<PAGE>
 
                                                                      EXHIBIT 13

1997 FINANCIAL REVIEW
 
                    MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                 FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
HOLDING COMPANY
 
  NIPSCO Industries, Inc. (Industries) is an energy/utility-based holding
company providing electric energy, natural gas and water to the public through
its six wholly-owned regulated subsidiaries (Utilities): Northern Indiana
Public Service Company (Northern Indiana); Kokomo Gas and Fuel Company (Kokomo
Gas); Northern Indiana Fuel and Light Company, Inc. (NIFL); Crossroads
Pipeline Company (Crossroads); Indianapolis Water Company (IWC); and Harbour
Water Corporation (Harbour). Industries' regulated gas and electric
subsidiaries (Northern Indiana, Kokomo Gas, NIFL and Crossroads) are referred
to as "Energy Utilities"; and regulated water subsidiaries (IWC and Harbour)
are referred to as "Water Utilities."
 
  On March 25, 1997, Industries acquired IWC Resources Corporation (IWCR).
IWCR's subsidiaries include two regulated water utilities (IWC and Harbour)
and five non-utility companies providing utility-related services including
installation, repair and maintenance of underground pipelines and utility line
locating and marking. The two primary non-utility subsidiaries are Miller
Pipeline Corporation (Miller) and SM&P Utility Resources, Inc. (SM&P).
 
  Industries also provides non-regulated energy/utility-related services
including energy marketing and trading; power generation; gas transmission,
supply and storage; installation, repair and maintenance of underground
pipelines; utility line locating and marking; and related products targeted at
customer segments principally through the following wholly-owned subsidiaries:
NIPSCO Development Company, Inc. (Development); NIPSCO Energy Services, Inc.
(Services); Primary Energy, Inc. (Primary); Miller; and SM&P. NIPSCO Capital
Markets, Inc. (Capital Markets) handles financing for Industries and its
subsidiaries, other than Northern Indiana. These subsidiaries are referred to
collectively as "Products and Services."
 
  On December 18, 1997, Industries and Bay State Gas Company signed a
definitive merger agreement under which Industries will acquire all of the
common stock of Bay State Gas Company in a stock-for-stock transaction. Refer
to Purchase of Bay State Gas Company in Notes to Consolidated Financial
Statements for a more detailed discussion of the proposed acquisition.
 
NET INCOME
 
  All references throughout this Annual Report to number of common shares
reported for the period including per share amounts, stock option data and
market prices of Industries' common stock have been restated to reflect a two-
for-one stock split which is payable February 20, 1998, to shareholders of
record at the close of business on January 30, 1998. At December 31, 1997,
Industries adopted SFAS No. 128 "Earnings per Share." The adoption of this
statement required Industries to present basic earnings per share and diluted
earnings per share in place of primary earnings per share. Refer to Earnings
per Share in Notes to Consolidated Financial Statements for information
related to this disclosure.
 
  For 1997, net income of Industries increased to $190.8 million, or basic
earnings of $1.54 per average common share, compared to $176.7 million, or
basic earnings of $1.44 per average common share, for 1996. There were
approximately 1.5 million more average common shares outstanding in 1997 than
1996. In 1995, net income was $175.5 million, or basic earnings of $1.36 per
average common share. See Notes to Consolidated Financial Statements for
Segments of Business regarding revenue and operating income derived from the
delivery of gas, electricity, water and products and services.
 
REVENUES
 
  In 1997, operating revenues increased $598.6 million, or 30.1%, over 1996.
Operating revenues in 1996 increased $218.6 million, or 12.4%, from 1995.
 
 
                                       2

<PAGE>
 
  During 1997, gas deliveries in dekatherms (dth), which include
transportation services, increased 2.7%. Gas sales levels in 1997 remained
relatively unchanged from 1996. Gas transportation services increased 4.6%
mainly due to increased deliveries of gas transported for others. The Energy
Utilities had approximately 729,400 gas customers at December 31, 1997. During
1996, gas deliveries increased 6.6% over 1995. Gas sales in 1996 increased
14.5% due to higher sales to residential and commercial customers as a result
of colder weather during the first quarter of 1996 and increased sales to
industrial and wholesale customers. Gas transportation services increased 1.6%
mainly due to increased deliveries by Crossroads, which were partially offset
by decreased deliveries to Northern Indiana's industrial customers.
 
