16 states are considering legislative proposals to
restructure electricity markets. The Company's management also believes the
businesses of electricity and natural gas are converging and consolidating and
these trends will alter the structure and business practices of companies
serving these markets in the future. In particular, the Company's management has
observed a trend toward performance based ratemaking for regulated transmission
and distribution operations. This trend should provide incentives for electric
utilities to become more efficient.
 
     Competition in Wholesale Market. The Energy Policy Act of 1992 and the
Texas Public Utility Regulatory Act of 1995 (PURA) both contain provisions
intended to facilitate the development of a wholesale energy market. Although
HL&P's wholesale sales traditionally have accounted for less than 1% of its
total revenues, the expansion of competition in the wholesale electric market is
significant in that it has increased the range of nonutility competitors, such
as exempt wholesale generators (EWGs) and power marketers, in the Texas electric
market as well as resulted in fundamental changes in the operation of the state
transmission grid.
 
     In February 1996, the Texas Utility Commission adopted rules granting
third-party users of transmission systems open access to such systems at rates,
terms and conditions comparable to those available to utilities owning such
transmission assets. Under the Texas Utility Commission order implementing the
rule, HL&P was required to separate, on an operational basis, its wholesale
power marketing operations from the operations of the transmission grid and, for
purposes of transmission pricing, to disclose each of its separate costs of
generation, transmission and distribution.
 
     In January 1997, the Texas Utility Commission approved interim transmission
cost of service rates under the new transmission access pricing rules. The
associated 1997 revenue was $86 million offset by transmission expenses of $88
million.
 
     In August 1996, the Texas Utility Commission approved the creation of an
Independent System Operator (ISO) to manage the electric grid of the Electric
Reliability Council of Texas (ERCOT). The ISO is a key component of implementing
the Texas Utility Commission's overall strategy to create a competitive
wholesale market. The ISO is responsible for ensuring that all power producers
and traders have fair access to the ERCOT electric transmission system. The
ERCOT ISO plan is the first ISO proposal to be implemented in the U.S. The ISO
is governed by an equal number of representatives from each of six wholesale
market groups: investor owned utilities, municipally owned utilities, electric
cooperatives and river authorities, transmission dependent utilities,
independent power producers and power marketers.
 
                                       40
<PAGE>   43
 
     Competition in Retail Market. The Company has agreed pursuant to the
Settlement Agreement to support legislation in 1999 that is intended to permit
Texas retail electric customers to choose their own suppliers beginning on
December 31, 2000.
 
     In January 1997, the Texas Utility Commission delivered a report to the
Texas legislature on the scope of competition in Texas electric markets and the
impact of competition and industry restructuring on customers in both
competitive and non-competitive markets (including legislative recommendations
to promote the public interest in such markets). In its report, the Texas
Utility Commission recommended that the Texas legislature enact legislation to
implement retail competition in Texas but recommended against any legislation
that would introduce broad-based retail competition before 2000. The Texas
Utility Commission is currently updating this report for the 1999 legislative
session.
 
     For information about the Company's proposed transition to competition
plan, see "-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Rate Proceedings -- Electric Operations."
 
     Stranded Costs. As the U.S. electric utility industry continues its
transition to a more competitive environment, a substantial amount of fixed
costs previously approved for recovery under traditional utility regulatory
practices (including regulatory assets and liabilities) may become "stranded,"
i.e., unrecoverable at competitive market prices. The issue of stranded costs
could be particularly significant with respect to fixed costs incurred in
connection with the past construction of generation plants, such as nuclear
power plants, which would not command the same price for their output as they
have in a regulated environment.
 
     In January 1997, the Texas Utility Commission delivered a report to the
Texas legislature on stranded investments in the electric utility industry in
Texas. The report estimated that the total amount of stranded costs for all
Texas utilities could be as high as $21 billion, based on one set of
assumptions, and alternatively projected that such costs could be minimal or
non-existent, based on another set of assumptions. Electric Operations'
estimated stranded costs as set forth in the Texas Utility Commission report,
calculated based on various sets of assumptions provided by the Texas Utility
Commission, ranged from non-existent to $6 billion. The broad range of estimates
illustrates the inherent uncertainty in calculating these costs. The Texas
Utility Commission is currently updating this report for the 1999 legislative
session.
 
     Regulatory Assets and Liabilities. Electric Operations applies the
accounting policies established in SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation" (SFAS No. 71). In general, SFAS No. 71 permits a
company with cost-based rates to defer certain costs that would otherwise be
expensed to the extent that the utility is recovering or expects to recover such
costs in rates charged to customers. If, as a result of changes in regulation or
competition, Electric Operations' ability to recover these assets and/or
liabilities would not be assured, then pursuant to SFAS No. 101, "Accounting for
Discontinuation of Application of SFAS No. 71 (SFAS No. 101) and SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of" (SFAS No. 121), Electric Operations would be required to write
off or write down such net regulatory assets to the extent that they ultimately
were determined not to be recoverable. For further information concerning
regulatory assets or the Company's balance sheet and discussion of the
accounting for regulatory assets and liabilities, see Note 1(c) to the Company's
Consolidated Financial Statements.
 
COMPETITION -- OTHER OPERATIONS
 
     Natural Gas Distribution competes primarily with alternate energy sources
such as electricity and other fuel sources as well as with providers of energy
conservation products. In addition, as a result of federal regulatory changes
affecting interstate pipelines, it has become possible for other natural gas
suppliers and distributors to bypass Natural Gas Distribution's facilities and
market, sell and/or transport natural gas directly to small commercial and/or
large volume customers.
 
     Interstate Pipeline competes with other interstate and intrastate pipelines
in the transportation and storage of natural gas. The principal elements of
competition among pipelines are rates, terms of service, and flexibility and
reliability of service. Interstate Pipeline competes indirectly with other forms
of energy available to its customers, including electricity, coal and fuel oils.
The primary competitive factor is price. Changes in
 
                                       41
<PAGE>   44
 
the availability of energy and pipeline capacity, the level of business
activity, conservation and governmental regulations, the capability to convert
to alternative fuels, and other factors, including weather, affect the demand
for natural gas in areas served by Interstate Pipeline and the level of
competition for transport and storage services.
 
     Energy Marketing competes for sales in its gas marketing business with
other natural gas merchants, producers and pipelines based on its ability to
aggregate supplies at competitive prices from different sources and locations
and to utilize efficiently transportation from third-party pipelines. Energy
Marketing also competes against other energy marketers on the basis of its
relative financial position and access to credit sources. This competitive
factor reflects the tendency of energy customers, natural gas suppliers and
natural gas transporters to seek financial guarantees and other assurances that
their energy contracts will be satisfied. As pricing information becomes
increasingly available in the energy marketing business and as deregulation in
the electricity markets continues to accelerate, the Company anticipates that
Energy Marketing will experience greater competition and downward pressure on
per-unit profit margins in the energy marketing industry.
 
     Competition for acquisition of international and domestic non-rate
regulated power projects is intense. HI Energy and HIPG compete against a number
of other participants in the non-utility power generation industry, some of
which have greater financial resources and have been engaged in non-utility
power projects for periods longer than the Company and have accumulated greater
portfolios of projects. Competitive factors relevant to the non-utility power
industry include financial resources, access to non-recourse funding and
regulatory factors.
 
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
 
     For information regarding the Company's exposure to risk as a result of
fluctuations in commodity prices and derivative instruments, see Item 7A of this
Report.
 
ACCOUNTING TREATMENT OF ACES
 
     The Company accounts for its investment in Time Warner Convertible
Preferred Stock (TW Preferred) under the cost method. As a result of the
Company's issuance of the ACES, certain increases in the market value of Time
Warner common stock (the security into which the TW Preferred is convertible)
could result in an accounting loss to the Company, pending the conversion of the
Company's TW Preferred into Time Warner common stock.
 
     Prior to the conversion of the TW Preferred into Time Warner common stock,
when the market price of Time Warner common stock increases above $55.5844, the
Company records in Other Income (Expense) an accounting loss equal to the
aggregate amount of such increase as applicable to all ACES multiplied by
0.8264. In accordance with generally accepted accounting principles, this
accounting loss (which reflects the unrealized increase in the Company's
indebtedness with respect to the ACES) may not be offset by accounting
recognition of the increase in the market price of the Time Warner common stock
that underlies the TW Preferred. Upon conversion of the TW Preferred, the
Company will begin recording unrealized net changes in the market prices of the
Time Warner common stock and the ACES as a component of common stock equity.
 
     As of December 31, 1997, the market price of Time Warner common stock was
$62.00 per share. Accordingly, the Company recognized an increase of $121
million in the unrealized liability relating to its ACES indebtedness (which
resulted in an after tax earnings reduction of $79 million or $.31 per share).
The Company believes that this unrealized loss for the ACES is more than
economically hedged by the approximately $430 million unrecorded unrealized gain
at December 31, 1997 relating to the increase in the fair value of the Time
Warner common stock underlying the investment in TW Preferred since the date of
its acquisition. Any gain related to the increase in the fair value of Time
Warner Common Stock would be recognized upon the sale of the TW Preferred or the
shares of common stock into which such TW Preferred is converted. As of February
28, 1998, the price of Time Warner common stock was $67.50 per share which would
have resulted in the Company recognizing an additional increase of $104 million
in the unrealized
                                       42
<PAGE>   45
 
liability represented by its indebtedness under the ACES. The related unrecorded
unrealized gain as of February 28, 1998 would have been computed as an
additional $126 million.
 
IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES
 
     The Company is currently evaluating its computer and software requirements
in light of changes in the electric utility and energy services industries and
the acquisition of NorAm and resulting expansions of the Company into energy
trading activities.
 
     In September 1997, the Company entered into an agreement with SAP America,
Inc. (SAP) to license SAP's proprietary R/3 enterprise software. The licensed
software includes finance and accounting, human resources, materials management
and service delivery components. Based on the current timetable for completion
of the SAP implementation and integration project (Project), the Company
estimates that the third-party cost (including software license fees, fees for
consulting and other services and hardware acquisition costs) plus internal
costs of the Project will be approximately $130 million. It is currently
projected that these costs would be incurred over a three-year period. All
business process reengineering costs associated with the Project will be
expensed by the Company when incurred. It is anticipated that the implementation
of SAP will negate the need to modify many of the Company's computer systems to
accommodate the year 2000. The Company is also considering installing a new
customer information system; expenditures for the installation of such a system
have not been determined but could be significant.
 
     The Company is also evaluating various alternatives intended to permit its
existing computer programs (those not anticipated to be replaced by SAP) to
accommodate the year 2000 and beyond. Based on current internal cost and
productivity studies as well as bids recently solicited from various computer
software contractors, the Company estimates that the cost of resolving the year
2000 issue for its current operations (other than those anticipated to be
replaced by SAP) will range between $20 million to $25 million.
 
     The costs of becoming year 2000 compliant and the dates by which the
Company plans to complete the year 2000 modifications are based on management's
estimates, which were derived utilizing numerous assumptions regarding future
events, including the continued availability of certain resources, third party
modification plans and other factors. However, there can be no guarantee that
these cost or time estimates will be achieved, and actual results could differ
materially. Specific factors that might cause such material differences include,
but are not limited to, the availability of personnel trained in this area and
the ability to locate and correct all relevant computer codes.
 
RISKS OF OVERSEAS OPERATIONS
 
     As of December 31, 1997, the Company's Consolidated Balance Sheets
reflected $803 million of foreign investments, a substantial portion of which
represent equity investments in foreign utility companies.
 
     Foreign power projects entail certain political and financial risks,
distinct from those associated with domestic power projects. Such risks include
(i) expropriation, (ii) political instability, (iii) currency exchange rate
fluctuations and repatriation restrictions and (iv) regulatory and legal
uncertainties. Although HI Energy seeks to minimize these risks in a variety of
ways, including co-investing with local partners, financing investments with
nonrecourse debt and reviewing the potential return of any investment against
related political and other risks, there can be no assurance that HI Energy's
efforts to minimize overseas operational risks will be successful.
 
     As of December 31, 1997, HI Energy held a 11.35% ownership interest in
Light. Equity earnings from Light constitute a substantial portion of
International's operating income. In December 1997, Light experienced numerous
power outages in its service territory during a period of record peaks in
electrical demand. The Brazilian electricity service regulatory agency (ANEEL)
in February 1998 assessed against Light a $1.2 million penalty because of these
outages. Light has protested the assessment of the fines.
 
     In February 1998, HI Energy and certain of its Argentine subsidiaries
initiated an arbitration proceeding before the International Centre for
Settlement of Investment Disputes against the Republic of Argentina, relating to
alleged violations by the Province of Santiago del Estero and others of certain
provisions of the
                                       43
<PAGE>   46
 
concession contract held by EDESE. HI Energy and its subsidiaries are seeking
recovery of damages in an amount to be determined, but estimated to be no less
than $10 million.
 
ENVIRONMENTAL EXPENDITURES
 
     The Federal Clean Air Act (Clean Air Act) and other federal and state laws
and regulations have required, and will continue to require, the Company to make
significant expenditures in order to comply with environmental standards.
 
     Clean Air Act Expenditures. In 1996, the Company incurred costs of
approximately $1 million and less than $1 million in 1997, in order to comply
with requirements applicable to Electric Operations under the Clean Air Act,
which requirements mandate that electric utilities install continuous emission
monitoring equipment. Installation of the new systems was completed in 1996,
and, based on existing regulatory requirements, the Company forecasts no
additional significant expenditures for the installation of continuous emissions
monitoring systems for 1998.
 
     The Clean Air Act also requires establishing new emission limitations for
oxides of nitrogen (NOx). However, implementation of these limitations has been
delayed until 1999. The Company did not incur NOx reduction costs in 1997 but it
estimates that it will expend up to $10 million between 1998 and 1999 for NOx
reductions. Current Texas Natural Resource Conservation Commission evaluations
indicate NOx reductions will be required subsequent to 1999, however the
magnitude and timing of such reductions have not been established.
 
     Expenditures Associated with Planned HIPG Acquisitions. The California
South Coast Air Quality Management District updated the Air Quality Management
Plan for attainment of the federal ozone standard in 1997. The plan included
provisions for future year reductions in NOx emissions. Various emission
reduction initiatives and emission credit purchases are being evaluated in
association with the proposed acquisitions of generation assets by HIPG in
California. The estimated capital expenditures associated with such reductions
and/or purchases have not yet been determined.
 
     EPA Proceedings. In 1992, the EPA (i) identified the Company, along with
several other parties, as "potentially responsible parties" (PRP) under the
Comprehensive Environmental Response, Compensation and Liability Act for the
costs of cleaning up a site located adjacent to one of the Company's
transmission lines and (ii) issued an administrative order for the remediation
of the site. The Company believes that the EPA took this action solely on the
basis of information indicating that the Company in the 1950s acquired record
title to a portion of the land on which the site is located. The Company does
not believe that it now or previously held any ownership interest in the site
covered by the order and has obtained a judgment to that effect from a court in
Galveston County, Texas. Based on this judgment and other defenses that the
Company believes to be meritorious the Company has elected not to adhere to the
EPA's administrative order, even though the Company understands that other PRPs
are proceeding with site remediation. To date, neither the EPA nor any other PRP
has instituted a claim against the Company for any share of the remediation
costs for the site. However, if the Company was determined to be a responsible
party, the Company could be found to be jointly and severally liable along with
the other PRPs, for the aggregate remediation costs of the site (which the
Company estimates to be approximately $80 million in the aggregate) and could be
subjected to substantial fines and damage claims. Although the ultimate outcome
of this proceeding cannot be predicted at this time, the Company does not
believe that this case will have a material adverse effect on the Company's
financial condition, liquidity or results of operations.
 
     Litigation Involving Site Remediation. The Company is a defendant in
litigation arising out of the environmental remediation of a site in Corpus
Christi, Texas. The site was operated by third parties as a metals reclaiming
operation. Although the Company neither operated nor owned the site, certain
transformers and other equipment originally sold by the Company may have been
delivered to the site by third parties. The Company and others have remediated
the site pursuant to a plan approved by appropriate state agencies and a federal
court. To date, the Company has recovered, or has commitments to recover from
other responsible parties $2.2 million of the more than $3 million it has spent
on remediation.
 
                                       44
<PAGE>   47
 
     In Dumes, et al. v. Company, et al. (filed in December 1991 and pending in
the U.S. District Court for the Southern District of Texas, Corpus Christi
Division), landowners near the Corpus Christi site have asserted claims that
their property has been contaminated as a result of the remediation effort and
are seeking approximately $70 million in compensatory damages, in addition to
punitive damages of $51 million. The Dumes case is currently scheduled for trial
in June 1998. Although the ultimate outcome of this case cannot be predicted at
this time, the Company does not believe that this case will have a material
adverse effect on the Company's financial condition, liquidity or results of
operations.
 
     Manufactured Gas Plant Sites. NorAm and its predecessors operated a
manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works (FMGW) until 1960. NorAm has completed
remediation of the main site other than ongoing water monitoring and treatment.
There are six other former MGP sites in the Minnesota service territory.
Remediation has been completed on one site. Of the remaining five sites, NorAm
believes that two were neither owned nor operated by NorAm; two were owned by
NorAm at one time but were operated by others and are currently owned by others;
and one site was previously operated by NorAm but was owned by others. NorAm
believes it has no liability with respect to the sites it neither owned nor
operated.
 
     At December 31, 1997, NorAm had estimated a range of $15 million to $77
million for possible remediation of the Minnesota sites. The low end of the
range was determined based on only those sites presently owned or known to have
been operated by NorAm, assuming use of NorAm's proposed remediation methods.
The upper end of the range was determined based on the sites once owned by
NorAm, whether or not operated by NorAm. 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 1995 rate case, NorAm's Minnegasco division was allowed to recover
approximately $7 million annually for remediation costs. Such costs are subject
to a true-up mechanism whereby any over or under recovered amounts, net of
certain insurance recoveries, plus carrying charges, would be deferred for
recovery or refund in the next rate case. At December 31, 1997 and 1996,
Minnegasco had recorded a liability of $20.6 million and $35.9 million,
respectively, to cover the cost of future remediation. In addition, at December
31, 1997, Minnegasco had receivables from insurance settlements of $2.9 million.
These insurance settlements will be collected through 1999. Minnegasco expects
that approximately half of its accrual as of December 31, 1997 will be expended
within the next five years. The remainder will be expended on an ongoing basis
for an estimated 40 years. In accordance with the provisions of SFAS No. 71, a
regulatory asset has been recorded equal to the liability accrued. Minnegasco is
continuing to pursue recovery of at least a portion of these costs from
insurers. Minnegasco believes the difference between any cash expenditures for
these costs and the amount recovered in rates during any year will not be
material to the Company's or NorAm's overall cash requirements, results of
operations or cash flows.
 
     Issues relating to the identification and remediation of MGPs are common in
the utility industry. NorAm has received notices from the EPA and others
regarding its status as a potentially responsible party for other sites. The
Company and NorAm have not been able to quantify a range of environmental
expenditures for potential remediation expenditures with respect to other MGP
sites.
 
     Mercury Contamination. Like other natural gas pipelines, NorAm's pipeline
operations have in the past employed elemental mercury in meters used on its
pipelines. Although the mercury has now been removed from the meters, it is
possible that small amounts of mercury have been spilled at some of those sites
in the course of normal maintenance and replacement operations and that such
spills have contaminated the immediate area around the meters with elemental
mercury. Such contamination has been found by NorAm at some sites in the past,
and NorAm has conducted remediation at sites found to be contaminated. Although
NorAm is not aware of additional specific sites, it is possible that other
contaminated sites exist and that remediation costs will be incurred for such
sites. Although the total amount of such costs cannot be known at this time,
based on experience by NorAm and others in the natural gas industry to date and
on the current
 
                                       45
<PAGE>   48
 
regulations regarding remediation of such sites, the Company and NorAm believe
that the cost of any remediation of such sites will not be material to the
Company or NorAm's financial position, results of operation or cash flows.
 
     Other. From time to time the Company and/or its subsidiaries have received
notice from regulatory authorities or others that they are considered to be
potentially responsible parties in connection with sites found to require
remediation due to the presence of environmental contaminants. In addition, the
Company has been named as a defendant in litigation related to such sites and in
recent years has been named, along with numerous others, as a defendant in
several lawsuits filed by a large number of individuals who claim injury due to
exposure to asbestos while working at sites along the Texas Gulf Coast. Most of
these claimants have been workers who participated in construction of various
industrial facilities, including power plants, and some of the claimants have
worked at locations owned by the Company. The Company anticipates that
additional claims like those received may be asserted in the future and intends
to continue its practice of vigorously contesting claims which it does not
consider to have merit. Although their ultimate outcome cannot be predicted at
this time, the Company does not believe, based on its experience to date, that
these matters, either individually or in the aggregate, will have a material
adverse effect on the Company's financial position, results of operation or cash
flows.
 
     There exists the possibility that additional legislation related to global
climate change, electromagnetic fields and other environmental and health issues
may be enacted. Compliance with such legislation could significantly affect the
Company and its subsidiaries. The precise impact of new legislation, if any,
will depend on the form of the legislation and the subsequent development and
implementation of applicable regulations.
 
OTHER CONTINGENCIES
 
     For a description of certain other legal and regulatory proceedings
affecting the Company and its subsidiaries, see Notes 3, 4, 5 and 12 to the
Company's Consolidated Financial Statements, which notes are incorporated herein
by reference.
 
                        LIQUIDITY AND CAPITAL RESOURCES
 
COMPANY CONSOLIDATED CAPITAL REQUIREMENTS
 
     The liquidity and capital requirements of the Company and its subsidiaries
are affected primarily by capital programs and debt service requirements. The
capital requirements for 1997 were, and as estimated for 1998 through 2000 are,
as follows:
 
<TABLE>
<CAPTION>
                                                           MILLIONS OF DOLLARS
                                                     --------------------------------
                                                     1997     1998     1999     2000
                                                     ----    ------    ----    ------
<S>                                                  <C>     <C>       <C>     <C>
Electric capital and nuclear fuel (excluding
  Allowance for funds used during construction)
  (AFUDC)..........................................  $234    $  331    $343    $  308
Natural Gas Distribution(1)........................    61       138     146       150
Interstate Pipeline(1).............................    16        73      17        17
Energy Marketing(1)................................    14         8       7         8
International project expenditures (excluding
  capitalized
  interest)(2).....................................   224         8       2         4
Corporate (excluding HIPG).........................    20        13      16        12
HIPG project expenditures (excluding capitalized
  interest)(2).....................................     3       311      26
Maturities of long-term debt, preferred stock and
  minimum capital lease payments...................   282       233     380     1,430
                                                     ----    ------    ----    ------
Total(3)...........................................  $854    $1,115    $937    $1,929
                                                     ====    ======    ====    ======
</TABLE>
 
---------------
 
(1) The 1997 capital expenditures for Natural Gas Distribution, Interstate
    Pipeline and Energy Marketing are reported on an actual basis and reflect
    expenditures only for the period from the effective date of the
 
                                       46
<PAGE>   49
 
    Merger, August 6, 1997, through December 31, 1997. On a pro forma basis
    after giving effect to the Merger on January 1, 1997, the capital
    expenditures for these business segments would have been: Natural Gas
    Distribution ($131 million), Interstate Pipeline ($26 million) and Energy
    Marketing ($24 million).
 
(2) Expenditures in the table reflect only expenditures made or to be made under
    existing contractual commitments entered into by International and HIPG.
    International and HIPG capital requirements are expected to be met through
    advances from the Company, the proceeds of project financings and the
    proceeds of borrowings at the Company's financial subsidiaries. Additional
    capital expenditures are dependent upon the nature and extent of future
    project commitments (some of which may be substantial). Expenditures for
    1998 include a $237 million commitment by HIPG to purchase four power plants
    from Southern California Edison, which commitment was entered into in the
    fourth quarter of 1997.
 
(3) Expenditures in the table do not reflect expenditures associated with the
    Year 2000 issue and other system integration issues. For a discussion of
    these expenditures, see "-- Certain Factors Affecting Future Earnings of the
    Company and its Subsidiaries -- Impact of Year 2000 Issue and Other System
    Implementation Issues."
 
     The foregoing estimates are forward looking statements and are based on
numerous assumptions, some of which may prove to be incorrect. Actual liquidity
and capital requirements will also vary because of changes in governmental
regulations, the resolution of various litigation and other contingencies and
changes in economic conditions.
 
     The Company and its subsidiaries generated $1.1 billion in cash flow from
operations in 1997. Substantially all of the Company's and its subsidiaries'
cash flow resulted from $421 million of income from continuing operations and
$652 million of non-cash depreciation and amortization expense. The Company used
this cash flow to reinvest in its existing businesses, to meet its dividend
requirements and to contribute to the financing of business expansion.
 
     Overall, the Company's cash flow from operating activities in 1997 exceeded
its cash flow from non-acquisition investing activities by $787 million. With
respect to acquisition activities, the Company invested $1.4 billion of cash in
the acquisition of NorAm and $235 million of cash in non-rate regulated electric
power project expenditures in 1997.
 
     In the first quarter of 1997, the Company repaid at maturity $40 million
aggregate principal amount of its 5 1/4% first mortgage bonds and $150 million
aggregate principal amount of its 7 5/8% first mortgage bonds.
 
     In April 1997, the Company redeemed all remaining 257,000 shares of its
$9.375 cumulative preferred stock pursuant to mandatory sinking fund
requirements at a cost of $25.7 million, plus accrued dividends. For additional
information, see Note 7(a) to the Company's Consolidated Financial Statements.
 
     In June 1997, the Company purchased $57.6 million aggregate principal
amount of its 9.15% first mortgage bonds due 2021 for a total price of $69.6
million, plus accrued interest. In November 1997, the Company repaid at maturity
$35 million aggregate principal amount of its 6 3/4% first mortgage bonds.
 
     In the fourth quarter of 1997, NorAm purchased $101.4 million aggregate
principal amount of its 10% Debentures due 2019 at an average price of 111.976%
plus accrued interest. In December 1997, NorAm repaid at maturity $52 million
aggregate principal amount of its medium term notes.
 
COMPANY CONSOLIDATED SOURCES OF CAPITAL RESOURCES AND LIQUIDITY
 
     In 1997, two Delaware business trusts established by the Company issued
capital securities and preferred securities aggregating $350 million. The trusts
sold securities to the public ($100 million of 8.257% capital securities and
$250 million of 8.125% preferred securities) and used the proceeds to purchase
subordinated debentures from the Company. The Company used the proceeds from the
sale of the subordinated debentures for general corporate purposes, including
the repayment of short-term debt and the redemption of three series
 
                                       47
<PAGE>   50
 
of cumulative preferred stock having an aggregate liquidation value of $125
million. For further discussion, see Note 9(a) to the Company's Consolidated
Financial Statements.
 
     In 1997, the Company sold in open market transactions 550,000 shares of
Time Warner common stock for approximately $25 million and transferred the
remaining 450,000 shares of its Time Warner common stock (having a market value
of $21.9 million) to Houston Industries Incorporated Foundation, a charitable
foundation not included in the Company's consolidated results, which was formed
to fund certain charitable activities in communities where the Company conducts
its business.
 
     In April 1997, a subsidiary of HI Energy borrowed $162.5 million under a
$167.5 million five-year term loan facility. The proceeds of the loan, net of a
$17.5 million debt reserve account established for the benefit of the lenders,
were used to refinance a portion of the acquisition costs of Light.
 
     In July 1997, the Company issued $1.052 billion aggregate face amount of
ACES. The Company used the proceeds from the sale of ACES for general corporate
purposes, including the retirement of then outstanding commercial paper. For
additional information regarding the ACES, see Note 8(e) to the Company's
Consolidated Financial Statements.
 
     In August 1997, FinanceCo, a limited partnership subsidiary of the Company,
entered into a five-year, $1.6 billion revolving credit facility (FinanceCo
Facility). At December 31, 1997, the FinanceCo Facility supported $1.4 billion
in commercial paper borrowings having a weighted average interest rate of 6.15%.
Proceeds from the initial issuances of commercial paper by FinanceCo were used
to fund the cash portion of the consideration paid to stockholders of NorAm
under the terms of the Merger. For additional information regarding the
FinanceCo Facility, see Note 8(c) to the Company's Consolidated Financial
Statements.
 
     At December 31, 1997, the Company, exclusive of NorAm and other
subsidiaries, had a revolving credit facility of $200 million with no borrowings
outstanding. In addition, at December 31, 1997, the Company had shelf
registration statements providing for the future issuance, subject to market and
other conditions, of $230 million aggregate liquidation value of its preferred
stock and $580 million aggregate principal amount of its debt securities.
 
     At December 31, 1997, NorAm had (i) a $400 million revolving credit
facility under which loans of $340 million were outstanding, (ii) uncommitted
lines of credit under which loans of $50 million were outstanding, (iii) a trade
receivables facility of $300 million under which receivables of $300 million had
been sold and (iv) a shelf registration statement, filed with the Securities and
Exchange Commission in November 1997, providing for the future issuance of debt
securities of up to $500 million (NorAm Shelf Registration). For information
regarding the Company's maturing long-term debt (including NorAm's long-term
debt), see Note 8 to the Company's Consolidated Financial Statements.
 
     In January 1998, pollution control revenue bonds aggregating $104.7 million
were issued on behalf of the Company by the Matagorda County Navigation District
Number One (MCND). Proceeds from the issuance were used in February 1998 to
redeem, at 102% of the aggregate principal amount, pollution control revenue
bonds aggregating $104.7 million.
 
     In February 1998, pursuant to the NorAm Shelf Registration, NorAm issued
$300 million of 6.5% debentures due February 1, 2008. The proceeds from the sale
of the debentures were used to repay short-term indebtedness of NorAm, including
the indebtedness incurred in connection with the purchase of $101.4 million of
its 10% debentures and the repayment of $53 million aggregate principal amount
of NorAm debt that matured in December 1997 and January 1998.
 
     In February 1998, pollution control revenue bonds aggregating $290 million
were issued on behalf of the Company by the Brazos River Authority (BRA).
Proceeds from the issuance will be used to redeem, at 102% of the aggregate
principal amount, pollution control revenue bonds aggregating $290 million.
 
     The Company owns 11 million shares of non-publicly traded TW Preferred. The
TW Preferred, which is entitled to cumulative annual dividends of $3.75 per
share until July 6, 1999, is currently convertible at the option of the Company
into 22.9 million shares of Time Warner common stock. The Company's ability to
transfer, sell or pledge the shares of TW Preferred is not restricted pursuant
to the terms of the ACES. The
                                       48
<PAGE>   51
 
Company reviews its investment in Time Warner on a regular basis and does not
expect to maintain its investment in Time Warner indefinitely. For additional
information regarding the Company's investment in Time Warner securities, see
Notes 1(n) and 8(e) to the Company's Consolidated Financial Statements.
 
     The Company has consolidated its financing activities in order to provide a
coordinated, cost-effective method of meeting short- and long-term capital
requirements. As part of the consolidated financing program, the Company has
established a "money fund" through which its subsidiaries can borrow or invest
on a short-term basis. The funding requirements of individual subsidiaries are
aggregated and borrowing or investing is based on the net cash position. In
1997, net funding requirements under the money fund were met with commercial
paper.
 
     Although the Company believes that its current level of cash and borrowing
capability along with future cash flows from operations are sufficient to meet
the needs of its existing businesses, the Company may, when it deems necessary,
supplement its available cash resources by seeking funds in the equity or debt
markets.
 
                             NEW ACCOUNTING ISSUES
 
     In February 1997, the Financial Accounting Standards Board (FASB) issued
SFAS No. 128, "Earnings per Share" (SFAS No. 128) which is required to be
implemented for financial statements issued for fiscal years ending after
December 15, 1997. In 1997, the Company adopted SFAS No. 128 and retroactively
restated prior periods. For further discussion, see Note 1(j) to the Company's
Consolidated Financial Statements.
 
     The FASB recently issued SFAS No. 130, "Reporting Comprehensive Income"
(SFAS No. 130), SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information" (SFAS No. 131) and SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits" (SFAS No. 132) effective for
financial statements issued for fiscal periods beginning after December 15,
1997. SFAS No. 130 requires that all items that meet the definition of a
component of comprehensive income be reported in a financial statement for the
period in which they are recognized and the total amount of comprehensive income
be prominently displayed in that same financial statement. Comprehensive income
is defined as the change in equity of a business enterprise during a period from
transactions and other events and circumstances from non-owner sources.
Currently, the Company does not have any material items which require reporting
of comprehensive income. SFAS No. 131 requires that companies report financial
and descriptive information about reportable operating segments in financial
statements. Segments are to be defined based upon the way in which management
reviews its operations in order to assess performance and allocate its
resources. SFAS No. 132 revises employers' disclosures about pension and other
postretirement benefit plans. The Company will adopt SFAS No. 130, SFAS No. 131
and SFAS No. 132 in 1998.
 
                                       49
<PAGE>   52
 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
     The following discussion of the Company and its subsidiaries' exposure to
various market risks contains "forward looking statements" that involve risks
and uncertainties. These projected results have been prepared utilizing certain
assumptions considered reasonable in the circumstances and in light of
information currently available to the Company and its subsidiaries.
Nevertheless, because of the inherent unpredictability of interest rates, equity
market prices and energy commodity prices as well as other factors, actual
results could differ materially from those projected in such forward-looking
information. For a description of the Company's significant accounting policies
associated with these activities, see Notes 1 and 2 to the Company's
Consolidated Financial Statements and Notes 1 and 2 to NorAm's Consolidated
Financial Statements.
 
INTEREST RATE RISK
 
     The Company and its subsidiaries have long-term debt, Company/NorAm
obligated mandatorily redeemable securities of subsidiary trusts holding solely
subordinated debentures of the Company/NorAm (Trust Securities), securities held
in the Company's nuclear decommissioning trust, short-term credit lines and
facilities, certain lease obligations and interest rate swaps which subject the
Company and certain of its subsidiaries to the risk of loss associated with
movements in market interest rates.
 
     At December 31, 1997, the Company and certain of its subsidiaries had
fixed-rate long-term debt (excluding ACES) and Trust Securities aggregating $4.2
billion in principal amount and having a fair value of $4.4 billion. These
instruments are fixed-rate and, therefore, do not expose the Company and its
subsidiaries to the risk of earnings loss due to changes in market interest
rates (see Notes 8 and 9 to the Company's Consolidated Financial Statements).
However, the fair value of these instruments would increase by approximately
$247.5 million if interest rates were to decline by 10% from their levels at
December 31, 1997. In general, such an increase in fair value would impact
earnings and cash flows only if the Company and its subsidiaries were to
reacquire all or a portion of these instruments in the open market prior to
their maturity.
 
     The Company and certain of its subsidiaries' floating-rate obligations
aggregated $2.6 billion at December 31, 1997 (see Note 8 to the Company's
Consolidated Financial Statements), inclusive of (i) amounts borrowed under
short-term and long-term credit lines and facilities of the Company and its
subsidiaries, (ii) borrowings underlying NorAm's receivables facility and (iii)
amounts subject to a master leasing agreement under which lease payments vary
depending on short-term interest rates, which expose the Company and its
subsidiaries to the risk of increased interest and lease expense in the event of
increases in short-term interest rates. If the floating rates were to increase
by 10% from December 31, 1997 levels, the Company's consolidated interest
expense and expense under operating leases would increase by a total of
approximately $1.4 million each month in which such increase continued.
 
     As discussed in Notes 1, 4 and 13 to the Company's Consolidated Financial
Statements, the Company contributes $14.8 million per year to a trust
established to fund the Company's share of the decommissioning costs for the
South Texas Project. The securities held by the trust for decommissioning costs
had an estimated fair value of $92.9 million as of December 31, 1997, of which
approximately 50 percent were fixed-rate debt securities that subject the
Company to risk of loss of fair value with movements in market interest rates.
If interest rates were to increase by 10% from their levels at December 31,
1997, the decrease in fair value of the fixed-rate debt securities would not be
material to the Company. In addition, the risk of an economic loss is mitigated
as a result of the Company's regulated status. Any unrealized gains or losses
are accounted for in accordance with SFAS No. 71 as a regulatory asset/liability
because the Company believes that its future contributions which are currently
recovered through the rate making process will be adjusted for these gains and
losses.
 
     Certain subsidiaries of the Company have entered into interest rate swaps
for the purpose of decreasing the amount of debt subject to interest rate
fluctuations. At December 31, 1997, these interest rate swaps had an aggregate
notional amount of $281.1 million, which the Company could terminate at a cost
of $2.4 million (see Notes 2 and 13 to the Company's Consolidated Financial
Statements). An increase of 10% in the December 31, 1997 level of interest rates
would not increase the cost of termination of the swaps by a material
 
                                       50
<PAGE>   53
 
amount to the Company. Swap termination costs would impact the Company and its
subsidiaries' earnings and cash flows only if all or a portion of the swap
instruments were terminated prior to their expiration.
 
EQUITY MARKET RISK
 
     The Company holds an investment in TW Preferred which is convertible into
Time Warner common stock as described in "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of
ACES" in Item 7 of this Form 10-K. As a result, the Company is exposed to losses
in the fair value of this security. For purposes of analyzing market risk in
this Item 7A, the Company assumed that the TW Preferred was converted into Time
Warner common stock. In addition, NorAm's investment in the common stock of
Itron, Inc. (Itron) exposes the Company and NorAm to losses in the fair value of
Itron Common Stock. A 10% decline in the per share price of Itron and Time
Warner common stock from the December 31, 1997 levels would result in a loss of
approximately $2.7 million and $142.0 million, respectively, in fair value.
 
     The Company and its subsidiaries' ability to realize gains and losses
related to TW Preferred and Itron is limited by the following: (i) the TW
Preferred is not publicly traded and its sale is subject to certain limitations
and (ii) the market for the common stock of Itron is fairly illiquid.
 
     The ACES expose the Company to accounting losses as the accounting for the
ACES requires the Company to record in Other Income (Expense) an unrealized
accounting loss equal to (i) the aggregate amount of the increase in the market
price of Time Warner common stock above $55.5844 as applicable to all ACES
multiplied by (ii) 0.8264. Prior to the conversion of the TW Preferred into Time
Warner common stock, such loss would effect earnings. After conversion such loss
would be recognized as an adjustment to common stock equity. See further
discussion of the accounting for the ACES in Notes 1 and 8 to the Company's
Consolidated Financial Statements. An increase of 15% in the price of the Time
Warner common stock above its December 31, 1997 market value of $62.00 per
share, would result in the recognition of an additional unrealized accounting
loss (net of tax) of approximately $114.4 million. The Company believes that
this additional unrealized loss for the ACES would be more than economically
hedged by the unrecorded unrealized gain relating to the increase in the fair
value of the Time Warner common stock underlying the investment in TW Preferred
since the date of its acquisition.
 
     As discussed above under "Interest Rate Risk," the Company contributes to a
trust established to fund the Company's share of the decommissioning costs for
the South Texas Project which held debt and equity securities in approximately
equal proportions as of December 31, 1997. The equity securities expose the
Company to losses in fair value. If the market prices of the individual equity
securities were to decrease by 10% from their levels at December 31, 1997, the
resulting loss in fair value of these securities would not be material to the
Company. Currently, the risk of an economic loss is mitigated as a result of the
Company's regulated status as discussed above under "Interest Rate Risk."
 
ENERGY COMMODITY PRICE RISK
 
     As further described in Note 2 to the Company's Consolidated Financial
Statements, certain of the Company's subsidiaries utilize a variety of
derivative financial instruments (Derivatives), including swaps and
exchange-traded futures and options, as part of the Company's overall risk
management strategies and for trading purposes. To reduce the risk from the
adverse effect of market fluctuations in the price of electric power, natural
gas and related transportation, NorAm and certain of its subsidiaries enter into
futures transactions, swaps and options (Energy Derivatives) in order to hedge
certain natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas and electric power (a portion of which are firm
commitments at the inception of the hedge). The Company's policies prohibit the
use of leveraged financial instruments. In addition, a subsidiary of NorAm
maintains a portfolio of Energy Derivatives for trading purposes (Trading
Derivatives).
 
     The Company uses a sensitivity analysis method for determining the market
risk of its Energy Derivatives, except for its Trading Derivatives, for which it
uses a value-at-risk method.
                                       51
<PAGE>   54
 
     With respect to the Energy Derivatives (other than for trading purposes)
held by subsidiaries of NorAm as of December 31, 1997, a decrease of 10% in the
market price of natural gas from the December 31, 1997 levels would decrease the
fair value of these instruments by approximately $7.0 million.
 
     The above analysis of the Energy Derivatives utilized for risk management
purposes does not include the favorable impact that the same hypothetical price
movement would have on the Company and its subsidiaries' physical purchases and
sales of natural gas and electric power. The portfolio of Energy Derivatives
held for risk management purposes approximates the notional quantity of the
expected or committed transaction volume of physical commodities with commodity
price risk for the same time periods. Furthermore, the Energy Derivative
portfolio is managed to complement the physical transaction portfolio, reducing
overall risks within limits. Therefore, the adverse impact to the fair value of
the portfolio of Energy Derivatives held for risk management purposes associated
with the hypothetical changes in commodity prices referenced above would be
offset by a favorable impact on the underlying hedged physical transactions,
assuming (i) the Energy Derivatives are not closed out in advance of their
expected term, (ii) the Energy Derivatives continue to function effectively as
hedges of the underlying risk, and (iii) as applicable, anticipated transactions
occur as expected.
 
     The disclosure with respect to the Energy Derivatives relies on the
assumption that the contracts will exist parallel to the underlying physical
transactions. If the underlying transactions or positions are liquidated prior
to the maturity of the Energy Derivatives, a loss on the financial instruments
may occur, or the options might be worthless as determined by the prevailing
market value on their termination or maturity date, whichever comes first.
 
     With respect to the Trading Derivatives held by a subsidiary of NorAm,
consisting of natural gas and electric power swaps, options and exchange-traded
futures, this subsidiary is exposed to losses in fair value due to price
movement. During the year ended December 31, 1997, the highest, lowest and
average quarterly value-at-risk in the Trading Derivative portfolio was less
than $5.0 million at a 95-percent confidence level and for a holding period of
one business day. The Company uses the variance/covariance method for
calculating the value-at-risk and includes the delta approximation for options
positions.
 
     The Company has established a Corporate Risk Oversight Committee that
oversees all corporate price and credit risk, including derivative trading
activities discussed above. The committee's duties are to establish the
Company's policies and to monitor and ensure compliance with risk management
limitations, policies and procedures.
 
                                       52
<PAGE>   55
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF THE COMPANY.
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                       STATEMENTS OF CONSOLIDATED INCOME
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                         --------------------------------------
                                                            1997          1996          1995
                                                         ----------    ----------    ----------
<S>                                                      <C>           <C>           <C>
Revenues:
  Electric Operations..................................  $4,251,243    $4,025,027    $3,680,297
  Natural Gas Distribution.............................     892,569
  Interstate Pipeline..................................     108,333
  Energy Marketing.....................................   1,604,999
  International........................................      92,028        62,059        46,789
  Other................................................      47,851         8,191         2,185
  Eliminations.........................................    (123,638)
                                                         ----------    ----------    ----------
          Total........................................   6,873,385     4,095,277     3,729,271
                                                         ----------    ----------    ----------
Expenses:
  Electric and natural gas utilities:
     Fuel and cost of gas sold.........................   2,819,512     1,024,945       879,148
     Purchased power...................................     698,823       322,263       233,494
     Operation and maintenance.........................   1,205,993       888,699       866,170
     Taxes other than income taxes.....................     296,668       246,288       245,890
  Depreciation and amortization........................     651,875       550,038       478,034
  Other operating expenses.............................     136,014        72,578       121,085
                                                         ----------    ----------    ----------
          Total........................................   5,808,885     3,104,811     2,823,821
                                                         ----------    ----------    ----------
Operating Income.......................................   1,064,500       990,466       905,450
                                                         ----------    ----------    ----------
Other Income (Expense):
  Unrealized loss on ACES..............................    (121,402)
  Litigation settlements...............................                   (95,000)
  Time Warner dividend income..........................      41,340        41,610        20,132
  Interest income......................................       6,636         6,246         9,774
  Interest income -- IRS refund........................      56,269
  Other -- net.........................................       3,711        (8,268)      (12,061)
                                                         ----------    ----------    ----------
          Total........................................     (13,446)      (55,412)       17,845
                                                         ----------    ----------    ----------
Interest and Other Charges:
  Interest on long-term debt...........................     320,845       276,242       279,491
  Other interest.......................................      77,112        33,738        21,586
  Distribution on trust securities.....................      26,230
  Allowance for borrowed funds used during
     construction......................................      (2,872)       (2,598)       (4,692)
  Preferred dividends of subsidiary....................       2,255        22,563        29,955
                                                         ----------    ----------    ----------
          Total........................................     423,570       329,945       326,340
                                                         ----------    ----------    ----------
Income from Continuing Operations Before Income
  Taxes................................................     627,484       605,109       596,955
Income Taxes...........................................     206,374       200,165       199,555
                                                         ----------    ----------    ----------
Income from Continuing Operations......................     421,110       404,944       397,400
Discontinued Operations (Net of Income Taxes):
  Gain on sale of cable television subsidiary..........                                 708,124
Preferred Dividends....................................         162
                                                         ----------    ----------    ----------
Net Income.............................................  $  420,948    $  404,944    $1,105,524
                                                         ==========    ==========    ==========
</TABLE>
 
                                                        (continued on next page)
 
                                       53
<PAGE>   56
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                       STATEMENTS OF CONSOLIDATED INCOME
                                  (CONTINUED)
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                         --------------------------------------
                                                            1997          1996          1995
                                                         ----------    ----------    ----------
<S>                                                      <C>           <C>           <C>
Basic Earnings Per Common Share:
  Continuing Operations................................  $     1.66    $     1.66    $     1.60
  Discontinued Operations:
     Gain on sale of cable television subsidiary.......                                    2.86
                                                         ----------    ----------    ----------
Basic Earnings Per Common Share........................  $     1.66    $     1.66    $     4.46
                                                         ==========    ==========    ==========
Diluted Earnings Per Common Share:
  Continuing Operations................................  $     1.66    $     1.66    $     1.60
  Discontinued Operations:
     Gain on sale of cable television subsidiary.......                                    2.86
                                                         ----------    ----------    ----------
Diluted Earnings Per Common Share......................  $     1.66    $     1.66    $     4.46
                                                         ==========    ==========    ==========
</TABLE>
 
         See Notes to the Company's Consolidated Financial Statements.
 
                                       54
<PAGE>   57
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                  STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
                (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
 
<TABLE>
<CAPTION>
                                                                   YEAR ENDED DECEMBER 31,
                                                             ------------------------------------
                                                                1997         1996         1995
                                                             ----------   ----------   ----------
<S>                                                          <C>          <C>          <C>
Balance at Beginning of Year...............................  $1,997,490   $1,953,672   $1,221,221
Add -- Net Income..........................................     420,948      404,944    1,105,524
                                                             ----------   ----------   ----------
          Total............................................   2,418,438    2,358,616    2,326,745
Common Stock Dividends:
     1997, $1.50; 1996, $1.50; 1995, $1.50 (per share).....    (405,383)    (361,126)    (371,760)
Stock Dividend Distribution................................                                (1,313)
                                                             ----------   ----------   ----------
Balance at End of Year.....................................  $2,013,055   $1,997,490   $1,953,672
                                                             ==========   ==========   ==========
</TABLE>
 
         See Notes to the Company's Consolidated Financial Statements.
 
                                       55
<PAGE>   58
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                          CONSOLIDATED BALANCE SHEETS
                             (THOUSANDS OF DOLLARS)
 
                                     ASSETS
 
<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 1997           1996
                                                              -----------    -----------
<S>                                                           <C>            <C>
Property, Plant and Equipment -- At Cost:
  Electric plant:
     Plant in service.......................................  $12,614,000    $12,387,375
     Construction work in progress..........................      224,959        251,497
     Nuclear fuel...........................................      255,567        241,001
     Plant held for future use..............................       48,631         48,631
  Gas plant and pipelines:
     Natural gas distribution...............................    1,326,442
     Interstate pipelines...................................    1,258,087
     Energy marketing.......................................      162,519
  Other property............................................      149,019         86,969
                                                              -----------    -----------
          Total.............................................   16,039,224     13,015,473
  Less accumulated depreciation and amortization............    4,770,179      4,259,050
                                                              -----------    -----------
          Property, plant and equipment -- net..............   11,269,045      8,756,423
                                                              -----------    -----------
Current Assets:
  Cash and cash equivalents.................................       51,712          8,001
  Accounts receivable -- net................................      962,974         36,277
  Accrued unbilled revenues.................................      205,860         77,853
  Time Warner dividends receivable..........................       10,313         10,313
  Fuel stock and petroleum products.........................       88,819         61,795
  Materials and supplies, at average cost...................      156,160        130,380
  Prepayments and other current assets......................       42,169         19,301
                                                              -----------    -----------
          Total current assets..............................    1,518,007        343,920
                                                              -----------    -----------
Other Assets:
  Goodwill -- net...........................................    2,026,395
  Investment in Time Warner securities......................      990,000      1,027,500
  Deferred plant costs -- net...............................      561,569        587,352
  Fuel-related debits.......................................      197,304         84,435
  Deferred debits...........................................      510,686        306,473
  Unamortized debt expense and premium on reacquired debt...      202,453        153,823
  Regulatory tax asset -- net...............................      356,509        362,310
  Recoverable project costs -- net..........................       78,485        163,630
  Equity investments in foreign and non-rate regulated
     affiliates -- net......................................      704,102        501,991
                                                              -----------    -----------
          Total other assets................................    5,627,503      3,187,514
                                                              -----------    -----------
            Total...........................................  $18,414,555    $12,287,857
                                                              ===========    ===========
</TABLE>
 
         See Notes to the Company's Consolidated Financial Statements.
 
                                       56
<PAGE>   59
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                          CONSOLIDATED BALANCE SHEETS
                             (THOUSANDS OF DOLLARS)
 
                         CAPITALIZATION AND LIABILITIES
 
<TABLE>
<CAPTION>
                                                                     DECEMBER 31,
                                                              --------------------------
                                                                 1997           1996
                                                              -----------    -----------
<S>                                                           <C>            <C>
Capitalization (statements on following pages):
  Common stock equity.......................................  $ 4,886,805    $ 3,827,961
  Preference stock, none outstanding........................
  Cumulative preferred stock, not subject to mandatory
     redemption.............................................        9,740        135,179
  Company/NorAm obligated mandatorily redeemable preferred
     securities of subsidiary trusts holding solely junior
     subordinated debentures of Company/NorAm...............      362,172
  Long-term debt............................................    5,218,015      3,025,650
                                                              -----------    -----------
          Total capitalization..............................   10,476,732      6,988,790
                                                              -----------    -----------
Current Liabilities:
  Notes payable.............................................    2,124,956      1,337,872
  Accounts payable..........................................      879,612        157,682
  Taxes accrued.............................................      240,739        191,011
  Interest accrued..........................................      109,901         67,707
  Dividends declared........................................      110,716         92,515
  Customer deposits.........................................       82,437         53,633
  Current portion of long-term debt and preferred stock.....      251,169        254,463
  Other.....................................................      193,384         89,238
                                                              -----------    -----------
          Total current liabilities.........................    3,992,914      2,244,121
                                                              -----------    -----------
Deferred Credits:
  Accumulated deferred income taxes.........................    2,792,781      2,265,031
  Benefit liabilities.......................................      397,586        249,875
  Unamortized investment tax credit.........................      349,072        373,749
  Fuel-related credits......................................       75,956         74,639
  Other.....................................................      329,514         91,652
                                                              -----------    -----------
          Total deferred credits............................    3,944,909      3,054,946
                                                              -----------    -----------
Commitments and Contingencies (Note 12)
              Total.........................................  $18,414,555    $12,287,857
                                                              ===========    ===========
</TABLE>
 
          See Notes to the Company's Consolidated Financial Statements
 
                                       57
<PAGE>   60
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                   CONSOLIDATED STATEMENTS OF CAPITALIZATION
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 1997           1996
                                                              -----------    ----------
<S>                                                           <C>            <C>
Common Stock Equity:
  Common stock, no par; authorized, 700,000,000 shares;
     issued, 295,357,276 and 262,748,447 shares at December
     31, 1997 and 1996, respectively........................  $ 3,112,098    $2,447,117
  Foreign currency translation loss.........................         (821)         (363)
  Treasury stock, at cost; 93,459 and 16,042,027 shares at
     December 31, 1997 and 1996, respectively...............       (2,066)     (361,196)
  Unearned ESOP shares, 12,388,551 and 13,370,939 shares at
     December 31, 1997 and 1996, respectively...............     (229,827)     (251,350)
  Retained earnings.........................................    2,013,055     1,997,490
  Unrealized loss on marketable equity securities...........       (5,634)       (3,737)
                                                              -----------    ----------
          Total common stock equity.........................    4,886,805     3,827,961
                                                              -----------    ----------
Preference Stock, no par; authorized, 10,000,000 shares;
  none outstanding..........................................
Cumulative Preferred Stock, no par; authorized, 10,000,000
  shares; outstanding, 97,397 and 1,604,397 shares at
  December 31, 1997 and 1996, respectively (entitled upon
  involuntary liquidation to $100 per share):
  Not subject to mandatory redemption:
     $4.00 series, 97,397 shares............................        9,740         9,740
     $6.72 series, 250,000 shares...........................                     25,115
     $7.52 series, 500,000 shares...........................                     50,226
     $8.12 series, 500,000 shares...........................                     50,098
                                                              -----------    ----------
          Total.............................................        9,740       135,179
                                                              -----------    ----------
  Subject to mandatory redemption:
     $9.375 series, 257,000 shares at December 31, 1996.....                     25,700
     Current redemptions....................................                    (25,700)
                                                              -----------    ----------
          Total.............................................
                                                              -----------    ----------
          Total cumulative preferred stock..................        9,740       135,179
                                                              -----------    ----------
Company/NorAm obligated mandatorily redeemable preferred
  securities of subsidiary trusts holding solely junior
  subordinated debentures of Company/NorAm:
     8.125% Trust Preferred Securities, Series A............      250,000
     8.257% Trust Capital Securities, Series B..............      100,000
     6 1/4% Convertible Trust Originated Preferred
      Securities............................................       21,730
     Unamortized Issuance Costs.............................       (9,558)
                                                              -----------    ----------
          Total Company/NorAm obligated mandatorily
            redeemable preferred securities of subsidiary
            trusts holding solely junior subordinated
            debentures of Company/NorAm-net.................      362,172
                                                              -----------    ----------
Long-Term Debt:
  7% Automatic common exchange securities, due 2000.........    1,173,786
                                                              -----------    ----------
</TABLE>
 
                                                        (continued on next page)
                                       58
<PAGE>   61
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
            CONSOLIDATED STATEMENTS OF CAPITALIZATION -- (CONTINUED)
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 1997           1996
                                                              -----------    ----------
<S>                                                           <C>            <C>
  Debentures:
     9 3/8% series, due 2001................................  $   250,000    $  250,000
     7 7/8% series, due 2002................................      100,000       100,000
     8.9% series, due 2006..................................      165,055
     6% convertible subordinated, due 2012..................      107,180
     10% series, due 2019...................................       47,773
     Unamortized discount...................................         (717)         (902)
                                                              -----------    ----------
          Total debentures..................................      669,291       349,098
                                                              -----------    ----------
  First Mortgage Bonds:
     5 1/4% series, due 1997................................                     40,000
     7 5/8% series, due 1997................................                    150,000
     6 3/4% series, due 1997................................                     35,000
     9.15% series, due 2021.................................      102,442       160,000
     8 3/4% series, due 2022................................       62,275        62,275
     7 3/4% series, due 2023................................      250,000       250,000
     7 1/2% series, due 2023................................      200,000       200,000
     4.90% pollution control series, due 2003...............       16,600        16,600
     7% pollution control series, due 2008..................       19,200        19,200
     6 3/8% pollution control series, due 2012..............       33,470        33,470
     6 3/8% pollution control series, due 2012..............       12,100        12,100
     8 1/4% pollution control series, due 2015..............       90,000        90,000
     5.80% pollution control series, due 2015...............       91,945        91,945
     7 3/4% pollution control series, due 2015..............       68,700        68,700
     5.80% pollution control series, due 2015...............       58,905        58,905
     7 7/8% pollution control series, due 2016..............                     68,000
     6.70% pollution control series, due 2017...............       43,820        43,820
     5.60% pollution control series, due 2017...............       83,565        83,565
     7 7/8% pollution control series, due 2018..............                     50,000
     7.20% pollution control series, due 2018...............       75,000        75,000
     7.20% pollution control series, due 2018...............      100,000       100,000
     7 7/8% pollution control series, due 2019..............       29,685        29,685
     7.70% pollution control series, due 2019...............       75,000        75,000
     8 1/4% pollution control series, due 2019..............      100,000       100,000
     8.10% pollution control series, due 2019...............      100,000       100,000
     7 5/8% pollution control series, due 2019..............      100,000       100,000
     7 1/8% pollution control series, due 2019..............      100,000       100,000
     7.60% pollution control series, due 2019...............       70,315        70,315
     6.70% pollution control series, due 2027...............       56,095        56,095
     Medium-term notes, series A, 9.80%-9.85%, due 1999.....      170,500       170,500
     Medium-term notes, series C, 6.10%, due 2000...........      150,000       150,000
     Medium-term notes, series B, 8.15%, due 2002...........      100,000       100,000
     Medium-term notes, series C, 6.50%, due 2003...........      150,000       150,000
     Unamortized discount...................................      (14,158)      (15,134)
                                                              -----------    ----------
          Total first mortgage bonds........................    2,495,459     2,895,041
                                                              -----------    ----------
</TABLE>
 
                                                        (continued on next page)
                                       59
<PAGE>   62
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
            CONSOLIDATED STATEMENTS OF CAPITALIZATION -- (CONTINUED)
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 1997           1996
                                                              -----------    ----------
<S>                                                           <C>            <C>
Pollution Control Revenue Bonds:
  Gulf Coast 1980-T series, floating rate, due 1998.........  $     5,000    $    5,000
  1997 pollution control series, variable rate revenue due
     2028...................................................       68,000
  1997 pollution control series, variable rate revenue due
     2018...................................................       50,000
                                                              -----------    ----------
          Total pollution control revenue bonds.............      123,000         5,000
                                                              -----------    ----------
Medium-Term Notes:
  Series A, 9.30%-9.39%, due 1998-2000......................       24,838
  Series B, 8.43%-9.23%, due 1998-2001......................      236,367
                                                              -----------    ----------
          Total medium-term notes...........................      261,205
                                                              -----------    ----------
Capitalized lease obligations, discount rates of 5.2%-11.7%,
  due 1998-2018.............................................       16,166         4,418
Notes payable...............................................      730,277           856
                                                              -----------    ----------
     Subtotal...............................................      746,443         5,274
                                                              -----------    ----------
          Total.............................................    5,469,184     3,254,413
          Current maturities................................     (251,169)     (228,763)
                                                              -----------    ----------
          Total long-term debt..............................    5,218,015     3,025,650
                                                              -----------    ----------
               Total capitalization.........................  $10,476,732    $6,988,790
                                                              ===========    ==========
</TABLE>
 
         See Notes to the Company's Consolidated Financial Statements.
 
                                       60
<PAGE>   63
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                     STATEMENTS OF CONSOLIDATED CASH FLOWS
 
                INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                           -----------------------------------
                                                              1997         1996        1995
                                                           -----------   ---------   ---------
<S>                                                        <C>           <C>         <C>
Cash Flows from Operating Activities:
  Income from continuing operations......................  $   421,110   $ 404,944   $ 397,400
  Adjustments to reconcile income from continuing
     operations to net cash provided by operating
     activities:
     Depreciation and amortization.......................      651,875     550,038     478,034
     Amortization of nuclear fuel........................       28,237      33,875      28,545
     Deferred income taxes...............................       35,523      54,098      78,382
     Investment tax credit...............................      (19,777)    (18,404)    (19,427)
     Unrealized loss on ACES.............................      121,402
     Contribution of marketable equity securities to
       charitable trust..................................       19,463
     Fuel (refund)/surcharge.............................      128,864                (189,571)
     Fuel cost over (under) recovery.....................     (212,683)   (137,362)     76,970
     Net cash provided by discontinued cable television
       operations........................................                               16,391
     Changes in other assets and liabilities, net of the
       effects of the acquisition:
       Accounts receivable -- net........................     (436,580)    (15,478)    (46,299)
       Inventory.........................................       55,111      21,624      13,901
       Other current assets..............................        6,966        (306)    (14,900)
       Accounts payable..................................      191,840      21,674     (23,217)
       Interest and taxes accrued........................       18,425       4,413      11,088
       Other current liabilities.........................        2,985      (4,135)     (9,215)
       Other -- net......................................       97,998        (661)     46,813
                                                           -----------   ---------   ---------
          Net cash provided by operating activities......    1,110,759     914,320     844,895
                                                           -----------   ---------   ---------
Cash Flows from Investing Activities:
  Capital expenditures (including allowance for borrowed
     funds used during construction).....................     (328,724)   (317,532)   (301,327)
  Purchase of NorAm net of cash acquired.................   (1,422,672)
  Non-rate regulated electric power project expenditures
     (including capitalized interest)....................     (234,852)   (495,379)    (49,835)
  Settlement of subsidiary debt in connection with sale
     of cable television subsidiary......................                              619,345
  Sale of investment in Time Warner common stock.........       25,043
  Corporate headquarters expenditures (including
     capitalized interest)...............................                   (6,543)    (96,469)
  Net cash used in discontinued cable television
     operations..........................................                              (47,601)
  Other -- net...........................................      (20,248)    (13,446)     (4,643)
                                                           -----------   ---------   ---------
          Net cash provided by (used in) investing
            activities...................................   (1,981,453)   (832,900)    119,470
                                                           -----------   ---------   ---------
</TABLE>
 
                                                        (continued on next page)
                                       61
<PAGE>   64
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
              STATEMENTS OF CONSOLIDATED CASH FLOWS -- (CONTINUED)
 
                INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                                 YEAR ENDED DECEMBER 31,
                                                           -----------------------------------
                                                              1997         1996        1995
                                                           -----------   ---------   ---------
<S>                                                        <C>           <C>         <C>
Cash Flows from Financing Activities:
  Proceeds from sale of ACES -- net......................  $ 1,020,777
  Proceeds from sale of Company obligated mandatorily
     redeemable preferred securities of subsidiary trusts
     holding solely junior subordinated debentures of
     Company -- net......................................      340,785
  Purchase of treasury stock.............................                $(361,196)
  Proceeds from issuance of pollution control bonds......      115,739
  Proceeds from first mortgage bonds.....................                            $ 142,972
  Payment of matured debt................................     (277,000)   (150,000)
  Payment of common stock dividends......................     (405,288)   (361,126)   (371,731)
  Redemption of preferred stock..........................     (153,628)   (271,400)    (91,400)
  Increase (decrease) in notes payable-net...............      587,791   1,331,572    (416,991)
  Extinguishment of long-term debt.......................     (303,893)   (285,263)   (195,224)
  Redemption of convertible securities...................       (9,504)
  Net cash used in discontinued cable television
     operations..........................................                              (40,798)
  Other -- net...........................................       (1,374)     12,215      10,143
                                                           -----------   ---------   ---------
          Net cash provided by (used in) financing
            activities...................................      914,405     (85,198)   (963,029)
                                                           -----------   ---------   ---------
Net Increase (Decrease) in Cash and Cash Equivalents.....       43,711      (3,778)      1,336
Cash and Cash Equivalents at Beginning of Year...........        8,001      11,779      10,443
                                                           -----------   ---------   ---------
Cash and Cash Equivalents at End of Year.................  $    51,712   $   8,001   $  11,779
                                                           ===========   =========   =========
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
  Interest (net of amounts capitalized)..................  $   437,952   $ 311,792   $ 342,551
  Income taxes...........................................      171,539     139,898     104,228
</TABLE>
 
The aggregate consideration paid to Former NorAm stockholders in connection with
the Merger consisted of $1.4 billion in cash and 47.8 million shares of the
Company's common stock valued at approximately $1.0 billion. The overall
transaction was valued at $4.0 billion consisting of $2.4 billion for Former
NorAm's common stock and common stock equivalents and $1.6 billion of Former
NorAm debt.
 
         See Notes to the Company's Consolidated Financial Statements.
 
                                       62
<PAGE>   65
 
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
 
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
(a) Nature of Operations.
 
     The Company (defined below), together with its subsidiaries, is a
diversified international energy services company. The Company is both an
electric utility company and a utility holding company. The Company's wholly
owned subsidiary, NorAm, operates in various phases of the natural gas industry,
including distribution, transmission, marketing and gathering.
 
(b) NorAm Acquisition.
 
     On August 6, 1997 (Acquisition Date), Houston Industries Incorporated
(Former HI) merged with and into Houston Lighting & Power Company, which was
renamed "Houston Industries Incorporated" (Company), and NorAm Energy Corp., a
natural gas gathering, transmission, marketing and distribution company (Former
NorAm) merged with and into a subsidiary of the Company, HI Merger, Inc., which
was renamed "NorAm Energy Corp." (NorAm). Effective upon the mergers
(collectively, the Merger), each outstanding share of common stock of Former HI
was converted into one share of common stock (including associated preference
stock purchase rights) of the Company, and each outstanding share of common
stock of Former NorAm was converted into the right to receive $16.3051 cash or
0.74963 shares of common stock of the Company. The aggregate consideration paid
to Former NorAm stockholders in connection with the Merger consisted of $1.4
billion in cash and 47.8 million shares of the Company's common stock valued at
approximately $1.0 billion. The overall transaction was valued at $4.0 billion
consisting of $2.4 billion for Former NorAm's common stock and common stock
equivalents and $1.6 billion of Former NorAm debt ($1.3 billion of which was
long-term debt).
 
     The Company has recorded the acquisition of NorAm under the purchase method
of accounting with assets and liabilities of NorAm reflected at their estimated
fair values as of the Acquisition Date. The Company has recorded the $2.0
billion excess of the acquisition cost over the fair value of the net assets
acquired as goodwill and is amortizing this amount over 40 years. On a
preliminary basis, the Company's fair value adjustments included increases in
property, plant and equipment, long-term debt, unrecognized pension and
postretirement benefits liabilities and related deferred taxes. The Company
expects to finalize these fair value adjustments during 1998; however, it is not
anticipated that any additional adjustments will be material.
 
     The Company's results of operations incorporate NorAm's results of
operations only for the period beginning on the Acquisition Date. The following
table presents certain unaudited pro forma information for the years ended
December 31, 1997 and 1996, as if the Merger had occurred on January 1, 1997 and
1996, respectively.
 
                    PRO FORMA COMBINED RESULTS OF OPERATIONS
                      (IN MILLIONS, EXCEPT PER SHARE DATA)
 
<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31,
                                          --------------------------------------------------
                                                   1997                       1996
                                          -----------------------    -----------------------
                                             AS                         AS
                                          REPORTED     PRO FORMA     REPORTED     PRO FORMA
                                          --------    -----------    --------    -----------
                                                      (UNAUDITED)                (UNAUDITED)
<S>                                       <C>         <C>            <C>         <C>
Revenues................................   $6,873       $10,210       $4,095       $8,884
Net Income Available for Common Stock...   $  421       $   439       $  405       $  432
Basic Earnings Per Share................   $ 1.66       $  1.56       $ 1.66       $ 1.48
Diluted Earnings Per Share..............   $ 1.66       $  1.56       $ 1.66       $ 1.48
</TABLE>
 
                                       63
<PAGE>   66
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     These and other pro forma results appearing in this Form 10-K are based on
assumptions deemed appropriate by the Company's management, have been prepared
for informational purposes only and are not necessarily indicative of the
combined results that would have resulted had the Merger occurred at the
beginning of the 1996 and 1997 reporting periods presented. Purchase related
adjustments to results of operations include amortization of goodwill and the
effects on depreciation, amortization, interest expense and deferred income
taxes of the revaluation, on a preliminary basis, of the fair value of certain
NorAm assets and liabilities.
 
     As a result of the Merger, the Company has organized its financial
reporting into the following segments: Electric Operations, Natural Gas
Distribution, Interstate Pipeline, Energy Marketing, International and
Corporate. For segment information, see Note 15.
 
(c) Regulatory Assets and Other Long-Lived Assets.
 
     The Company and certain subsidiaries of NorAm apply the accounting policies
established in SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," to the accounts of Electric Operations, Natural Gas Distribution
and the Interstate Pipeline operations of MRT. In general, SFAS No. 71 permits a
company with cost-based rates to defer certain costs that would otherwise be
expensed to the extent that the rate regulated company is recovering or expects
to recover such costs in rates charged to its customers.
 
     The following is a list of regulatory assets and liabilities reflected on
the Company's Consolidated Balance Sheet as of December 31, 1997, detailed by
Electric Operations and other segments.
 
<TABLE>
<CAPTION>
                                                           ELECTRIC               TOTAL
                                                          OPERATIONS    OTHER    COMPANY
                                                          ----------    -----    -------
                                                              (MILLIONS OF DOLLARS)
<S>                                                       <C>           <C>      <C>
Deferred plant costs -- net.............................    $  562               $  562
Recoverable project costs -- net........................        78                   78
Regulatory tax asset -- net.............................       357                  357
Unamortized loss on reacquired debt.....................       127                  127
Deferred debits.........................................        71       $48        119
Accumulated deferred income taxes -- regulatory tax
  asset.................................................       (99)                 (99)
                                                            ------       ---     ------
          Total.........................................    $1,096       $48     $1,144
                                                            ======       ===     ======
</TABLE>
 
     If, as a result of changes in regulation or competition, the Company and
NorAm's ability to recover these assets and/or liabilities would not be assured,
then pursuant to SFAS No. 101, "Accounting for the Discontinuation of
Application of SFAS No. 71" and SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," the Company and
NorAm would be required to write off or write down such net regulatory assets to
the extent that they ultimately were determined not to be recoverable.
 
     Effective January 1, 1996, the Company and NorAm adopted SFAS No. 121. SFAS
No. 121 requires that long-lived assets and certain identifiable intangibles to
be held and used or disposed of by an entity be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. Adoption of the standard did not result in a write-down
of the carrying amount of any asset on the books of the Company or NorAm.
 
     In July 1997, the Emerging Issues Task Force (EITF) of the FASB reached a
consensus on Issue No. 97-4, "Deregulation of the Pricing of
Electricity -- Issues Related to the Application of FASB Statements No. 71,
Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises -- Accounting for the Discontinuation of Application of
FASB Statement No. 71" (EITF 97-4). EITF 97-4 concluded that the application of
SFAS No. 71 to a segment which is subject to a deregulation
 
                                       64
<PAGE>   67
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
plan should cease when the legislation and enabling rate order contain
sufficient detail for the utility to reasonably determine what the transition
plan will entail. In addition, EITF 97-4 requires the regulatory assets and
liabilities to be allocated to the applicable portion of the electric utility
from which the source of the regulated cash flows will be derived. On June 2,
1997, the Texas legislature adjourned without having adopted or taken any formal
action with respect to various proposals concerning the restructuring of the
Texas electric utility industry, including proposals related to retail electric
competition and stranded cost recovery. At this time, the Company cannot predict
what, if any, action the Texas legislature may take in the next legislative
session (scheduled to commence in 1999) with respect to any of these proposals
or the ultimate form in which such proposals may be adopted, if at all. Although
the Company has determined that no impairment loss or write-offs of regulatory
assets need be recognized for applicable assets of continuing operations as of
December 31, 1997, this conclusion may change in the future (i) as competition
influences wholesale and retail pricing in the electric utility industry, (ii)
depending on regulatory action, if any and (iii) depending on legislation, if
any, that is passed.
 
(d) Principles of Consolidation.
 
     The consolidated financial statements include the accounts of the Company
and its wholly owned and majority owned subsidiaries including, effective as of
the Acquisition Date, the accounts of NorAm and its wholly owned and majority
owned subsidiaries.
 
     Investments in entities in which the Company or its subsidiaries have an
ownership interest between 20% and 50% or are able to exercise significant
influence are accounted for using the equity method. For additional information
regarding investments recorded using the equity method or the cost method of
accounting, see Note 5.
 
     All significant intercompany transactions and balances are eliminated in
consolidation.
 
(e) Property, Plant and Equipment and Goodwill.
 
     Property, plant and equipment are stated at original cost of the acquirer.
Repair and maintenance costs are expensed as incurred. Depreciation is computed
using the straight-line method.
 
     Goodwill is being amortized on a straight-line basis over 40 years. The
Company will periodically compare 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 of yet no impairment is indicated
or expected.
 
(f) Depreciation and Amortization Expense.
 
     The Company's 1997 depreciation and amortization expenses included $50
million of additional depreciation in connection with the South Texas Project
and $21.6 million for goodwill amortization associated with the acquisition of
NorAm. For additional information regarding the amortization of goodwill in
connection with the Merger, see Note 1(b) above. The amortization expenses
recorded in connection with the South Texas Project are being made pursuant to
the terms of the Company's most recent rate case settlement (1995 Rate Case
Settlement), which permits the Company to write down up to $50 million per year
of its investment in the South Texas Project through December 31, 1999. These
write-downs are treated under the settlement as reasonable and necessary
expenses for purposes of any future earnings reviews or other proceedings. In
each of 1997, 1996 and 1995, the Company recorded the maximum $50 million
pre-tax write-down permitted under the 1995 Rate Case Settlement.
 
     In 1996 and 1997, the Company, as permitted by the 1995 Rate Case
Settlement, also amortized $50 million and $66 million (pre-tax), respectively,
of its $153 million investment in certain lignite reserves associated with a
canceled generating station. The Company's remaining investment in the canceled
 
                                       65
<PAGE>   68
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
generating station and certain lignite reserves ($78 million at December 31,
1997) will be amortized fully no later than December 31, 2000.
 
     The Company's consolidated depreciation expense for 1997 was $475 million
compared to $410 million for 1996 and $399 million for 1995.
 
(g) Deferred Plant Costs.
 
     Under a "deferred accounting" plan authorized by the Texas Utility
Commission, Electric Operations was permitted for regulatory purposes to accrue
carrying costs in the form of allowance for funds used during construction on
its investment in the South Texas Project and to defer and capitalize
depreciation and other operating costs on its investment after commercial
operation until such costs were reflected in rates. In addition, the Texas
Utility Commission authorized Electric Operations under a "qualified phase-in
plan" to capitalize allowable costs (including return) deferred for future
recovery as deferred charges.
 
     In 1991, Electric Operations ceased all cost deferrals related to the South
Texas Project and began amortizing such amounts on a straight-line basis. The
accumulated deferrals for "deferred accounting" are being amortized over the
estimated depreciable life of the South Texas Project. The accumulated deferrals
for the "qualified phase-in plan" are being amortized over a ten-year phase-in
period that commenced in 1991. The amortization of all deferred plant costs
(which totaled $25.8 million for each of the years 1997, 1996 and 1995) is
included on the Company's Statements of Consolidated Income as depreciation and
amortization expense.
 
(h) Fuel Stock.
 
     Gas inventory (primarily using the average cost method) was $71.7 million
and $19.6 million at December 31, 1997 and 1996, respectively. Coal, lignite,
and oil inventory balances (using last-in, first-out) were $7.5 million, $6.4
million and $3.3 million, respectively, at December 31, 1997 and $27.3 million,
$11.8 million and $3.0 million, respectively, at December 31, 1996.
 
(i) Revenues.
 
     The Company records electricity sales under the full accrual method,
whereby unbilled electricity sales are estimated and recorded each month.
NorAm'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.
International revenues include electricity sales of a majority owned foreign
electric utility, which are also recorded under the full accrual method, and
equity income (net of foreign taxes) in unconsolidated investments of HI Energy.
Included in other revenues are management fees and other sales and services,
which are recorded when earned.
 
     Revenue eliminations of $124 million represent intersegment sales of
natural gas and transportation services. For the five month period ended
December 31, 1997, Interstate Pipeline had intersegment revenues of $59 million
from Natural Gas Distribution and Energy Marketing. For the same period, Energy
Marketing had intersegment sales of $61 million to Interstate Pipeline and
Natural Gas Distribution. The remaining intercompany revenue balances were
between Corporate and other segments.
 
                                       66
<PAGE>   69
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(j) Earnings Per Common Share.
 
     In February 1997, the FASB issued SFAS No. 128, "Earnings per Share", which
is required to be implemented for fiscal years ending after December 15, 1997.
This statement requires restatement of all prior period earnings per share (EPS)
data presented herein. SFAS No. 128 requires dual presentation of basic and
diluted EPS on the face of the Statements of Consolidated Income and requires a
reconciliation of the numerators and denominators used in the basic and diluted
earnings per share calculations.
 
     Following is a reconciliation of the Company's numerators and denominators
of basic and diluted earnings per share calculations:
 
<TABLE>
<CAPTION>
                                                                       FOR THE YEAR ENDED
                                                            ----------------------------------------
                                                               1997          1996           1995
                                                            ----------    ----------    ------------
                                                            (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S>                                                         <C>           <C>           <C>
Basic EPS Calculation:
  Income from continuing operations......................    $421,110      $404,944      $  397,400
  Gain on sale of cable television subsidiary............                                   708,124
  Less: Preferred dividends..............................         162
                                                             --------      --------      ----------
  Net income available for common stock..................    $420,948      $404,944      $1,105,524
                                                             ========      ========      ==========
  Weighted average shares outstanding....................     253,599       244,443         247,706
Basic EPS:
  Income from continuing operations......................    $   1.66      $   1.66      $     1.60
  Gain on sale of cable television subsidiary............                                      2.86
  Less: Preferred dividends..............................         .00
                                                             --------      --------      ----------
  Net income available for common stock..................    $   1.66      $   1.66      $     4.46
                                                             ========      ========      ==========
Diluted EPS Calculation:
  Income from continuing operations......................    $421,110      $404,944      $  397,400
  Plus: Income impact of assumed conversions
     Interest on 6 1/4% convertible debentures...........         668
                                                             --------      --------      ----------
  Income from continuing operations assuming dilution....     421,778       404,944         397,400
  Gain on sale of cable television subsidiary............                                   708,124
  Less: Preferred dividends..............................         162
                                                             --------      --------      ----------
  Net income available for common stock assuming
     dilution............................................    $421,616      $404,944      $1,105,524
                                                             ========      ========      ==========
  Weighted average shares outstanding....................     253,599       244,443         247,706
  Plus: Incremental shares from assumed conversions:
     Stock options.......................................          89            33              21
     6 1/4% convertible debentures.......................         510
                                                             --------      --------      ----------
  Weighted average shares assuming dilution..............     254,198       244,476         247,727
                                                             ========      ========      ==========
Diluted EPS:
  Income from continuing operations......................    $   1.66      $   1.66      $     1.60
  Gain on sale of cable television subsidiary............                                      2.86
  Less: Preferred dividends..............................         .00
                                                             --------      --------      ----------
  Net income available for common stock..................    $   1.66      $   1.66      $     4.46
                                                             ========      ========      ==========
</TABLE>
 
     Options to purchase 405,684 shares of common stock at prices ranging from
$22.09 to $35.18 per share were outstanding during 1997 but were not included in
the computation of diluted EPS because, during the
 
                                       67
<PAGE>   70
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
reporting period, the options' exercise prices were greater than the average
market price of the common shares of $21.875 and would thus be anti-dilutive if
conversion were assumed.
 
(k) Statements of Consolidated Cash Flows.
 
     For purposes of reporting cash flows, cash equivalents are considered to be
short-term, highly liquid investments readily convertible to cash.
 
(l) Derivative Financial Instruments (Risk Management).
 
     For information regarding the Company's accounting for derivative financial
instruments associated with its subsidiaries' natural gas, electric power and
transportation risk management activities, see Note 2.
 
(m) Income Taxes.
 
     The Company and its subsidiaries file a consolidated federal income tax
return. The Company follows a policy of comprehensive interperiod income tax
allocation. Investment tax credits were deferred and are being amortized over
the estimated lives of the related property. For additional information
regarding income taxes, see Note 11.
 