  Gas revenues were $807.2 million in 1997, an increase of $7.8 million from
1996. The increase in gas revenues was mainly due to increased sales to
wholesale customers, increased gas costs per dth and increased deliveries of
gas transported for others, partially offset by decreased sales to residential
and commercial customers and decreased gas transition costs. Gas revenues were
$799.4 million in 1996, an increase of $108.0 million from 1995. The increase
in gas revenues was mainly due to increased sales to residential and
commercial customers as the result of colder weather during the first quarter
of 1996, increased sales to industrial and wholesale customers and increased
gas costs per dth, which were partially offset by decreased gas transition
costs. The large commercial and industrial customers continued to utilize
transportation services provided by the Energy Utilities. Gas transportation
customers purchase much of their gas directly from producers and marketers and
then pay a transportation fee to have their gas delivered over the Energy
Utilities' systems. The Energy Utilities transported 203.7, 194.4 and 191.6
million dth in 1997, 1996 and 1995, respectively.
 
  In 1997, sales of electricity in kilowatt-hours (kwh) decreased 4.5% from
1996 mainly due to decreased sales to wholesale and industrial customers
partially offset by increased sales to residential and commercial customers.
Industrial sales decreased during the period as a result of cogeneration
projects with two of Northern Indiana's major industrial customers coming
online during the period. Northern Indiana had approximately 416,300 electric
customers at December 31, 1997. In 1996, sales of electricity in kilowatt-
hours (kwh) decreased 1.1% from 1995 mainly due to decreased sales to
residential customers due to cooler summer weather in 1996 and decreased sales
to industrial customers due to operational difficulties at several major
industrial customers, which were partially offset by increased sales to
commercial and wholesale customers.
 
  In 1997, electric revenues were $1.017 billion, a decrease of $5.1 million
from 1996. The decrease in electric revenues was mainly due to decreased sales
to industrial customers, partially offset by increased sales to residential
and commercial customers and increased revenues related to wholesale
transactions. Industrial sales decreased during the period as a result of
cogeneration projects with two of Northern Indiana's major industrial
customers coming online during the period. In 1996, electric revenues were
$1.022 billion, a decrease of $8.7 million from 1995. The decrease in electric
revenues was mainly due to decreased sales to residential customers due to
cooler summer weather in 1996 and decreased sales to industrial customers due
to operational difficulties at several major industrial customers, which were
partially offset by increased sales to commercial and wholesale customers.
 
  Water revenue for the period April 1997 through December 1997 was $60.7
million. Water sales to residential and commercial customers accounted for
$54.4 million of 1997 revenues. The Water Utilities had sales in millions of
gallons (m.g.) of 35,566 during the last nine months of 1997 and served
approximately 246,600 customers at December 31, 1997.
 
  In 1997, Products and Services revenues were $701.5 million, an increase of
$535.2 million from 1996. The increase was partially due to an additional
$274.4 million in gas energy marketing revenue resulting from increased sales
to existing customers and customer growth during 1997. NESI Power Marketing,
Inc., a wholly-owned subsidiary of Services, formed in December 1996 to market
wholesale electric power accounted for $167.5 million of additional energy
marketing revenue in 1997. Miller and SM&P contributed $95.6 million to
operating revenues since the March 1997 acquisition of IWCR. Products and
Services revenue in 1996 was $166.3 million, an increase of $119.3 million
from 1995. This increase was primarily due to increased volumes in gas energy
marketing.
 