(n) Investments in Time Warner Securities.
 
     The Company owns 11 million shares of non-publicly traded Time Warner
convertible preferred stock (TW Preferred). The TW Preferred is redeemable after
July 6, 2000, has an aggregate liquidation preference of $100 per share (plus
accrued and unpaid dividends), is entitled to annual dividends of $3.75 per
share until July 6, 1999, is currently convertible by the Company and after July
6, 1999 is exchangeable by Time Warner into approximately 22.9 million shares of
Time Warner common stock. Each share of preferred stock is entitled to two votes
(voting together with the holders of the Time Warner common stock as a single
class).
 
     The Company has recorded its investment in these securities at a value of
$990 million on the Company's Consolidated Balance Sheets. Investment in the TW
Preferred is accounted for under the cost method. Dividends on these securities
are recognized as income at the time they are earned. The Company recorded
pre-tax dividend income with respect to the Time Warner securities of $41.3
million, $41.6 million and $20.1 million in 1997, 1996 and 1995, respectively.
 
     To monetize its investment in the TW Preferred, the Company sold in July
1997, 22.9 million of its unsecured 7% ACES. For additional information about
the offering of ACES, see Note 8(e). As a result of the issuance of the ACES, a
portion of the increase in the market value above $55.5844 per share of Time
Warner common stock (the security into which the TW Preferred is convertible)
results in unrealized accounting losses to the Company for the ACES, pending the
conversion of the Company's TW Preferred into Time Warner common stock. For
example, prior to the conversion of the TW Preferred into Time Warner common
stock, when the market price of Time Warner common stock increases above
$55.5844, the Company records in Other Income (Expense) an accounting loss for
the ACES equal to (i) the aggregate amount of such increase as applicable to all
ACES multiplied by (ii) 0.8264. In accordance with generally accepted accounting
principles, this accounting loss (which reflects the unrealized increase in the
Company's indebtedness with respect to the ACES) may not be offset by accounting
recognition of the increase in the market value of the Time Warner common stock
that underlies the TW Preferred. Upon conversion of the TW Preferred, the
Company will begin recording unrealized net changes in the market prices of the
Time Warner common stock and the ACES as a component of common stock equity.
 
     As of December 31, 1997, the market price of Time Warner common stock was
$62.00 per share. Accordingly, the Company recognized an increase of $121
million in the unrealized liability relating to its ACES indebtedness (which
resulted in an after-tax earnings reduction of $79 million or $.31 per share).
The
                                       68
<PAGE>   71
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
Company believes that this unrealized loss for the ACES is more than
economically hedged by the approximately $430 million unrecorded unrealized gain
at December 31, 1997 relating to the increase in the fair value of the Time
Warner common stock underlying the investment in TW Preferred since the date of
its acquisition. As of February 28, 1998, the price of Time Warner common stock
was $67.50 per share which would have resulted in the Company recognizing an
additional increase of $104 million in the unrealized liability represented by
its indebtedness under the ACES. The related unrecorded unrealized gain as of
February 28, 1998 would have been computed as an additional $126 million.
 
(o) Investment in Other Debt and Equity Securities.
 
     The securities held in the Company's nuclear decommissioning trust are
classified as "available-for-sale" and, in accordance with SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," (SFAS No.
115) are reported at estimated fair value of $92.9 million as of December 31,
1997 and $67 million as of December 31, 1996 on the Company's Consolidated
Balance Sheets under deferred debits. The liability for nuclear decommissioning
is reported on the Company's Consolidated Balance Sheets under deferred credits.
Any unrealized gains or losses are accounted for in accordance with SFAS No. 71
as a regulatory asset/liability and reported on the Company's Consolidated
Balance Sheets as a deferred debit/ credit.
 
     The Company, through its subsidiary, NorAm, holds certain equity securities
classified as "available-for-sale" and in accordance with SFAS No. 115 reports
such investments at estimated fair values on the Company's Consolidated Balance
Sheets as deferred debits and any unrealized gain or loss, net of tax, as a
separate component of stockholders' equity. At December 31, 1997, the unrealized
loss relating to these equity securities was approximately $5.6 million, net of
tax.
 
(p) Discontinued Operations.
 
     In July 1995, the Company sold KBLCOM, its cable television subsidiary. The
Company's 1995 earnings include a one-time after-tax gain of $708 million
related to the sale, which includes the net loss for discontinued operations of
KBLCOM through the date of sale (July 6, 1995).
 
(q) Reclassifications and Use of Estimates.
 
     Certain amounts from the previous years have been reclassified to conform
to the 1997 presentation of financial statements. Such reclassifications do not
affect earnings.
 
     The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
 
(r) Other.
 
     For information regarding executive incentive compensation, pensions and
other benefits, see Note 10.
 
(2) DERIVATIVE FINANCIAL INSTRUMENTS (RISK MANAGEMENT)
 
(a) Trading Activities.
 
     The Company, through NES, a subsidiary of NorAm, offers price risk
management services primarily in the natural gas and electric industries. NES
provides these services through, and by utilizing, a variety of derivative
financial instruments, including fixed-price swap agreements, variable-price
swap agreements,
 
                                       69
<PAGE>   72
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
exchange-traded energy futures and option contracts, and swaps and options
traded in the over-the-counter financial markets. Fixed-price swap agreements
require payments to, or receipts of payments from, counterparties based on the
differential between a fixed and variable price for the commodity.
Variable-price swap agreements require payments to, or receipts of payments
from, counterparties based on the differential between either industry pricing
publications or exchange quotations.
 
     Certain trading transactions qualify for hedge accounting and accordingly
unrealized gains and losses associated with these transactions are deferred. For
trading transactions that do not qualify for hedge accounting, NES uses
mark-to-market accounting. Accordingly, such financial instruments are recorded
at fair value with realized and unrealized gains (losses) recorded as a
component of operating revenues in the Company's Consolidated Statements of
Income. The recognized, unrealized balance is recorded as a deferred debit on
the Company's Consolidated Balance Sheets.
 
     The notional quantities and maximum terms of derivative financial
instruments held for trading purposes at December 31, 1997 are presented below
(volumes in billions of British thermal units equivalent (Bbtue)):
 
<TABLE>
<CAPTION>
                                                                  VOLUME-FIXED
                                                   VOLUME-FIXED      PRICE         MAXIMUM
                                                   PRICE PAYOR      RECEIVER     TERM (YEARS)
                                                   ------------   ------------   ------------
<S>                                                <C>            <C>            <C>
Natural gas......................................     85,701         64,890           4
Electricity......................................     40,511         42,976           1
</TABLE>
 
     In addition to the fixed-price notional volumes above, NES also has
variable-price swap agreements, as discussed above, totaling 101,465 Bbtue.
Notional amounts reflect the volume of transactions but do not represent the
amounts exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not accurately measure the Company's exposure to market or
credit risks.
 
     The estimated fair value of derivative financial instruments held for
trading purposes at December 31, 1997 are presented below (dollars in millions):
 
<TABLE>
<CAPTION>
                                                                              AVERAGE FAIR
                                                      FAIR VALUE                VALUE(A)
                                                 ---------------------    ---------------------
                                                 ASSETS    LIABILITIES    ASSETS    LIABILITIES
                                                 ------    -----------    ------    -----------
<S>                                              <C>       <C>            <C>       <C>
Natural gas..................................     $46          $39         $56          $48
Electricity..................................     $ 6          $ 6         $ 3          $ 2
</TABLE>
 
---------------
 
(a) Computed using the ending balance of each month.
 
     Substantially all of the fair value shown in the table above at December
31, 1997 has been recognized in income. The fair value as of and for the year
ended December 31, 1997 was estimated using quoted prices where available and
considering the liquidity of the market for the derivative financial
instruments. The prices are subject to significant changes based on changing
market conditions. The derivative financial instruments included in the NES
trading portfolio as of and for the year ended December 31, 1996 were
immaterial.
 
     The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein are not
indicative of likely future cash flows as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and the Company's risk management portfolio needs
and strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
 
                                       70
<PAGE>   73
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(b) Non-Trading Activities.
 
     To reduce the risk from market fluctuations in the price of electric power,
natural gas and related transportation, NorAm and certain of its subsidiaries
enter into futures transactions, swaps and options (Energy Derivatives) in order
to hedge certain natural gas in storage, as well as certain expected purchases,
sales and transportation of natural gas and electric power (a portion of which
are firm commitments at the inception of the hedge). Energy Derivatives 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.
Usage of electricity derivative financial instruments by the Company and its
subsidiaries for purposes other than trading is immaterial.
 
     Certain subsidiaries of the Company also utilize interest-rate derivatives
(principally interest-rate swaps) in order to adjust the portion of its overall
borrowings which are subject to interest-rate risk, and also utilize such
derivatives to effectively fix the interest rate on debt expected to be issued
for refunding purposes.
 
     For transactions involving either Energy Derivatives or interest-rate
derivatives, hedge accounting is applied only if the derivative (i) reduces the
price risk of the underlying hedged item and (ii) is designated as a hedge at
its inception. Additionally, the derivatives must be expected to result in
financial impacts which are inversely correlated to those of the item(s) to be
hedged. This correlation (a measure of hedge effectiveness) is measured both at
the inception of the hedge and on an ongoing basis, with an acceptable level of
a correlation of at least 80% for hedge designation. If and when correlation
ceases to exist at an acceptable level, hedge accounting ceases and
mark-to-market accounting is applied.
 
     In the case of interest-rate swaps associated with existing obligations,
cash flows and expenses associated with the interest-rate derivative
transactions are matched with the cash flows and interest expense of the
obligation being hedged, resulting in an adjustment to the effective interest
rate. When interest rate swaps are utilized to effectively fix the interest rate
for an anticipated debt issuance, changes in the market value of the
interest-rate derivatives are deferred and recognized as an adjustment to the
effective interest rate on the newly issued debt.
 
     Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in the Company's Consolidated Statements of
Income until the underlying hedged transaction occurs. Once it becomes probable
that an anticipated transaction will not occur, deferred gains and losses are
recognized. In general, the financial impact of transactions involving these
Energy Derivatives is included in the Company's Statement of Consolidated Income
under the captions (i) fuel expenses, in the case of natural gas transactions,
and (ii) purchased power, in the case of electric power transactions. Cash flows
resulting from these transactions in Energy Derivatives are included in the
Company's Statements of Consolidated Cash Flows in the same category as the item
being hedged.
 
     At December 31, 1997, subsidiaries of NorAm were fixed-price payors and
fixed-price receivers in Energy Derivatives covering 38,754 Bbtu and 7,647 Bbtu
of natural gas, respectively. Also, at December 31, 1997 subsidiaries of NorAm
were parties to variable-priced Energy Derivatives totaling 3,630 Bbtu of
natural gas. The weighted average maturity of these instruments is less than one
year.
 
     The notional amount is intended to be indicative of the Company and its
subsidiaries' 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 Energy
Derivatives 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 as further discussed below. Under such circumstances, gains (losses) are
deferred and recognized as a component of income when the underlying hedged item
is recognized in income.
 
                                       71
<PAGE>   74
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The average maturity discussed above and the fair value discussed in Note
13 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions in the trading portfolio at any time in
response to changing market conditions, market liquidity and the Company's risk
management portfolio needs and strategies. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash receipts and
payments.
 
(c) Trading and Non-trading -- General Policy.
 
     In addition to the risk associated with price movements, credit risk is
also inherent in the Company and its subsidiaries' risk management activities.
Credit risk relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. While, as yet, the Company and its
subsidiaries have 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 and/or its subsidiaries, as the case may be, enter into such contracts
primarily with those counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively. For long-term arrangements, the Company
and its subsidiaries periodically review 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 obtain compensatory damages in lieu thereof. 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
financial statement loss due to the non-performance of counterparties to these
transactions is minimal.
 
     The Company's policies prohibit the use of leveraged financial instruments.
 
     The Company has established a Risk Oversight Committee to oversee all
corporate price and credit risk, including NES' risk management and trading
activities. The Risk Oversight Committee's responsibilities include reviewing
the Company and its subsidiaries' overall risk management strategy and
monitoring risk management activities to ensure compliance with the Company's
risk management limitations, policies and procedures.
 
(3) RATE MATTERS
 
(a) Electric Proceedings.
 
     The Texas Utility Commission has original (or in some cases appellate)
jurisdiction over Electric Operations' electric rates and services. Texas
Utility Commission orders may be appealed to a District Court in Travis County,
and from that court's decision an appeal may be taken to the Court of Appeals
for the 3rd District at Austin (Austin Court of Appeals). Discretionary review
by the Supreme Court of Texas may be sought from decisions of the Austin Court
of Appeals. In the event that the courts ultimately reverse actions of the Texas
Utility Commission, such matters are remanded to the Texas Utility Commission
for action in light of the courts' orders.
 
(b) Transition and Price Reduction Plan.
 
     In 1997, the Texas legislature considered but did not pass legislation
intended to address various issues concerning the restructuring of the electric
utility industry, including proposals that would permit Texas retail electric
customers to choose their own electric suppliers beginning on December 31, 2001.
The legislative proposals included provisions relating to full stranded cost
recovery; rate reductions; rate freezes; the
 
                                       72
<PAGE>   75
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
unbundling of generation operations, transmission and distribution and customer
service operations; securitization of regulatory assets; and consumer
protections. Although the Company and certain other parties (including the Texas
Utility Commission) supported the bill, it was not enacted prior to the
expiration of the legislative session.
 
     In October 1997, the Company announced a proposed transition to competition
plan intended to address certain aspects of the proposals contained in the
legislation formerly pending before the Texas legislature. By mid December 1997,
negotiations resulted in a settlement agreement (Settlement Agreement) executed
by the Company, the staffs of the Texas Utility Commission and the City of
Houston, representatives of the state's principal consumer and industrial groups
and others. The Settlement Agreement was subsequently filed with the Texas
Utility Commission, where it is currently under consideration.
 
     Under the terms of the Settlement Agreement, residential customers will
receive a 4% credit to the base cost of electricity in 1998, increasing to 6% in
1999. Small and mid-sized businesses will receive a 2% credit to their base
costs beginning in 1998. The combined effect of these reductions is expected to
decrease base revenues by $166 million over a two year period. In addition, the
Company (over the next two years) will be permitted, as a way to assist the
Company in mitigating its potentially stranded costs, to (i) redirect to
production property all of its current depreciation expenses that would
otherwise be credited to accumulated depreciation for transmission and
distribution property, and (ii) apply any and all earnings above a rate of
return cap of 9.95% to increase the depreciation of production property. The
Company estimates that redirected depreciation over the two-year period of 1998
and 1999 will be approximately $364 million. As part of the Settlement
Agreement, the Company agreed to support proposed legislation in the 1999 Texas
legislative session that includes provisions providing for retail customer
choice effective December 31, 2001 and other provisions consistent with those in
the 1997 proposed legislation.
 
     The Settlement Agreement is currently under consideration by the Texas
Utility Commission, the City of Houston and other cities served by HL&P. In
December 1997, the Texas Utility Commission approved the petition filed by the
Company to implement the requested base rate credits on a temporary basis
beginning January 1, 1998, and pending final Texas Utility Commission
consideration. The approval also included the accounting order necessary to
permit the Company to begin redirecting depreciation from its transmission and
distribution facilities to production property on a temporary basis pending
final Texas Utility Commission consideration. A procedural schedule has been
developed by the Texas Utility Commission whereby a final decision regarding the
Settlement Agreement would be reached by the end of March 1998.
 
(c) 1995 Rate Case.
 
     In August 1995, the Texas Utility Commission unanimously approved a
settlement resolving the Company's most recent rate case (Docket No. 12065) as
well as a separate proceeding (Docket No. 13126) regarding the prudence of
operation of the South Texas Project.
 
     See Note 1(f) regarding additional depreciation and amortization that is
permitted under the 1995 Rate Case Settlement with respect to the South Texas
Project and the Company's investment in certain lignite reserves associated with
a canceled generating station.
 
(d) Docket No. 6668.
 
     In September 1997, the Company received a judgment dismissing all
outstanding appeals of the Texas Utility Commission's order in Docket No. 6668,
an inquiry into the prudence of the planning and construction of the South Texas
Project. In that order, the Texas Utility Commission had determined that $375.5
million of the Company's $2.8 billion investment in the South Texas Project had
been imprudently incurred. That ruling was incorporated into Electric
Operations' 1988 and 1991 rate cases. As a result of this judgment, all
 
                                       73
<PAGE>   76
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
outstanding appeals of prior rate cases involving the Company have now been
dismissed and the orders granted in such cases are now final.
 
(4) JOINTLY OWNED ELECTRIC UTILITY PLANT
 
(a) Investment in South Texas Project.
 
     The Company has a 30.8% interest in the South Texas Project, which consists
of two 1,250 MW nuclear generating units, and bears a corresponding 30.8% share
of capital and operating costs associated with the project. As of December 31,
1997, the Company's investment in the South Texas Project was $1.8 billion (net
of $714 million accumulated depreciation). The Company's investment in nuclear
fuel (including AFUDC) was $51 million (net of $205 million amortization) as of
such date.
 
     Effective November 1997, the Company and the other three owners of the
South Texas Project completed the transfer of the Company's responsibilities for
operation of the South Texas Project to a new Texas non-profit corporation
formed by the four owners and known as the STP Nuclear Operating Company
(STPNOC). STPNOC was formed exclusively for the purpose of operating the South
Texas Project, and the Company's officers and employees who had been responsible
for day-to-day operation and management of the South Texas Project were
transferred to the operating company in October, 1997 and the related employee
benefit obligations were transferred in December, 1997. The operating company is
managed by a board of directors composed of one director from each of the four
owners, along with the chief executive officer of STPNOC. Formation of STPNOC
did not affect the underlying ownership of the South Texas Project, which
continues as a tenancy in common among the four owners, with each owner
retaining its undivided ownership interest in the two nuclear-fueled generating
units and the electrical output from those units. The four owners continue to
provide overall oversight of the operations of the South Texas Project through
an owners' committee composed of representatives of each of the owners and
through the board of directors of STPNOC.
 
(b) 1996 Settlement of South Texas Project Litigation.
 
     In 1996, the Company recorded an aggregate $95 million ($62 million net of
tax) charge in connection with various settlements of lawsuits filed by
co-owners of the South Texas Project. The formation of STPNOC by the four
co-owners (including the Company) of the South Texas Project was contemplated by
these settlements. For information about the execution of an operations
agreement with the City of San Antonio in connection with one of these
settlements, see Note 12(c).
 
(c) Nuclear Insurance.
 
     The Company and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
This coverage consists of $500 million in primary property damage insurance and
excess property insurance in the amount of $2.25 billion. With respect to excess
property insurance, the Company and the other owners of the South Texas Project
are subject to assessments, the maximum aggregate assessment under current
policies being $11.5 million during any one policy year. The application of the
proceeds of such property insurance is subject to the priorities established by
the Nuclear Regulatory Commission (NRC) regulations relating to the safety of
licensed reactors and decontamination operations.
 
     Pursuant to the Price Anderson Act (Act), the maximum liability to the
public of owners of nuclear power plants, such as the South Texas Project, was
$8.72 billion as of December 1997. Owners are required under the Act to insure
their liability for nuclear incidents and protective evacuations by maintaining
the
 
                                       74
<PAGE>   77
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
maximum amount of financial protection available from private sources and by
maintaining secondary financial protection through an industry retrospective
rating plan. The assessment of deferred premiums provided by the plan for each
nuclear incident is up to $79.3 million per reactor, subject to indexing for
inflation, a possible 5% surcharge (but no more than $10 million per reactor per
incident in any one year) and a 3% state premium tax. The Company and the other
owners of the South Texas Project currently maintain the required nuclear
liability insurance and participate in the industry retrospective rating plan.
 
     There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition and results of operations.
 
(d) Nuclear Decommissioning.
 
     The Company contributes $14.8 million per year to a trust established to
fund its share of the decommissioning costs for the South Texas Project. For a
discussion of securities held in the Company's nuclear decommissioning trust,
see Note 1(o). In May 1994, an outside consultant estimated the Company's
portion of decommissioning costs to be approximately $318 million (1994
dollars). The consultant's calculation of decommissioning costs for financial
planning purposes used the DECON methodology (prompt removal/dismantling), one
of the three alternatives acceptable to the NRC, and assumed deactivation of
Units Nos. 1 and 2 upon the expiration of their 40-year operating licenses.
While the current and projected funding levels currently exceed minimum NRC
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning,
changes in regulatory and accounting requirements, changes in technology and
changes in costs of labor, materials and equipment.
 
(e) Assessment Fees for Spent Fuel Disposal and Enrichment and Decommission
 
     By contract, the United States Department of Energy (DOE) has committed
itself ultimately to take possession of all spent fuel generated by the South
Texas Project. The DOE contract currently requires payment of a spent fuel
disposal fee on nuclear plant-generated electricity of one mill (one-tenth of a
cent) per net KWH sold. This fee is subject to adjustment to ensure full cost
recovery by the DOE. The Energy Policy Act also includes a provision that
assesses a fee upon domestic utilities that purchased nuclear fuel enrichment
services from the DOE before October 24, 1992. The South Texas Project's
assessment is approximately $2 million per year (subject to escalation for
inflation). The Company has a remaining estimated liability of $5.5 million for
such assessments.
 
(5) EQUITY INVESTMENTS IN FOREIGN AFFILIATES
 
     HI Energy, a wholly owned subsidiary of the Company formed in 1993,
participates primarily in the development and acquisition of foreign independent
power projects and the privatization of foreign generating and distribution
companies.
 
     The Company accounts for affiliate investments of its subsidiaries under
the equity method of accounting where: (i) the subsidiary's ownership interest
in the affiliate ranges from 20% to 50%, (ii) the ownership interest is less
than 20% but the subsidiary exercises significant influence over operating and
financial policies of such affiliate or (iii) the subsidiary's ownership
interest in the affiliate exceeds 50% but the subsidiary does not exercise
control over the affiliate. The Company's proportionate share of the equity in
net income in these affiliates for the years ended December 31, 1997, 1996 and
1995 was $48.6 million, $17 million and $.5 million, respectively, which amounts
are included on the Company's Statements of Consolidated Income in
Revenues -- International.
 
                                       75
<PAGE>   78
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The Company's and its subsidiaries' equity investments in foreign and
non-regulated affiliates at December 31, 1997 and 1996 were $704 million and
$502 million, respectively.
 
(a) Acquisitions.
 
     In May 1996, a subsidiary of HI Energy acquired 11.35% of the common stock
of Light, a publicly held Brazilian corporation, for $393 million which includes
the direct costs of the acquisition. Light is the operator under a 30-year
concession agreement of an integrated electric power and distribution system
that serves a portion of the state of Rio de Janeiro, Brazil, including the city
of Rio de Janeiro. The winning bidders in the government-sponsored auction of
Light, including a subsidiary of HI Energy, formed a consortium whose aggregate
ownership interest of 50.44% represents a controlling interest in Light.
 
     In June 1997, a consortium of investors which included a subsidiary of HI
Energy, acquired for $496 million a 56.7% controlling ownership interest in
Empresa de Energia del Pacifico S.A.E.S.P. (EPSA), an electric utility system
serving the Valle de Cauca region of Colombia, including the area surrounding
the city of Cali. HI Energy contributed $152 million of the purchase price for a
28% ownership interest in EPSA. In addition to its distribution facilities, EPSA
owns 850 MW of electric generation capacity.
 
     In May 1997, HI Energy increased its indirect ownership interest in Empresa
de la Plata S.A. (EDELAP), an Argentina electric utility, from 48% to 63%. The
purchase price of the additional interest was $28 million. HI Energy has
recorded its investment in EDELAP using the equity method because of the
significance of the participatory rights held by a minority shareholder.
 
     HI Energy has accounted for these transactions under purchase accounting
and has recorded its investments and its interest in the affiliates' earnings
after the acquisition dates using the equity method. The purchase prices were
allocated on the basis of the estimated fair market values of the assets
acquired and the liabilities assumed as of the dates of acquisition. The
differences between the amounts paid and the underlying fair values of the net
assets acquired are being amortized as a component of earnings attributable to
unconsolidated affiliates over the estimated lives of the projects ranging from
30 to 40 years. Purchase price adjustments to fixed assets are being amortized
over the underlying assets' estimated useful lives.
 
(b) Valuation Allowance.
 
     HI Energy is an investor in two waste tire-to-energy projects in the State
of Illinois. The projects had been developed by HI Energy in reliance upon a
state subsidy intended to encourage development of energy project facilities for
the disposal of solid waste. In March 1996, the State of Illinois repealed the
subsidy. As a result of the loss of the subsidy, the Company recorded (i) a $28
million valuation allowance effective in the fourth quarter of 1995 (resulting
in an $18 million after-tax charge in that year) and (ii) an additional $8
million valuation allowance in the first quarter of 1996 (resulting in a $5
million after-tax charge in that year). At the time of the Illinois
legislature's actions, construction work on one of the waste-to-energy projects
had been substantially completed.
 
     The valuation allowance reflects the combined amounts lent to the projects
on a subordinated basis by HI Energy. HI Energy also is a party to two separate
note purchase agreements committing it, under certain circumstances, to lend up
to an additional $16 million. The Company has entered into a support agreement
to enable HI Energy to honor its obligation under these note purchase
agreements. In the Company's opinion, it is unlikely that additional loans would
be required to be made under the note purchase agreements relating to the
facility for which construction had been substantially completed (Ford Heights
Project). In March 1996, a subsidiary of HI Energy purchased from a senior
lending bank all notes relating to the project for which construction had not
yet commenced (Fulton Project) (approximately $4.1 million). As a consequence,
HI Energy has discretion over when, if ever, the construction activities for the
Fulton project will
 
                                       76
<PAGE>   79
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
resume and, in turn, control over future obligations of HI Energy to acquire
additional subordinated notes for the Fulton project.
 
     The Company and HI Energy are defendants in various lawsuits filed in
connection with the Ford Heights Project. CGE Ford Heights, L.L.C., (CGE Ford
Heights) the owner of the project, has filed for reorganization under Chapter 11
of the Federal Bankruptcy Code. In October 1997, CGE Ford Heights filed a
lawsuit against First Trust National Association, HI Energy and Zurn Industries,
Inc. (Zurn). CGE Ford Heights is seeking a determination of the funding
obligations of HI Energy and Zurn. In addition, the trustee for the holders of
the bonds issued to finance the project has filed suit against the Company, HI
Energy and Zurn. The trustee alleges that the Company and HI Energy are
obligated to contribute to CGE Ford Heights approximately $15 million in the
form of subordinated debt obligations. The Company and HI Energy are vigorously
contesting the matter. The Company does not believe that the litigation will
have a material adverse impact on the Company's or HI Energy's financial
statements.
 
(6) COMMON STOCK
 
     At December 31, 1997, the Company had 282,875,266 shares of common stock
issued and outstanding (out of a total of 700,000,000 authorized shares). At
December 31, 1996, the number of shares of outstanding common stock of Former HI
was 233,335,481.
 
     Outstanding common shares excluded (i) shares pledged to secure a loan to
the Company's Employee Stock Ownership Plan (12,388,551 and 13,370,939 at
December 31, 1997 and 1996, respectively) and (ii) treasury shares (93,459 and
16,042,027 at December 31, 1997 and 1996, respectively). Treasury shares at
December 31, 1996 represent shares purchased under a common stock repurchase
program prior to the Merger. In connection with the Merger, these treasury
shares were canceled and retired in August 1997. At December 31, 1997, the
Company held 93,459 shares, which shares were received from holders of Company
stock options, who surrendered shares of Company stock as partial payment for
the exercise price of their stock options.
 
     In 1997, the Company paid four regular quarterly dividends aggregating
$1.50 per share on its common stock pursuant to dividend declarations made in
December 1996, March 1997, June 1997 and September 1997. In December 1997, the
Company declared its regular quarterly dividend of $0.375 per share to be paid
in March 1998. For information regarding certain restrictions on payments of
dividends, see Note 8(c).
 
(7) PREFERRED AND PREFERENCE STOCK
 
(a) Preferred Stock.
 
     At December 31, 1997, the Company had 10,000,000 authorized shares of
preferred stock, of which 97,397 shares were outstanding. As of such date, the
Company's only outstanding series of preferred stock was its $4.00 Preferred
Stock. The $4.00 Preferred Stock pays an annual dividend of $4.00 per share, is
redeemable at $105 per share and has a liquidation price of $100 per share.
 
     In April 1997, the Company redeemed all remaining 257,000 shares of its
$9.375 cumulative preferred stock pursuant to mandatory sinking fund
requirements at a cost of $25.7 million, plus accrued dividends. In February
1997, the Company redeemed the following three series of its cumulative
preferred stock at the redemption prices, plus accrued dividends, indicated:
 
<TABLE>
<CAPTION>
                                                            NUMBER OF    REDEMPTION PRICE
                         SERIES                              SHARES         PER SHARE
                         ------                             ---------    ----------------
<S>                                                         <C>          <C>
$6.72....................................................    250,000         $102.51
$7.52....................................................    500,000         $102.35
$8.12....................................................    500,000         $102.25
</TABLE>
 
                                       77
<PAGE>   80
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(b) Preference Stock.
 
     At December 31, 1997, the Company had 10,000,000 authorized shares of
preference stock, of which 700,000 shares are classified as Series A Preference
Stock and 27,000 shares are classified as Series B Preference Stock. As of
December 31, 1997, there were no shares of Series A Preference Stock issued and
outstanding (such shares being issuable in accordance with the Company's
Shareholder Rights Agreement upon the occurrence of certain events). The number
of shares of Series B Preference Stock issued and outstanding as of December 31,
1997 was 17,000. The sole holder of the Series B Preference Stock is a wholly
owned financing subsidiary of the Company. See Note 8(c).
 
     Each share of common stock of the Company includes one associated
preference stock purchase right (Company Right). Under certain circumstances,
each Company Right entitles the registered holder to purchase from the Company a
unit consisting of one-thousandth of a share (Fractional Share) of Series A
Preference Stock, without par value (Series A Preference Stock), at a purchase
price of $42.50 per Fractional Share, subject to adjustments. The shareholder
rights plan was adopted by the shareholders of Former HI in August 1990 and was
assumed by the Company, with certain amendments, effective upon the Merger.
 
(8) LONG-TERM DEBT AND SHORT-TERM FINANCING
 
(a) Consolidated Debt.
 
     The Company's consolidated long-term and short-term debt outstanding is
summarized in the following table. Of the amount of long-term and short-term
debt outstanding as of December 31, 1997, $1.8 billion represents debt of NorAm
which was assumed and adjusted to fair market value as of the Acquisition Date.
 
             CONSOLIDATED LONG-TERM DEBT AND SHORT-TERM BORROWINGS
                                 (IN MILLIONS)
 
<TABLE>
<CAPTION>
                                              DECEMBER 31, 1997       DECEMBER 31, 1996
                                             --------------------    --------------------
                                             LONG-TERM    CURRENT    LONG-TERM    CURRENT
                                             ---------    -------    ---------    -------
<S>                                          <C>          <C>        <C>          <C>
Short-Term Borrowings:
  Commercial Paper........................                $1,435                  $1,338
  Lines of Credit.........................                   390
  NorAm Receivables Facility..............                   300
                                                          ------                  ------
Total Short-Term Borrowings...............                 2,125                   1,338
                                                          ------                  ------
Long-Term Debt -net:
  ACES....................................    $1,174
  Debentures(1)(2)........................       669                  $  349
  First Mortgage Bonds(1).................     2,495                   2,670         225
  Pollution Control Bonds.................       118           5           5
  NorAm Medium-Term Notes(2)..............       182          79
  Notes Payable(2)........................       565         166           1
  Capital Leases..........................        15           1           1           4
                                              ------      ------      ------      ------
Total Long-Term Debt......................     5,218         251       3,026         229
                                              ------      ------      ------      ------
  Total Long-Term and Short-Term Debt.....    $5,218      $2,376      $3,026      $1,567
                                              ======      ======      ======      ======
</TABLE>
 
---------------
 
(1) Includes unamortized discount related to debentures of approximately $1
    million at December 31, 1997 and 1996 and unamortized discount related to
    first mortgage bonds of approximately $14 million and $15 million at
    December 31, 1997 and 1996, respectively.
 
                                       78
<PAGE>   81
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(2) Includes unamortized premium related to fair value adjustments of
    approximately $15.8 million for Debentures at December 31, 1997. The
    unamortized premium for NorAm long-term and current medium-term notes at
    December 31, 1997 was approximately $16.7 million and $2.8 million,
    respectively. The unamortized premium for long-term and current notes
    payable was approximately $13.7 million and $3.3 million, respectively, at
    December 31, 1997. See Note 1(b).
 
     Consolidated maturities of long-term debt and sinking fund requirements for
the Company (including NorAm) are approximately $251 million in 1998, $378
million in 1999, $1.430 billion in 2000, $401 million in 2001 and $207 million
in 2002.
 
(b) First Mortgage Bonds.
 
     As of December 31, 1997, the Company had an aggregate of $2.5 billion
principal amount of its first mortgage bonds issued and outstanding.
 
     In the first quarter of 1997, the Company repaid at maturity $40 million
aggregate principal amount of its 5 1/4% first mortgage bonds and $150 million
aggregate principal amount of its 7 5/8% first mortgage bonds. In June 1997, the
Company purchased $57.6 million aggregate principal amount of its 9.15% first
mortgage bonds due 2021 for a total purchase price of $69.6 million, plus
accrued interest. In November 1997, the Company repaid at maturity $35 million
aggregate principal amount of its 6 3/4% first mortgage bonds.
 
     Sinking or improvement fund requirements of the Company's first mortgage
bonds outstanding will be approximately $28.3 million for each of the years 1998
through 2002. Such requirements may be satisfied by certification of property
additions at 100% of the requirements. Sinking or improvement fund requirements
for 1997 and prior years have been satisfied by certification of property
additions.
 
     The Company has agreed to expend an amount each year for replacements and
improvements in respect of its depreciable mortgaged utility property equal to
$1,450,000 plus 2 1/2% of net additions to such mortgaged property made after
March 31, 1948 and before July 1 of the preceding year. Such requirement may be
met with cash, first mortgage bonds, gross property additions or expenditures
for repairs or replacements, or by taking credit for property additions at 100%
of the requirements. With respect to first mortgage bonds of a series subject to
special redemption, the Company has the option to use deposited cash to redeem
first mortgage bonds of such series at the applicable special redemption price.
The replacement fund requirement to be satisfied in 1998 is approximately $310.3
million.
 
     The amount of the first mortgage bonds that may be issued by the Company is
unlimited as to issuance, but limited by property, earnings and other provisions
of the Mortgage and Deed of Trust dated as of November 1, 1944, between the
Company and South Texas Commercial National Bank of Houston (Chase Bank of
Texas, National Association, as Successor Trustee) and the supplemental
indentures thereto. Substantially all properties used in the conduct of the
business and operations of Electric Operations are subject to liens securing the
long-term debt under the mortgage.
 
(c) FinanceCo Credit Facility.
 
     In August 1997, a limited partnership special purpose subsidiary of the
Company (FinanceCo) established a five-year, $1.644 billion revolving credit
facility with a consortium of commercial banks (FinanceCo Facility). The
FinanceCo Facility supported $1.435 billion in commercial paper borrowings by
FinanceCo at December 31, 1997 recorded as notes payable on the Consolidated
Balance Sheet. The weighted average interest rate of these borrowings at
December 31, 1997 was 6.15%. Proceeds from the initial issuances of commercial
paper were used to purchase newly issued shares of Series B Preference Stock of
the Company. The Company, in turn, used the proceeds from such stock issuance to
fund the cash portion of the consideration paid to Former NorAm stockholders
under the terms of the Merger.
 
                                       79
<PAGE>   82
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Borrowings under the FinanceCo Facility bear interest at a rate based upon
the London interbank offered rate (LIBOR) plus a margin, a base rate or at a
rate determined through a bidding process. The FinanceCo Facility may be used
(i) to support the issuance of commercial paper or other short-term indebtedness
of FinanceCo, (ii) subject to certain limitations, to finance repurchases of
Company common stock and (iii) subject to certain limitations, to provide funds
for general purposes of FinanceCo, including the making of intercompany loans
to, or securing letters of credit for the benefit of, FinanceCo's affiliates.
 
     The FinanceCo Facility requires the Company to maintain a ratio of
consolidated indebtedness for borrowed money to consolidated capitalization (as
defined) that does not exceed 0.62:1.00 from January 1, 1998 through December
31, 1998 and 0.60:1.00 from January 1, 1999 until termination of the FinanceCo
Facility. The FinanceCo Facility also contains restrictions applicable to the
Company and certain of its subsidiaries with respect to, among other things, (i)
liens, (ii) consolidations, mergers and dispositions of assets, (iii) dividends
and repurchases of common stock, (iv) certain types of investments and (v)
certain changes in its business. The FinanceCo Facility contains customary
covenants and default provisions applicable to FinanceCo and its subsidiaries,
including limitations on, among other things, additional indebtedness (other
than certain permitted indebtedness), liens and certain investments or loans.
 
     Subject to certain conditions and limitations, the Company is required to
make cash payments from time to time to FinanceCo from excess cash flow (as
defined in the FinanceCo Facility) to the extent necessary to enable FinanceCo
to meet its financial obligations. At December 31, 1997, commercial paper
supported by the FinanceCo Facility was secured by pledges of (i) the shares of
common stock of NorAm held by the Company, (ii) all of the limited and general
partner interests of FinanceCo and all of the Company's interest in the general
partner of FinanceCo, (iii) the capital stock of HI Energy, (iv) the Series B
Preference Stock and (v) certain intercompany notes held by FinanceCo. The
obligations under the FinanceCo Facility are not secured by the utility assets
of the Company or NorAm or by the Company's investment in Time Warner
securities.
 
     The Company's outstanding commercial paper balance at December 31, 1996 was
$1.3 billion. The weighted average interest rate at December 31, 1996 was 5.90%.
 
(d) Company Bank Facility.
 
     The Company meets its short-term financing needs primarily through sales of
commercial paper supported by a $200 million revolving credit facility.
Borrowings under the facility are unsecured and a facility fee is paid. At
December 31, 1997, there was no outstanding commercial paper and there were no
outstanding borrowings under the bank facility.
 
(e) ACES.
 
     The Company owns 11 million shares of non-publicly traded TW Preferred. See
Note 1(n). To monetize its investment in these securities, the Company sold in
July 1997, 22,909,040 of its unsecured 7% ACES having a face amount of $45.9375
per security.
 
     At maturity, the principal amount of the ACES will be mandatorily
exchangeable by the Company into either (i) a number of shares of common stock
of Time Warner based on an exchange rate or (ii) cash having an equal value.
Subject to adjustments that may result from certain dilution events, the
exchange rate for each ACES is determined as follows: (i) 0.8264 shares of Time
Warner common stock if the price of Time Warner common stock at maturity
(Maturity Price) is at least $55.5844 per share, (ii) a fractional share of Time
Warner common stock such that the fractional share will have a value equal to
$45.9375 if the Maturity Price is less than $55.5844 but greater than $45.9375
and (iii) one share of Time Warner common stock if the Maturity Price is not
more than $45.9375.
 
                                       80
<PAGE>   83
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Prior to maturity, the Company has the option of redeeming the ACES if (i)
changes in federal tax regulations require recognition of a taxable gain on the
Company's TW Preferred and (ii) the Company could defer such gain by redeeming
the ACES. The redemption price is 105% of the closing sales price of the ACES as
determined over a period prior to the redemption notice. The redemption price
may be paid in cash or in shares of Time Warner common stock or a combination of
the two.
 
     The Company used the net proceeds of the sale of the ACES (approximately
$1.021 billion) to retire in 1997 an equivalent amount of the Company's then
outstanding commercial paper.
 
     For information regarding the Company's accounting treatment of the ACES,
including certain accounting losses that may result upon increases in the price
of Time Warner common stock, see Note 1(n).
 
(f) Pollution Control Revenue Refunding Bonds.
 