                                       3

<PAGE>
 
  The components of the changes in operating revenues are shown in the
following table:
 
<TABLE>
<CAPTION>
                                                        YEAR 1997   YEAR 1996
                                                       COMPARED TO COMPARED TO
                                                        YEAR 1996   YEAR 1995
                                                       ----------- -----------
                                                            (IN MILLIONS)
   <S>                                                 <C>         <C>
   Gas Revenue
     Pass through of net changes in purchased gas
      costs, gas storage and storage transportation
      costs...........................................   $ 14.8      $ 55.3
     Gas transition costs.............................     (4.3)      (33.5)
     Changes in sales levels..........................     (6.6)       85.6
     Gas transported..................................      3.9         0.6
                                                         ------      ------
   Gas Revenue Change.................................      7.8       108.0
                                                         ------      ------
   Electric Revenue
     Pass through of net changes in fuel costs........      4.0         3.2
     Changes in sales levels..........................     (9.1)      (11.9)
                                                         ------      ------
   Electric Revenue Change............................     (5.1)       (8.7)
                                                         ------      ------
   Water Revenue Change...............................     60.7         --
                                                         ------      ------
   Products and Services Revenue
     Energy Marketing.................................    441.9        84.0
     Pipeline construction............................     47.2         --
     Locate and marking...............................     48.4         --
     Other............................................     (2.3)       35.3
                                                         ------      ------
   Products and Services
     Revenue Change...................................    535.2       119.3
                                                         ------      ------
       Total Operating Revenue Change.................   $598.6      $218.6
                                                         ======      ======
</TABLE>
 
  See Rate Matters in Notes to Consolidated Financial Statements regarding
FERC Order No. 636 transition costs.
 
  The basic steel industry accounted for 30% of natural gas delivered
(including volumes transported) and 33% of electric sales during 1997.
 
  The Energy Utilities' rate schedules for electric and gas service to their
customers contain an electric rate adjustment clause for changes in the cost
of fuel and firm purchases of electric energy; and gas rate adjustment clauses
to reflect changes in the cost of gas purchased, contracted gas storage and
storage transportation costs. (See Fuel Adjustment Clause and Gas Cost
Adjustment Clause under Summary of Significant Accounting Policies in Notes to
Consolidated Financial Statements.)
 
GAS COSTS
 
  The Energy Utilities' gas costs increased $11.5 million (2.3%) in 1997 due
to increased gas costs per dth, which were partially offset by decreased gas
transition costs. The average cost for the Energy Utilities purchased gas in
1997, after adjustment for gas transition costs billed to transport customers,
was $3.15 per dth as compared to $3.06 per dth in 1996. Gas costs increased
$84.6 million (21.2%) in 1996 due to increased purchases and increased gas
costs per dth, which were partially offset by decreased gas transition costs.
The average cost for the Energy Utilities purchased gas in 1996, after
adjustment for gas transition costs billed to transport customers, was $3.06
per dth as compared to $2.68 per dth in 1995.
 
                                       4

<PAGE>
 
FUEL AND PURCHASED POWER
 
  Cost of fuel for electric generation in 1997 increased mainly as a result of
increased production. The average cost per kwh generated decreased 2.3% from
1996 to 15.43 mills. The cost of fuel for electric generation in 1996
decreased mainly as a result of decreased production. The average cost per kwh
generated decreased 0.6% from 1995 to 15.79 mills.
 
  Power purchased decreased $16.5 million in 1997 as a result of decreased
bulk power purchases. Power purchased increased $10.1 million in 1996 as a
result of increased bulk power purchases and increased cost per megawatt
purchased.
 
COST OF PRODUCTS AND SERVICES
 
  The cost of sales for Products and Services increased $503.3 million in 1997
to $604.5 million. Nine months of operations at IWCR's non-regulated
subsidiaries increased cost of sales $67.2 million in 1997. Additionally,
increased energy marketing activities increased cost of sales $435.7 million
in 1997 compared to 1996. The cost of sales for Products and Services
increased $91.9 million in 1996 to $101.2 million. This increase reflects
primarily an increase in gas marketing activities.
 
OPERATING MARGINS
 
  Operating margins increased $95.0 million in 1997 to $1.211 billion. The gas
operating margin decreased $3.7 million in 1997 due to decreased sales to
residential and commercial customers reflecting milder weather, partially
offset by increased sales to wholesale customers and increased deliveries of
gas transported for others. Operating margin from electric sales increased
$6.0 million due to increased sales to residential and commercial customers,
and increased wholesale transactions, partially offset by decreased sales to
industrial customers. The Water Utilities contributed $60.7 million to
operating margin since the March 1997 acquisition of IWCR. Additionally,
Miller and SM&P increased Products and Services operating margin $28.4 million
during 1997. Operating margins increased $41.1 million in 1996 to $1.116
billion. The gas operating margin increased $23.3 million in 1996 due to
increased sales to residential and commercial customers reflecting colder
weather during the first quarter of 1996, increased sales to industrial and
wholesale customers and increased deliveries of gas transported for others.
Operating margin from electric sales decreased $9.6 million in 1996 due to
decreased sales to residential customers reflecting cooler summer weather in
1996 and decreased sales to industrial customers due to plant operational
difficulties at several major customers, which were partially offset by
increased sales to commercial and wholesale customers. Operating margin from
Products and Services increased $27.4 million in 1996 mainly due to improved
margins in gas production and gas marketing activities.
 
OPERATING EXPENSES AND TAXES
 
  Operating expenses and taxes (except income) in 1997 increased 9.6% from
1996 to $800.4 million and in 1996 increased 5.3% from 1995 to $729.7 million.
 
  Operation expenses increased $44.2 million in 1997 over 1996. Nine months of
operations at IWCR increased operation expenses $44.1 million in 1997.
Additionally, new operations at Primary and Services increased operation
expenses $8.4 million in 1997. These increases were partially offset by
reduced pension costs, environmental costs of $4.2 million and pollution
control facility costs of $4.1 million at Northern Indiana. Operation expenses
increased $3.3 million in 1996 over 1995 due to increased pollution control
facility costs, environmental costs of $5.9 million and other various
increased operating costs partially offset by reduced pension costs.
 
  Maintenance expenses increased $2.5 million in 1997 from 1996 mainly
reflecting nine months of maintenance at the Water Utilities. Maintenance
expenses decreased $4.7 million in 1996 from 1995 mainly reflecting decreased
maintenance activity at electric production facilities and gas underground
storage facilities.
 
                                       5

<PAGE>
 
  Depreciation and amortization expense increased $15.8 million in 1997 from
1996 resulting from plant additions, amortization of plant acquisition
adjustments and intangible assets. Depreciation and amortization expense
increased $27.0 million in 1996 from 1995 resulting from plant additions,
increased amortization of computer software and the amortization of deferred
costs related to scrubber services provided by Pure Air at the Bailly
Generating Station.
 
  Other Income (Deductions) increased $2.6 million in 1997 from 1996 mainly
resulting from the disposition of certain oil and natural gas properties
during the first quarter of 1997. Other Income (Deductions) increased $10.5
million in 1996 from 1995 mainly reflecting the sale of Crescent Dunes
Lakeshore property to the National Park Service.
 
  Interest and other charges increased $14.9 million and $8.4 million in 1997
and 1996, respectively. The 1997 increase reflects the issuance of $300
million of Capital Markets' medium-term notes and interest expense at IWCR.
The 1996 increase reflects the issuance of $169,275,000 of Northern Indiana's
Medium-Term Notes, Series D, and $75 million of Capital Markets' Junior
Subordinated Deferrable Interest Debentures, Series A, and the discontinuance
of carrying charges on deferred charges related to the Bailly Generating
Station scrubber service agreement.
 
  See Notes to Consolidated Financial Statements for a discussion of
accounting policies and transactions impacting this analysis.
 
ENVIRONMENTAL MATTERS
 
  The Utilities have an ongoing program to remain aware of laws and
regulations involved with hazardous waste and other environmental matters. The
Utilities intend to continue to evaluate their facilities and properties with
respect to these rules and identify any sites that would require corrective
action. The Utilities have recorded a reserve of approximately $20 million to
cover probable corrective actions as of December 31, 1997; however,
environmental regulations and remediation techniques are subject to future
change. The ultimate cost could be significant, depending on the extent of
corrective actions required. Based upon investigations and management's
understanding of current laws and regulations, the Utilities believe that any
corrective actions required, after consideration of insurance coverages and
contributions from other potentially responsible parties, will not have a
significant impact on the results of operations or financial position of
Industries.
 