     In January 1997, the Brazos River Authority (BRA) and the Matagorda County
Navigation District Number One (MCND) issued, on behalf of the Company, $118
million aggregate principal amount of pollution control revenue bonds. The BRA
and MCND bonds will mature in 2018 and 2028, respectively. The proceeds from the
sale of these securities were used to redeem all outstanding 7 7/8% BRA Series
1986A pollution control revenue bonds ($50 million) and 7 7/8% MCND Series 1986A
pollution control revenue bonds ($68 million) at a redemption price of 102% of
the aggregate principal amount of each series. In 1997, the bonds bore interest
at a floating rate. The weighted average interest rate at December 31, 1997 was
5.01%. Subject to certain conditions, the Company may change the method of
determining the interest rate on the bonds from a daily to a weekly, commercial
paper or long-term interest rate. The bonds are subject to a mandatory tender
for purchase upon certain events, including changes in the method of determining
interest rates on the bonds. When a daily or weekly rate is in effect for the
bonds, holders of the bonds of such issue have the option to have their bonds
purchased at 100% of their principal amount plus accrued interest to the date of
the purchase. Bonds tendered prior to maturity may be remarketed. Although it is
anticipated that all bonds tendered will be purchased with proceeds from the
subsequent offer and sale of the tendered bonds, the Company has entered into
standby purchase agreements with commercial banks to provide approximately $120
million for the purchase of tendered bonds in the event such proceeds are not
available. Facility fees are payable in connection with these facilities.
 
(g) NorAm Bank Facilities.
 
     In 1997, NorAm met its short-term financing needs primarily through a bank
facility, bank lines of credit and a receivables facility. NorAm's principal
short-term credit facility (NorAm Credit Facility) of $400 million expires in
December 1998. Unsecured borrowings under the NorAm Credit Facility at December
31, 1997 aggregated $340 million and had a weighted average interest rate of
6.30%. A facility fee of .14% per annum is payable on the $400 million
commitment. In addition, NorAm had $50 million of outstanding loans under
uncommitted lines of credit at December 31, 1997 having a weighted average
interest rate of 6.82%.
 
     Under a trade receivables facility (Receivables Facility) which expires in
August 1999, NorAm sells, with limited recourse, an undivided interest (limited
to a maximum of $300 million) in a designated pool of accounts receivable. The
amount of receivables sold and uncollected was $300 million at December 31,
1997. The weighted average interest rate at December 31, 1997 was approximately
5.65%. Certain of NorAm's remaining receivables serve as collateral for
receivables sold and represent the maximum exposure to NorAm should all
receivables sold prove ultimately uncollectible. NorAm has retained servicing
responsibility under the Receivables Facility for which it is paid a servicing
fee. Beginning in 1997 and pursuant to SFAS No. 125, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishment of Liabilities", NorAm
accounts for amounts transferred pursuant to the Receivables Facility as
collateralized borrowings. As a result,
 
                                       81
<PAGE>   84
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
these receivables are recorded as assets on the Company's December 31, 1997
Consolidated Balance Sheet and amounts received by NorAm pursuant to this
facility are recorded as notes payable.
 
     In May 1997, NorAm obtained an unsecured, 18-month bank term loan in the
amount of $150 million (included in Notes Payable). The term loan carries a
LIBOR-based floating interest rate. Proceeds from the term loan were used to
refund a portion of NorAm's 9.875% Notes which matured in April 1997. NorAm has
entered into two interest rate swaps, each with a term of 19 months, having an
aggregate notional amount of $150 million which, as of December 31, 1997,
effectively fixed the interest rate on borrowings under the term loan agreement
at approximately 6.775%.
 
(h) NorAm Long-Term Debt.
 
     At December 31, 1997, NorAm has issued and outstanding $116 million
aggregate principal amount ($107 million after Merger fair value adjustments) of
its 6% Convertible Subordinated Debentures due 2012 (Subordinated Debentures).
The holders of the Subordinated Debentures receive interest quarterly and have
the right at any time on or before the maturity date thereof to convert each
Subordinated Debenture into 0.65 shares of Company common stock and $14.24 in
cash. NorAm 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 up to and including March 15, 2011. NorAm (i) may credit against the
sinking fund requirements any Subordinated Debentures redeemed by NorAm and
Subordinated Debentures which have been converted at the option of the holder
and (ii) may deliver purchased Subordinated Debentures in satisfaction of the
sinking fund requirements. Since the Acquisition Date, Subordinated Debentures
aggregating $27,250 were converted.
 
     In the fourth quarter of 1997, NorAm purchased $101.4 million aggregate
principal amount of its 10% Debentures due 2019 at an average price of 111.98%
plus accrued interest. Because NorAm's debt was stated at fair market value as
of the date of the acquisition, the loss on the reacquisition of these
debentures was not material. In December 1997, NorAm repaid at maturity $52
million aggregate principal amount of its medium-term notes.
 
(i) Restrictions on NorAm's Stockholders' Equity and Debt.
 
     Under the provisions of NorAm's revolving credit facility or certain other
NorAm financial arrangements, NorAm's total debt is limited to 72% of its total
capitalization and NorAm is required to maintain a minimum level of
stockholders' equity. In addition, NorAm's total debt would be limited to $2.055
billion if its ratio of total debt to total capitalization increased to 60%. The
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. At December 31, 1997, these provisions did
not significantly restrict NorAm's ability to issue debt or to pay dividends.
 
(j) HI Energy Notes Payable.
 
     In 1996, a subsidiary of HI Energy entered into a $167.5 million loan
agreement in order to refinance a portion of the acquisition costs of Light. The
full proceeds of the loan, net of a $17.5 million debt reserve account
established for the benefit of the lenders, was funded in April 1997. The loan
(included in Notes Payable) is secured by, among other things, a pledge of the
shares of Light and of a subsidiary of HI Energy that is the indirect holder of
the shares of Light.
 
                                       82
<PAGE>   85
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(9) TRUST SECURITIES
 
(a) Company.
 
     In February 1997, two Delaware statutory business trusts (HI Trusts)
established by the Company issued (i) $250 million of preferred securities and
(ii) $100 million of capital securities, respectively. The preferred securities
have a distribution rate of 8.125% payable quarterly in arrears, a stated
liquidation amount of $25 per preferred security and must be redeemed by March
2046. The capital securities have a distribution rate of 8.257% payable
quarterly in arrears, a stated liquidation amount of $1,000 per capital security
and must be redeemed by February 2037.
 
     The HI Trusts sold the preferred and capital securities to the public and
used the proceeds to purchase $350 million aggregate principal amount of
subordinated debentures (Debentures) from the Company having interest rates
corresponding to the distribution rates of the securities and maturity dates
corresponding to the mandatory redemption dates of the securities. The HI Trusts
are accounted for as wholly owned consolidated subsidiaries of the Company. The
Debentures are the HI Trusts' sole assets. Proceeds from the sale of the
Debentures were used by the Company for general corporate purposes, including
the repayment of short-term debt and the redemption of three series of the
Company's outstanding cumulative preferred stock at the following redemption
prices, plus accrued dividends:
 
<TABLE>
<CAPTION>
                                                            NUMBER OF    REDEMPTION PRICE
                         SERIES                              SHARES         PER SHARE
                         ------                             ---------    ----------------
<S>                                                         <C>          <C>
$6.72...................................................     250,000         $102.51
$7.52...................................................     500,000         $102.35
$8.12...................................................     500,000         $102.25
</TABLE>
 
     The Company has fully and unconditionally guaranteed, on a subordinated
basis, each Trust's obligations, including the payment of distributions and all
other payments due with respect to the respective preferred and capital
securities.
 
     The preferred and capital securities are mandatorily redeemable upon the
repayment of the related Debentures at their stated maturity or earlier
redemption.
 
     Subject to certain limitations, the Company has the option of deferring
payments of interest on the Debentures held by the HI Trusts. If and for as long
as payments on the Debentures have been deferred, or an event of default under
the indenture relating thereto has occurred and is continuing, the Company may
not pay dividends on its capital stock. As of December 31, 1997, no interest
payments on the Debentures had been deferred.
 
(b) NorAm.
 
     In June 1996, a Delaware statutory business trust (NorAm Trust) established
by NorAm issued $172.5 million of convertible preferred securities and sold
approximately $5.3 million of NorAm Trust common securities (106,720 securities,
representing 100% of the NorAm Trust's common equity) to NorAm . The convertible
preferred securities have a distribution rate of 6.25% payable quarterly in
arrears, a stated liquidation amount of $50 per convertible preferred security
and must be redeemed by 2026. The NorAm Trust sold the convertible preferred
securities to the public and used the proceeds, in addition to the common stock
proceeds, to purchase $177.8 million of 6.25% Convertible Junior Subordinated
Debentures from NorAm having an interest rate corresponding to the distribution
rate of the convertible preferred securities and a maturity date corresponding
to the mandatory redemption date of the convertible preferred securities. The
NorAm Trust is accounted for as a wholly owned consolidated subsidiary of NorAm.
The junior subordinated debentures are the sole assets of the NorAm Trust. NorAm
has fully and unconditionally guaranteed, on a subordinated basis, the NorAm
Trust's obligations, including the payment of distributions and all other
 
                                       83
<PAGE>   86
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
payments, with respect to the convertible preferred securities. The convertible
preferred securities are mandatorily redeemable upon the repayment of the
related junior subordinated debentures at their stated maturity or earlier
redemption. Following the Merger, each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Company common stock. Since the Acquisition Date, convertible preferred
securities aggregating $14.1 million were converted, leaving $16.4 million
principal amount (unamortized fair value of $21.3 million, net of issuance
costs) of convertible preferred securities outstanding at December 31, 1997.
 
(10) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS
 
(a) Incentive Compensation Plans.
 
     The Company has Long-Term Incentive Compensation plans (LICP) and other
incentive compensation plans that provide for the issuance of stock-based
incentives (including performance-based stock compensation and restricted
shares, stock options and stock appreciation rights) to key employees of the
Company, including officers. As of December 31, 1997, 96 current and former
employees participated in the plans. A maximum of approximately 9 million shares
of common stock may be issued under these plans. Under the LICP, beginning one
year after the grant date, the options become exercisable in one-third
increments each year. Performance-based stock compensation issued and restricted
shares granted were 704,865 in 1997, 69,905 in 1996, and 49,792 in 1995.
 
     Stock option activity for the years 1995 through 1997 is summarized below:
 
<TABLE>
<CAPTION>
                                                                            WEIGHTED
                                                                             AVERAGE
                                                            NUMBER      PRICE AT DATE OF
                                                           OF SHARES    GRANT OR EXERCISE
                                                           ---------    -----------------
<S>                                                        <C>          <C>
Outstanding at December 31, 1994.......................      302,578      $    22.7025
  Options Granted......................................      133,324      $    17.8277
  Options Canceled.....................................      (24,560)

Outstanding at December 31, 1995.......................      411,342      $    21.1414
  Options Granted......................................      101,798      $     24.375
  Options Exercised....................................         (574)     $      17.75
  Options Withheld for Taxes...........................          (90)
  Options Canceled.....................................      (13,824)

Outstanding at December 31, 1996.......................      498,652      $    21.7796
  Options Granted......................................      382,954      $    21.0673
  Options Converted at Acquisition(1)..................      622,504      $    12.9002
  Options Exercised(1).................................     (281,053)     $     9.2063
  Options Withheld for Taxes...........................          (72)
  Options Canceled.....................................     (148,418)

Outstanding at December 31, 1997.......................    1,074,567      $    19.0728

Exercisable at:
  December 31, 1997....................................      645,304      $ 7.00-35.18
  December 31, 1996....................................      280,270      $17.75-23.25
  December 31, 1995....................................      181,924      $21.75-23.25
</TABLE>
 
---------------
 
(1) Effective upon the Merger, each holder of an unexpired NorAm stock option,
    whether or not then exercisable, was entitled to elect to either (i) have
    all or any portion of their NorAm stock options canceled and "cashed out" or
    (ii) have all or any portion of their NorAm stock options converted to the
    Company's stock options. There were 622,504 NorAm stock options converted
    into the Company's stock
 
                                       84
<PAGE>   87
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
    options at the Acquisition Date. Options exercised during 1997 included
    approximately 277,000 shares related to NorAm stock options which were
    converted at the Merger.
 
     Effective January 1, 1996, the Company adopted SFAS No. 123, "Accounting
for Stock-Based Compensation." (SFAS No. 123) In accordance with SFAS No. 123,
the Company will continue to apply the existing rules contained in Accounting
Principles Opinion No. 25, "Accounting for Stock Issued to Employees," and
disclose the required pro forma effect on net income and earnings per share of
the fair value based method of accounting for stock compensation as required by
SFAS No. 123.
 
     The following pro forma summary of the Company's consolidated results of
operations have been prepared as if the fair value based method of accounting
for employee stock compensation as required by SFAS No. 123 had been applied:
 
<TABLE>
<CAPTION>
                                                      1997        1996         1995
                                                    --------    --------    ----------
                                                          (THOUSANDS OF DOLLARS,
                                                          EXCEPT PER SHARE DATA)
<S>                                                 <C>         <C>         <C>
Net Income as reported............................  $420,948    $404,944    $1,105,524
SFAS No. 123 effect...............................    (2,374)     (1,098)         (244)
                                                    --------    --------    ----------
Pro forma Net Income..............................  $418,574    $403,846    $1,105,280
                                                    ========    ========    ==========
Basic and Diluted Earnings per Common Share As
  reported........................................  $   1.66    $   1.66    $     4.46
                                                    $   1.65    $   1.66    $     4.46
</TABLE>
 
     The fair value of options granted during 1995, 1996 and 1997 were
calculated using the Black-Scholes model. The significant assumptions
incorporated in the Black-Scholes model in estimating the fair value of the
options include (i) an interest rate of 7.78% for 1995 and 5.65% for 1996 and an
interest rate of 6.58% for 1997 that represents the interest rate on a U.S.
Treasury security with a maturity date corresponding with the option term, (ii)
an option term of ten years, (iii) volatility of 19.647% for 1995, 15.713% for
1996 and a volatility of 22.06% for 1997 calculated using daily stock prices for
the period prior to the grant date, and (iv) expected common dividends of $1.50
per share representing annualized dividends at the date of grant.
 
(b) Pension.
 
     The Company has a noncontributory retirement plan which covers the
employees of the Company and its subsidiaries other than NorAm. NorAm has two
noncontributory retirement plans: (i) the plan which covers the employees of
NorAm other than Minnegasco employees and (ii) the plan which covers Minnegasco
employees. The plans provide retirement benefits based on years of service and
compensation. The Company and NorAm's funding policy is to contribute amounts
annually in accordance with applicable regulations in order to achieve adequate
funding of projected benefit obligations. The assets of the plans consist
principally of common stocks and high-quality, interest-bearing obligations.
 
                                       85
<PAGE>   88
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Net pension cost for the Company attributable to continuing operations
includes the following components:
 
<TABLE>
<CAPTION>
                                                          YEAR ENDED DECEMBER 31,
                                                     ---------------------------------
                                                       1997         1996        1995
                                                     ---------    --------    --------
                                                           (THOUSAND OF DOLLARS)
<S>                                                  <C>          <C>         <C>
Service cost -- benefits earned during the
  period...........................................  $  26,848    $ 24,392    $ 22,852
Interest cost on projected benefit obligation......     67,640      51,560      49,317
Actual (return) loss on plan assets................   (100,390)    (75,326)    (96,004)
Net amortization and deferrals.....................     14,025      17,514      50,889
                                                     ---------    --------    --------
          Net pension cost.........................      8,123      18,140      27,054
Transfer of obligation to STPNOC...................     (6,077)
SFAS No. 88 -- curtailment expense.................     12,947      12,698       7,096
                                                     ---------    --------    --------
          Total pension cost.......................  $  14,993    $ 30,838    $ 34,150
                                                     =========    ========    ========
</TABLE>
 
     The funded status of the Company's retirement plans was as follows:
 
<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              ----------------------
                                                                 1997         1996
                                                              ----------    --------
                                                              (THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
Actuarial present value of:
  Vested benefit obligation.................................  $  948,017    $542,714
                                                              ==========    ========
  Accumulated benefit obligation............................  $1,017,190    $578,786
                                                              ==========    ========
Plan assets at fair value(1)................................  $1,304,023    $675,401
Projected benefit obligation(1).............................   1,246,582     756,597
                                                              ----------    --------
Assets in excess of (less than) projected benefit
  obligation................................................      57,441     (81,196)
Unrecognized transitional asset.............................      (9,008)    (11,502)
Unrecognized prior service cost.............................      14,735      31,154
Unrecognized net loss.......................................       8,750      19,405
                                                              ----------    --------
     (Accrued) prepaid pension cost.........................  $   71,918    $(42,139)
                                                              ==========    ========
</TABLE>
 
---------------
 
(1) Includes transfer of approximately $40 million of assets and related
    liabilities of plans related to STPNOC. See Note 4(a).
 
     The projected benefit obligation was determined using an assumed discount
rate of 7.25% in 1997 and in 1996. A long-term annual rate of compensation
increase ranging from 4% to 6% was assumed for both the Company and NorAm plans
in 1997 and 1996. The assumed long-term rate of return on plan assets was 9.5%
in 1997 and 1996 (10% for the NorAm plans in 1997). The transitional asset at
January 1, 1986, is being recognized over approximately 17 years, and the prior
service cost is being recognized over approximately 15 years for the Company's
plan. The unrecognized transitional asset, prior service cost and net (gain) or
loss related to the NorAm plans were recognized at the Acquisition Date.
 
     In 1995, the Company offered eligible employees (excluding officers) of the
Company and HI Energy, who were 55 years of age or older and had at least 10
years of service as of July 31, 1995, an incentive program to retire early. For
employees electing early retirement, the program added five years of service
credit and five years in age up to 35 years of service and age 65, respectively,
in determining an employee's pension. Each participating employee (under age 62)
would also receive a supplemental benefit to age 62. During July 1995, the early
retirement incentive was accepted by approximately 300 employees.
 
                                       86
<PAGE>   89
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Pension benefits and supplemental benefits (if applicable) are being paid
out from the Houston Industries Incorporated Retirement Trust. Based on the
projected costs associated with the program, the Company increased its
retirement plan and supplemental benefits in 1995 by approximately $28 million
and $5 million, respectively. Pursuant to SFAS No. 71, the Company deferred the
costs associated with the increases in its benefit obligations and amortized the
costs through the period ending December 31, 1997. In 1997, 1996 and 1995, the
Company amortized $12.9 million, $12.7 million and $7.1 million, respectively,
of those costs as a curtailment under SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," with regards to the Company's early retirement program.
 
(c) Savings Plan.
 
     The Company has an employee savings plan that qualifies as cash or deferred
arrangements under Section 401(k) of the Internal Revenue Code of 1986, as
amended (IRC). Under the plan, participating employees may contribute a portion
of their compensation, pretax or after-tax, up to a maximum of 16% of
compensation limited by an annual deferral limit ($9,500 for calendar year 1997)
prescribed by IRC Section 402(g) and the IRC Section 415 annual additions
limits. The Company matches 70% of the first 6% of each employee's compensation
contributed, subject to a vesting schedule which entitles the employee to a
percentage of the matching contributions depending on years of service.
Substantially all of the Company's match is invested in the Company's common
stock.
 
     In October 1990, the Company amended its savings plan to add a leveraged
Employee Stock Ownership Plan (ESOP) component. The Company may use ESOP shares
to satisfy its obligation to make matching contributions under the savings plan.
Debt service on the ESOP loan is paid using all dividends on shares in the ESOP,
interest earnings on funds held in the ESOP and cash contributions by the
Company. Shares of the Company's common stock are released from the encumbrance
of the ESOP loan based on the proportion of debt service paid during the period.
 
     The Company adopted Statement of Position (SOP) 93-6, effective January 1,
1994, which requires that the Company recognize benefit expense for the ESOP
equal to the fair value of the ESOP shares committed to be released. In
accordance with SOP 93-6, the Company credits to unearned ESOP shares the
original purchase price of ESOP shares committed to be released to plan
participants with the difference between the fair value of the shares and the
original purchase price recorded to common stock. Dividends on allocated ESOP
shares are recorded as a reduction to retained earnings; dividends on
unallocated ESOP shares are recorded as a reduction of debt or accrued interest
on the ESOP loan.
 
     The Company's savings plan benefit expense attributable to continuing
operations was $18.4 million, $16.0 million, and $18.9 million in 1997, 1996 and
1995, respectively. Savings plan benefit expense attributable to discontinued
operations was not material.
 
     The ESOP shares were as follows:
 
<TABLE>
<CAPTION>
                                                                  DECEMBER 31,
                                                          ----------------------------
                                                              1997            1996
                                                          ------------    ------------
<S>                                                       <C>             <C>
Allocated shares transferred/distributed from the
  Savings Plan(1).......................................     1,920,406         580,132
Allocated shares........................................     4,453,227       4,811,113
Unearned shares.........................................    12,388,551      13,370,939
                                                          ------------    ------------
     Total Original ESOP shares.........................    18,762,184      18,762,184
                                                          ============    ============
Fair value of unearned ESOP shares......................  $331,393,739    $302,517,495
</TABLE>
 
---------------
 
(1) 1,102,203 allocated shares transferred are related to shares transferred to
    STPNOC in December, 1997.
 
                                       87
<PAGE>   90
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     NorAm has an employee savings plan (NorAm Savings Plan) which covers
substantially all employees other than Minnegasco employees. Under the terms of
the NorAm Savings Plan, employees may contribute up to 12% of total
compensation, which contributions up to 6% are matched by the Company. The
Minnegasco employees are covered by a savings plan, the terms of which are
somewhat similar to the NorAm Savings Plan. Employer contributions related to
the NorAm and Minnegasco Savings Plan of $3.7 million have been expensed since
the Acquisition Date.
 
(d) Postretirement Benefits.
 
     The Company and NorAm record the liability for post-retirement benefit
plans other than pensions (primarily health care) under SFAS No. 106,
"Employer's Accounting for Postretirement Benefits Other Than Pensions" (SFAS
No. 106). The Company is amortizing over a 22 year period approximately $213
million to cover the "transition cost" of adopting SFAS No. 106 (i.e., the
Company's liability for postretirement benefits payable with respect to employee
service years accrued prior to the adoption of SFAS No. 106). The unrecognized
transitional asset and net (gain) loss related to the NorAm plans were
recognized at the Acquisition Date.
 
     As provided in the Rate Case Settlement, the Company is required to fund
during each year in an irrevocable external trust approximately $22 million of
postretirement benefit costs which are included in Electric Operations' rates.
In December 1995, the Company commenced funding by contributing a total of $15.1
million to three Voluntary Employees' Beneficiary Association trusts and one
Section 401(h) account of the retirement plan. This contribution represented the
amount of postretirement benefits included in Electric Operations' rates (which
included the Company's interest in the South Texas Project costs) less the
estimated pay-as-you-go amounts for 1995 plus interest as if the contributions
had been made on a monthly basis during the year. Beginning in 1996, the Company
funded postretirement benefits costs on a monthly basis for the amount included
in Electric Operations' rates. Minnegasco is required to fund postretirement
benefit costs for the amount included in its rates. The Company and NorAm,
excluding Electric Operations and Minnegasco, will continue funding their
postretirement benefits on a pay-as-you-go basis. The net postretirement benefit
cost for the Company and its subsidiaries includes the following components:
 
<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31,
                                                          ---------------------------
                                                           1997      1996      1995
                                                          -------   -------   -------
                                                            (THOUSANDS OF DOLLARS)
<S>                                                       <C>       <C>       <C>
Service cost -- benefits earned during the period.......  $ 8,927   $ 8,242   $ 9,093
Interest cost on accumulated benefit obligation.........   14,176    12,265    11,143
Actual return on plan assets............................   (5,063)   (2,342)
Net amortization and deferrals..........................    4,732     5,983     6,061
                                                          -------   -------   -------
Net postretirement benefit cost.........................  $22,772   $24,148   $26,297
                                                          =======   =======   =======
</TABLE>
 
                                       88
<PAGE>   91
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The funded status of the Company's and its subsidiaries' postretirement
benefit costs were as follows:
 
<TABLE>
<CAPTION>
                                                                   DECEMBER 31,
                                                              ----------------------
                                                                1997         1996
                                                              ---------    ---------
                                                              (THOUSANDS OF DOLLARS)
<S>                                                           <C>          <C>
Accumulated benefit obligation:
  Retirees..................................................  $ 220,436    $ 107,642
  Fully eligible active plan participants...................     22,150       16,340
  Other active plan participants............................     26,945       26,090
                                                              ---------    ---------
          Total.............................................    269,531      150,072
Plan assets at fair market value............................     56,340       38,493
                                                              ---------    ---------
Assets (less than) accumulated benefit obligation...........   (213,191)    (111,579)
Unrecognized transitional obligation........................    155,107      173,954
Unrecognized net gain.......................................    (96,463)     (99,417)
                                                              ---------    ---------
(Accrued) postretirement benefit cost.......................  $(154,547)   $ (37,042)
                                                              =========    =========
</TABLE>
 
     The assumed health care cost trend rates used in measuring the accumulated
postretirement benefit obligation in 1997 are as follows:
 
<TABLE>
<S>                                                           <C>
Medical -- under 65.........................................  6.6%
Medical -- 65 and over......................................  7.3%
Dental......................................................  6.0%
</TABLE>
 
     The assumed health care rates gradually decline to 5.4% for both medical
categories and 3.7% for dental by 2001. The accumulated postretirement benefit
obligation was determined using an assumed discount rate of 7.25% for 1997 and
1996.
 
     If the healthcare cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 1997 would be
increased by approximately 8%. The annual effect of the 1% increase on the total
of the service and interest costs would be an increase of approximately 11%.
 
     The discount rate used in determining the accumulated postretirement
benefit obligation for the NorAm plan was 7.25% in 1997. 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 8.5%
per year initially and then increase at a decreasing rate to an annual and
continuing increase of 4.5% by 2006. Based on these assumptions, a one
percentage point increase in the assumed health care cost trend rate would
increase the total of the service plus interest costs (before any deferral for
regulatory reasons) and the accumulated postretirement benefit obligation
related to the NorAm plan at December 31, 1997 by 9.2% and 10.8%, respectively.
 
(e) Postemployment Benefits.
 
     Effective January 1, 1994, the Company adopted SFAS No. 112, "Employer's
Accounting for Postemployment Benefits," which requires the recognition of a
liability for benefits, not previously accounted for on the accrual basis,
provided to former or inactive employees, their beneficiaries and covered
dependents, after employment but before retirement (primarily health care and
life insurance benefits for participants in the long-term disability plan). Net
postemployment benefit costs were not material in 1997, 1996 and 1995.
 
                                       89
<PAGE>   92
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(11) INCOME TAXES
 
     The Company records income taxes under SFAS No. 109, "Accounting for Income
Taxes," (SFAS No. 109) which, among other things, (i) requires the liability
method be used in computing deferred taxes on all temporary differences between
book and tax bases of assets other than nondeductible goodwill; (ii) requires
that deferred tax liabilities and assets be adjusted for an enacted change in
tax laws or rates; and (iii) prohibits net-of-tax accounting and reporting. SFAS
No. 109 requires that regulated enterprises recognize such adjustments as
regulatory assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates.
 
     The Company's current and deferred components of income tax expense from
continuing operations are as follows:
 
<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                                     --------------------------------
                                                       1997        1996        1995
                                                     --------    --------    --------
                                                          (THOUSANDS OF DOLLARS)
<S>                                                  <C>         <C>         <C>
Current............................................  $199,011    $150,658    $141,076
Deferred...........................................     7,363      49,507      58,479
                                                     --------    --------    --------
Income taxes for continuing operations.............  $206,374    $200,165    $199,555
                                                     ========    ========    ========
</TABLE>
 
     The Company's effective income tax rates are lower than statutory corporate
rates for each year as follows:
 
<TABLE>
<CAPTION>
                                                         YEAR ENDED DECEMBER 31,
                                                     --------------------------------
                                                       1997        1996        1995
                                                     --------    --------    --------
                                                          (THOUSANDS OF DOLLARS)
<S>                                                  <C>         <C>         <C>
Income from continuing operations before income
  taxes............................................  $627,484    $605,109    $596,955
Preferred dividends of subsidiary..................     2,255      22,563      29,955
                                                     --------    --------    --------
          Total....................................   629,739     627,672     626,910
Statutory rate.....................................        35%         35%         35%
                                                     --------    --------    --------
Income taxes at statutory rate.....................   220,409     219,685     219,419
                                                     --------    --------    --------
Net reduction (addition) in taxes resulting from:
  Amortization of investment tax credit............    19,777      18,404      19,427
  Excess deferred taxes............................     5,570       4,331       4,384
  Difference between book and tax depreciation for
     which deferred taxes have not been
       normalized..................................   (27,466)    (22,638)    (15,211)
  Equity dividend exclusion........................     5,075      10,194       4,932
  Equity income -- foreign affiliates..............    17,011       5,936
  Goodwill.........................................    (7,242)
  Other -- net.....................................     1,310       3,293       6,332
                                                     --------    --------    --------
          Total....................................    14,035      19,520      19,864
                                                     --------    --------    --------
Income taxes.......................................  $206,374    $200,165    $199,555
                                                     ========    ========    ========
Effective rate.....................................      32.8%       31.9%       31.8%
</TABLE>
 
                                       90
<PAGE>   93
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Following are the Company's tax effects of temporary differences
attributable to continuing operations resulting in deferred tax assets and
liabilities:
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                              ------------------------
                                                                 1997          1996
                                                              ----------    ----------
                                                               (THOUSANDS OF DOLLARS)
<S>                                                           <C>           <C>
Deferred Tax Assets:
  Alternative minimum tax credit carryforwards..............  $   60,669    $   19,014
  Employee benefits.........................................     145,794        68,078
  Internal Revenue Service (IRS) audit assessment...........                    74,966
  Disallowed plant cost -- net..............................      22,378        23,237
  ACES......................................................      42,491
  State operating loss carryforwards........................      29,515
  Deferred state income taxes...............................      14,460
  Other.....................................................      69,235        26,061
  Valuation allowance.......................................      (6,353)
                                                              ----------    ----------
     Total deferred tax assets -- net.......................     378,189       211,356
                                                              ----------    ----------
Deferred Tax Liabilities:
  Depreciation..............................................   2,115,717     1,450,894
  Deferred plant costs -- net...............................     186,472       194,243
  Regulatory assets -- net..................................     356,509       362,310
  Capitalized taxes, employee benefits and removal costs....      46,584       108,530
  Gain on sale of cable television subsidiary...............     222,942       228,449
  Deferred state income taxes...............................      70,000
  Deferred gas costs........................................      34,113
  Other.....................................................     138,633       131,961
                                                              ----------    ----------
     Total deferred tax liabilities.........................   3,170,970     2,476,387
                                                              ----------    ----------
          Accumulated deferred income taxes -- net..........  $2,792,781    $2,265,031
                                                              ==========    ==========
</TABLE>
 
     Tax Refund Case. In July 1990, Former HI paid approximately $104.5 million
to the Internal Revenue Service (IRS) following an IRS audit of Former HI's 1983
and 1984 federal income tax returns. In November 1991, Former HI filed a refund
suit in the U.S. Court of Federal Claims seeking the return of $52.1 million of
tax and $36.3 million of accrued interest, plus interest on both of those
amounts accruing after July 1990. The major contested issue in the refund case
involved the IRS allegation that certain amounts related to the over-recovery of
fuel costs should have been included as taxable income in 1983 and 1984 even
though the Company had an obligation to refund the over-recoveries to its
ratepayers.
 
     In September 1997, the United States Court of Appeals for the Federal
Circuit upheld a lower court ruling that the Company (as successor corporation
to Former HI) was due a refund of federal income taxes assessed on fuel
over-recoveries during 1983 and 1984 that subsequently were refunded to HL&P's
customers.
 
     In February 1998, the Company received a refund of approximately $142
million in taxes and interest paid by Former HI in July 1990, including interest
accrued since 1990 in the amount of approximately $57 million. After giving
effect to the Company's deferred recognition of the 1990 tax payment and payment
of federal income taxes due on the accrued interest on the refund, the refund
had the effect of increasing the Company's earnings in the fourth quarter of
1997 by $37 million (after-tax).
 
     Tax Attribute Carryforwards. At December 31, 1997, NorAm has approximately
$439 million of state net operating losses available to offset future state
taxable income through the year 2012. Based on the Company's assessment of its
ability to use such loss carryforwards in future tax years, a valuation
allowance of
 
                                       91
<PAGE>   94
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
$6.4 million was recorded at the Acquisition Date. In addition, NorAm has
approximately $58 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), and approximately $2.6 million of state alternative minimum tax
credits which are available to reduce future state income taxes payable, if any,
through the year 2001.
 
(12) COMMITMENTS AND CONTINGENCIES
 
(a) Commitments.
 
     The Company has various commitments for capital expenditures, fuel,
purchased power, cooling water and operating leases. Commitments in connection
with Electric Operations' capital program are generally revocable by the
Company, subject to reimbursement to manufacturers for expenditures incurred or
other cancellation penalties. The Company's and its subsidiaries' other
commitments have various quantity requirements and durations. However, if these
requirements could not be met, various alternatives are available to mitigate
the cost associated with the contracts' commitments.
 
(b) Fuel and Purchased Power.
 
     The Company is a party to several long-term coal, lignite and natural gas
contracts which have various quantity requirements and durations. Minimum
payment obligations for coal and transportation agreements are approximately
$200 million in 1998, $203 million in 1999 and $177 million in 2000.
Additionally, minimum payment obligations for lignite mining and lease
agreements are approximately $9 million for 1998, $9 million for 1999 and $10
million for 2000. Minimum payment obligations for both natural gas purchase and
storage contracts associated with Electric Operations are approximately $9
million annually in 1998, 1999 and 2000.
 
     The Company also has commitments to purchase firm capacity from
cogenerators of approximately $22 million in both 1998 and 1999. Texas Utility
Commission rules currently allow recovery of these costs through Electric
Operations' base rates for electric service and additionally authorize the
Company to charge or credit customers through a purchased power cost recovery
factor for any variation in actual purchased power costs from the cost utilized
to determine its base rates. In the event that the Texas Utility Commission, at
some future date, does not allow recovery through rates of any amount of
purchased power payments, the two principal firm capacity contracts contain
provisions allowing the Company to suspend or reduce payments and seek repayment
for amounts disallowed.
 
(c) Operations Agreement with City of San Antonio.
 
     As part of the settlement with the City of San Antonio, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in order to take advantage of each system's lower cost
resources. Under the terms of the joint operations agreement entered into
between CPS and Electric Operations, the Company has guaranteed CPS minimum
annual savings of $10 million and a minimum cumulative savings of $150 million
over the 10-year term of the agreement. Based on current forecasts and other
assumptions regarding the combined operation of the two generating systems, the
Company anticipates that the savings resulting from joint operations will equal
or exceed the minimum savings guaranteed under the joint operating agreement. In
1996, savings generated for CPS' account for a partial year of joint operations
were approximately $14 million. In 1997, savings generated for CPS' account for
a full year of operation were approximately $22 million.
 
(d) Transportation Agreement.
 
     NorAm had an agreement (the ANR Agreement) with ANR Pipeline Company (ANR)
which contemplated a transfer to ANR of an interest in certain of NorAm's
pipeline and related assets, representing
                                       92
<PAGE>   95
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
capacity of 250 Mmcf/day, and pursuant to which ANR had advanced $125 million to
the Company. The ANR Agreement has been restructured and, after refunds of $84
million through December 31, 1997, NorAm currently retains $41 million (recorded
as a liability) in exchange for ANR's or its affiliates' use of 130 Mmcf/ day of
capacity in certain of NorAm'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.
 
(e) Lease Commitments.
 
     The following table sets forth certain information concerning NorAm's
obligations under operating leases:
 
     Minimum Lease Commitments at December 31, 1997(1)
 
<TABLE>
<CAPTION>
                                                             (MILLIONS OF DOLLARS)
                                                             ---------------------
<S>                                                          <C>
1998.......................................................          $ 24
1999.......................................................            19
2000.......................................................            16
2001.......................................................            15
2002.......................................................             9
2003 and beyond............................................            22
                                                                     ----
          Total............................................          $105
                                                                     ====
</TABLE>
 
---------------
 
(1) Principally consisting of rental agreements for building space and data
    processing equipment and vehicles (including major work equipment).
 
     NorAm has a master leasing agreement which provides for the lease of
vehicles, construction equipment, office furniture, data processing equipment
and other property. For accounting purposes, the lease is treated as an
operating lease. At December 31, 1997, NorAm had leased assets with a value of
approximately $58.1 million under this lease with a basic term of one year.
NorAm does not expect to lease additional property under this lease agreement.
 
     Lease payments related to NorAm's master leasing agreement are included in
the preceding table for only their basic term. Total rental expense for all
leases since the Acquisition Date was approximately $15 million in 1997.
 
(f) Letters of Credit.
 
     At December 31, 1997, NorAm had letters of credit incidental with its
ordinary business operations totaling approximately $42 million under which
NorAm is obligated to reimburse drawings, if any.
 
(g) Indemnity Provisions.
 
     At December 31, 1997, NorAm has $11.4 million accounting reserve on the
Company's Consolidated Balance Sheet in Other Deferred Credits for possible
indemnity claims asserted in connection with its disposition of NorAm's former
subsidiaries or divisions, including the sale of (i) Louisiana Intrastate Gas
Corporation, a former NorAm subsidiary engaged in the intrastate pipeline and
liquids extraction business; (ii) Arkla Exploration Company, a former NorAm
subsidiary engaged in oil and gas exploration and production activities; and
(iii) Dyco Petroleum Company, a former NorAm subsidiary engaged in oil and gas
exploration and production.
 
                                       93
<PAGE>   96
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(h) Other.
 
     Electric Operations' service area is heavily dependent on oil, gas, refined
products, petrochemicals and related businesses. Significant adverse events
affecting these industries would negatively affect the revenues of the Company.
The Company and NorAm are involved in legal, tax and regulatory proceedings
before various courts, regulatory commissions and governmental agencies
regarding matters arising in the ordinary course of business, some of which
involve substantial amounts. The Company's management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. The Company's management believes that
the effect on the Company's and NorAm's respective financial statements, if any,
from the disposition of these matters will not be material.
 
     In February 1996, the cities of Wharton, Galveston and Pasadena filed suit,
for themselves and a proposed class, against the Company and Houston Industries
Finance Inc. (formerly a wholly owned subsidiary of the Company) citing
underpayment of municipal franchise fees. The plaintiffs claim, among other
things, that from 1957 to the present, franchise fees should have been paid on
sales taxes collected by HL&P on non-electric receipts as well as electric
sales. Plaintiffs advance their claims notwithstanding their failure to notice
such claims over the previous four decades. Because all of the franchise
ordinances affecting HL&P expressly impose fees only on electric sales, the
Company regards plaintiffs' allegations as spurious and is vigorously contesting
the matter. The plaintiffs' pleadings assert that their damages exceed $250
million. No trial date is currently set. Although the Company believes the
claims to be without merit, the Company cannot at this time estimate a range of
possible loss, if any, from the lawsuit, nor can any assurance be given as to
its ultimate outcome
 
     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 financial statements, if any, from the
disposition of these matters will not be material.
 
                                       94
<PAGE>   97
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(13) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
 
<TABLE>
<CAPTION>
                                                                    DECEMBER 31,
                                                  -------------------------------------------------
                                                           1997                      1996
                                                  -----------------------   -----------------------
                                                   CARRYING       FAIR       CARRYING       FAIR
                                                    AMOUNT       VALUE        AMOUNT       VALUE
                                                  ----------   ----------   ----------   ----------
                                                               (THOUSANDS OF DOLLARS)
<S>                                               <C>          <C>          <C>          <C>
Financial Assets:
  Company:
     Investment in Time Warner securities.......  $  990,000   $1,420,360   $1,027,500   $1,027,500
  NorAm:
     Energy derivatives.........................       9,399       13,060
Financial Liabilities:
  Company:
     First mortgage bonds.......................   2,495,459    2,651,260    2,895,041    3,045,833
     Debentures.................................     349,283      379,490      349,098      380,455
     ACES.......................................   1,173,786    1,307,247           --           --
     Cumulative preferred stock (subject to
       mandatory redemption)....................          --           --       25,700       25,957
     Trust preferred and capital securities.....     340,882      366,220           --           --
  NorAm:
     Long-term debt.............................   1,148,848    1,147,344
     Trust preferred securities.................      21,290       24,569
     Interest rate swaps........................          --          755
  HI Energy:
     Interest rate swaps........................          --        1,679           --           --
</TABLE>
 
     The fair values of cash and short-term investments, investment in the
Company's nuclear decommissioning trust, short-term and other notes payable,
floating rate debt of HI Energy, and floating rate pollution control revenue
bonds are estimated to be equivalent to carrying amounts. The remaining fair
values have been determined using quoted market prices of the same or similar
securities when available or other estimation techniques.
 
(14) UNAUDITED QUARTERLY INFORMATION
 
     The following unaudited quarterly financial information includes, in the
opinion of management, all adjustments (which comprise only normal recurring
accruals) necessary for a fair presentation. Quarterly results are not
necessarily indicative of a full year's operations because of seasonality and
other factors, including rate increases and variations in operating expense
patterns. Results of operations of the newly acquired NorAm businesses are
included beginning on the Acquisition Date.
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31, 1997
                                                   ---------------------------------------------------
                                                     FIRST       SECOND         THIRD        FOURTH
                                                    QUARTER      QUARTER       QUARTER       QUARTER
                                                   ---------   -----------   -----------   -----------
                                                    (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S>                                                <C>         <C>           <C>           <C>
Revenues.........................................  $878,101    $1,064,448    $2,158,551    $2,772,285
Operating Income.................................   156,216       247,172       462,716       198,396
Net Income.......................................    59,620       121,463       243,898        (4,033)
Basic Earnings (loss) per common share(a)........       .26           .52           .93          (.01)
Diluted earnings (loss) per common share(a)......       .26           .52           .93          (.01)
</TABLE>
 
                                       95
<PAGE>   98
                HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31, 1996
                                                   ---------------------------------------------------
                                                     FIRST       SECOND         THIRD        FOURTH
                                                    QUARTER      QUARTER       QUARTER       QUARTER
                                                   ---------   -----------   -----------   -----------
                                                    (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<S>                                                <C>         <C>           <C>           <C>
Revenues.........................................  $823,507    $1,113,763    $1,251,025    $  906,982
Operating Income.................................   137,139       286,280       441,069       125,978
Net income (loss)................................   (16,740)      145,334       240,024        36,326
Basic Earnings (loss) per common share(a)........      (.07)          .58           .98           .15
Diluted earnings (loss) per common share(a)......      (.07)          .58           .98           .15
</TABLE>
 
---------------
 
(a) Quarterly earnings per common share are based on the weighted average number
    of shares outstanding during the quarter, and the sum of the quarters may
    not equal annual earnings per common share.
 
                                       96
<PAGE>   99
 
(15) REPORTABLE SEGMENTS
 
     Upon the acquisition of NorAm, the Company organized its business into the
following segments: Electric Operations, Natural Gas Distribution, Interstate
Pipeline, Energy Marketing, International and Corporate segments. Consistent
with the purchase accounting treatment of the Merger, financial information for
the Natural Gas Distribution, Interstate Pipeline and Energy Marketing segments
are presented only for periods beginning on the Acquisition Date. In 1996 and
1995, the Company's Electric Operations accounted for in excess of 90% of the
Company's total revenues, income and identifiable assets and as such, the
required segment information for those periods is provided on the face of the
Company's consolidated financial statements and in the related notes thereto.
The Company has presented the following summary of financial information by
business segment for 1997 and has included supplemental comparative information
for 1996.
 
<TABLE>
<CAPTION>
                                                                YEAR ENDED DECEMBER 31,
                                                              ---------------------------
                                                                1997(1)          1996
                                                              ------------    -----------
<S>                                                           <C>             <C>
Revenues:
  Electric Operations.......................................  $  4,251,243    $ 4,025,027
  Natural Gas Distribution..................................       892,569
  Interstate Pipeline.......................................       108,333
  Energy Marketing..........................................     1,604,999
  International.............................................        92,028         62,059
  Corporate and Other.......................................        47,851          8,191
  Eliminations..............................................      (123,638)
                                                              ------------    -----------
         Total Revenues.....................................  $  6,873,385    $ 4,095,277
                                                              ============    ===========
Operating Income (Loss):
  Electric Operations.......................................  $    994,938    $   997,147
  Natural Gas Distribution..................................        54,502
  Interstate Pipeline.......................................        31,978
  Energy Marketing..........................................        16,407
  International.............................................        19,510          2,339
  Corporate and Other.......................................       (52,835)        (9,020)
                                                              ------------    -----------
         Total Operating Income.............................     1,064,500        990,466
                                                              ------------    -----------
Other income (expenses).....................................       (13,446)       (55,412)
Interest and Other Charges..................................       423,570        329,945
                                                              ------------    -----------
Income from Continuing Operations Before Tax................  $    627,484    $   605,109
                                                              ============    ===========
Depreciation and Amortization:
  Electric Operations.......................................  $    568,541    $   545,685
  Natural Gas Distribution..................................        51,883
  Interstate Pipeline.......................................        19,088
  Energy Marketing..........................................         4,448
  International.............................................         3,470          1,648
  Corporate and Other.......................................         4,445          2,705
                                                              ------------    -----------
         Total Depreciation and Amortization................  $    651,875    $   550,038
                                                              ============    ===========
Identifiable Assets:
  Electric Operations.......................................  $ 10,540,849    $10,596,232
  Natural Gas Distribution..................................     3,047,195
  Interstate Pipeline.......................................     3,055,610
  Energy Marketing..........................................     1,267,867
  International.............................................       869,485        607,103
  Corporate and Other.......................................    12,837,302      5,771,648
  Eliminations..............................................   (13,203,753)    (4,687,126)
                                                              ------------    -----------
         Total Identifiable Assets..........................  $ 18,414,555    $12,287,857
                                                              ============    ===========
Capital Expenditures:
  Electric Operations.......................................  $    236,977    $   317,532
  Natural Gas Distribution..................................        61,078
  Interstate Pipeline.......................................        16,304
  Energy Marketing..........................................        14,365
  International.............................................       231,528        495,379
  Corporate and Other.......................................        23,572         19,989
                                                              ------------    -----------
         Total Capital Expenditures.........................  $    583,824    $   832,900
                                                              ============    ===========
</TABLE>
 
---------------
 
(1) New categories for segments in 1997 result from the NorAm Merger. See Note
    1(b).
 
                                       97
<PAGE>   100
 
(16) SUBSEQUENT EVENTS
 
     In January 1998, the MCND issued on behalf of the Company $104.7 million
aggregate principal amount of pollution control revenue refunding bonds with
$29.7 million at 5.25% and $75 million at 5.15%. The MCND bonds will mature in
2029. The Company used the proceeds from the sale of these securities to redeem
all outstanding 7 7/8% MCND Series 1989A pollution control revenue bonds ($29.7
million) and 7.70% MCND Series 1989B pollution control revenue bonds ($75
million) at a redemption price of 102% of the aggregate principal amount of each
series.
 
     In February 1998, the BRA issued on behalf of the Company $290 million
aggregate principal amount of pollution control revenue refunding bonds. The BRA
bonds will mature in May 2019 ($200 million at 5 1/8%) and November 2020 ($90
million at 5 1/8%). The Company will use the proceeds from the sale of these
securities to redeem all the outstanding 8.25% BRA 1988A Series pollution
control revenue bonds ($100 million), the 8.25% BRA 1988B Series pollution
control revenue bonds ($90 million), and the 8.10% BRA 1988C Series pollution
control revenue bonds ($100 million) at a redemption price of 102% of the
aggregate principal amount of each series.
 
     In February 1998, NorAm issued $300 million principal amount of 6.5%
debentures due February 1, 2008. The debentures are not redeemable prior to
maturity and are not subject to any sinking fund requirements. The proceeds from
the sale of the debentures were used to repay short-term indebtedness of NorAm,
including the indebtedness incurred in connection with the 1997 purchase of $101
million aggregate principal amount of its 10% Debentures and the repayment of
$53 million aggregate principal amount of NorAm debt that matured in December
1997 and January 1998. In connection with the issuance of the 6.5% debentures
NorAm received approximately $1 million upon unwinding a $300 million treasury
rate lock agreement, which was tied to the interest rate on 10-year treasury
bonds. The rate lock agreement was executed in January 1998, and proceeds from
the unwind will be amortized over the 10 year life of NorAm's 6.5% debentures.
 
                                       98
<PAGE>   101
 
                          INDEPENDENT AUDITORS' REPORT
 
Houston Industries Incorporated:
 
     We have audited the accompanying consolidated balance sheets and the
consolidated statements of capitalization of Houston Industries Incorporated and
its subsidiaries (Company) as of December 31, 1997 and 1996, and the related
statements of consolidated income, consolidated retained earnings and
consolidated cash flows for each of the three years in the period ended December
31, 1997. Our audits also included the Company's financial statement schedule
listed in Item 14(a)(3). 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, such consolidated financial statements present fairly, in
all material respects, the financial position of Houston Industries Incorporated
and its subsidiaries at December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
February 20, 1998
 
                                       99
<PAGE>   102
 
                               NORAM ENERGY CORP.
                            AND SUBSIDIARY COMPANIES
 
                                       100
<PAGE>   103
 
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF NORAM
        ENERGY CORP. AND CONSOLIDATED SUBSIDIARIES.
 
     The following narrative and analysis should be read in combination with
NorAm's consolidated financial statements and notes (NorAm's Consolidated
Financial Statements) contained in Item 8 of the Form 10-K of NorAm.
 
                               NORAM ENERGY CORP.
 
     NorAm conducts operations primarily in the natural gas industry, including
gathering, transmission, marketing, storage and distribution. Collectively,
these operations accounted for in excess of 90% of NorAm's total revenues,
income or loss and identifiable assets during 1997. Accordingly, NorAm is not
required to report on a "segment" basis, although NorAm is organized into, and
the following business description focuses on, the operating units described
below. NorAm also makes sales of electricity, non-energy sales and provides
certain non-energy services, primarily to retail gas distribution customers. In
recognition of the manner in which NorAm manages its portfolio of businesses,
NorAm has segregated its results of operations into: Natural Gas Distribution,
Interstate Pipeline, Energy Marketing and Corporate.
 
     On August 6, 1997 (Acquisition Date), NorAm became a wholly owned
subsidiary of Houston Industries Incorporated (Houston Industries) in a
transaction involving the merger (Merger) of NorAm Energy Corp. (Former NorAm)
with and into a subsidiary of Houston Industries. For additional information
regarding Houston Industries' acquisition of NorAm, see Note 1(b) to NorAm's
Consolidated Financial Statements.
 
     NorAm meets the conditions specified in General Instruction I to Form 10-K
and is thereby permitted to use the reduced disclosure format for wholly owned
subsidiaries of reporting companies specified therein. Accordingly, NorAm has
omitted from this Combined Annual Report the information called for by Item 4
(submission of matters to a vote of security holders), Item 10 (directors and
executive officers), Item 11 (executive compensation), Item 12 (security
ownership of certain beneficial owners and management) and Item 13 (related
party transactions) of Form 10-K. In lieu of the information called for by Item
6 (selected financial data) and Item 7 (management's discussion and analysis of
financial condition and results of operations) of Form 10-K, NorAm has included
the following Management's Narrative Analysis of the Results of Operations to
explain material changes in the amount of revenue and expense items of NorAm
between 1997 and 1996. Reference is hereby made to Item 1 (business), Item 2
(properties), Item 3 (legal proceedings), Item 5 (NorAm common stock), Item 7A
(market risk disclosure) and Item 9 (changes in and disagreements with
accountants) of this Combined Annual Report for additional information regarding
NorAm required by the reduced disclosure format of General Instruction I to Form
10-K.
 
                       CONSOLIDATED RESULTS OF OPERATIONS
 
     Seasonality and Other Factors. NorAm's results of operations are seasonal
due to seasonal fluctuations in the demand for and, to a lesser extent, the
price of natural gas. NorAm's results of operations are also affected by, among
other things, the actions of various federal and state governmental authorities
having jurisdiction over rates charged by NorAm and its subsidiaries,
competition in NorAm's various business operations, debt service costs and
income tax expense. For a discussion of certain other factors that may affect
NorAm's future earnings see "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- Certain Factors Affecting
Future Earnings of the Company and its Subsidiaries -- Competition -- Electric
Operations -- Regulatory Assets"; " -- Competition -- Other Operations";
"-- Impact of the Year 2000 Issue and Other System Implementation Issues";
"-- Environmental Expenditures -- Manufactured Gas Plant Sites"; and
"-- Environmental Expenditures -- Mercury Contamination" in Item 7 of Houston
Industries' Form 10-K.
 
     Accounting Impact of the Merger. The Merger created a new basis of
accounting for NorAm, resulting in new carrying values for certain of NorAm's
assets, liabilities and equity commencing upon the Acquisition
 
                                       101
<PAGE>   104
 
Date. NorAm's financial statements for periods subsequent to the Acquisition
Date are not comparable to prior periods because of the following purchase
accounting adjustments:
 
          1. The impact ($21.6 million) of the amortization of newly-recognized
             goodwill;
 
          2. The amortization (to interest expense) of the revaluation of
             long-term debt ($9.8 million);
 
          3. The removal of the amortization (to operating expense) previously
             associated with the pension and post-retirement obligations ($2.1
             million); and
 
          4. The deferred income tax expense ($4.9 million) associated with
             these adjustments.
 
Interest expense and related debt incurred by Houston Industries to fund the
cash portion of the purchase consideration has not been pushed down to NorAm and
its subsidiaries.
 
     Because results of operations and other financial information for periods
before and after the Acquisition Date are not comparable, NorAm is presenting
certain financial data on: (i) an actual basis for NorAm for 1997 and 1996 and
(ii) a pro forma basis for 1997 and 1996 as if the Merger had taken place at the
beginning of each period presented. These results do not necessarily reflect the
results which would have been obtained if the Merger had actually occurred on
the dates indicated or the results that may be expected in the future.
 
     1997 Compared to 1996 (Pro Forma). NorAm had pro forma operating revenues
of $5.9 billion in 1997 compared to $4.8 billion in 1996. Pro forma operating
expenses for 1997 were $5.6 billion compared to $4.5 billion for 1996. Pro forma
operating income for 1997 decreased $59.0 million (19%) in comparison to 1996
(before a one time charge of $22.3 million for early retirement and severance in
1996). This decrease is principally the result of (i) hedging-related losses of
approximately $17.4 million incurred in the first quarter of 1997 (prior to the
Merger) by a subsidiary of NorAm, (ii) a weather-related decline in sales
volumes of approximately $18.0 million from Natural Gas Distribution, and (iii)
increased administrative and general expense of approximately $10.0 million
associated with increased staffing and marketing in connection with increasing
the scope of energy marketing activities. For a more detailed comparative
discussion regarding pro forma operating revenue and expense items, see "Results
of Operations By Business Unit" below.
 
     1997 Compared to 1996 (Actual). NorAm had actual operating revenues of $5.9
billion in 1997 compared to $4.8 billion in 1996. Actual operating expenses for
1997 were $5.6 billion compared to $4.5 billion for 1996. The increase in
operating revenues and expenses was caused primarily by increases in trading
activities in NorAm's Energy Marketing business unit. The decrease in operating
income was caused by the same factors referenced in the discussion of pro forma
operating income.
 
     During the first quarter of 1996, NorAm instituted a reorganization plan
affecting its NorAm Gas Transmission Company (NGT) and Mississippi River
Transmission Corporation (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) NorAm's Entex division instituted an early retirement program which
was accepted by approximately 100 employees and (2) NorAm'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 after tax),
which pre-tax amount is reported in the accompanying Statements of Consolidated
Income as "Early retirement and severance".
 
                                       102
<PAGE>   105
 
     The following table sets forth selected financial and operating data on an
actual and pro forma basis for the year ended December 31, 1997 and 1996,
followed by a discussion of significant variances in period-to-period results:
 
SELECTED FINANCIAL RESULTS:
 
<TABLE>
<CAPTION>
                                                 ACTUAL(1)                  PRO FORMA(2)
                                          YEAR ENDED DECEMBER 31,     YEAR ENDED DECEMBER 31,
                                          ------------------------    ------------------------
                                             1997          1996          1997          1996       % CHANGE
                                          ----------    ----------    ----------    ----------    --------
                                                                             UNAUDITED
                                                         (THOUSANDS OF DOLLARS)
<S>                                       <C>           <C>           <C>           <C>           <C>
Operating Revenues:
  Natural Gas Distribution..............  $2,202,301    $2,113,589    $2,202,301    $2,113,589        4%
  Interstate Pipeline...................     295,044       346,762       295,044       346,762      (15%)
  Energy Marketing......................   3,589,118     2,645,106     3,589,118     2,645,106       36%
  Corporate and Other...................      81,694        55,403        81,694        55,403       47%
  Elimination of Inter-unit
    Revenues(5).........................    (309,767)     (372,398)     (309,767)     (372,398)     (17%)
                                          ----------    ----------    ----------    ----------
                                           5,858,390     4,788,462     5,858,390     4,788,462      (22%)
                                          ----------    ----------    ----------    ----------
Operating Income (loss):
  Natural Gas Distribution..............     166,435       183,972       152,463       160,020       (5%)
  Interstate Pipeline...................     108,708       124,417        99,927       109,362       (9%)
  Energy Marketing......................      19,288        55,693        15,295        48,848      (69%)
  Corporate and Other...................     (30,235)      (27,272)      (22,613)      (14,204)      59%
                                          ----------    ----------    ----------    ----------
                                             264,196       336,810       245,072       304,026      (19%)
Merger Transaction Costs(3).............      18,400
Early Retirement and Severance(4).......                    22,344                      22,344     (100%)
                                          ----------    ----------    ----------    ----------
Consolidated............................     245,796       314,466       245,072       281,682      (13%)
Interest Expense, Net...................     126,150       132,557       112,482       109,128        3%
Distributions on Subsidiary Trust
  Securities............................       6,596         5,842         1,479         1,110       33%
Other (Income) and Deductions...........      (9,453)       14,577        (9,453)       14,577     (165%)
Income Tax Expense......................      55,781        66,352        72,261        79,973      (10%)
Extraordinary (Gain) Loss, Less Taxes...        (237)        4,280            --            --        --
                                          ----------    ----------    ----------    ----------
  Net Income............................  $   66,959    $   90,858    $   68,303    $   76,894      (11%)
                                          ==========    ==========    ==========    ==========
</TABLE>
 
---------------
 
(1)  Actual results for 1997 combine Former NorAm's results for the seven months
     ended July 31, 1997 with Current NorAm's results for the five months ended
     December 31, 1997.
 
(2)  Pro forma results reflect purchase accounting adjustments as if the Merger
     had occurred on January 1, 1996 and 1997, as applicable. Adjustments for
     goodwill have been allocated to the respective business units.
 
(3)  For expenses associated with the completion of the business combination
     with Houston Industries, see Note 1(o) to NorAm's Financial Statements.
 
(4)  Expenses associated with an early retirement and severance plan, see Note
     1(n) to NorAm's Financial Statements.
 
(5)  Elimination of operating revenues derived from sales to affiliated business
     units.
 
                                       103
<PAGE>   106
 
                     RESULTS OF OPERATIONS BY BUSINESS UNIT
 
NATURAL GAS DISTRIBUTION
 
     NorAm's domestic natural gas distribution operations (Natural Gas
Distribution) are conducted through its Arkla, Entex and Minnegasco divisions.
These operations consist of natural gas sales to, and natural gas transportation
for, residential, commercial and certain industrial customers in six states:
Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
 
     The following table provides summary data regarding the unaudited pro forma
financial results of operations of Natural Gas Distribution, including operating
statistics, for 1997 and 1996.
 
<TABLE>
<CAPTION>
                                                               UNAUDITED
                                                               PRO FORMA
                                                               YEAR ENDED
                                                              DECEMBER 31,
                                                            ----------------    PERCENT
                                                             1997      1996     CHANGE
                                                            ------    ------    -------
                                                            ($ IN MILLIONS)
<S>                                                         <C>       <C>       <C>
Operating Revenues........................................  $2,202    $2,113       4%
Operating Expenses:
  Natural Gas.............................................   1,441     1,348       7%
  Operation and Maintenance...............................     247       250      (1%)
  Depreciation and Amortization...........................     123       120       3%
  Other Operating Expenses(1).............................     238       235       1%
                                                            ------    ------
Total Operating Expenses..................................   2,049     1,953       5%
                                                            ------    ------
  Operating Income........................................  $  153    $  160      (4%)
                                                            ======    ======
Throughput Data (in Bcf):
  Residential and Commercial Sales........................     326       333      (2%)
  Industrial Sales........................................      59        58       2%
  Transportation..........................................      42        42       --
                                                            ------    ------
     Total Throughput.....................................     427       433      (1%)
                                                            ======    ======
</TABLE>
 
---------------
 
(1) Before a $6 million one-time charge incurred in 1996 for early retirement
    and severance costs.
 
     1997 Compared to 1996 (Pro Forma). The increase of approximately $89
million (4%) in pro forma Natural Gas Distribution operating revenue for the
year ended December 31, 1997 in comparison to the corresponding period of 1996
is principally due to the increase in purchased gas costs.
 
     Pro forma operating income was $153 million in 1997 compared with $160
million (before a one-time charge of $6 million for early retirement and
severance) in 1996. The decrease of approximately $7 million (4%) in 1997 pro
forma operating income was principally due to decreased Minnegasco customer
usage due to warmer weather and customer conservation, decreased Arkla customer
usage due to warmer weather (primarily in the first quarter of 1997) and Arkla's
charges associated with the applicable state regulatory commission's methodology
of calculating the price of gas charged to customers (the purchased gas
adjustment) primarily in Louisiana. Partially offsetting the decrease is an
increase in Minnegasco's performance based rate incentive recoveries and
customer growth and increased revenues from Entex due to rate relief granted in
1996 and fully reflected in 1997.
 
     The $93 million (7%) increase in gas purchased costs in 1997 compared to
1996 primarily reflects the increase in Natural Gas Distribution's average cost
of gas in 1997 (consistent with the overall increase in the market price of gas)
along with the purchased gas adjustment described above.
 
INTERSTATE PIPELINE
 
     NorAm's interstate natural gas pipeline operations (Interstate Pipeline)
are conducted through NorAm Gas Transmission Company (NGT) and Mississippi River
Transmission Corporation (MRT), two wholly
 
                                       104
<PAGE>   107
 
owned subsidiaries of NorAm. The NGT system consists of approximately 6,200
miles of natural gas transmission lines located in portions of Arkansas, Kansas,
Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas. The MRT system
consists of approximately 2,000 miles of pipeline serving principally the
greater St. Louis area in Missouri and Illinois.
 
     The following table provides summary data regarding the unaudited pro forma
results of operations of Interstate Pipeline including operating statistics for
1997 and 1996.
 
<TABLE>
<CAPTION>
                                                                 UNAUDITED
                                                                 PRO FORMA
                                                                 YEAR ENDED
                                                                DECEMBER 31,
                                                              ----------------    PERCENT
                                                               1997      1996     CHANGE
                                                              ------    ------    -------
                                                              ($ IN MILLIONS)
<S>                                                           <C>       <C>       <C>
Operating Revenues..........................................   $295      $347      (15%)
Operating Expenses:
  Natural Gas...............................................     42        76      (45%)
  Operation and Maintenance.................................     45        49       (8%)
  Depreciation and Amortization.............................     46        45        2%
  Other Operating Expenses(1)...............................     62        68       (9%)
                                                               ----      ----
          Total Operating Expenses..........................    195       238      (18%)
                                                               ----      ----
Operating Income............................................   $100      $109       (9%)
                                                               ====      ====
Throughput Data (in million MMBtu):
Natural Gas Sales...........................................     18        33      (45%)
Transportation..............................................    911       952       (4%)
     Elimination(2).........................................    (17)      (31)      45%
                                                               ----      ----
Total Throughput............................................    912       954       (4%)
                                                               ====      ====
</TABLE>
 
---------------
 
(1) Before a $17 million one-time charge incurred in 1996 for early retirement
    and severance costs.
 
(2) Elimination of volumes both transported and sold.
 
     1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for
Interstate Pipeline decreased by $52 million (15%) for the year ended December
31, 1997 in comparison to the corresponding period of 1996. The decrease in
revenues primarily reflects a decline in natural gas sales revenue resulting
from the expiration in 1996 of an unbundled natural gas sales contract between
Interstate Pipeline and Arkla. Natural gas sales to Natural Gas Distribution
were $60 million in 1996 and none in 1997. It is anticipated that substantially
all future revenues for Interstate Pipeline will be from natural gas
transportation only.
 
     Pro forma operating income was $100 million in 1997 compared to $109
million (before a one-time charge of $17 million for early retirement and
severance) in 1996. This decrease of approximately $9 million (9%) in Interstate
Pipeline's pro forma operating income between 1997 and 1996 results primarily
from three factors: (i) a 6% decrease in transportation revenues, (ii) a 43%
decrease in natural gas sales revenue (as described above) and (iii) lower
demand for natural gas transportation as a result of lower natural gas
consumption (primarily weather-related) in the eastern markets served by
Interstate Pipeline. These factors were offset partially by an approximately 18%
decline in operating expenses primarily due to decreases in gas purchased.
 
     The decline in transportation revenues are largely attributable to price
differentials between the average spot price for Mid-continent natural gas
(Interstate Pipeline's primary supply area) and Gulf Coast natural gas in 1997.
When prices of Gulf Coast gas decrease significantly relative to Mid-continent
gas, downward pressure on transportation prices occurs when selling in west to
east markets like those of NGT. This competitive pressure, in turn, results in a
decline in average transportation rates under contracts that contain
market-sensitive pricing provisions.
 
                                       105
<PAGE>   108
 
     The $34 million (45%) decrease in gas purchased costs in 1997 compared to
1996 is largely attributable to the expiration of long-term supply contracts
entered into prior to unbundling, as discussed above. Other operating expenses
decreased $4 million (9%) in 1997 compared to 1996 primarily due to the
elimination of non-recurring costs combined with cost reductions related to the
1996 early retirement and severance program and reductions in costs allocated
from NorAm.
 
     During 1997, Interstate Pipeline's largest unaffiliated customer was a
natural gas utility that serves the greater St. Louis metropolitan area.
Revenues from this customer are generated pursuant to several long-term firm
transportation and storage contracts that currently are scheduled to expire at
various dates between October 1999 and May 2000. Interstate Pipeline is
currently negotiating with the natural gas utility to renew these agreements.
 
ENERGY MARKETING
 
     NorAm's energy marketing and gathering business (Energy Marketing) includes
the operations of NorAm's wholesale and retail energy marketing businesses and
natural gas gathering activities (conducted, respectively, by NorAm Energy
Services, Inc. (NES), NorAm Energy Management, Inc., and NorAm Field Services
Corp., three wholly owned subsidiaries of NorAm).
 
     The following table provides summary data regarding the unaudited pro forma
results of operations of Energy Marketing, including operating statistics for
1997 and 1996.
 
<TABLE>
<CAPTION>
                                                           UNAUDITED PRO FORMA
                                                                YEAR ENDED
                                                               DECEMBER 31
                                                           --------------------     PERCENT
                                                             1997        1996       CHANGE
                                                           --------    --------     -------
                                                              (IN MILLIONS)
<S>                                                        <C>         <C>          <C>
Operating Revenues.......................................   $3,589      $2,645        36%
Operating Expenses:
  Natural Gas and Purchased Power, net...................    3,477       2,489        40%
  Operation and Maintenance..............................       46          68       (32%)
  Depreciation and Amortization..........................       11          10        10%
  Other Operating Expenses...............................       40          29        38%
                                                            ------      ------
          Total Operating Expenses.......................    3,574       2,596        38%
                                                            ------      ------
Operating Income.........................................   $   15      $   49       (69%)
                                                            ======      ======
Operations Data:
  Natural Gas (in Bcf):
     Sales...............................................    1,185       1,076        10%
     Transportation......................................       24          26        (8%)
     Gathering...........................................      242         231         5%
                                                            ------      ------
          Total..........................................    1,451       1,333         9%
                                                            ======      ======
  Electricity:
     Wholesale Power Sales (in thousand MWH).............   24,997       2,776       800%
                                                            ======      ======
</TABLE>
 
     1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for Energy
Marketing increased by $944 million (36%) for 1997 in comparison to 1996 due to
increased natural gas and electricity trading volumes. Increased volumes in 1997
had minimal effect on operating income due to low operating margins in both
periods.
 
     Pro forma operating income for 1997 was $15 million compared to $49 million
in 1996. This decrease of approximately $34 million (69%) was primarily
attributed to: (i) hedging losses associated with anticipated first quarter 1997
sales under peaking contracts and (ii) losses from the sale of natural gas held
in storage and unhedged in the first quarter of 1997 totaling $17 million. In
addition, other operating expenses increased
 
                                       106
<PAGE>   109
 
$11 million largely due to increased staffing and marketing activities made in
support of the increased sales and expanded marketing efforts. Partially
offsetting these unfavorable impacts were increased margins from natural gas
gathering activities.
 
     Natural gas and purchased power expense increased $988 million (40%) in
1997 compared to 1996 primarily due to increased gas and electricity marketing
activities but also included hedging losses and losses from the sale of natural
gas, as discussed above.
 
     To minimize fluctuations in the price of natural gas and transportation,
NorAm, primarily through NES, enters into futures transactions, swaps and
options in order to hedge against market price changes affecting (i) certain
commitments to buy, sell and transport natural gas, (ii) existing gas storage
inventory and (iii) certain anticipated transactions, some of which carry
off-balance sheet risk. NES also enters into natural gas derivatives for trading
purposes and electricity derivatives for hedging and trading purposes. For a
discussion about NorAm's accounting treatment of derivative instruments, see
Note 2 to NorAm's Consolidated Financial Statements and Quantitative and
Qualitative Disclosure About Market Risk in Item 7A of this report.
 
     NorAm believes that NES' energy marketing and risk management services have
the potential of complementing Houston Industries' strategy of developing and/or
acquiring unregulated generation assets in other markets. As a result, NorAm has
made, and expects to continue to make, significant investments in developing
NES' internal software, trading and personnel resources.
 
CORPORATE
 
     NorAm's corporate and other business (Corporate) includes the operations of
NorAm's unregulated retail services business, international operations, certain
real estate investments, corporate costs, and elimination of transactions
between affiliated business units.
 
     While pro forma operating revenues for Corporate increased $26.3 million
(47%) from 1996 to 1997, pro forma operating loss increased by $8.4 million
(59%). The increased revenues and operating loss were principally due to 1997
increased activities and development costs associated with NorAm's utility
services and consumer services businesses.
 
NON-OPERATING INCOME AND EXPENSE
 
     The $3.4 million increase in Interest Expense, Net on a pro forma basis for
the year ended December 31, 1997 in comparison to the corresponding period of
1996 reflects the impact of the inclusion in 1997 results of $15 million of
expense associated with NorAm's receivables facility, for which the
corresponding costs in 1996 ($10 million) are included with Other (Income) and
Deductions; see Note 4(a) to NorAm's Consolidated Financial Statements. Apart
from the impact of this reclassification, the $11.3 million decrease in interest
expense in 1997 reflected $5.4 million and $5.9 million of reduction due to a
decrease in the average interest rate and a decrease in the average level of
debt, respectively.
 
     After adjusting for the costs associated with NorAm's receivables facility
as described above, there was a favorable variance of $14 million in other
(income) and deductions on a pro forma basis from the year ended December 31,
1996 to the corresponding period of 1997. A portion of this favorable variance
was due to the close-out of certain interest rate swaps; see Note 4(b) to
NorAm's Consolidated Financial Statements.
 
     The net favorable variance of $7.7 million in pro forma income tax expense
from the year ended December 31, 1996 to the corresponding period of 1997 is
primarily due to decreased 1997 pre-tax income.
 
     Reference is made to Note 4 of NorAm's Consolidated Financial Statements
for a discussion of NorAm's short and long-term debt.
 
                                       107
<PAGE>   110
 
                             NEW ACCOUNTING ISSUES
 
     Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations of the Company -- New Accounting Issues" in
Item 7 of the Form 10-K of Houston Industries, which has been jointly filed with
the NorAm Form 10-K, for a discussion of certain new accounting issues.
 
                                       108
<PAGE>   111
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF NORAM.
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                       STATEMENTS OF CONSOLIDATED INCOME
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                       CURRENT NORAM                     FORMER NORAM
                                       -------------    ----------------------------------------------
                                        FIVE MONTHS     SEVEN MONTHS    TWELVE MONTHS    TWELVE MONTHS
                                           ENDED           ENDED            ENDED            ENDED
                                       DECEMBER 31,       JULY 31,      DECEMBER 31,     DECEMBER 31,
                                           1997             1997            1996             1995
                                       -------------    ------------    -------------    -------------
<S>                                    <C>              <C>             <C>              <C>
Operating Revenues...................   $2,521,342       $3,337,048      $4,788,462       $2,964,679
                                        ----------       ----------      ----------       ----------
Operating Expenses
  Natural gas and purchased power,
     net.............................    2,041,504        2,636,340       3,571,411        1,857,166
  Operation and maintenance..........      259,315          370,369         621,279          564,790
  Depreciation and amortization......       78,207           84,901         142,362          147,109
  Taxes other than income taxes......       50,416           73,142         116,600          108,309
  Merger transaction costs...........        1,144           17,256              --               --
  Early retirement and severance.....           --               --          22,344               --
                                        ----------       ----------      ----------       ----------
                                         2,430,586        3,182,008       4,473,996        2,677,374
                                        ----------       ----------      ----------       ----------
Operating Income.....................       90,756          155,040         314,466          287,305
                                        ----------       ----------      ----------       ----------
Other (Income) and Deductions
  Interest expense, net..............       47,490           78,660         132,557          157,959
  Dividend requirement on preferred
     securities of subsidiary
     trust...........................          279            6,317           5,842               --
  Other, net.........................       (2,243)          (7,210)          3,078           (1,333)
  Loss on sale of accounts
     receivable......................           --               --          11,499            9,771
                                        ----------       ----------      ----------       ----------
                                            45,526           77,767         152,976          166,397
                                        ----------       ----------      ----------       ----------
Income Before Income Taxes...........       45,230           77,273         161,490          120,908
Income Tax Expense...................       24,383           31,398          66,352           55,379
                                        ----------       ----------      ----------       ----------
Income Before Extraordinary Item.....       20,847           45,875          95,138           65,529
Extraordinary gain(loss) on early
  retirement of debt, less taxes.....           --              237          (4,280)             (52)
                                        ----------       ----------      ----------       ----------
Net Income...........................       20,847           46,112          90,858           65,477
Preferred dividend requirement.......           --               --           3,597            7,800
                                        ----------       ----------      ----------       ----------
Earnings Available to Common Stock...   $   20,847       $   46,112      $   87,261       $   57,677
                                        ==========       ==========      ==========       ==========
</TABLE>
 
            See Notes to NorAm's Consolidated Financial Statements.
 
                                       109
<PAGE>   112
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                                                         UNREALIZED
                                COMMON STOCK(1)         PREFERRED STOCK(2)                   RETAINED    INVESTMENT
                            -----------------------   ----------------------     PAID-IN     EARNINGS    GAIN (LOSS)
                               SHARES       AMOUNT      SHARES      AMOUNT       CAPITAL     (DEFICIT)   NET OF TAX      TOTAL
                            ------------   --------   ----------   ---------   -----------   ---------   -----------   ----------
<S>                         <C>            <C>        <C>          <C>         <C>           <C>         <C>           <C>
FORMER NORAM:
Balance at January 1,
  1995....................   122,530,248   $ 76,581    2,600,000   $ 130,000   $   868,289   $(360,079)    $ 2,586     $  717,377
Net Income................                                                                      65,477                     65,477
Cash Dividends:
  Preferred stock -- $3.00
    per share.............                                                                      (7,800)                    (7,800)
  Common stock -- $0.28
    per share.............                                                                     (34,538)                   (34,538)
Change in Market Value of
  Marketable Equity
  Securities, net of
  tax.....................                                                                                  12,730         12,730
Issuance of Common stock
  under Direct Stock
  Purchase Plan...........     1,610,148      1,006                                  8,795                                  9,801
Other Issuances...........       663,297        415                                  3,801                                  4,216
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
Balance at December 31,
  1995....................   124,803,693     78,002    2,600,000     130,000       880,885    (336,940)     15,316        767,263
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
Net Income................                                                                      90,858                     90,858
Cash Dividends:
  Preferred stock -- $1.50
    per share.............                                                                      (3,900)                    (3,900)
  Common stock -- $0.28
    per share.............                                                                     (36,721)                   (36,721)
Change in Market Value of
  Marketable Equity
  Securities, net of
  tax.....................                                                                                 (15,311)       (15,311)
Conversion to Subordinated
  Debentures..............                            (2,600,000)   (130,000)                                            (130,000)
Issuance of Common Stock
  under Direct Stock
  Purchase Plan...........       937,193        586                                  9,668                                 10,254
Public Issuance of Common
  Stock...................    11,500,000      7,188                                101,775                                108,963
Other Issuances...........       667,287        417                                  8,725                                  9,142
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
Balance at December 31,
  1996....................   137,908,173     86,193           --          --     1,001,053    (286,703)          5        800,548
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
Net Income................                                                                      46,112                     46,112
Cash Dividends:
  Common stock -- $0.14
    per share.............                                                                     (19,281)                   (19,281)
Change in Market Value of
  Marketable Equity
  Securities, net of
  tax.....................                                                                                   5,874          5,874
Conversion of
  NorAm-Obligated
  Mandatorily Redeemable
  Convertible Preferred
  Securities of Subsidiary
  Trust Holding Solely
  Subordinated Debentures
  of NorAm to Common
  Stock...................    11,428,262      7,143                                131,425                                138,568
Other Issuances...........       347,527        216                                  5,796                                  6,012
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
  Balance at July 31,
    1997..................   149,683,962     93,552           --          --     1,138,274    (259,872)      5,879        977,833
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
CURRENT NORAM (POST
  MERGER):
Adjustments due to Merger:
  Eliminate Former NorAm
    Balances..............  (149,683,962)   (93,552)                            (1,138,274)    259,872      (5,879)      (977,833)
Capital contribution from
  Parent..................         1,000          1                              2,463,831                              2,463,832
Net Income................                                                                      20,847                     20,847
Change in Market Value of
  Marketable Equity
  Securities, net of
  tax.....................                                                                                  (5,634)        (5,634)
                            ------------   --------   ----------   ---------   -----------   ---------     -------     ----------
Balance at December 31,
  1997....................         1,000   $      1           --   $      --   $ 2,463,831   $  20,847     $(5,634)    $2,479,045
                            ============   ========   ==========   =========   ===========   =========     =======     ==========
</TABLE>
 
---------------
 
(1) $.625 par, authorized 250,000,000 shares. On the Acquisition Date, NorAm's
    pre-merger common stock was canceled and replaced with 1,000 shares of
    common stock (all of which are owned by Houston Industries); see Note 1(b).
 
(2) $3.00 Convertible exchangeable preferred stock, Series A ($50 liquidation
    preference), cumulative, non-voting; authorized 10,000,000 shares. On the
    Acquisition Date, NorAm's pre-merger preferred stock was canceled.
 
            See Notes to NorAm's Consolidated Financial Statements.
 