  The Environmental Protection Agency (EPA) has notified Northern Indiana that
it is a "potentially responsible party" (PRP) under the Comprehensive
Environmental Response Compensation and Liability Act (CERCLA) and may be
required to share in the cost of cleanup of several waste disposal sites
identified by the EPA. The sites are in various stages of investigation,
analysis and remediation. At each of the sites, Northern Indiana is one of
several PRPs, and it is expected that remedial costs, as provided under
CERCLA, will be shared among them. At some sites, Northern Indiana and/or the
other named PRPs are presently working with the EPA to clean up the sites and
avoid the imposition of fines or added costs.
 
  Refer to Environmental Matters in Notes to Consolidated Financial Statements
for a more detailed discussion of the status of certain environmental issues.
 
LIQUIDITY AND CAPITAL RESOURCES
 
  During the next few years, it is anticipated that the great majority of
earnings available for distribution of dividends will depend upon dividends
paid to Industries by Northern Indiana. See Notes to Consolidated Financial
Statements for a discussion of the Common Share Dividend.
 
  Utility construction expenditures for 1997, 1996 and 1995 were approximately
$219 million, $208 million and $193 million, respectively. Industries' total
utility plant investment on December 31, 1997, was $6.4 billion.
 
                                       6

<PAGE>
 
  During 1997, Industries' non-utility subsidiaries acquired interests in
other properties and investments totaling approximately $38 million.
 
  On May 28, 1997, Northern Indiana was authorized to issue and sell up to
$217,692,000 of its Medium-Term Notes, Series E, with various maturities, for
purposes of refinancing certain first mortgage bonds and medium-term notes. As
of December 31, 1997, $139.0 million of the medium-term notes had been issued
with various interest rates and maturities. The proceeds from these issuances
were used to pay short-term debt incurred to redeem its First Mortgage Bonds,
Series N, and to pay at maturity various issues of Medium-Term Notes, Series
D.
 
  IWC's first mortgage bonds are secured by its utility plant. Provisions of
trust indentures related to the 8% Series Bonds require annual sinking or
improvement payments amounting to 1/2% of the maximum aggregate amount
outstanding. As permitted, this requirement has been satisfied by substituting
a portion of permanent additions to utility plant.
 
  On February 13, 1996, Capital Markets issued $75 million of 7 3/4% Junior
Subordinated Deferrable Interest Debentures, Series A, due March 31, 2026
(Debentures) pursuant to an underwritten public offering. Proceeds from the
sale of the Debentures were used to pay short-term debt incurred to redeem on
January 12, 1996 Industries' $35 million of 8.75% Preferred Shares, pursuant
to mandatory redemption, and to pay other short-term debt of Capital Markets.
 
  Between March 27, 1997 and May 7, 1997, Capital Markets issued and sold $300
million of medium-term notes with various interest rates and maturities. The
proceeds from these issuances were used for the purchase of IWCR and to pay
outstanding short-term obligations of Capital Markets.
 
  On December 1, 1997, Capital Markets issued $75 million of 6.78% Senior
Notes due December 1, 2027. Proceeds from the sale of these notes were
primarily used to pay Capital Markets' Zero Coupon Notes which matured
December 1, 1997. The remaining balance of the proceeds will be used for
Industries' general corporate purposes.
 
  Capital Markets has a $150 million revolving Credit Agreement which
terminates August 19, 1999. This facility provides short-term financing
flexibility to Industries and also serves as the back-up instrument for a
commercial paper program. As of December 31, 1997, there were no borrowings
outstanding under this agreement.
 
  Capital Markets also has $130 million of money market lines of credit. As of
December 31, 1997, $20.1 million of borrowings were outstanding under these
lines of credit.
 
  As of December 31, 1997, Capital Markets had $17.0 million in commercial
paper outstanding, having a weighted average interest rate of 7.00%.
 
  The obligations of Capital Markets are subject to a Support Agreement
between Industries and Capital Markets, under which Industries has committed
to make payments of interest and principal on Capital Markets' securities in
the event of a failure to pay by Capital Markets. Restrictions in the Support
Agreement prohibit recourse on the part of Capital Markets' investors against
the stock and assets of Northern Indiana. Under the terms of the Support
Agreement, in addition to the cash flow of cash dividends paid to Industries
by any of its consolidated subsidiaries, the assets of Industries, other than
the stock and assets of Northern Indiana, are available as recourse to holders
of Capital Markets' securities. The carrying value of the assets of
Industries, other than the stocks and assets of Northern Indiana, reflected in
the consolidated financial statements of Industries, is approximately $1.3
billion at December 31, 1997.
 
  Cash flow from operations has provided sufficient liquidity to meet current
operating requirements. Because of the seasonal nature of the utility business
and the construction program, Northern Indiana makes use of commercial paper
intermittently as short-term financing. As of December 31, 1997, Northern
Indiana had $71.5 million in commercial paper outstanding, having a weighted
average interest rate of 6.16%.
 
                                       7

<PAGE>
 
  Northern Indiana has a $250 million revolving Credit Agreement with several
banks which terminates August 19, 1999. As of December 31, 1997, there were no
borrowings outstanding under this agreement. In addition, Northern Indiana has
$14.2 million in lines of credit which run to May 31, 1998. The credit pricing
of each of the lines varies from either the lending banks' commercial prime or
market rates. Northern Indiana has agreed to compensate the participating
banks with arrangements that vary from no commitment fees to a combination of
fees which are mutually satisfactory to both parties. As of December 31, 1997,
there were no borrowings under these lines of credit. The Credit Agreement and
lines of credit are also available to support the issuances of commercial
paper.
 
  Northern Indiana also has $273.5 million of money market lines of credit. As
of December 31, 1997, $47.5 million of borrowings were outstanding under these
lines of credit.
 
  Northern Indiana has a $50 million uncommitted finance facility. At December
31, 1997, there were no borrowings outstanding under this facility.
 
  IWCR and its subsidiaries have lines of credit with banks aggregating $73.7
million. At December 31, 1997, $48.9 million of borrowings were outstanding
under these lines of credit.
 
  During recent years, Northern Indiana has been able to finance its
construction program with internally generated funds and expects to be able to
meet future commitments through such funds.
 
  The Utilities do not expect the effects of inflation at current levels to
have a significant impact on their results of operations, ability to contain
cost increases, or need to seek timely and adequate rate relief. The Energy
Utilities do not anticipate the need to file for gas and electric base rate
increases in the near future.
 
MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS
 
  The primary market risks to which Industries is exposed and in connection
with which Industries uses market risk sensitive instruments are commodity
price risk and interest rate risk.
 
  Industries engages in price risk management activities related to
electricity and natural gas. Price risk arises from fluctuations in energy
commodity prices due to changes in supply and demand. Industries actively
monitors and limits its exposure to commodity price risk. Industries' price
risk management policy allows the use of derivative financial and commodity
instruments to reduce (hedge) exposure to price risk of its supply and related
purchase and sales commitments of energy, as well as related anticipated
transactions. As part of this commodity price risk, Industries is exposed to
geographic price differentials due primarily to transportation costs and local
supply-demand factors. Industries uses basis swaps to hedge a portion of this
exposure. For economic reasons or otherwise, Industries does not hedge all of
its basis exposure.
 
  Industries enters into certain sales contracts with customers based upon a
fixed sales price and varying volumes which are ultimately dependent upon the
customer's supply requirements. Industries utilizes financial instruments to
reduce the commodity price risk based on modeling techniques to anticipate
these future supply requirements. Industries continues to be exposed to price
risk for the difference between the ultimate supply requirements and those
modeled.
 