                                       110
<PAGE>   113
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                          CONSOLIDATED BALANCE SHEETS
                             (THOUSANDS OF DOLLARS)
 
                                     ASSETS
 
<TABLE>
<CAPTION>
                                                              CURRENT NORAM    FORMER NORAM
                                                              -------------    ------------
                                                              DECEMBER 31,     DECEMBER 31,
                                                                  1997             1996
                                                              -------------    ------------
<S>                                                           <C>              <C>
Property, Plant and Equipment
  Natural gas distribution..................................   $1,326,442       $2,158,013
  Interstate pipeline.......................................    1,258,087        1,685,959
  Energy marketing..........................................      162,519          252,509
  Other.....................................................       14,972           20,150
                                                               ----------       ----------
          Total.............................................    2,762,020        4,116,631
  Less accumulated depreciation and amortization............       59,531        1,675,576
                                                               ----------       ----------
  Property, plant and equipment -- net......................    2,702,489        2,441,055
                                                               ----------       ----------
Current Assets
  Cash and cash equivalents.................................       35,682           27,981
  Accounts and notes receivable, principally customer.......      969,248          696,982
  Accounts receivable from parent...........................       10,161
  Deferred income taxes.....................................        8,309           10,495
  Gas in underground storage................................       63,702           70,651
  Materials and supplies....................................       29,611           30,595
  Gas purchased in advance of delivery......................        6,200            6,200
  Other current assets......................................       24,386           15,423
                                                               ----------       ----------
          Total current assets..............................    1,147,299          858,327
                                                               ----------       ----------
Other Assets
  Goodwill, net.............................................    2,026,395          466,938
  Prepaid pension asset.....................................       92,064           45,390
  Investment in marketable equity securities................       27,046           26,670
  Regulatory asset for environmental costs..................       21,745           39,152
  Gas purchased in advance of delivery......................       29,048           34,895
  Deferred debits, net......................................       23,954           32,200
                                                               ----------       ----------
          Total other assets................................    2,220,252          645,245
                                                               ----------       ----------
Deferred Charges, net.......................................       69,056           72,850
                                                               ----------       ----------
Total Assets................................................   $6,139,096       $4,017,477
                                                               ==========       ==========
</TABLE>
 
             See Notes to NorAm's Consolidated Financial Statements
 
                                       111
<PAGE>   114
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                   CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
                             (THOUSANDS OF DOLLARS)
 
                      LIABILITIES AND STOCKHOLDERS' EQUITY
 
<TABLE>
<CAPTION>
                                                              CURRENT NORAM    FORMER NORAM
                                                              -------------    ------------
                                                              DECEMBER 31,     DECEMBER 31,
                                                                  1997             1996
                                                              -------------    ------------
<S>                                                           <C>              <C>
Stockholders' Equity:
  Common stock..............................................   $        1       $   86,193
  Paid-in capital...........................................    2,463,831        1,001,053
  Retained earnings (deficit)...............................       20,847         (286,703)
  Unrealized gain (loss) on marketable equity securities,
     net of tax.............................................       (5,634)               5
                                                               ----------       ----------
          Total.............................................    2,479,045          800,548
                                                               ----------       ----------
NorAm-Obligated Mandatorily Redeemable Convertible Preferred
  Securities of Subsidiary Trust Holding Solely Junior
  Subordinated Debentures of NorAm, net.....................       21,290          167,768
Long-Term Debt, less Current Maturities.....................      916,703        1,054,221
Current Liabilities:
  Current maturities of long-term debt......................      232,145          277,000
  Notes payable to banks....................................      390,000          115,000
  Notes payable to parent...................................       22,100
  Receivables facility......................................      300,000
  Accounts payable, principally trade.......................      668,269          762,164
  Income taxes payable......................................                        11,684
  Interest payable..........................................       27,273           31,928
  General taxes.............................................       41,315           51,082
  Customer deposits.........................................       36,626           35,711
  Other current liabilities.................................      133,278          113,628
                                                               ----------       ----------
          Total current liabilities.........................    1,851,006        1,398,197
                                                               ----------       ----------
Deferred Credits and Other Liabilities:
  Accumulated deferred income taxes.........................      483,039          320,506
  Estimated environmental remediation costs.................       21,745           39,152
  Payable under capacity lease agreement....................       41,000           41,000
  Benefit liabilities.......................................      182,687           90,544
  Estimated obligations under indemnification provisions of
     sale agreements........................................       11,391           29,098
  Refundable excess deferred income taxes...................       13,569           17,946
  Other.....................................................      117,621           58,497
                                                               ----------       ----------
          Total.............................................      871,052          596,743
                                                               ----------       ----------
Commitments and Contingencies (Note 8)
Total Liabilities and Stockholders' Equity..................   $6,139,096       $4,017,477
                                                               ==========       ==========
</TABLE>
 
             See Notes to NorAm's Consolidated Financial Statements
 
                                       112
<PAGE>   115
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                     STATEMENTS OF CONSOLIDATED CASH FLOWS
                INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                                                  CURRENT NORAM                   FORMER NORAM
                                                  -------------   --------------------------------------------
                                                   FIVE MONTHS    SEVEN MONTHS   TWELVE MONTHS   TWELVE MONTHS
                                                      ENDED          ENDED           ENDED           ENDED
                                                  DECEMBER 31,      JULY 31,     DECEMBER 31,    DECEMBER 31,
                                                      1997            1997           1996            1995
                                                  -------------   ------------   -------------   -------------
<S>                                               <C>             <C>            <C>             <C>
Cash Flows from Operating Activities:
  Net income....................................   $   20,847      $  46,112       $  90,858       $  65,477
  Adjustments to reconcile net income to net
     cash provided by (used in) operating
     activities:
     Depreciation and amortization..............       78,207         84,901         142,362         147,109
     Deferred income taxes......................       36,770         14,589          28,809          34,883
     Early retirement and severance, less cash
       costs....................................                                      12,941
     Extraordinary (gain)loss, less taxes.......                        (237)          4,280              52
     Utilization of tax loss carryforwards......                                      (2,405)        (19,797)
     Changes in other assets and liabilities,
       net of the effects of the acquisition:
       Accounts and notes receivable-net........     (361,285)       313,586        (353,703)       (119,933)
       Inventories..............................       (2,250)         9,980         (14,895)         25,112
       Deferred gas costs.......................        8,655         (7,715)         12,788         (19,831)
       Other current assets.....................       (1,298)        (1,128)         10,935          10,661
       Accounts payable.........................      148,071       (224,590)        266,446         162,595
       Interest and taxes accrued...............      (13,402)       (19,996)          4,712          19,597
       Other current liabilities................       42,284        (22,633)         10,483           5,151
       Recoveries under gas contract disputes...        2,600          5,500          10,900          24,200
       Other-net................................       10,557            903           3,642           3,633
                                                   ----------      ---------       ---------       ---------
          Net cash provided by (used in)
            operating activities................      (30,244)       199,272         228,153         338,909
                                                   ----------      ---------       ---------       ---------
Cash Flows from Investing Activities:
  Purchase of Former NorAm, net of cash
     acquired...................................   (1,422,672)
  Capital expenditures..........................      (93,414)       (88,638)       (172,200)       (173,600)
  Cash surrender value of life insurance........                                                      12,276
  Other, net....................................       (1,079)        (6,424)         (4,957)         (4,403)
                                                   ----------      ---------       ---------       ---------
          Net cash used in investing
            activities..........................   (1,517,165)       (95,062)       (177,157)       (165,727)
                                                   ==========      =========       =========       =========
</TABLE>
 
                                                                      (continued
on next page)
 
                                       113
<PAGE>   116
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                     STATEMENTS OF CONSOLIDATED CASH FLOWS
                INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
                             (THOUSANDS OF DOLLARS)
                                  (CONTINUED)
 
<TABLE>
<CAPTION>
                                                  CURRENT NORAM                   FORMER NORAM
                                                  -------------   --------------------------------------------
                                                   FIVE MONTHS    SEVEN MONTHS   TWELVE MONTHS   TWELVE MONTHS
                                                      ENDED          ENDED           ENDED           ENDED
                                                  DECEMBER 31,      JULY 31,     DECEMBER 31,    DECEMBER 31,
                                                      1997            1997           1996            1995
                                                  -------------   ------------   -------------   -------------
<S>                                               <C>             <C>            <C>             <C>
Cash Flows from Financing Activities:
  Cash portion of capital contribution from
     Houston Industries.........................   $1,426,067
  Proceeds from issuance of 7 1/2% notes........                                                   $ 200,000
  Retirements and reacquisitions of long-term
     debt.......................................     (165,808)     $(230,667)      $(396,733)       (335,352)
  Proceeds from bank term loan..................                     150,000                         150,000
  Public issuance of common stock...............                                     108,963
  Public issuance of convertible preferred
     securities by
     subsidiary trust...........................                                     167,756
  Other debt borrowings (repayments)............      317,500        (42,500)        105,000        (100,000)
  Return of advance received under contingent
     sales agreement............................                                                     (50,000)
  Increase in receivables facility..............       24,000         41,000
  Issuance of common stock under direct stock
     purchase plan, net.........................                                      10,254           9,801
  Common and preferred stock dividends..........                     (19,281)        (40,621)        (42,338)
  Redemption of convertible securities..........       (9,504)
  Increase (decrease) in overdrafts.............       (9,164)       (27,348)          9,055          (9,614)
                                                   ----------      ---------       ---------       ---------
          Net cash provided by (used in)
            financing activities................    1,583,091       (128,796)        (36,326)       (177,503)
                                                   ----------      ---------       ---------       ---------
Net Increase (Decrease) in Cash and Cash
  Equivalents...................................       35,682        (24,586)         14,670          (4,321)
Cash and Cash Equivalents at Beginning of the
  Period........................................                      27,981          13,311          17,632
                                                   ----------      ---------       ---------       ---------
Cash and Cash Equivalents at End of the
  Period........................................   $   35,682      $   3,395       $  27,981       $  13,311
                                                   ==========      =========       =========       =========
Supplemental Disclosure of Cash Flow
  Information:
Cash Payments:
  Interest (net of amounts capitalized).........   $   55,951      $  67,100       $ 140,751       $ 154,866
  Income taxes, net.............................          714         20,900          29,657          19,970
</TABLE>
 
The aggregate consideration paid to Former NorAm stockholders in connection with
the Merger consisted of $1.4 billion in cash and 47.8 million shares of Houston
Industries common stock valued at approximately $1.0 billion. The overall
transaction was valued at $4.0 billion consisting of $2.4 billion for Former
NorAm's common stock and common stock equivalents and $1.6 billion of Former
NorAm debt. A significant portion ($139 million) of NorAm obligated mandatorily
redeemable convertible preferred securities of subsidiary trust holding solely
subordinated debentures of NorAm was converted to NorAm Common Stock in non-cash
transactions prior to the Merger; see Note 5.
 
            See Notes to NorAm's Consolidated Financial Statements.
 
                                       114
<PAGE>   117
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
 
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
(a) Nature of Operations.
 
     NorAm Energy Corp. (NorAm), a Delaware corporation, is a wholly owned
subsidiary of Houston Industries defined below. NorAm is principally engaged in
the natural gas industry, including gathering, transmission, marketing, storage
and distribution. Collectively, these operations accounted for in excess of 90%
of NorAm's total revenues, income or loss and identifiable assets during 1997.
 
     NorAm's natural gas distribution operations (Natural Gas Distribution) are
conducted by three of its unincorporated divisions: Entex, Minnegasco and Arkla.
NorAm's interstate pipeline operations (Interstate Pipeline) are conducted by
its wholly owned subsidiaries, NorAm Gas Transmission Company (NGT) and
Mississippi River Transmission Corporation (MRT). NorAm's energy marketing
activities are conducted primarily by NorAm Energy Services, Inc. (NES) and
NorAm Energy Management, Inc. (NEM) and its gathering activities are conducted
by NorAm Field Services Corp. (NFS) (collectively Energy Marketing). NorAm's
principal operations are located in Arkansas, Louisiana, Minnesota, Mississippi,
Missouri and Texas.
 
     As of December 31, 1997, all shares of NorAm's common stock were pledged as
collateral under a $1.64 billion loan arrangement entered into by a subsidiary
of Houston Industries in connection with the Merger (defined below). Under the
provisions of this facility, Houston Industries may become obligated to pledge
additional stock of subsidiaries of NorAm if such subsidiaries should become
"significant subsidiaries" (as defined under the facility) of Houston
Industries.
 
(b) Merger With Houston Industries Incorporated.
 
     On August 6, 1997 (Acquisition Date), Houston Industries Incorporated
(Former HI) merged with and into Houston Lighting & Power Company, which was
renamed "Houston Industries Incorporated" (Houston Industries), and NorAm Energy
Corp., (Former NorAm) merged with and into a subsidiary of Houston Industries,
HI Merger, Inc., which was renamed "NorAm Energy Corp." (NorAm). Effective upon
the mergers (collectively, the Merger), each outstanding share of common stock
of Former HI was converted into one share of common stock (including associated
preference stock purchase rights) of Houston Industries, and each outstanding
share of common stock of Former NorAm was converted into the right to receive
$16.3051 cash or 0.74963 shares of common stock of Houston Industries. The
aggregate consideration paid to Former NorAm stockholders in connection with the
Merger consisted of $1.4 billion in cash and 47.8 million shares of Houston
Industries' common stock valued at approximately $1.0 billion. The overall
transaction was valued at $4.0 billion consisting of $2.4 billion for Former
NorAm's common stock and common stock equivalents and $1.6 billion of Former
NorAm debt ($1.3 billion of which was long-term debt).
 
     The Merger was recorded under the purchase method of accounting with assets
and liabilities of NorAm reflected at their estimated fair values as of the
Acquisition Date, resulting in a "new basis" of accounting. In NorAm's
consolidated financial statements (NorAm's Consolidated Financial Statements),
periods which reflect the new basis of accounting are labeled as "Current NorAm"
and periods which do not reflect the new basis of accounting are labeled "Former
NorAm". Former NorAm's Statement of Consolidated Income for the seven months
ended July 31, 1997 include certain adjustments from August 1, 1997 to the
Acquisition Date for pre-merger transactions.
 
     NorAm's Consolidated Balance Sheets for periods after the Acquisition Date
reflect adjustments associated with Houston Industries' assignment of the
purchase price, principally consisting of (1) the revaluation of certain
property, plant and equipment and long-term debt to their estimated fair market
value, (2) the recognition of certain pension and postretirement benefit
obligations previously being recognized through amortization, (3) the
recognition of goodwill as described above, (4) the elimination of NorAm's
historical goodwill, (5) the elimination of NorAm's historical stockholders'
equity balances and accumulated
 
                                       115
<PAGE>   118
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
depreciation and amortization as of the Acquisition Date and (6) the recognition
of the associated deferred income tax effects. In addition, NorAm's pre-merger
common stock was canceled and replaced with 1,000 shares of common stock (all of
which are owned by Houston Industries), rendering presentation of per share data
no longer meaningful. Houston Industries' debt to fund the cash portion of the
purchase consideration has not been allocated or "pushed down" to NorAm and is
not reflected on NorAm's Financial Statements.
 
     NorAm's Statements of Consolidated Income for periods after the Acquisition
Date are principally affected by (1) the amortization (over 40 years) of the
newly-recognized goodwill, partially offset by the elimination of the
amortization of NorAm's historical goodwill, (2) the amortization (to interest
expense) of the revaluation of long-term debt, (3) the removal of the
amortization (to operating expense) previously associated with the pension and
postretirement obligations as described preceding and (4) the deferred income
tax expense associated with these adjustments. Interest expense on Houston
Industries' debt which was used to fund the cash portion of the acquisition has
not been allocated or "pushed down" to NorAm and is not reflected on NorAm's
Financial Statements. For these reasons, among others, certain financial
information for periods before and after the Acquisition Date is not comparable.
 
     If the Merger had occurred on January 1, 1997 and 1996, NorAm's unaudited
pro forma net income for 1997 and 1996 would have been $68.3 million and $76.9
million, respectively. Pro forma results are based on assumptions deemed
appropriate by NorAm's management, have been prepared for informational purposes
only and are not necessarily indicative of the results which would have resulted
had the Merger actually taken place on the date indicated.
 
(c) Regulatory Assets and Regulation.
 
     In general, NorAm's interstate pipelines are subject to regulation by the
Federal Energy Regulatory Commission, while its natural gas distribution
operations are subject to regulation at the state or municipal level.
Historically, all of NorAm's rate-regulated businesses have followed the
accounting guidance contained in Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" .
NorAm discontinued application of SFAS No. 71 to NGT in 1992. As a result of the
continued application of SFAS No. 71 to MRT and the natural gas distribution
operations, NorAm's financial statements contain assets and liabilities which
would not be recognized by unregulated entities.
 
     At December 31, 1997 approximately $48 million in regulatory assets are
reflected on NorAm's Consolidated Balance Sheet as deferred debits. These assets
represent probable future revenue to NorAm associated with certain incurred
costs as these costs are recovered through the rate making process. These costs
are being recovered through rates over varying periods up to 40 years.
 
(d) Principles of Consolidation.
 
     NorAm's Consolidated Financial Statements include the accounts of NorAm and
its wholly owned subsidiaries (NorAm). All significant intercompany transactions
and balances are eliminated in consolidation.
 
(e) Property, Plant and Equipment.
 
     Property, plant and equipment have been revalued to estimated fair market
value as of the Acquisition Date in accordance with the purchase method of
accounting, and depreciated or amortized on a straight-line basis over their
estimated useful lives; see Note 1(b) above. Prior to the Acquisition Date, such
assets were carried at cost. 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.
 
                                       116
<PAGE>   119
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(f) Depreciation and Amortization Expense.
 
     Goodwill, none of which is being recovered in regulated service rates, is
amortized on a straight-line basis over 40 years. Approximately $29.9 million of
goodwill was amortized during 1997. Of this amount, $21.6 million represents
amortization related to the Merger and incurred during the period from the
Acquisition Date through December 31, 1997. Goodwill amortization for 1996 was
approximately $14.2 million. NorAm 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. For additional information regarding the
amortization of goodwill in connection with the Merger, see Note 1(b) above.
 
(g) Fuel Stock and Other Inventories.
 
     Inventories principally follow the average cost method. Gas inventory (at
average cost) was $63.7 million and $70.7 million at December 31, 1997 and 1996,
respectively. All non-utility inventories held for resale are valued at the
lower of cost or market.
 
(h) Revenues.
 
     NorAm'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.
 
(i) Statements of Consolidated Cash Flows.
 
     For purposes of reporting cash flows, cash equivalents are considered to be
short-term, highly liquid investments readily convertible into cash.
 
(j) Derivative Financial Instruments (Risk Management).
 
     For information regarding NorAm's accounting for derivative financial
instruments associated with natural gas, electric power and transportation risk
management activities, see Note 2.
 
(k) Income Taxes.
 
     Houston Industries files a consolidated federal income tax return, in which
NorAm and its subsidiaries are included (as of the Acquisition Date). Houston
Industries follows a policy of comprehensive interperiod income tax allocation.
For additional information regarding income taxes, see Note 7.
 
(l) Investments in Marketable Equity Securities.
 
     A subsidiary of NorAm holds certain equity securities classified as
"available-for-sale" and, in accordance with SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," reports such investments at
estimated fair value with any unrealized gain or loss, net of tax, as a separate
component of stockholders' equity. At December 31, 1997, NorAm's unrealized loss
relating to these marketable equity securities was approximately $5.6 million,
net of tax of $3.0 million.
 
(m) Reclassifications and Use of Estimates.
 
     Certain amounts from the previous years have been reclassified to conform
to the 1997 presentation of financial statements. Such reclassifications do not
affect earnings.
 
     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
                                       117
<PAGE>   120
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
 
(n) Early Retirement and Severance.
 
     During the first quarter of 1996, NorAm instituted several early retirement
and reorganization plans, pursuant to which a total of approximately 400
positions were eliminated resulting in expense for severance payments and
enhanced retirement benefits reported as a non-recurring pre-tax charge of
approximately $22.3 million (approximately $13.4 million after tax).
 
(o) Merger Transaction Costs.
 
     "Merger transaction costs" include expenses associated with completion of
the business combination with Houston Industries (see Note 1(b)), principally
consisting of investment banking and legal fees.
 
(p) Allowance for Doubtful Accounts.
 
     Accounts and notes receivable, principally customer as presented on NorAm's
Consolidated Balance Sheets are net of an allowance for doubtful accounts of
$15.3 million and $13.0 million at December 31, 1997 and 1996, respectively.
 
(q) Accounts Payable.
 
     Certain of NorAm'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 on the NorAm Consolidated Balance Sheets
were approximately $17.0 million and $53.5 million at December 31, 1997 and
1996, respectively.
 
(2) DERIVATIVE FINANCIAL INSTRUMENTS (RISK MANAGEMENT)
 
(a) Trading Activities.
 
     NorAm, through NES, offers price risk management services primarily in the
natural gas and electric industries. NES provides these services through, and by
utilizing, a variety of derivative financial instruments, including fixed-price
swap agreements, variable-price swap agreements, exchange-traded energy futures
and option contracts, and swaps and options traded in the over-the-counter
financial markets. Fixed-price swap agreements require payments to, or receipts
of payments from, counterparties based on the differential between a fixed and
variable price for the commodity. Variable-price swap agreements require
payments to, or receipts of payments from, counterparties based on the
differential between either industry pricing publications or exchange
quotations.
 
     Certain trading transactions qualify for hedge accounting and accordingly
unrealized gains and losses associated with these transactions are deferred. For
trading transactions that do not qualify for hedge accounting, NES uses
mark-to-market accounting. Accordingly, such financial instruments are recorded
at fair value with realized and unrealized gains (losses) recorded as a
component of revenues in NorAm's Statements of Consolidated Income. The
recognized, unrealized balance is recorded as a deferred debit on NorAm's
Consolidated Balance Sheets.
 
                                       118
<PAGE>   121
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The notional quantities and maximum terms of derivative financial
instruments held for trading purposes at December 31, 1997 are presented below
(volumes in billions of British thermal units equivalent (Bbtue)):
 
<TABLE>
<CAPTION>
                                               VOLUME-FIXED     VOLUME-FIXED       MAXIMUM
                                               PRICE PAYOR     PRICE RECEIVER    TERM (YEARS)
                                               ------------    --------------    ------------
<S>                                            <C>             <C>               <C>
Natural gas..................................     85,701           64,890             4
Electricity..................................     40,511           42,976             1
</TABLE>
 
     In addition to the fixed-price notional volumes above, NES also has
variable-price swap agreements, as discussed above, totaling 101,465 Bbtue.
Notional amounts reflect the volume of transactions but do not represent the
amounts exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not accurately measure NorAm's exposure to market or credit
risks.
 
     The estimated fair value of derivative financial instruments held for
trading purposes at December 31, 1997 are presented below (dollars in millions):
 
<TABLE>
<CAPTION>
                                                    FAIR VALUE           AVERAGE FAIR VALUE(A)
                                               ---------------------    -----------------------
                                               ASSETS    LIABILITIES    ASSETS      LIABILITIES
                                               ------    -----------    ------      -----------
<S>                                            <C>       <C>            <C>         <C>
Natural gas..................................   $46          $39         $56            $48
Electricity..................................   $ 6          $ 6         $ 3            $ 2
</TABLE>
 
---------------
 
(a)  Computed using the ending balance of each month.
 
     Substantially all of the fair value shown in the table above at December
31, 1997 has been recognized in income. The fair value as of and for the year
ended December 31, 1997 was estimated using quoted prices where available and
considering the liquidity of the market for the derivative financial
instruments. The prices are subject to significant changes based on changing
market conditions. The derivative financial instruments included in the NES
trading portfolio as of and for the year ended December 31, 1996 were
immaterial.
 
     The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein are not
indicative of likely future cash flows as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and NorAm's risk management portfolio needs and
strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
 
(b) Non-Trading Activities.
 
     To reduce the risk from market fluctuations in the price of electric power,
natural gas and related transportation, NorAm and certain of its subsidiaries
enter into futures transactions, swaps and options (Energy Derivatives) in order
to hedge certain natural gas in storage, as well as certain expected purchases,
sales and transportation of natural gas and electric power (a portion of which
are firm commitments at the inception of the hedge). Energy Derivatives 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.
Usage of electricity derivative financial instruments by NorAm and its
subsidiaries for purposes other than trading is immaterial.
 
     NorAm also utilizes interest-rate derivatives (principally interest-rate
swaps) in order to adjust the portion of its overall borrowings which are
subject to interest-rate risk, and also utilizes such derivatives to effectively
fix the interest rate on debt expected to be issued for refunding purposes.
 
     For transactions involving either Energy Derivatives or interest-rate
derivatives, hedge accounting is applied only if the derivative (i) reduces the
price risk of the underlying hedged item and (ii) is designated as a hedge at
its inception. Additionally, the derivatives must be expected to result in
financial impacts which are
 
                                       119
<PAGE>   122
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
inversely correlated to those of the item(s) to be hedged. This correlation (a
measure of hedge effectiveness) is measured both at the inception of the hedge
and on an ongoing basis, with an acceptable level of correlation of 80% for
hedge designation. If and when correlation ceases to exist at an acceptable
level, hedge accounting ceases and mark-to-market accounting is applied.
 
     In the case of interest-rate swaps associated with existing obligations,
cash flows and expenses associated with the interest-rate derivative
transactions are matched with the cash flows and interest expense of the
obligation being hedged, resulting in an adjustment to the effective interest
rate. When interest rate swaps are utilized to effectively fix the interest rate
for an anticipated debt issuance, changes in the market value of the
interest-rate derivatives are deferred and recognized as an adjustment to the
effective interest rate on the newly issued debt.
 
     Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in NorAm's Statements of Consolidated Income
until the underlying hedged transaction occurs. Once it becomes probable that an
anticipated transaction will not occur, deferred gains and losses are
recognized. In general, the financial impact of transactions involving these
Energy Derivatives is included in NorAm's Statements of Consolidated Income
under the caption natural gas and purchased power, net. Cash flows resulting
from these transactions in Energy Derivatives are included in NorAm's Statements
of Consolidated Cash Flows in the same category as the item being hedged.
 
     At December 31, 1997, subsidiaries of NorAm were fixed-price payors and
fixed-price receivers in Energy Derivatives covering 38,754 Bbtu and 7,647 Bbtu
of natural gas, respectively. At December 31, 1996, subsidiaries of NorAm were
fixed-price payors and fixed-price receivers in Energy Derivatives covering
approximately 150,300 Bbtu and 66,500 Bbtu of natural gas, respectively. Also,
at December 31, 1997, subsidiaries of NorAm were parties to variable-priced
Energy Derivatives totaling 3,630 Bbtu of natural gas. The weighted average
maturity of these instruments at December 31, 1997 and 1996, respectively, is
less than one year.
 
     NorAm has entered into options with various third parties which principally
serve to limit the year-to-year escalation from January 1998 to April 1999 in
the purchase price of gas which NorAm is committed to deliver to a distribution
affiliate. These options, which covered 9,800 Bbtu and 2,400 Bbtu at December
31, 1997 and 1996, respectively, expired in January 1998 unexercised. NorAm
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 notional amount is intended to be indicative of NorAm and its
subsidiaries' 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 Energy
Derivatives 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 as further discussed below. Under such circumstances gains (losses) are
deferred and recognized as a component of income when the underlying hedged item
is recognized in income.
 
     The average maturity discussed above and the fair value discussed in Note
10 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions in the trading portfolio at any time in
response to changing market conditions, market liquidity and NorAm's risk
management portfolio needs and strategies. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash receipts and
payments.
 
(c) Trading and Non-trading -- General Policy.
 
     In addition to the risk associated with price movements, credit risk is
also inherent in NorAm and its subsidiaries' risk management activities. Credit
risk relates to the risk of loss resulting from non performance
 
                                       120
<PAGE>   123
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
of contractual obligations by a counterparty. While, as yet, NorAm and its
subsidiaries have experienced no significant losses due to the credit risk
associated with these arrangements, NorAm 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,
NorAm and/or its subsidiaries, as the case may be, enter into such contracts
primarily with those counterparties with a minimum Standard & Poor's or Moody's
rating of BBB- or Baa3, respectively. For long-term arrangements, NorAm and its
subsidiaries periodically review the financial condition of such firms in
addition to monitoring the effectiveness of these financial contracts in
achieving NorAm's objectives. Should the counterparties to these arrangements
fail to perform, NorAm would seek to compel performance at law or otherwise, or
obtain compensatory damages in lieu thereof. NorAm might be forced to acquire
alternative hedging arrangements or be required to honor the underlying
commitment at then-current market prices. In such event, NorAm 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, NorAm believes
that the risk of incurring a significant financial statement loss due to the
non-performance of counterparties to these transactions is minimal.
 
     NorAm's policies prohibit the use of leveraged financial instruments.
 
     Houston Industries has established a Risk Oversight Committee that oversees
all price and credit risk, including NES's risk management and trading
activities. The Risk Oversight Committee's responsibilities include reviewing
NorAm's overall risk management strategy and monitoring risk management
activities to ensure compliance with Houston Industries' risk management
limitations, policies and procedures.
 
(3) CAPITAL STOCK
 
(a) Earnings Per Share.
 
     As a result of the Merger, NorAm is no longer required to present earnings
per share (EPS) data as its common shares (all of which are owned by Houston
Industries) are not publicly held. EPS data for 1996 and 1995 has not been
included because NorAm believes it is no longer meaningful.
 
(b) Equity Transactions Prior to the Merger.
 
     In June 1996, NorAm issued 11,500,000 shares of NorAm common stock to the
public at a price of $9.875 per share, yielding net cash proceeds of
approximately $109 million. The net proceeds from the offering principally were
used to retire debt as described in Note 4(b).
 
(c) Direct Stock Purchase Plan and Dividend Reinvestment Plan.
 
     The Direct Stock Purchase Plan and Dividend Reinvestment Plan were
suspended and canceled in connection with the Merger.
 
(4) LONG-TERM AND SHORT-TERM FINANCING
 
(a) Short-Term Financing.
 
     In 1997 and 1996, NorAm met its short-term financing needs primarily
through a bank facility, bank lines of credit and a receivables facility.
NorAm's principal short-term credit facility (NorAm Credit Facility) of $400
million expires in December 1998. Borrowings under the NorAm Credit Facility are
unsecured. The weighted average interest rate at December 31, 1997 and 1996 was
6.3%. NorAm pays a facility fee on the $400 million facility of .14% per annum
which is subject to increase based on NorAm's debt rating. Borrowings under the
credit facility at December 31, 1997 and 1996 were $340 million and $115
million, respectively. In addition, NorAm had $50 million of outstanding loans
under uncommitted lines of credit at December 31, 1997 having a weighted average
interest rate of 6.82%.
                                       121
<PAGE>   124
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Under a trade receivables facility (Receivables Facility) which expires in
August 1999, NorAm sells, with limited recourse, an undivided interest (limited
to a maximum of $300 million) in a designated pool of accounts receivable. The
amount of receivables sold and uncollected was $300 million and $235 million at
December 31, 1997 and 1996, respectively. The weighted average interest rate at
December 31, 1997 and 1996 was 5.65% and 5.41%, respectively. Certain of NorAm's
remaining receivables serve as collateral for receivables sold and represent the
maximum exposure to NorAm should all receivables sold prove ultimately
uncollectible. NorAm has retained servicing responsibility under the Receivables
Facility for which it is paid a servicing fee. Beginning in 1997 and pursuant to
SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and
Extinguishment of Liabilities", NorAm accounts for amounts transferred pursuant
to the Receivables Facility as collateralized borrowings. As a result, these
receivables are recorded as assets on NorAm's December 31, 1997 Consolidated
Balance Sheet and amounts received by NorAm pursuant to this facility are
recorded as a current liability under the caption Receivables facility. In 1996,
pursuant to SFAS No. 77, "Reporting by Transferors for Transfers of Receivables
with Recourse", the receivables sold were deducted from "Accounts and notes
receivable, principally customers" in the accompanying Consolidated Balance
Sheet. Additionally, amounts reported in 1996 and 1995 in NorAm's Statements of
Consolidated Income as "Loss on sale of accounts receivables" are recorded as
interest expense in NorAm's 1997 Statement of Consolidated Income.
 
(b) Long-Term Debt.
 
     NorAm's consolidated long-term debt outstanding, which is summarized in the
following table, is noncallable and without sinking fund requirements except as
noted. Carrying amounts and amounts due in one year reflect $46.3 million and
$6.1 million, respectively, for fair value adjustments recorded in connection
with the Merger.
 
<TABLE>
<CAPTION>
                                                              CURRENT NORAM
                                                            DECEMBER 31, 1997
                                             ------------------------------------------------
                                                                          CARRYING AMOUNTS
                                                                       ----------------------
                                             EFFECTIVE    PRINCIPAL    NON-CURRENT    CURRENT
                                               RATE        AMOUNT        PORTION      PORTION
                                             ---------    ---------    -----------    -------
                                                          (MILLIONS OF DOLLARS)
<S>                                          <C>          <C>          <C>            <C>
Medium-term notes, Series A and B due
  through 2001, weighted average rate of
  8.90% at December 31, 1997..............     8.23%      $  241.6       $182.4       $ 78.8
Bank Term Loan due 1998...................     6.54%         150.0                     153.3
8.875% Series due 1999....................     8.54%         200.0        207.8
7.5% Series due 2000......................     7.32%         200.0        205.0
8.9% Series due 2006......................     7.82%         145.1        165.1
6% Convertible Subordinated Debentures due
  2012....................................     6.51%         116.3        107.2
10% Series due 2019(1)....................     8.95%          42.8         47.8
Other.....................................     4.10%           0.6          1.4
                                                          --------       ------       ------
                                                          $1,096.4       $916.7       $232.1
                                                          ========       ======       ======
</TABLE>
 
                                       122
<PAGE>   125
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
<TABLE>
<CAPTION>
                                                                    FORMER NORAM
                                                                 DECEMBER 31, 1996
                                                               ----------------------
                                                                  CARRYING AMOUNTS
                                                               ----------------------
                                                               NON-CURRENT    CURRENT
                                                                 PORTION      PORTION
                                                               -----------    -------
                                                               (MILLIONS OF DOLLARS)
<S>                                                            <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
9.875% Series due 1997......................................                   225.0
8.875% Series due 1999......................................       200.0
7.5% Series due 2000........................................       200.0
8.9% Series due 2006........................................       145.1
6% Convertible Subordinated Debentures due 2012.............       122.7
10% Series due 2019(1)......................................       144.2
Other.......................................................         0.6
                                                                --------      ------
                                                                $1,054.2      $277.0
                                                                ========      ======
</TABLE>
 
---------------
 
(1) In the fourth quarter of 1997 NorAm purchased $101.4 million aggregate
    principal amount of its 10% Debentures due 2019 at an average price of
    111.98% plus accrued interest. Because NorAm's debt was stated at fair
    market value as of the Acquisition Date, the loss on the reacquisition of
    these debentures was not material.
 
     Consolidated maturities of long-term debt and sinking fund requirements for
NorAm are approximately $232 million for 1998, $201 million in 1999, $222
million in 2000, $144 million in 2001 and $0 in 2002.
 
     NorAm's retirements and reacquisitions of long-term debt are summarized in
the following table. In cases where premiums were paid or discounts were
realized in association with these reacquisitions and retirements, such amounts
are reported in NorAm's Statements of Consolidated Income as "Extraordinary gain
(loss) on early retirement of debt, less taxes" and are net of taxes of $0.1
million, ($2.5) million and ($0.03) million in 1997, 1996 and 1995,
respectively. For retirements and reacquisitions after the Acquisition Date,
gains or losses on early retirement are immaterial since the carrying amounts
reflect the fair value adjustments described above.
 
<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                                           ---------------------------
                                                           1997(1)     1996      1995
                                                           -------    ------    ------
                                                              (MILLIONS OF DOLLARS)
<S>                                                        <C>        <C>       <C>
Reacquisition of 8% Series due 1997......................                       $150.0
Reacquisition of 9.875% Debentures due 2018..............             $  7.4       5.7
Reacquisition of 10% Debentures due 2019.................  $101.4                 15.0
Reacquisition of 6% Convertible Subordinated Debentures
  due 2012(2)............................................     5.8        7.2
Retirement, at maturity, of Medium Term Notes(3).........    52.0      118.8       1.0
Retirement of Bank Term Loan due 2000....................              150.0
Retirement of 9.45% Series due 1995......................                        150.0
Retirement of 9.875% Notes due 1997......................   225.0
Retirement of 9.875% Debentures due 2018.................              109.0
Retirement of Note Payable to Gas Supplier...............                         13.6
Net (gain) loss on reacquisition of debt, less taxes.....    (0.2)       4.3       0.1
                                                           ------     ------    ------
                                                           $384.0     $396.7    $335.4
                                                           ======     ======    ======
</TABLE>
 
---------------
 
(1) Excludes the conversion of 6% Convertible Subordinated Debentures due 2012
    in the amount of approximately $1.0 million.
 
(2) These reacquired debentures may be credited against sinking fund
    requirements.
 
(3) Weighted average interest rate of 9.25%, 9.06% and 9.0% in 1997, 1996 and
    1995, respectively.
 
                                       123
<PAGE>   126
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     In June 1996, NorAm exercised its right to exchange the $130 million
principal amount of its $3.00 Convertible Exchangeable Preferred Stock, Series A
for its 6% Convertible Subordinated Debentures due 2012 (Subordinated
Debentures). The holders of the Subordinated Debentures receive interest
quarterly and have the right at any time on or before the maturity date thereof
to convert each Subordinated Debenture into 0.65 shares of common stock of
Houston Industries and $14.24 in cash. The Subordinated Debentures are callable
beginning in 1999 at redemption prices beginning at 105.0% and declining to par
in November 2009. NorAm is required to make annual sinking fund payments of $6.5
million on the Subordinated Debentures which began on March 15, 1997 and will
continue on each succeeding March 15 up to and including March 15, 2011. NorAm
(i) may credit against the sinking fund requirements any Subordinated Debentures
redeemed by NorAm and Subordinated Debentures which have been converted at the
option of the holder and (ii) may deliver purchased Subordinated Debentures in
satisfaction of the sinking fund requirements. NorAm satisfied its 1997 sinking
fund requirement of $6.5 million by delivering a portion of the $7.2 million
principal amount of Subordinated Debentures purchased in 1996.
 
     In May 1997, NorAm obtained an unsecured, 18-month bank term loan in the
amount of $150 million. The term loan carries a LIBOR-based floating interest
rate. Proceeds from the term loan were used to refund a portion of NorAm's
9.875% Notes which matured in April 1997. NorAm has entered into two interest
rate swaps, each with a term of 19 months, having an aggregate notional amount
of $150 million which effectively fixed the interest rate on borrowings under
the term loan agreement at approximately 6.775%.
 
     At December 31, 1996 NorAm had a portfolio of six interest rate swaps with
a total notional amount of $300 million. Five of these swaps were terminated
during 1997 representing a total notional amount of $250 million. The remaining
$50 million was terminated in January 1998.
 
(c) Restrictions on Stockholders' Equity and Debt.
 
     Under the provisions of NorAm's revolving credit facility or certain other
NorAm financial arrangements, NorAm's total debt is limited to 72% of its total
capitalization and NorAm is required to maintain a minimum level of
stockholders' equity. In addition, NorAm's total debt would be limited to $2.055
billion if its ratio of total debt to total capitalization increased to 60%. The
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. At December 31, 1997, these provisions did
not significantly restrict NorAm's ability to issue debt or to pay dividends.
 
(5) TRUST SECURITIES
 
     In June 1996, a Delaware statutory business trust (NorAm Trust) established
by NorAm issued in a public offering $172.5 million of convertible preferred
securities and sold approximately $5.3 million of NorAm Trust common stock
(106,720 shares, representing 100% of the NorAm Trusts common equity) to NorAm.
The convertible preferred securities have a distribution rate of 6.25% payable
quarterly in arrears, a stated liquidation amount of $50 per convertible
preferred security and must be redeemed by 2026. The proceeds from the sale of
the preferred and common securities were used by NorAm Trust to purchase $177.8
million of 6.25% Convertible Junior Subordinated Debentures from NorAm having an
interest rate corresponding to the distribution rate of the convertible
preferred securities and a maturity date corresponding to the mandatory
redemption date of the convertible preferred securities. Under existing law,
interest payments made by NorAm for the junior subordinated debentures are
deductible for federal income tax purposes. NorAm has the right at any time and
from time to time to defer interest payments on the junior subordinated
debentures for successive periods not to exceed 20 consecutive quarters for each
such extension period. In such case, (1) quarterly distributions on the junior
subordinated debentures would also be deferred
 
                                       124
<PAGE>   127
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
and (2) NorAm has agreed to not declare or pay any dividend on any common or
preferred stock, except in certain instances.
 
     The NorAm Trust is accounted for as a wholly owned consolidated subsidiary
of NorAm. The junior subordinated debentures are the sole assets of the NorAm
Trust. NorAm has fully and unconditionally guaranteed, on a subordinated basis,
NorAm Trust's obligations, including the payment of distributions and all other
payments, with respect to the convertible preferred securities. The convertible
preferred securities are mandatorily redeemable upon the repayment of the
related junior subordinated debentures at their stated maturity or earlier
redemption. Following the Merger, each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Houston Industries common stock. In 1997, convertible preferred securities
aggregating $156.1 million were converted, leaving $16.4 million principal
amount (unamortized fair value of $21.3 million, net of issuance costs) of
convertible preferred securities outstanding at December 31, 1997.
 
     Utilizing, in large part, the proceeds from the offerings previously
discussed, in June 1996, NorAm (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 after tax) and (2) retired its $150 million
bank term loan due 2000 at face value.
 
(6) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS
 
(a) Incentive Compensation Plans.
 
     Prior to the Merger, NorAm had several incentive compensation plans which
provide for the issuance of stock-based incentives (including restricted shares,
stock options and stock appreciation rights) to directors and key employees of
NorAm, including officers. The charge to earnings in 1997, 1996 and 1995 related
to the incentive compensation plans was $1.4 million, $4.4 million and $0.5
million, respectively. All stock options granted under such plans were either
converted into similar Houston Industries options or "cashed out" prior to the
Merger. All restricted stock and substantially all stock appreciation rights
were "cashed out" with the Merger. NorAm granted 463,856 shares of restricted
stock in 1996 with a weighted average fair value at the grant date of $11.86. At
December 31, 1996, there were 77,371 stock appreciation rights outstanding. As
of the Acquisition Date, less than 1,000 stock appreciation rights were
outstanding. The following is certain information relating to options issued
pursuant to NorAm's incentive compensation plans.
 
<TABLE>
<CAPTION>
                                                                        WEIGHTED-AVERAGE
                                                           NUMBER        EXERCISE PRICE
                                                          OF SHARES        PER SHARE
                                                          ---------     ----------------
<S>                                                       <C>           <C>
Outstanding at December 31, 1994........................    650,938          $12.89
Options Granted(2)......................................    546,550          $ 5.54
Options Forfeited/Expired...............................   (164,469)         $14.05
Outstanding at December 31, 1995........................  1,033,019          $ 8.82
Options Granted(2)......................................    579,749          $ 8.69
Options Exercised.......................................    (28,019)         $ 6.44
Options Forfeited/Expired...............................    (76,821)         $11.99
</TABLE>
 
                                       125
<PAGE>   128
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
<TABLE>
<CAPTION>
                                                                        WEIGHTED-AVERAGE
                                                           NUMBER        EXERCISE PRICE
                                                          OF SHARES        PER SHARE
                                                          ---------     ----------------
<S>                                                       <C>           <C>
Outstanding at December 31, 1996........................  1,507,928          $ 8.65
Options Exercised.......................................   (147,092)         $ 6.47
Options Forfeited/Expired...............................    (10,682)         $12.42
Options Cashed Out Upon Merger..........................   (521,857)
Options Converted at Acquisition(1).....................   (828,297)
Outstanding at December 31, 1997........................          0
Exercisable at:
  December 31, 1997.....................................          0
  December 31, 1996.....................................    911,660          $ 9.48
  December 31, 1995.....................................    431,615          $16.14
</TABLE>
 
---------------
 
(1) Effective upon the Merger, each holder of an unexpired NorAm stock option,
    whether or not then exercisable, was entitled to elect to either (i) have
    all or any portion of their NorAm stock options canceled and "cashed out" or
    (ii) have all or any portion of their NorAm stock options converted to the
    Houston Industries stock options. There were 828,297 NorAm stock options
    converted into 622,504 Houston Industries stock options at the Acquisition
    Date.
 
(2) The weighted average grant date fair value of the options granted in 1995
    and 1996 was $1.64 and $2.39, respectively.
 
     In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, "Accounting for Stock-Based Compensation" (SFAS No. 123). SFAS No. 123
provides for the disclosure of certain information concerning the "fair value"
of securities issued pursuant to stock-based employee compensation plans, and
gives NorAm the option of calculating and recording compensation expense
utilizing either (1) SFAS No. 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" (APB No. 25)
which, in general, do not require the recording of compensation expense for
options and stock appreciation rights issued pursuant to plans structured
similarly to those of NorAm. NorAm elected to continue to apply the provisions
of APB No. 25 for the purpose of computing compensation expense associated with
the relevant plan, although certain additional required disclosure has been made
in accordance with the provisions of SFAS No. 123.
 
     The "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 granted in 1996 and 1995 is a statistical calculation
made utilizing a methodology generally referred to as the Black-Scholes option
pricing model (BS 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 table, NorAm assumed (i) a risk free interest rate (based on
U.S. Treasury strips with a remaining term of five years) of 5.24% to 7.84%,
(ii) an expected option life (duration) of five years, (iii) an expected
volatility of 31.6% to 36.4% and (iv) an expected dividend yield of 3.4%. To the
extent that actual conditions during the post-grant, pre-exercise period differ
from these assumptions, the actual value of the options to the employee will
differ from the calculated "fair value" at grant date (see above regarding the
effect of the Merger). Had compensation cost been determined in accordance with
the provisions of SFAS No. 123, the impact on NorAm's earnings for 1995 and 1996
would have been immaterial.
 
                                       126
<PAGE>   129
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(b) Employee Benefit Plans.
 
     NorAm has two qualified pension plans (the Qualified Plans) which cover
substantially all employees: (1) the plan which covers NorAm's employees other
than Minnegasco employees and (2) the plan which covers Minnegasco employees.
The Qualified Plans provide benefits based on the participants' 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
NorAm's consulting actuaries. Plan assets are made up of marketable equity and
high-grade fixed income securities.
 
     In addition to the Qualified Plans, NorAm 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 NorAm with respect to these
benefits, as these plans are not funded by NorAm in advance of the cash payment
of benefits. Expense of approximately $3.1 million, $2.0 million and $2.1
million associated with these non-qualified plans was recorded during 1997,
1996, and 1995, respectively.
 
     Net Pension cost (qualified plans only) for NorAm includes the following
components:
 
<TABLE>
<CAPTION>
                                                                         FORMER NORAM
                                        CURRENT NORAM    --------------------------------------------
                                        -------------                       TWELVE          TWELVE
                                         FIVE MONTHS     SEVEN MONTHS       MONTHS          MONTHS
                                            ENDED           ENDED           ENDED           ENDED
                                        DECEMBER 31,       JULY 31,      DECEMBER 31,    DECEMBER 31,
                                            1997             1997            1996            1995
                                        -------------    ------------    ------------    ------------
                                                           (THOUSANDS OF DOLLARS)
<S>                                     <C>              <C>             <C>             <C>
Service cost -- benefits earned during
  the period..........................    $  5,095         $  7,220        $ 11,817        $  9,900
Interest cost on projected benefit
  obligation..........................      15,014           20,313          29,946          27,097
Actual return on plan assets..........      (1,851)         (90,148)        (41,800)        (36,909)
Amortization and deferrals (a)........     (22,004)          63,498            (641)         (1,388)
                                          --------         --------        --------        --------
Net pension cost (credit).............    $ (3,746)        $    883        $   (678)       $ (1,300)
                                          ========         ========        ========        ========
</TABLE>
 
                                       127
<PAGE>   130
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     Following is the funded status of NorAm's pension plans.
 
<TABLE>
<CAPTION>
                                                      CURRENT NORAM               FORMER NORAM
                                                -------------------------   -------------------------
                                                                    DECEMBER 31,
                                                -----------------------------------------------------
                                                          1997                        1996
                                                -------------------------   -------------------------
                                                QUALIFIED   NON-QUALIFIED   QUALIFIED   NON-QUALIFIED
                                                  PLANS         PLANS         PLANS         PLANS
                                                ---------   -------------   ---------   -------------
                                                             (THOUSANDS OF DOLLARS)
<S>                                             <C>         <C>             <C>         <C>
Net assets available for benefits.............  $569,718            --      $500,452            --
                                                --------      --------      --------      --------
Actuarial present value of accumulated plan
  benefits:
  Vested (assuming immediate separation)......   401,468      $ 34,578       325,461      $ 30,554
  Non-vested..................................    36,359           973        30,096         1,663
                                                --------      --------      --------      --------
  Accumulated benefit obligation..............   437,827        35,551       355,557        32,217
  Additional amount related to projected pay
     increases................................    75,420           746        79,933           712
                                                --------      --------      --------      --------
          Total projected benefit
            obligation........................   513,247        36,297       435,490        32,929
                                                --------      --------      --------      --------
Funded status.................................    56,471       (36,297)       64,962       (32,929)
Unrecognized transition obligation at January
  1(a)........................................        --            --        (8,290)           --
Unrecognized prior service costs(a)...........        --            --        (2,222)        5,004
Unrecognized net loss (gain) from past
  experience different from that assumed and
  effects of changes in actuarial
  assumptions(a)..............................    35,593           646        (9,060)       (1,506)
                                                --------      --------      --------      --------
  (Accrued) prepaid pension cost..............  $ 92,064      $(35,651)     $ 45,390      $(29,431)
                                                ========      ========      ========      ========
</TABLE>
 
---------------
 
(a) The unrecognized transition obligation, unrecognized prior service costs and
    net actuarial gain were recognized on the Acquisition Date pursuant to the
    purchase method of accounting for the Merger. Amortization and deferrals
    after the Acquisition Date represents deferral of net loss from past
    experience identified after the Acquisition Date. For further discussion of
    the accounting for the Merger; see Note 1(b).
 
     The assumed rate of increase in future compensation levels utilized in the
above calculations was 4.5% in 1997 and 4% in 1996. The expected long-term rate
of return on fund assets utilized in the above calculations was 10% for 1997 and
1996. The weighted average discount rate was 7.5% for 1997 and 1995 and 7.25%
for 1996.
 
     NorAm 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, of which contributions up to 6%
are matched by NorAm. Employer contributions to the ESP of $9.3 million, $8.9
million and $8.9 million were expensed during 1997, 1996 and 1995, 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 $1.5
million, $1.4 million and $1.4 million related to these plans was recorded
during 1997, 1996, and 1995, respectively.
 
     NorAm records the liability for post-retirement benefit plans other than
pensions (primarily health care) under SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other than Pensions". NorAm provides these benefits
under a defined 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 NorAm'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, 1997, NorAm had contributed a total of $4.5
million to an
 
                                       128
<PAGE>   131
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
external fund (associated with Minnegasco employees) to provide for these
benefits. NorAm currently expects that it will fund these benefits utilizing
external funding techniques for additional employees in the future.
 
     The net postretirement benefit cost includes the following components:
 
<TABLE>
<CAPTION>
                                      CURRENT NORAM                     FORMER NORAM
                                      -------------    ----------------------------------------------
                                       FIVE MONTHS     SEVEN MONTHS    TWELVE MONTHS    TWELVE MONTHS
                                          ENDED           ENDED            ENDED            ENDED
                                      DECEMBER 31,       JULY 31,      DECEMBER 31,     DECEMBER 31,
                                          1997             1997            1996             1995
                                      -------------    ------------    -------------    -------------
                                                          (THOUSANDS OF DOLLARS)
<S>                                   <C>              <C>             <C>              <C>
Service cost.......................      $  115           $  164          $   306          $   291
Interest cost on accumulated
  benefit obligation...............       3,561            4,948            9,234           10,183
Actual (return) loss on plan
  assets...........................        (143)             142             (108)
Amortization of transition
  obligation on a straight line
  basis over 20 years(a)...........                        3,886            6,662            6,663
Amortization of actuarial
  loss(a)..........................          70             (249)           1,321
Deferral of asset loss.............                          (11)                             (195)
                                         ------           ------          -------          -------
Net periodic cost..................      $3,603           $8,880          $17,415          $16,942
                                         ======           ======          =======          =======
</TABLE>
 
Following is the funded status of NorAm's postretirement benefit plans:
 
<TABLE>
<CAPTION>
                                                          CURRENT NORAM    FORMER NORAM
                                                          -------------    ------------
                                                                  DECEMBER 31,
                                                          -----------------------------
                                                              1997             1996
                                                          -------------    ------------
                                                             (THOUSANDS OF DOLLARS)
<S>                                                       <C>              <C>
Accumulated postretirement benefit obligation
  Retirees.............................................     $110,579        $ 121,183
  Fully-eligible active plan participants..............        3,349            3,711
  Other active plan participants.......................        4,544            4,487
                                                            --------        ---------
          Total........................................      118,472          129,381
  Fair value of plan assets............................        4,502            3,051
                                                            --------        ---------
          Total........................................      113,970          126,330
  Unrecognized transition obligation(a)................                      (106,599)
  Unrecognized net actuarial (gain) loss...............       (1,563)          14,292
                                                            --------        ---------
  Accrued postretirement benefit cost..................     $112,407        $  34,023
                                                            ========        =========
</TABLE>
 
---------------
 
(a)  The unrecognized transition obligation and unrecognized prior service costs
     were recognized on the Acquisition Date pursuant to the purchase method of
     accounting for the Merger. Amortization after the Acquisition Date
     represents amortization of unrecognized actuarial loss incurred after the
     Acquisition Date. For further discussion of the accounting for the Merger,
     see Note 1(b).
 
     The weighted average discount rate used in determining the accumulated
benefit obligation for postretirement benefits was 7.25% for 1997, 7.5% for 1996
and 7.25% for 1995. 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 8.5% per year initially and then
increase at a decreasing rate to an annual and continuing increase of 4.5% by
2006. 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
 
                                       129
<PAGE>   132
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
any deferral for regulatory reasons) and the accumulated benefit obligation at
December 31, 1997 by approximately 9.2% and 10.8%, respectively.
 
(7) INCOME TAXES
 
     Prior to the Acquisition Date, NorAm and its subsidiaries filed a
consolidated federal income tax return. Such returns have been audited and
settled through the year 1986. Subsequent to the Acquisition Date, Houston
Industries files a consolidated federal income tax return, in which NorAm and
its subsidiaries are included. Investment tax credits are generally deferred and
amortized over the lives of the related assets. The unamortized investment tax
credit in deferred credits on the accompanying Consolidated Balance Sheets was
$5.2 million and $4.5 million for 1997 and 1996, respectively.
 
     Following are the components of NorAm's income tax provision:
 
<TABLE>
<CAPTION>
                                      CURRENT NORAM                     FORMER NORAM
                                      -------------    ----------------------------------------------
                                       FIVE MONTHS     SEVEN MONTHS    TWELVE MONTHS    TWELVE MONTHS
                                          ENDED           ENDED            ENDED            ENDED
                                      DECEMBER 31,       JULY 31,      DECEMBER 31,     DECEMBER 31,
                                          1997             1997            1996             1995
                                      -------------    ------------    -------------    -------------
                                                          (THOUSANDS OF DOLLARS)
<S>                                   <C>              <C>             <C>              <C>
Federal
  Current...........................    $(12,005)        $16,339          $33,654          $18,760
  Deferred..........................      36,673          12,795           25,760           24,377
  Investment tax credit.............        (262)           (363)            (636)            (639)
State
  Current...........................         536             833            4,525            2,375
  Deferred..........................        (559)          1,794            3,049           10,506
                                        --------         -------          -------          -------
Income tax expense..................    $ 24,383         $31,398          $66,352          $55,379
                                        ========         =======          =======          =======
</TABLE>
 
     The provision for income taxes differs from the amount computed by applying
the statutory federal income tax rate of 35% to income from continuing
operations. The reasons for this difference are as follows:
 
<TABLE>
<CAPTION>
                                           CURRENT NORAM                    FORMER NORAM
                                           -------------   ----------------------------------------------
                                            FIVE MONTHS    SEVEN MONTHS   TWELVE MONTHS    TWELVE MONTHS
                                               ENDED          ENDED           ENDED            ENDED
                                           DECEMBER 31,      JULY 31,      DECEMBER 31,     DECEMBER 31,
                                               1997            1997            1996             1995
                                           -------------   ------------   --------------   --------------
                                                               (THOUSANDS OF DOLLARS)
<S>                                        <C>             <C>            <C>              <C>
Income before income taxes...............     $45,230        $77,273         $161,490         $120,908
Statutory rate...........................          35%            35%              35%              35%
                                              -------        -------         --------         --------
Income taxes at statutory rate...........      15,831         27,046           56,522           42,318
                                              -------        -------         --------         --------
Increase (decrease) in tax resulting
  from:
  State income taxes, net of federal
     income tax benefit(1)...............          (9)         1,708            4,923            8,373
  Investment tax credit..................        (262)          (363)            (636)            (639)
  Research and experimentation credit....                                        (188)            (375)
  Adjustment to prior year accruals......         106            (34)             301              510
  Goodwill amortization..................       7,242          2,430            4,163            4,163
  Other, net.............................       1,475            611            1,267            1,029
                                              -------        -------         --------         --------
Provision for income taxes...............     $24,383        $31,398         $ 66,352         $ 55,379
                                              =======        =======         ========         ========
</TABLE>
 
---------------
 
(1) Calculation of the accrual for state income taxes at the end of each year
    requires that NorAm estimate the manner in which its income for that year
    will be allocated and/or apportioned among the various
 
                                       130
<PAGE>   133
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
    states in which it conducts business, which states have widely differing tax
    rules and rates. These allocation/apportionment factors change from year to
    year and the amount of taxes ultimately payable may differ from that
    estimated as a part of the accrual process. For these reasons, the amount of
    state income tax expense may vary significantly from year-to-year, even in
    the absence of significant changes to state income tax valuation allowances
    or changes in individual state income tax rates.
 
     The tax effects of temporary differences that gave rise to significant
portions of the deferred tax assets and liabilities as of December 31, 1997 and
1996, were as follows:
 
<TABLE>
<CAPTION>
                                                              CURRENT      FORMER
                                                               NORAM       NORAM
                                                              --------    --------
                                                                  DECEMBER 31,
                                                              --------------------
                                                                1997        1996
                                                              --------    --------
                                                                 (THOUSANDS OF
                                                                    DOLLARS)
<S>                                                           <C>         <C>
Deferred Tax Assets:
  Employee benefit accruals.................................  $ 53,277    $ 27,282
  Inventory revaluation and capitalization..................       466         552
  Gas purchase contract accruals............................     8,267      15,495
  Regulatory obligations....................................                 7,469
  Indemnifications and other reserves.......................     3,497       9,332
  Deferred state income taxes...............................    14,460      13,799
  Other.....................................................    53,546      29,295
  State operating loss carryforwards........................    29,515      28,517
  Alternative minimum tax credit carryforwards..............    60,669      76,089
  Valuation allowance.......................................    (6,353)     (6,761)
                                                              --------    --------
          Total deferred tax assets -- net..................   217,344     201,069
                                                              --------    --------
Deferred Tax Liabilities:
  Property, plant and equipment, principally due to
     depreciation methods and lives.........................   558,758     458,506
  Deferred gas costs........................................    34,113      25,043
  Employee benefit accruals.................................                 5,807
  Deferred state income taxes...............................    70,000
  Regulatory obligations....................................     6,690
  Other.....................................................    22,513      21,724
                                                              --------    --------
          Total deferred tax liabilities....................   692,074     511,080
                                                              --------    --------
          Net deferred tax liabilities......................  $474,730    $310,011
                                                              ========    ========
</TABLE>
 
     At December 31, 1997, NorAm has approximately $439 million of state net
operating losses available to offset future state taxable income through the
year 2012. In addition, NorAm has approximately $58 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), and approximately $2.6 million
of state alternative minimum tax credits which are available to reduce future
state income taxes payable, if any, through the year 2001. The change in the
valuation allowance during 1997 was a net reduction of $0.4 million, resulting
from a reassessment of NorAm's ability to use state net operating loss
carryforwards and state alternative minimum tax credit carryforwards in future
tax years, offset by expiring state net operating losses for which valuation
allowances had been provided in prior years.
 
                                       131
<PAGE>   134
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(8) COMMITMENTS AND CONTINGENCIES
 
(a) Lease Commitments.
 
     The following table sets forth certain information concerning NorAm's
obligations under operating leases:
 
     Minimum Lease Commitments at December 31, 1997(1)
 
<TABLE>
<CAPTION>
                                                             (MILLIONS OF DOLLARS)
                                                             ---------------------
<S>                                                          <C>
1998.......................................................          $ 24
1999.......................................................            19
2000.......................................................            16
2001.......................................................            15
2002.......................................................             9
2003 and beyond............................................            22
                                                                     ----
          Total............................................          $105
                                                                     ====
</TABLE>
 
---------------
 
(1) Principally consisting of rental agreements for building space and data
    processing equipment and vehicles (including major work equipment).
 
     NorAm has a master leasing agreement which provides for the lease of
vehicles, construction equipment, office furniture, data processing equipment
and other property. For accounting purposes, the lease is treated as an
operating lease. At December 31, 1997, NorAm had leased assets with a value of
approximately $58.1 million under this lease with a basic term of one year.
NorAm does not expect to lease additional property under this lease agreement.
 
     Lease payments related to NorAm's leasing agreements are included in the
preceding table for only their basic term. Total rental expense for all leases
was $24.0 million, $33.4 million and $48.9 million in 1997, 1996 and 1995,
respectively.
 
(b) Letters of Credit.
 
     At December 31, 1997, NorAm had letters of credit incidental to its
ordinary business operations totaling approximately $42 million under which
NorAm is obligated to reimburse drawings, if any.
 
(c) Indemnity Provisions.
 
     At December 31, 1997, NorAm has an $11.4 million accounting reserve on its
Consolidated Balance Sheets in "Estimated obligations under indemnification
provisions of sale agreements" for possible indemnity claims asserted in
connection with its disposition of former subsidiaries or divisions, including
the sale of (i) Louisiana Intrastate Gas Corporation, a former subsidiary
engaged in the intrastate pipeline and liquids extraction business (1992); (ii)
Arkla Exploration Company, a former subsidiary engaged in oil and gas
exploration and production activities (June 1991); and (iii) Dyco Petroleum
Company, a former subsidiary engaged in oil and gas exploration and production
(1991).
 
(d) Sale of Receivables.
 
     Certain of NorAm's receivables are collateral for receivables which have
been sold pursuant to the terms of NorAm's receivables facility, see
"Receivables Facility" included in Note 4(a).
 
                                       132
<PAGE>   135
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(e) Gas Purchase Claims.
 
     In conjunction with settlements of "take-or-pay" claims, NorAm has prepaid
for certain volumes of gas, which prepayments have been recorded at their net
realizable value and, to the extent that NorAm is unable to realize at least the
carrying amount as the gas is delivered and sold, NorAm's earnings will be
reduced, although such reduction is not expected to be material. In addition to
these prepayments, NorAm 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. To the extent
that NorAm expects that these commitments will result in losses over the
contract term, NorAm has established reserves equal to such expected losses.
 
(f) Transportation Agreement.
 
     NorAm had an agreement (ANR Agreement) with ANR Pipeline Company (ANR)
which contemplated a transfer to ANR of an interest in certain of NorAm's
pipeline and related assets, representing capacity of 250 Mmcf/day, and pursuant
to which ANR had advanced $125 million to NorAm. The ANR Agreement has been
restructured and, after refunds of $50 million and $34 million in 1995 and 1993,
respectively, NorAm currently retains $41 million (recorded as a liability) in
exchange for ANR's or its affiliates' use of 130 Mmcf/ day of capacity in
certain of NorAm'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.
 
(g) Environmental Matters.
 
     To the extent that potential environmental remediation costs are quantified
within a range, NorAm 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 NorAm's business
subject to SFAS No. 71, corresponding regulatory assets are recorded in
anticipation of recovery through the rate making process.
 
     Manufactured Gas Plant Sites. NorAm and its predecessors operated a
manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works (FMGW) until 1960. NorAm has completed
remediation of the main site other than ongoing water monitoring and treatment.
There are six other former MGP sites in the Minnesota service territory.
Remediation has been completed on one site. Of the remaining five sites, NorAm
believes that two were neither owned nor operated by NorAm; two were owned by
NorAm at one time but were operated by others and are currently owned by others;
and one site was previously operated by NorAm but was owned by others. NorAm
believes it has no liability with respect to the sites it neither owned nor
operated.
 
     At December 31, 1997, NorAm had estimated a range of $15 million to $77
million for possible remediation of the Minnesota sites. The low end of the
range was determined based on only those sites presently owned or known to have
been operated by NorAm, assuming use of NorAm's proposed remediation methods.
The upper end of the range was determined based on the sites once owned by
NorAm, whether or not operated by NorAm. 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 1995 rate case, NorAm's Minnegasco division was allowed to recover
approximately $7 million annually for remediation costs. Such costs are subject
to a true-up mechanism whereby any over or under recovered amounts, net of
certain insurance recoveries, plus carrying charges, would be deferred for
recovery
 
                                       133
<PAGE>   136
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
or refund in the next rate case. At December 31, 1997 and 1996, Minnegasco had
recorded a liability of $20.6 million and $35.9 million, respectively, to cover
the cost of future remediation. In addition, at December 31, 1997, Minnegasco
had receivables from insurance settlements of $2.9 million. These insurance
settlements will be collected through 1999. Minnegasco expects that
approximately half of its accrual as of December 31, 1997 will be expended
within the next five years. The remainder will be expended on an ongoing basis
for an estimated 40 years. In accordance with the provisions of SFAS No. 71, a
regulatory asset has been recorded equal to the liability accrued. Minnegasco is
continuing to pursue recovery of at least a portion of these costs from
insurers. Minnegasco believes the difference between any cash expenditures for
these costs and the amount recovered in rates during any year will not be
material to NorAm's overall cash requirements, results of operations or cash
flows.
 
     At December 31, 1997 and 1996, NorAm 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 previously
discussed.
 
     Issues relating to the identification and remediation of MGPs are common in
the natural gas distribution industry. NorAm has received notices from the EPA
and others regarding its status as a potentially responsible party for other
sites. Based on current information, NorAm has not been able to quantify a range
of environmental expenditures for potential remediation expenditures with
respect to other MGP sites.
 
     Mercury Contamination. Like other natural gas pipelines, NorAm's pipeline
operations have in the past employed elemental mercury in meters used on its
pipelines. Although the mercury has now been removed from the meters, it is
possible that small amounts of mercury have been spilled at some of those sites
in the course of normal maintenance and replacement operations and that such
spills have contaminated the immediate area around the meters with elemental
mercury. Such contamination has been found by NorAm at some sites in the past,
and NorAm has conducted remediation at sites found to be contaminated. Although
NorAm is not aware of additional specific sites, it is possible that other
contaminated sites exist and that remediation costs will be incurred for such
sites. Although the total amount of such costs cannot be known at this time,
based on experience by NorAm and others in the natural gas industry to date and
on the current regulations regarding remediation of such sites, NorAm believes
that the cost of any remediation of such sites will not be material to NorAm's
financial position, results of operation or cash flows.
 
     Potentially Responsible Party Notifications. From time to time NorAm and
its subsidiaries have been notified that they are potentially responsible
parties with respect to properties which environmental authorities have
determined warrant remediation under state or federal environmental laws and
regulations. In October 1994 the United States Environmental Protection Agency
issued such a notice with respect to a landfill site in West Memphis, Arkansas,
and in December 1995, the Louisiana Department of Environmental Quality advised
that one of NorAm subsidiaries had been identified as a potentially responsible
party with respect to a hazardous waste site in Shreveport, Louisiana.
Considering the information currently known about such sites and the involvement
of NorAm or its subsidiaries in activities at these sites, NorAm does not
believe that these matters will have a material adverse effect on NorAm's
financial position, results of operation or cash flows.
 
(h) Other
 
     NorAm Merger Lawsuit. In August 1996, a purported NorAm stockholder filed a
lawsuit, Shaw v. NorAm Energy Corp., et al., in the District Court of Harris
County, Texas, against NorAm, certain of its officers and directors and the
Company to enjoin the Merger or to rescind the Merger and/or to recover damages
in the event that the Merger was consummated. In February 1998, the plaintiffs
withdrew their lawsuit and the court issued an order of non-suit dismissing the
litigation.
 
                                       134
<PAGE>   137
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     NorAm 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
NorAm's financial statements, if any, from the disposition of these matters will
not be material.
 
                                       135
<PAGE>   138
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(9) BUSINESS UNITS REPORTING
 
     Because NorAm's operations in the natural gas industry account for in
excess of 90% of NorAm's total revenues, income or loss and identifiable assets
during 1997, NorAm is not required to report on a "segment" basis. However, in
recognition of the manner in which NorAm manages its portfolio of businesses now
that it is a wholly owned subsidiary of Houston Industries, NorAm has presented
for supplemental comparative purposes the following summary of financial
information by business unit:
 
<TABLE>
<CAPTION>
                                                  CURRENT NORAM                FORMER NORAM
                                                  -------------   --------------------------------------
                                                   FIVE MONTHS         SEVEN MONTHS        TWELVE MONTHS
                                                      ENDED               ENDED                ENDED
                                                  DECEMBER 31,           JULY 31,          DECEMBER 31,
                                                      1997                 1997                1996
                                                  -------------   ----------------------   -------------
                                                                  (THOUSANDS OF DOLLARS)    (UNAUDITED)
<S>                                               <C>             <C>                      <C>
Revenues:
  Natural Gas Distribution......................   $   892,569          $1,309,732          $ 2,113,589
  Interstate Pipeline...........................       108,333             186,711              346,762
  Energy Marketing..............................     1,604,999           1,984,119            2,645,106
  Corporate.....................................        39,079              42,615               55,403
  Eliminations(1)...............................      (123,638)           (186,129)            (372,398)
                                                   -----------          ----------          -----------
          Total Revenues........................   $ 2,521,342          $3,337,048          $ 4,788,462
                                                   ===========          ==========          ===========
Operating Income:
  Natural Gas Distribution......................   $    54,502          $  111,933          $   178,141
  Interstate Pipeline...........................        31,978              76,730              107,904
  Energy Marketing..............................        16,407               2,881               55,693
  Corporate.....................................       (12,131)            (36,504)             (27,272)
                                                   -----------          ----------          -----------
          Total Operating Income................        90,756             155,040              314,466
Other Income (Expense)..........................         2,243               7,210              (14,577)
  Interest and Other Charges....................        47,769              84,977              138,399
                                                   -----------          ----------          -----------
  Income Before Income Taxes....................   $    45,230          $   77,273          $   161,490
                                                   ===========          ==========          ===========
Depreciation and Amortization:
  Natural Gas Distribution......................   $    51,883          $   56,626          $    94,853
  Interstate Pipeline...........................        19,088              17,229               29,172
  Energy Marketing..............................         4,448               2,115                2,931
  Corporate.....................................         2,788               8,931               15,406
                                                   -----------          ----------          -----------
          Total Depreciation and Amortization...   $    78,207          $   84,901          $   142,362
                                                   ===========          ==========          ===========
Identifiable Assets:
  Natural Gas Distribution......................   $ 3,047,195                              $ 1,920,601
  Interstate Pipeline...........................     3,055,610                                2,151,092
  Energy Marketing..............................     1,267,867                                  778,348
  Corporate.....................................     4,517,953                                4,580,845
  Eliminations..................................    (5,749,529)                              (5,413,409)
                                                   -----------                              -----------
          Total Identifiable Assets(2)..........   $ 6,139,096                              $ 4,017,477
                                                   ===========                              ===========
Capital Expenditures:
  Natural Gas Distribution......................   $    61,078          $   69,422          $   116,400
  Interstate Pipeline...........................        16,304               9,619               39,900
  Energy Marketing..............................        14,365               9,637               12,300
  Corporate.....................................         1,667                 (40)               3,600
                                                   -----------          ----------          -----------
          Total Capital Expenditures............   $    93,414          $   88,638          $   172,200
                                                   ===========          ==========          ===========
</TABLE>
 
---------------
 
(1) Elimination of operating revenues derived from sales to affiliated business
    units.
 
(2) As of the Acquisition Date, NorAm's assets and liabilities are reflected at
    their estimated fair market value; see Note 1(b).
                                       136
<PAGE>   139
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
(10) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
 
<TABLE>
<CAPTION>
                                                    CURRENT NORAM              FORMER NORAM
                                               -----------------------    -----------------------
                                                                  DECEMBER 31,
                                               --------------------------------------------------
                                                        1997                       1996
                                               -----------------------    -----------------------
                                                CARRYING       FAIR        CARRYING       FAIR
                                                 AMOUNT       VALUE         AMOUNT       VALUE
                                               ----------   ----------    ----------   ----------
                                                             (THOUSANDS OF DOLLARS)
<S>                                            <C>          <C>           <C>          <C>
Financial Assets of NorAm:
  Interest rate swaps........................                                          $    6,700
  Energy Derivatives(1)......................  $    9,399   $   13,060    $      800        9,800
Financial Liabilities of NorAm:
  Long-term debt.............................   1,148,848    1,147,344     1,331,200    1,389,500
  Trust preferred securities.................      21,290       24,569       167,800      219,100
  Interest rate swaps........................                      755
</TABLE>
 
---------------
 
(1) At December 31, 1996, NorAm 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.
 
     The fair values of cash and short-term investments, marketable equity
securities, short-term and other notes payable are estimated to be equivalent to
carrying amounts. The remaining fair values have been determined using quoted
market prices of the same or similar securities when available or other
estimation techniques.
 
(11) UNAUDITED QUARTERLY INFORMATION
 
     The following unaudited quarterly financial information includes, in the
opinion of management, all adjustments (which comprise only normal recurring
accruals) necessary for a fair presentation. Quarterly results are not
necessarily indicative of a full year's operations because of seasonality and
other factors, including rate increases and variations in operating expense
patterns.
 
     The merger in 1997 was recorded under the purchase method of accounting,
resulting in new carrying values for certain of NorAm's assets, liabilities and
equity based on preliminary analysis. The new basis is reflected in NorAm's
Consolidated Financial Statements beginning with the Acquisition Date. For
additional information; see Note 1(b).
 
<TABLE>
<CAPTION>
                                                       YEAR ENDED DECEMBER 31, 1997
                                   --------------------------------------------------------------------
                                               FORMER NORAM                        CURRENT NORAM
                                   -------------------------------------    ---------------------------
                                                               ONE MONTH     TWO MONTHS
                                                                 ENDED          ENDED
                                     FIRST         SECOND      JULY 31,     SEPTEMBER 30,      FOURTH
                                    QUARTER       QUARTER        1997           1997          QUARTER
                                   ----------    ----------    ---------    -------------    ----------
                                          (THOUSANDS OF DOLLARS)              (THOUSANDS OF DOLLARS)
<S>                                <C>           <C>           <C>          <C>              <C>
Operating Revenues...............  $1,924,182    $1,015,998    $396,868       $749,412       $1,771,930
Operating Income (loss)..........     145,221        36,616     (26,797)        10,781           79,975
Income (loss) before
  extraordinary item.............      68,410           702     (23,237)        (6,646)          27,493
Extraordinary item, less
  taxes(1).......................         237            --          --             --               --
Net income (loss)(3).............  $   68,647    $      702    $(23,237)      $ (6,646)      $   27,493
</TABLE>
 
                                       137
<PAGE>   140
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
<TABLE>
<CAPTION>
                                                                     FORMER NORAM
                                                             YEAR ENDED DECEMBER 31, 1996
                                                   ------------------------------------------------
                                                     FIRST        SECOND      THIRD        FOURTH
                                                   QUARTER(2)    QUARTER     QUARTER      QUARTER
                                                   ----------    --------    --------    ----------
                                                                (THOUSANDS OF DOLLARS)
<S>                                                <C>           <C>         <C>         <C>
Operating revenues...............................  $1,417,663    $891,325    $899,283    $1,580,191
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(1)................        (278)     (4,455)        477           (24)
Net income (loss)(3).............................  $   60,919    ($ 2,120)   ($ 7,706)   $   39,765
</TABLE>
 
---------------
 
(1)  Net gain (loss) on early retirement of debt, less taxes.
 
(2)  Includes a pre-tax charge of $22.3 million associated with early retirement
     and severance costs.
 
(3)  Before preferred dividend requirement.
 
(12) SUBSEQUENT EVENTS
 
     In February 1998, NorAm issued $300 million principal amount of 6.5%
debentures due February 1, 2008. The debentures are not redeemable prior to
maturity and are not subject to any sinking fund requirements. The proceeds from
the sale of the debentures were used to repay short-term indebtedness of NorAm,
including the indebtedness incurred in connection with the 1997 purchase of $101
million aggregate principal amount of its 10% Debentures and the repayment of
$53 million aggregate principal amount of NorAm debt that matured in December
1997 and January 1998. In connection with the issuance of the 6.5% debentures
NorAm received approximately $1 million upon unwinding a $300 million treasury
rate lock agreement, which was tied to the interest rate on 10-year treasury
bonds. The rate lock agreement was executed in January 1998, and proceeds from
the unwind will be amortized over the 10 year life of NorAm's 6.5% debentures.
 
                                       138
<PAGE>   141
 
                          INDEPENDENT AUDITORS' REPORT
 
NorAm Energy Corp.:
 
     We have audited the accompanying consolidated balance sheet of NorAm Energy
Corp. and its subsidiaries (NorAm) as of December 31, 1997, and the related
statements of consolidated income, consolidated stockholders' equity and
consolidated cash flows for the five months ended December 31, 1997 and the
seven months ended July 31, 1997. Our audit also included the Company's
financial statement schedule listed in Item 14(a)(4) for the year ended December
31, 1997. These financial statements and the financial statement schedule are
the responsibility of NorAm's management. Our responsibility is to express an
opinion on these financial statements and the financial statement schedule based
on our audit.
 
     We conducted our audit 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 audit provides a reasonable basis for our opinion.
 
     In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of NorAm Energy Corp. and its
subsidiaries at December 31, 1997, and the results of their operations and their
cash flows for the five months ended December 31, 1997 and the seven months
ended July 31, 1997 in conformity with generally accepted accounting principles.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
February 20, 1998
 
                                       139
<PAGE>   142
 
REPORT OF INDEPENDENT ACCOUNTANTS
 
NorAm Energy Corp.
 
     We have audited the consolidated financial statements and financial
statement schedule of NorAm Energy Corp. and Subsidiaries (NorAm) as of December
31, 1996 and for the two years in the period ended December 31, 1996 as listed
in Item 14(a)(2) and Item 14(a)(4) of this Form 10-K. These financial statements
and the financial statement schedule are the responsibility of NorAm'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 the consolidated results of
their operations and their cash flows for each of the two years in the period
ended December 31, 1996, in conformity with general 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
 
                                       140
<PAGE>   143
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.
 
     None.
 
                                    PART III
 
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY AND NORAM.
 
     (a) The Company. The information called for by Item 10, to the extent not
set forth under Item 1 "Business -- Executive Officers of the Company", is or
will be set forth in the definitive proxy statement relating to the Company's
1998 annual meeting of shareholders pursuant to the Commission's Regulation 14A.
Such definitive proxy statement relates to a meeting of shareholders involving
the election of directors and the portions thereof called for by Item 10 are
incorporated herein by reference pursuant to Instruction G to Form 10-K.
 
     (b) NorAm. The information called for by Item 10 with respect to NorAm is
omitted pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by
Certain Wholly-Owned Subsidiaries).
 
ITEM 11. EXECUTIVE COMPENSATION.
 
     (a) The Company. The information called for by Item 11 is or will be set
forth in the definitive proxy statement relating to the Company's 1998 annual
meeting of shareholders pursuant to the Commission's Regulation 14A. Such
definitive proxy statement relates to a meeting of shareholders involving the
election of directors and the portions thereof called for by Item 11 are
incorporated herein by reference pursuant to Instruction G to Form 10-K.
 
     (b) NorAm. The information called for by Item 11 with respect to NorAm is
omitted pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by
Certain Wholly-Owned Subsidiaries).
 
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
 
     (a) The Company. The information called for by Item 12 is or will be set
forth in the definitive proxy statement relating to the Company's 1998 annual
meeting of shareholders pursuant to the Commission's Regulation 14A. Such
definitive proxy statement relates to a meeting of shareholders involving the
election of directors and the portions thereof called for by Item 12 are
incorporated herein by reference pursuant to Instruction G to Form 10-K.
 