  Although the Energy Utilities are subject to commodity price risk as part of
their traditional operations, the current regulatory framework within which
the Energy Utilities operate allows for full collection of fuel and gas costs
in rate-making. Consequently, there is limited commodity price risk after
consideration of the related rate-making. However, as the utility industry
deregulates, Energy Utilities will be providing services without the benefit
of the traditional rate-making allowances and will therefore be more exposed
to commodity price risk.
 
  Because the commodities covered by Industries' derivative financial and
commodity instruments are substantially the same commodities that Industries
buys and sells in the physical market, no special correlation studies other
than monitoring the degree of convergence between the derivative and cash
markets are deemed necessary.
 
                                       8

<PAGE>
 
  Industries' daily net commodity position consists of natural gas
inventories, commodity purchase and sales contracts and derivative financial
and commodity instruments. The fair value of such positions is a summation of
the fair values calculated for each commodity by valuing each net position at
quotes from exchanges and over-the-counter markets and includes location
differentials. Based on Industries' net commodity position at fair value at
December 31, 1997, a 10% adverse movement in electric and natural gas market
prices would have reduced net income by approximately $2.3 million. However,
any such movements in prices is not indicative of actual results and is
subject to change. Refer to Summary of Significant Accounting Policies--
Hedging Activities for further discussion of Industries' hedging policies.
 
  Industries utilizes long-term debt as a primary source of capital in its
business. A significant portion of Industries' long-term debt consists of
medium-term notes, the interest component of which resets on a periodic basis
to reflect current market conditions. The Utilities utilize longer term fixed
price debt instruments which have been and will be refinanced at lower
interest rates if Industries deems it to be economical. Refer to Consolidated
Statement of Long-term Debt for detailed information related to Industries'
long-term debt outstanding and Fair Value of Financial Instruments in Notes to
Consolidated Financial Statements for current market valuation of long-term
debt.
 
YEAR 2000 COSTS
 
  Industries has several major projects underway to modify portions of its
systems for proper functioning in the year 2000. These include a project to
evaluate Industries' proprietary software and to work with each of Industries'
software vendors to assure that appropriate steps are being taken to mitigate
the problem in each vendor's software or, in some cases, to replace software
with year 2000 compliant software; a project to identify and mitigate problems
wherever they exist in Industries' systems ranging from equipment used in
Northern Indiana's generating stations to Industries' phone system that have
date information within them; and an initiative to assure that each entity
that electronically receives information from Industries or sends information
to Industries is aware of the steps that Industries is taking and is taking
appropriate steps of its own to address the problem. Consistent with its plan,
Industries expects to be year 2000 compliant with some systems as early as
third quarter 1998 and other systems no later than the third quarter of 1999.
  Costs related to maintenance or modification of Industries' systems have
been and will be expensed as incurred. Industries estimates that costs to
become year 2000 compliant will be approximately $10-$15 million, including
acquisition costs of new systems which will be capitalized consistent with
Industries' accounting policies. Industries does not anticipate the related
costs to have a material impact on its results of operations, nor does
Industries anticipate any disruption of its ability to deliver service as a
result of the year 2000 issue.
 
COMPETITION
 
  The Energy Policy Act of 1992 (Energy Act) allows FERC to order electric
utilities to grant access to transmission systems by third-party power
producers. The Energy Act specifically prohibits federally mandated wheeling
of power for retail customers. On April 24, 1996, FERC issued its Order No.
888-A which opens wholesale power sales to competition and requires public
utilities owning, controlling, or operating transmission lines to file non-
discriminatory open access tariffs that offer others the same transmission
service they provide themselves. Northern Indiana filed its tariff as did
virtually all other transmission owners subject to FERC jurisdiction. Order
No. 888-A also provides for the full recovery of stranded costs--that is,
costs that were prudently incurred to serve power customers and that could go
unrecovered if these customers use open access to move to another supplier.
FERC expects this rule will accelerate competition and bring lower prices and
more choices to wholesale energy customers. On November 25, 1997, FERC issued
Order No. 888-B on rehearing, affirming in all important respects its earlier
Order No. 888-A. Although wholesale customers represent a relatively small
portion of Northern Indiana's sales, Northern Indiana will continue its
efforts to retain and add customers by offering competitive rates.
 
  In January 1997, legislation was introduced in the Indiana General Assembly
addressing electric utility competition and deregulation. This proposed
legislation was not adopted. Legislation similar to the 1997 electric
 
                                       9

<PAGE>
 
restructuring legislation was introduced in January 1998. Northern Indiana has
begun discussions with other utilities and its largest customers on the
technical and economic aspects of possible legislation to allow customer
choice. Operating in a competitive environment will place added pressures on
utility profit margins and credit quality. Increasing competition in the
electric utility industry has already led the credit rating agencies to apply
more stringent guidelines in making credit rating determinations.
 
  Competition within the electric utility industry will create opportunities
to compete for new customers and revenues, as well as increase the risk of the
loss of customers. Industries' management has taken steps to make the company
more competitive and profitable in the changing utility environment, including
partnering on energy projects with major industrial customers and conversions
of some of its generating units to allow use of lower cost, low sulfur coal.
 
  FERC Order No. 636 shifted primary responsibility for gas acquisition,
transportation and peak days' supply from pipelines to local gas distribution
companies such as the Energy Utilities. Although pipelines continue to
transport gas, they no longer provide sales service. The Energy Utilities
believe they have taken appropriate steps to ensure the continued acquisition
of adequate gas supplies at reasonable prices.
 
  The mix of gas revenues from retail sales, interruptible retail sales, firm
transportation service and interruptible transportation services has changed
significantly over the past several years. The deregulation of the gas
industry, since the mid-1980s, allows large industrial and commercial
customers to purchase their gas supplies directly from producers and use the
Energy Utilities' facilities to transport the gas. Transportation customers
pay the Energy Utilities only for transporting their gas from the pipeline to
the customers' premises.
 
  Northern Indiana filed a petition for an Alternative Regulatory Plan (ARP)
with the Commission on November 29, 1995. Following negotiation and settlement
with major intervenors, Northern Indiana submitted a modified ARP to the
Commission on May 9, 1997. In its modified ARP, Northern Indiana proposed to
implement new rates and services that would include, among other things,
further unbundling of services for additional customer classes, increased
customer choice for sources of natural gas supply, negotiated services and
prices, an incentive gas cost mechanism and a price protection program. On
October 8, 1997, the Commission issued an order approving, in all respects,
the modified ARP which became effective November 1, 1997. The first pilot
program was launched in January 1998 and the first gas volumes will flow under
this program by March 1998. Significantly, the Commission order allows the
natural gas marketing affiliate of Northern Indiana to participate as a
supplier in this pilot and in future expansions of supplier choice to other
customers on the Northern Indiana system. On October 28, 1997, ERI Services,
Inc. and Enron Capital and Trade Resources Corp. filed Petitions for Rehearing
of the October 8, 1997 order. Northern Indiana expects a Commission decision
on these Petitions during the first quarter of 1998.
 
  To date, the Energy Utilities' system has not been materially affected by
competition, and management does not foresee substantial adverse effects in
the near future, unless the current regulatory structure is substantially
altered. The Energy Utilities believe the steps they are taking to deal with
increased competition will have significant, positive effects in the next few
years.
 
FORWARD LOOKING STATEMENTS
 
  This Annual Report contains forward looking statements within the meaning of
the securities laws. Industries cautions that, while it believes such
statements to be based on reasonable assumptions and makes such statements in
good faith, there can be no assurance that the actual results will not differ
materially from such assumptions or that the expectations set forth in the
forward looking statements derived from such assumptions will be realized.
Investors should be aware of important factors that could have a material
impact on future results. These factors include, but are not limited to,
weather, the federal and state regulatory environment, the economic climate,
regional, commercial, industrial and residential growth in the service
territories served by Industries' subsidiaries, customers' usage patterns and
preferences, the speed and degree to which competition enters the utility
industries, the timing and extent of changes in commodity prices, changing
conditions in the capital and equity markets and other uncertainties, all of
which are difficult to predict, and many of which are beyond the control of
Industries.
 
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