     (b) NorAm. The information called for by Item 12 with respect to NorAm is
omitted pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by
Certain Wholly-Owned Subsidiaries).
 
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
 
     (a) The Company. The information called for by Item 13 is or will be set
forth in the definitive proxy statement relating to the Company's 1998 annual
meeting of shareholders pursuant to the Commission's Regulation 14A. Such
definitive proxy statement relates to a meeting of shareholders involving the
election of directors and the portions thereof called for by Item 13 are
incorporated herein by reference pursuant to Instruction G to Form 10-K.
 
     (b) NorAm. The information called for by Item 13 with respect to NorAm is
omitted pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by
Certain Wholly-Owned Subsidiaries).
 
                                       141
<PAGE>   144
 
                                    PART IV
 
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
 
<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
     (a)(1) Company Financial Statements.
Statements of Consolidated Income for the Three Years Ended
  December 31, 1997.........................................   53
Statements of Consolidated Retained Earnings for the Three
  Years Ended December 31, 1997.............................   55
Consolidated Balance Sheets at December 31, 1997 and 1996...   56
Consolidated Statements of Capitalization at December 31,
  1997 and 1996.............................................   58
Statements of Consolidated Cash Flows for the Three Years
  Ended December 31, 1997...................................   61
Notes to Consolidated Financial Statements..................   63
Independent Auditors' Report -- Company.....................   99
</TABLE>
 
     (a)(2) NorAm Financial Statements.
 
<TABLE>
<S>                                                           <C>
Statements of Consolidated Income for the Five Months Ended
  December 31, 1997, the Seven Months Ended July 31, 1997
  and the Two Years Ended December 31, 1996.................  109
Consolidated Statements of Stockholders' Equity for the Five
  Months Ended December 31, 1997, the Seven Months Ended
  July 31, 1997 and the Two Years Ended December 31, 1996...  110
Consolidated Balance Sheets at December 31, 1997 and 1996...  111
Statements of Consolidated Cash Flows for the Five Months
  Ended December 31, 1997, the Seven Months Ended July 31,
  1997 and the Two Years Ended December 31, 1996............  113
Notes to Consolidated Financial Statements..................  115
Independent Auditors' Reports -- NorAm......................  139
</TABLE>
 
     (a)(3) Company Financial Statement Schedules For The Three Years Ended
December 31, 1997.
 
<TABLE>
<S>                                                           <C>
THE COMPANY:
II -- Reserves..............................................  143
</TABLE>
 
     (a)(4) NorAm Financial Statement Schedules For The Three Years Ended
December 31, 1997.
 
<TABLE>
<S>                                                           <C>
NORAM:
II -- Reserves..............................................  144
</TABLE>
 
     The following schedules are omitted for each of the Company and NorAm
because of the absence of the conditions under which they are required or
because the required information is included in the financial statements:
     I, III, IV and V.
 
<TABLE>
<S>                                                           <C>
     (a)(5) Exhibits........................................  148
</TABLE>
 
     See Index of Exhibits for the Company (page 148) and NorAm (page 159),
which indexes also include the management contracts or compensatory plans or
arrangements required to be filed as exhibits to this Form 10-K by Item
601(10)(iii) of Regulation S-K.
 
     (b) Reports on Form 8-K.
 
     COMPANY: None
 
     NORAM: None
 
                                       142
<PAGE>   145
 
                        HOUSTON INDUSTRIES INCORPORATED
 
                            SCHEDULE II -- RESERVES
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                   COL. A                       COL. B           COL. C           COL. D       COL. E
                   ------                     ----------   ------------------   ----------   ----------
                                                               ADDITIONS
                                                           ------------------
                                              BALANCE AT   CHARGED   CHARGED    DEDUCTIONS   BALANCE AT
                                              BEGINNING      TO      TO OTHER      FROM         END
                DESCRIPTION                   OF PERIOD    INCOME    ACCOUNTS    RESERVES    OF PERIOD
                -----------                   ----------   -------   --------   ----------   ----------
<S>                                           <C>          <C>       <C>        <C>          <C>
Year Ended December 31, 1997:
  Accumulated provisions deducted from
     related assets on balance sheet:
     Uncollectible accounts.................               $ 5,625   $15,404     $  5,685     $15,344
     Uncollectible advances.................   $ 33,159                            33,159           0
  Reserves other than those deducted from
     assets on balance sheet:
     Property insurance.....................         70      2,187                  5,824      (3,567)
     Injuries and damages...................      1,128      5,215                  3,162       3,181
     Non-regulated project contingencies....      2,296                               516       1,780
Year Ended December 31, 1996:
  Accumulated provisions deducted from
     related assets on balance sheet:
     Uncollectible advances.................     27,412      5,015       732                   33,159
  Reserves other than those deducted from
     assets on balance sheet:
     Property insurance.....................     (2,117)     2,187                                 70
     Injuries and damages...................      1,523      3,156                  3,551       1,128
     Non-regulated project contingencies....                 2,929      (633)                   2,296
Year Ended December 31, 1995:
  Accumulated provisions deducted from
     related assets on balance sheet:
     Uncollectible advances.................                27,412                             27,412
     Net assets of discontinued cable
       television operations................    282,958                           282,958
  Reserves other than those deducted from
     assets on balance sheet:
     Property insurance.....................     (3,468)     2,187                    836      (2,117)
     Injuries and damages...................      2,241      2,327                  3,045       1,523
</TABLE>
 
---------------
 
Notes:
 
(a)   Deductions from reserves represent losses or expenses for which the
      respective reserves were created. In the case of the uncollectible
      accounts reserve, such deductions are net of recoveries of amounts
      previously written off.
 
(b)   Charged to other account represents the provision for uncollectible
      accounts acquired in the August 1997 merger with NorAm.
 
                                       143
<PAGE>   146
 
                      NORAM ENERGY CORP. AND SUBSIDIARIES
 
                            SCHEDULE II -- RESERVES
                  FOR THE THREE YEARS ENDED DECEMBER 31, 1997
                             (THOUSANDS OF DOLLARS)
 
<TABLE>
<CAPTION>
                  COLUMN A                      COLUMN B         COLUMN C         COLUMN D     COLUMN E
                  --------                     ----------   ------------------   ----------   ----------
                                                                ADDITIONS
                                                            ------------------
                                               BALANCE AT   CHARGED   CHARGED    DEDUCTIONS   BALANCE AT
                                               BEGINNING      TO      TO OTHER      FROM         END
                 DESCRIPTION                   OF PERIOD    INCOME    ACCOUNTS    RESERVES    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, 1997............   $13,023     $13,245    $2,383     $13,307      $15,344
     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
  (b) Deferred Tax Assets Valuation Allowance
     Year ended December 31, 1997............   $ 6,761     $ 2,539               $ 2,947      $ 6,353
     Year ended December 31, 1996............   $ 6,188     $   573                            $ 6,761
     Year ended December 31, 1995............   $ 5,974     $   214                            $ 6,188
</TABLE>
 
---------------
 
Notes:
 
(a)   Deductions from reserves represent losses or expenses for which the
      respective reserves were created. In the case of the uncollectible
      accounts reserve, such deductions are net of recoveries of amounts
      previously written off.
 
                                       144
<PAGE>   147
 
                                   SIGNATURES
 
     Pursuant to the requirements of Section 13 or 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, in the City of Houston
and State of Texas, on the 23rd day of March, 1998.
 
                                            HOUSTON INDUSTRIES INCORPORATED
                                            (Registrant)
 
                                            By:      /s/ DON D. JORDAN
                                              ----------------------------------
                                                        Don D. Jordan
                                                 Chairman and Chief Executive
                                                            Officer
 
     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 indicated on March 23, 1998.
 
<TABLE>
<CAPTION>
                      SIGNATURE                                            TITLE
                      ---------                                            -----
<S>                                                    <C>
 
                  /s/ DON D. JORDAN                             Chairman and Chief Executive
-----------------------------------------------------               Officer and Director
                   (Don D. Jordan)                             (Principal Executive Officer)
 
                /s/ STEPHEN W. NAEVE                            Executive Vice President and
-----------------------------------------------------             Chief Financial Officer
                 (Stephen W. Naeve)                            (Principal Financial Officer)
 
              /s/ MARY P. RICCIARDELLO                         Vice President and Comptroller
-----------------------------------------------------          (Principal Accounting Officer)
               (Mary P. Ricciardello)
 
                 /s/ JAMES A. BAKER                                       Director
-----------------------------------------------------
                  (James A. Baker)
 
              /s/ RICHARD E. BALZHISER                                    Director
-----------------------------------------------------
               (Richard E. Balzhiser)
 
                 /s/ MILTON CARROLL                                       Director
-----------------------------------------------------
                  (Milton Carroll)
 
                  /s/ JOHN T. CATER                                       Director
-----------------------------------------------------
                   (John T. Cater)
 
              /s/ O. HOLCOMBE CROSSWELL                                   Director
-----------------------------------------------------
               (O. Holcombe Crosswell)
 
              /s/ ROBERT J. CRUIKSHANK                                    Director
-----------------------------------------------------
               (Robert J. Cruikshank)
 
                 /s/ LINNET F. DEILY                                      Director
-----------------------------------------------------
                  (Linnet F. Deily)
 
                 /s/ JOSEPH M. GRANT                                      Director
-----------------------------------------------------
                  (Joseph M. Grant)
</TABLE>
 
                                       145
<PAGE>   148
 
<TABLE>
<CAPTION>
                      SIGNATURE                                            TITLE
                      ---------                                            -----
<S>                                                    <C>
 
                 /s/ ROBERT C. HANNA                                      Director
-----------------------------------------------------
                  (Robert C. Hanna)
 
                  /s/ LEE W. HOGAN                                        Director
-----------------------------------------------------
                   (Lee W. Hogan)
 
                 /s/ T. MILTON HONEA                                      Director
-----------------------------------------------------
                  (T. Milton Honea)
 
               /s/ R. STEVE LETBETTER                                     Director
-----------------------------------------------------
                (R. Steve Letbetter)
 
               /s/ ALEXANDER F. SCHILT                                    Director
-----------------------------------------------------
                (Alexander F. Schilt)
 
                  /s/ BERTRAM WOLFE                                       Director
-----------------------------------------------------
                   (Bertram Wolfe)
</TABLE>
 
                                       146
<PAGE>   149
 
                                   SIGNATURES
 
     Pursuant to the requirements of Section 13 or 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, in the City of Houston
and State of Texas, on the 23rd day of March, 1998.
 
                                            NORAM ENERGY CORP.
                                            (Registrant)
 
                                            By:      /s/ DON D. JORDAN
                                              ----------------------------------
                                                        Don D. Jordan
                                                 Chairman and Chief Executive
                                                            Officer
 
     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 indicated on March 23, 1998.
 
<TABLE>
<CAPTION>
                      SIGNATURE                                                TITLE
                      ---------                                                -----
<S>                                                         <C>
 
                  /s/ DON D. JORDAN                             Chairman and Chief Executive Officer
-----------------------------------------------------             (Principal Executive Officer and
                   (Don D. Jordan)                                  Principal Financial Officer)
 
              /s/ MARY P. RICCIARDELLO                             Vice President and Comptroller
-----------------------------------------------------              (Principal Accounting Officer)
               (Mary P. Ricciardello)
 
                /s/ STEPHEN W. NAEVE                                       Sole Director
-----------------------------------------------------
                  (Stephen W. Naeve
</TABLE>
 
                                       147
<PAGE>   150
 
                        HOUSTON INDUSTRIES INCORPORATED
                               NORAM ENERGY CORP.
 
              EXHIBITS TO THE COMBINED ANNUAL REPORT ON FORM 10-K
                    FOR FISCAL YEAR ENDED DECEMBER 31, 1997
 
                               INDEX OF EXHIBITS
 
     Exhibits not incorporated by reference to a prior filing are designated by
a cross(+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated. Exhibits designated by an asterisk (*) are
management contracts or compensatory plans or arrangements required to be filed
as exhibits to this Form 10-K by Item 601(10)(iii) of Regulation S-K.
 
(A) HOUSTON INDUSTRIES INCORPORATED
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
 EXHIBIT                                            REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
 -------              -----------                   ------------         ------------    ---------
<C>          <S>                               <C>                       <C>             <C>
 2(a)(1)     Agreement and Plan of Merger      Former HI's Form 8-K      1-7629          2
             among the Company, Former         dated August 11, 1996
             HL&P, HI Merger, Inc. and
             Former NorAm dated August 11,
             1996
 2(a)(2)     Amendment to Agreement and        Registration Statement    333-11329       2(c)
             Plan of Merger among the          on Form S-4
             Company, Former HL&P, HI
             Merger, Inc. and Former NorAm
             dated August 11, 1996
+3(a)        Restated Articles of
             Incorporation of the Company,
             restated as of September 1997
+3(b)        Amended and Restated Bylaws of
             the Company, as of December
             1996
 4(a)(1)     Mortgage and Deed of Trust        Form S-7 of Former        2-59748         2(b)
             dated November 1, 1944 between    HL&P filed on August
             the Company and Chase Bank of     25, 1977
             Texas, National Association
             (formerly, South Texas
             Commercial National Bank of
             Houston), as Trustee, as
             amended and supplemented by 20
             Supplemental Indentures
             thereto
 4(a)(2)     Twenty-First through Fiftieth     Former HL&P's Form        1-3187          4(a)(2)
             Supplemental Indentures to        10-K for year ended
             Exhibit 4(a)(1)                   December 31, 1989
 4(a)(3)     Fifty-First Supplemental          Former HL&P's Form        1-3187          4(a)
             Indenture to Exhibit 4(a)(1)      10-Q for quarter ended
             dated as of March 25, 1991        June 30, 1991
 4(a)(4)     Fifty-Second through              Former HL&P's Form        1-3187          4
             Fifty-Fifth Supplemental          10-Q for quarter ended
             Indentures to Exhibit 4(a)(1)     March 31, 1992
             each dated as of March 1, 1992
</TABLE>
 
                                       148
<PAGE>   151
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
 EXHIBIT                                            REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
 -------              -----------                   ------------         ------------    ---------
<C>          <S>                               <C>                       <C>             <C>
 4(a)(5)     Fifty-Sixth and Fifty-Seventh     Former HL&P's Form        1-3187          4
             Supplemental Indentures to        10-Q for quarter ended
             Exhibit 4(a)(1) each dated as     September 30, 1992
             of October 1, 1992
 4(a)(6)     Fifty-Eighth and Fifty-Ninth      Former HL&P's Form        1-3187          4
             Supplemental Indenture to         10-Q for quarter ended
             Exhibit 4(a)(1) each dated as     March 31, 1993
             of March 1, 1993
 4(a)(7)     Sixtieth Supplemental             Former HL&P's Form        1-3187          4
             Indenture to Exhibit 4(a)(1)      10-Q for quarter ended
             dated as of July 1, 1993          June 30, 1993
 4(a)(8)     Sixty-First through               Former HL&P's Form        1-3187          4
             Sixty-Third Supplemental          10-K for year ended
             Indentures to Exhibit 4(a)(1)     December 31, 1993
             each dated as of December 1,
             1993
 4(a)(9)     Sixty-Fourth and Sixty-Fifth      Former HL&P's Form        1-3187          4(a)(9)
             Supplemental Indentures to        10-K for year ended
             Exhibit 4(a)(1) each dated as     December 31, 1995
             of July 1, 1995
 4(a)(10)    Junior Subordinated Trust         Former HL&P's Form 8-K    1-3187          4.1
             Debenture Indenture between       dated February 4, 1997
             the Company and The Bank of
             New York, as Trustee, dated as
             of February 1, 1997
 4(a)(11)    Supplemental Indenture No. 1      Former HL&P's Form 8-K    1-3187          4.2-A
             to Junior Subordinated            dated February 4, 1997
             Indenture, dated as of
             February 1, 1997, providing
             for issuance of the Company's
             8.125% Junior Subordinated
             Deferrable Interest
             Debentures, Series A due March
             31, 2046, including form of
             8.125% junior subordinated
             interest debenture, Series A
 4(a)(12)    Supplemental Indenture No. 2      Former HL&P's Form 8-K    1-3187          4.2-B
             to Junior Subordinated            dated February 4, 1997
             Indenture, dated as of
             February 1, 1997, providing
             for issuance of 8.257% Junior
             Subordinated Deferrable
             Interest Debentures, Series B
             (due February 1, 2037)
             including form of junior
             subordinated interest
             debenture, Series B
 4(a)(13)    Amended and Restated Trust        Former HL&P's Form 8-K    1-3187          4.3-A
             Agreement, dated as of            dated February 4, 1997
             February 4, 1997, of HL&P
             Capital Trust I, including
             form of Preferred Security and
             Agreement as to Expenses and
             Liabilities
</TABLE>
 
                                       149
<PAGE>   152
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
 EXHIBIT                                            REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
 -------              -----------                   ------------         ------------    ---------
<C>          <S>                               <C>                       <C>             <C>
 4(a)(14)    Amended and Restated Trust        Former HL&P's Form 8-K    1-3187          4.3-B
             Agreement, dated as of            dated February 4, 1997
             February 4, 1997, of HL&P
             Capital Trust II, including
             form of Capital Security of
             HL&P Capital Trust II and
             Agreement as to Expenses and
             Liabilities
 4(a)(15)    Guarantee Agreement relating      Former HL&P's Form 8-K    1-3187          4.6-A
             to Capital Trust I dated as of    dated February 4, 1997
             February 4, 1997
 4(a)(16)    Guarantee Agreement relating      Former HL&P's Form 8-K    1-3187          4.6-B
             to Capital Trust II dated as      dated February 4, 1997
             of February 4, 1997
 4(a)(17)    Form of Indenture governing 7%    Former HI's Form 10-Q     1-7629          4
             Automatic Common Exchange         for the quarter ended
             Securities due July 1, 2000       June 30, 1997
             between the Company and the
             First National Bank of
             Chicago, as Trustee
 4(b)(1)     Rights Agreement, dated July      Former HI's Form 8-K      1-7629          4(a)(1)
             11, 1990, between the Company     dated July 11, 1990
             and Texas Commerce Bank
             National Association, as
             Rights Agent (Rights Agent),
             which includes form of
             Statement of Resolution
             Establishing Series of Shares
             designated Series A Preference
             Stock and form of Rights
             Certificate
 4(b)(2)     Agreement and Appointment of      Form 8-K dated July       1-7629          4(a)(2)
             Agent, dated as of July 11,       11, 1990
             1990, between the Company and
             the Rights Agent
 4(b)(3)     Form of Amended and Restated      Registration Statement    333-11329       4(b)(1)
             Rights Agreement to be            on Form S-4
             executed upon the closing of
             the Merger, including form of
             Statement of Resolution
             Establishing Series Shares
             Designated Series A Preference
             Stock and form of Rights
             Agreement
 4(c)        Indenture, dated as of April      Former HI's Form 10-Q     1-7629          4(b)
             1, 1991, between the Company      for the quarter ended
             and NationsBank of Texas,         June 30, 1991
             National Association, as
             Trustee
</TABLE>
 
                                       150
<PAGE>   153
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
 EXHIBIT                                            REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
 -------              -----------                   ------------         ------------    ---------
<C>          <S>                               <C>                       <C>             <C>
 4(d)        Credit Agreement, dated as of     Former HI's Form 10-Q     1-7629          10(f)
             August 6, 1997, by and among      for the quarter ended
             Houston Industries FinanceCo      June 30, 1997
             LP, the Company, Chase
             Manhattan Bank and the other
             banks named therein
+4(d)(1)     First Amendment to Exhibit
             4(d) dated as of December 27,
             1997
+4(d)(2)     Second Amendment to Exhibit
             4(d) dated as of February 27,
             1998
</TABLE>
 
     Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the Company has not
filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of securities authorized do
not exceed 10 percent of the total assets of the Company and its subsidiaries on
a consolidated basis. The Company hereby agrees to furnish a copy of any such
instrument to the SEC upon request.
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(a)        Executive Benefit Plan of       Former HI's Form 10-Q     1-7629          10(a)(1)
               the Company and First and       for the quarter ended                     10(a)(2)
               Second Amendments thereto       March 31, 1987                            and
               effective as of June 1,                                                   10(a)(3)
               1982, July 1, 1984, and May
               7, 1986, respectively
 *10(b)(1)     Executive Incentive             Former HI's Form 10-K     1-7629          10(b)
               Compensation Plan of the        for the year ended
               Company effective as of         December 31, 1991
               January 1, 1982
 *10(b)(2)     First Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(a)
               10(b)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(b)(3)     Second Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(b)
               10(b)(1) effective as of        for the year ended
               November 4, 1992                December 31, 1992
 *10(b)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(b)(4)
               10(b)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
+*10(b)(5)     Fourth Amendment to Exhibit
               10(b)(1) effective as of
               August 6, 1997
 *10(c)(1)     Executive Incentive             Former HI's Form 10-Q     1-7629          10(b)(1)
               Compensation Plan of the        for the quarter ended
               Company effective as of         March 31, 1987
               January 1, 1985
</TABLE>
 
                                       151
<PAGE>   154
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(c)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(b)(3)
               10(c)(1) effective as of        for the year ended
               January 1, 1985                 December 31, 1988
 *10(c)(3)     Second Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(c)(3)
               10(c)(1) effective as of        for the year ended
               January 1, 1985                 December 31, 1991
 *10(c)(4)     Third Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(b)
               10(c)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(c)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(c)(5)
               10(c)(1) effective as of        for the year ended
               November 4, 1992                December 31, 1992
 *10(c)(6)     Fifth Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(c)(6)
               10(c)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
+*10(c)(7)     Sixth Amendment to Exhibit
               10(c)(1) effective as of
               August 6, 1997
 *10(d)        Executive Incentive             Former HI's Form 10-Q     1-7629          10(b)(2)
               Compensation Plan of HL&P       for the quarter ended
               effective as of January 1,      March 31, 1987
               1985
 *10(e)(1)     Executive Incentive             Former HI's Form 10-Q     1-7629          10(b)
               Compensation Plan of the        for the quarter ended
               Company effective as of         June 30, 1989
               January 1, 1989
 *10(e)(2)     First Amendment to Exhibit      Former HI's 10-K for      1-7629          10(e)(2)
               10(e)(1) effective as of        the year ended
               January 1, 1989                 December 31, 1991
 *10(e)(3)     Second Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(c)
               10(e)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(e)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(c)(4)
               10(e)(1) effective as of        for the year ended
               November 4, 1992                December 31, 1992
 *10(e)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(e)(5)
               10(e)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
 *10(f)(1)     Executive Incentive             Former HI's Form 10-K     1-7629          10(b)
               Compensation Plan of the        for the year ended
               Company effective as of         December 31, 1990
               January 1, 1991
</TABLE>
 
                                       152
<PAGE>   155
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(f)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(f)(2)
               10(f)(1) effective as of        for the year ended
               January 1, 1991                 December 31, 1991
 *10(f)(3)     Second Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(d)
               10(f)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(f)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(f)(4)
               10(f)(1) effective as of        for the year ended
               November 4, 1992                December 31, 1992
 *10(f)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(f)(5)
               10(f)(1) effective as of        for the year ended
               January 1, 1993                 December 31, 1992
 *10(f)(6)     Fifth Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(f)(6)
               10(f)(1) effective in part,     for the year ended
               January 1, 1995 and in part,    December 31, 1994
               September 7, 1994
 *10(f)(7)     Sixth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(a)
               10(f)(1) effective as of        for the quarter ended
               August 1, 1995                  June 30, 1995
 *10(f)(8)     Seventh Amendment to Exhibit    Former HI's Form 10-Q     1-7629          10(a)
               10(f)(1) effective as of        for the quarter ended
               January 1, 1996                 June 30, 1996
 *10(f)(9)     Eighth Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(a)
               10(f)(1) effective as of        for the quarter ended
               January 1, 1997                 June 30, 1997
+*10(f)(10)    Ninth Amendment to Exhibit
               10(f)(1) effective in part,
               January 1, 1997, and in
               part, January 1, 1998
 *10(g)        Benefit Restoration Plan of     Former HI's Form 10-Q     1-7629          10(c)
               the Company, effective as of    for the quarter ended
               June 1, 1985                    March 31, 1987
 *10(h)        Benefit Restoration Plan of     Former HI's Form 10-K     1-7629          10(g)(2)
               the Company as amended and      for the year ended
               restated effective as of        December 31, 1991
               January 1, 1988
 *10(i)(1)     Benefit Restoration Plan of     Former HI's Form 10-K     1-7629          10(g)(3)
               the Company, as amended and     for the year ended
               restated effective as of        December 31, 1991
               July 1, 1991
</TABLE>
 
                                       153
<PAGE>   156
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
+*10(i)(2)     First Amendment to Exhibit
               10(i)(1) effective in part,
               August 6, 1997, and in part,
               September 3, 1997 and in
               part, October 1, 1997
 *10(j)(1)     Deferred Compensation Plan      Former HI's Form 10-Q     1-7629          10(d)
               of the Company effective as     for the quarter ended
               of September 1, 1985            March 31, 1987
 *10(j)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(d)(2)
               10(j)(1) effective as of        for the year ended
               September 1, 1985               December 31, 1990
 *10(j)(3)     Second Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(e)
               10(j)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(j)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(h)(4)
               10(j)(1) effective as of        for the year ended
               June 2, 1993                    December 31, 1993
 *10(j)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(h)(5)
               10(j)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
 *10(j)(6)     Fifth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(d)
               10(j)(1) effective as of        for the quarter ended
               August 1, 1995                  June 30, 1995
 *10(j)(7)     Sixth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(b)
               10(j)(1) effective as of        for the quarter ended
               December 1, 1995                June 30, 1995
 *10(j)(8)     Seventh Amendment to Exhibit    Former HI's Form 10-Q     1-7629          10(b)
               10(j)(1) effective as of        for the quarter ended
               January 1, 1997                 June 30, 1997
+*10(j)(9)     Eighth Amendment to Exhibit
               10(j)(1) effective as of
               September 1, 1997
+*10(j)(10)    Ninth Amendment to Exhibit
               10(j)(1) effective as of
               September 3, 1997
 *10(k)(1)     Deferred Compensation Plan      Former HI's Form 10-Q     1-7629          10(a)
               of the Company effective as     for the quarter ended
               of January 1, 1989              June 30, 1989
 *10(k)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(e)(3)
               10(k)(1) effective as of        for the year ended
               January 1, 1989                 December 31, 1989
</TABLE>
 
                                       154
<PAGE>   157
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(k)(3)     Second Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(f)
               10(k)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(k)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(i)(4)
               10(k)(1) effective as of        for the year ended
               June 2, 1993                    December 31, 1993
 *10(k)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(i)(5)
               10(k)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
 *10(k)(6)     Fifth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(c)
               10(k)(1) effective as of        for the quarter ended
               August 1, 1995                  June 30, 1995
 *10(k)(7)     Sixth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(c)
               10(k)(1) effective as of        for the quarter ended
               December 1, 1995                June 30, 1995
 *10(k)(8)     Seventh Amendment to Exhibit    Former HI's Form 10-Q     1-7629          10(c)
               10(k)(1) effective as of        for the quarter ended
               January 1, 1997                 June 30, 1997
+*10(k)(9)     Eighth Amendment to Exhibit
               10(k)(1) effective as in
               part October 1, 1997 and in
               part January 1, 1998
+*10(k)(10)    Ninth Amendment to Exhibit
               10(k)(1) effective as of
               September 3, 1997
 *10(l)(1)     Deferred Compensation Plan      Former HI's Form 10-K     1-7629          10(d)(3)
               of the Company effective as     for the year ended
               of January 1, 1991              December 31, 1990
 *10(l)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(j)(2)
               10(l)(1) effective as of        for the year ended
               January 1, 1991                 December 31, 1991
 *10(l)(3)     Second Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(g)
               10(l)(1) effective as of        for the quarter ended
               March 30, 1992                  March 31, 1992
 *10(l)(4)     Third Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(j)(4)
               10(l)(1) effective as of        for the year ended
               June 2, 1993                    December 31, 1993
 *10(l)(5)     Fourth Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(j)(5)
               10(l)(1) effective as of        for the year ended
               December 1, 1993                December 31, 1993
</TABLE>
 
                                       155
<PAGE>   158
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(l)(6)     Fifth Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(j)(6)
               10(l)(1) effective as of        for the year ended
               September 7, 1994               December 31, 1994
 *10(l)(7)     Sixth Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(b)
               10(l)(1) effective as of        for the quarter ended
               August 1, 1995                  June 30, 1995
 *10(l)(8)     Seventh Amendment to Exhibit    Former HI's Form 10-Q     1-7629          10(d)
               10(l)(1) effective as of        for the quarter ended
               December 1, 1995                June 30, 1996
 *10(l)(9)     Eighth Amendment to Exhibit     Former HI's Form 10-Q     1-7629          10(d)
               10(l)(1) effective as of        for the quarter ended
               January 1, 1997                 June 30, 1997
+*10(l)(10)    Ninth Amendment to Exhibit
               10(l)(1) effective in part
               August 6, 1997, in part
               October 1, 1997 and in part
               January 1, 1998
+*10(l)(11)    Tenth Amendment to Exhibit
               10(l)(1) effective as of
               September 3, 1997
 *10(m)(1)     Long-Term Incentive             Former HI's Form 10-Q     1-7629          10(c)
               Compensation Plan of the        for the quarter ended
               Company effective as of         June 30, 1989
               January 1, 1989
 *10(m)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(f)(2)
               10(m)(1) effective as of        for the year ended
               January 1, 1990                 December 31, 1989
 *10(m)(3)     Second Amendment to Exhibit     Former HI's Form 10-K     1-7629          10(k)(3)
               10(m)(1) effective as of        for the year ended
               December 22, 1992               December 31, 1992
+*10(m)(4)     Third Amendment to Exhibit
               10(m)(1) effective as of
               August 6, 1997
 *10(n)        Form of stock option            Former HI's Form 10-Q     1-7629          10(h)
               agreement for nonqualified      for the quarter ended
               stock options granted under     March 31, 1992
               the Company's 1989 Long-Term
               Incentive Compensation Plan
 *10(o)        Forms of restricted stock       Former HI's Form 10-Q     1-7629          10(i)
               agreement for restricted        for the quarter ended
               stock granted under the         March 31, 1992
               Company's 1989 Long-Term
               Incentive Compensation Plan
</TABLE>
 
                                       156
<PAGE>   159
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
 *10(p)(1)     1994 Long-Term Incentive        Former HI's Form 10-K     1-7629          10(n)(1)
               Compensation Plan of the        for the year ended
               Company effective as of         December 31, 1993
               January 1, 1994
 *10(p)(2)     Form of stock option            Former HI's Form 10-K     1-7629          10(n)(2)
               agreement for non-qualified     for the year ended
               stock options granted under     December 31, 1993
               the Company's 1994 Long-Term
               Incentive Compensation Plan
 *10(p)(3)     First Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10(e)
               10(p)(1) effective as of May    for the quarter ended
               9, 1997                         June 30, 1997
+*10(p)(4)     Second Amendment to Exhibit
               10(p)(1) effective as of
               August 6, 1997
 *10(q)(1)     Savings Restoration Plan of     Former HI's Form 10-K     1-7629          10(f)
               the Company effective as of     for the year ended
               January 1, 1991                 December 31, 1990
 *10(q)(2)     First Amendment to Exhibit      Former HI's Form 10-K     1-7629          10(l)(2)
               10(q)(1) effective as of        for the year ended
               January 1, 1992                 December 31, 1991
+*10(q)(3)     Second Amendment to Exhibit
               10(q)(1) effective in part,
               August 6, 1997, and in part,
               October 1, 1997
 *10(r)        Director Benefits Plan,         Former HI's Form 10-K     1-7629          10(m)
               effective as of January 1,      for the year ended
               1992                            December 31, 1991
 *10(s)(1)     Executive Life Insurance        Former HI's Form 10-K     1-7629          10(q)
               Plan of the Company             for the year ended
               effective as of January 1,      December 31, 1993
               1994
 *10(s)(2)     First Amendment to Exhibit      Former HI's Form 10-Q     1-7629          10
               10(s)(1) effective as of        for the quarter ended
               January 1, 1994                 June 30, 1995
+*10(s)(3)     Second Amendment to Exhibit
               10(s)(1) effective as of
               August 6, 1997
 *10(t)        Employment and Supplemental     Former HI's Form 10-Q     1-7629          10(f)
               Benefits Agreement between      for the quarter ended
               HL&P and Hugh Rice Kelly        March 31, 1987
</TABLE>
 
                                       157
<PAGE>   160
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
  10(u)(1)     Houston Industries              Former HI's Form 10-K     1-7629          10(s)(4)
               Incorporated Savings Trust      for the year ended
               between the Company and The     December 31, 1995
               Northern Trust Company, as
               Trustee (as amended and
               restated effective July 1,
               1995)
  10(u)(2)     Note Purchase Agreement         Former HI's Form 10-K     1-7629          10(j)(3)
               between the Company and the     for the year ended
               ESOP Trustee, dated as of       December 31, 1990
               October 5, 1990
  10(v)(1)     Stockholder's Agreement         Schedule 13-D dated       5-19351         2
               dated as of July 6, 1995        July 6, 1995
               between the Company and Time
               Warner Inc.
  10(v)(2)     Registration Rights             Schedule 13-D dated       5-19351         3
               Agreement dated as of July      July 6, 1995
               6, 1995 between the Company
               and Time Warner Inc.
  10(v)(3)     Amendment to Exhibits           Former HI's Form 10-K     1-7629          10(x)(4)
               10(v)(1) and 10(v)(2) dated     for the year ended
               November 18, 1996               December 31, 1996
  10(v)(4)     Certificate of Voting           Schedule 13-D dated       5-19351         4
               Powers, Designations,           July 6, 1995
               Preferences and Relative
               Participating, Optional or
               Other Special Rights, and
               Qualifications, Limitations
               or Restrictions Thereof of
               Series D Convertible
               Preferred Stock of Time
               Warner Inc.
 *10(w)        Houston Industries              Former HI's Form 10-K     1-7629          10(7)
               Incorporated Executive          for the year ended
               Deferred Compensation Trust,    December 31, 1995
               effective as of December 19,
               1995
 *10(x)        Supplemental Pension            Registration Statement    333-11329       10(aa)
               Agreement, dated July 17,       on Form S-4
               1996, between the Company
               and Lee W. Hogan
 *10(y)        Consulting Agreement, dated     Former HI's Form 10-K     1-7629          10(bb)
               January 14, 1997, between       for the year ended
               the Company and Milton          December 31, 1996
               Carroll
 *10(z)(1)     Employment Agreement, dated     Former HI's Form 10-K     1-7629          10(cc)
               February 25, 1997, between      for the year ended
               the Company and Don D.          December 31, 1996
               Jordan
+*10(z)(2)     Amended and Restated
               Employment Agreement, dated
               November 7, 1997, between
               the Company and Don D.
               Jordan
</TABLE>
 
                                       158
<PAGE>   161
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
  EXHIBIT                                           REGISTRATION         REGISTRATION     EXHIBIT
  NUMBER               DESCRIPTION                   STATEMENT              NUMBER       REFERENCE
  -------              -----------                  ------------         ------------    ---------
<C>            <S>                             <C>                       <C>             <C>
+*10(aa)(1)    Executive Severance Benefits
               Plan of the Company and
               Summary Plan Description
               effective as of September 3,
               1997
+*10(aa)(2)    Form of Severance
               Agreements, dated September
               3, 1997, between the Company
               and each of the following
               executive officers: Lee W.
               Hogan, Hugh Rice Kelly, R.
               Steve Letbetter, and Stephen
               W. Naeve
 +12           Computation of Ratios of
               Earnings to Fixed Charges
 +21           Subsidiaries of the Company
 +23           Consent of Deloitte & Touche
               LLP
 +27           Financial Data Schedule
</TABLE>
 
(B) NORAM ENERGY CORP.
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
EXHIBIT                                             REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
-------               -----------                   ------------         ------------    ---------
<C>         <S>                                <C>                       <C>             <C>
 2(a)(1)    Agreement and Plan of Merger       Former HI's Form 8-K      1-7629          2
            among the Company, Former HL&P,    dated August 11, 1996
            HI Merger, Inc. and Former
            NorAm dated August 11, 1996
 2(b)(2)    Amendment to Agreement and Plan    Registration Statement    333-11329       2(c)
            of Merger among the Company,       on Form S-4
            Former HL&P, HI Merger, Inc.
            and Former NorAm dated August
            11, 1996
+3(a)(1)    Certificate of Incorporation of
            NorAm
+3(a)(2)    Certificate of Merger merging
            NorAm Energy Corp. with and
            into HI Merger, Inc. dated
            August 6, 1997
+3(b)       Bylaws of NorAm
 4(a)(1)    Indenture, dated as of December    Former NorAm's Form       1-13265         4.14
            1, 1986, between NorAm and         10-K for the year
            Citibank, N.A., as Trustee         ended December 31,
                                               1986
+4(a)(2)    First Supplemental Indenture to
            Exhibit 4(a)(1) dated as of
            September 30, 1988
</TABLE>
 
                                       159
<PAGE>   162
 
<TABLE>
<CAPTION>
                                                     REPORT OR           SEC FILE OR
EXHIBIT                                             REGISTRATION         REGISTRATION     EXHIBIT
 NUMBER               DESCRIPTION                    STATEMENT              NUMBER       REFERENCE
-------               -----------                   ------------         ------------    ---------
<C>         <S>                                <C>                       <C>             <C>
+4(a)(3)    Second Supplemental Indenture
            to Exhibit 4(a)(1) dated as of
            November 15, 1989
+4(a)(4)    Third Supplemental Indenture to
            Exhibit 4(a)(1) dated as of
            August 6, 1997
 4(b)(1)    Indenture, dated as of March       Former NorAm's            33-14586        4.20
            31, 1987, between NorAm and        Registration Statement
            Chase Manhattan Bank, N.A., as     on Form S-3
            Trustee, authorizing 6%
            Convertible Subordinated
            Debentures due 2012
+4(b)(2)    Supplemental Indenture to
            Exhibit 4(b)(1) dated as of
            August 6, 1997
 4(c)(1)    Indenture, dated as of April       Former NorAm's            33-23375        4.1
            15, 1990, between NorAm and        Registration Statement
            Citibank, N.A. as Trustee          on Form S-3
+4(c)(2)    Supplemental Indenture to
            Exhibit 4(c)(1) dated as of
            August 6, 1997
 4(d)(1)    Form of Indenture between NorAm    Former NorAm's            33-64001        4.8
            and The Bank of New York as        Registration Statement
            Trustee                            on Form S-3
 4(d)(2)    Form of First Supplemental         Former NorAm's Form       1-13265         4.01
            Indenture to Exhibit 4(d)(1)       8-K dated as of June
                                               10, 1996
+4(d)(3)    Second Supplemental Indenture
            to Exhibit 4(d)(1) dated as of
            August 6, 1997
 4(e)       Indenture between NorAm and        Registration Statement    333-41017       4.1
            Chase Bank of Texas, National      on Form S-3
            Association, dated as of
            December 1, 1997
</TABLE>
 
     There have not been filed as exhibits to this Form 10-K certain long-term
debt instruments, including indentures, under which the total amount of
securities do not exceed 10 percent of the total assets of NorAm. NorAm hereby
agrees to furnish a copy of any such instrument to the SEC upon request.
 
<TABLE>
<CAPTION>
                                                                            SEC FILE
                                                      REPORT OR                OR
EXHIBIT                                              REGISTRATION         REGISTRATION     EXHIBIT
NUMBER                DESCRIPTION                     STATEMENT              NUMBER       REFERENCE
-------               -----------                    ------------         ------------    ---------
<C>        <S>                                  <C>                       <C>             <C>
  10(a)    Service Agreement by and between     Former NorAm Form 10-K    1-13265         10.20
           Mississippi River Transmission       for the year ended
           Corporation and Laclede Gas          December 31, 1989
           Company dated August 22, 1989
 +12       Computation of Ratios of Earnings
           to Fixed Charges
 +23(a)    Consent of Deloitte & Touche LLP
 +23(b)    Consent of Coopers & Lybrand
           L.L.P.
 +27       Financial Data Schedule
</TABLE>
 
                                       160