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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
X Annual Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the fiscal year ended December 31, 1999
OR
() Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ________________ to ________________
Commission file number 1-4125
NORTHERN INDIANA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Indiana 35-0552990
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5265 Hohman Avenue, Hammond, Indiana 46320-1775
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (219) 853-5200
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
--------------------- ---------------------
Series A Cumulative Preferred - No Par Value New York
4-1/4% Cumulative Preferred - $100 Par Value American
Securities registered pursuant to Section 12(g) of the Act:
Cumulative Preferred Stock - $100 Par Value
(4-1/2%, 4.22%, 4.88%, 7.44% and 7.50% Series)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months, (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 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)
As of February 29, 2000, 73,282,258 shares of the registrant's
Common Shares, no par value, were issued and outstanding, all held
beneficially and of record by NiSource Inc.
DOCUMENTS INCORPORATED BY REFERENCE
None
NORTHERN INDIANA PUBLIC SERVICE COMPANY
Form 10-K
Table of Contents
Page
====
PART I
Item 1 Business 2
2 Properties 8
3 Legal Proceedings 8
4 Submission of Matters to a Vote
of Security Holders 9
PART II
Item 5 Market for the Registrant's Common
Equity and Related Shareholder Matters 9
6 Selected Financial Data 9
7 Management's Discussion and Analysis of
Financial Condition and Results of Operation 10
7a Quantitative and Qualitative Disclosures About
Market Risk 18
8 Financial Statements and Supplementary Data 18
9 Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 53
PART III
Item 10 Directors and Executive Officers of
the Registrant 54
11 Executive Compensation 56
12 Security Ownership of Certain Beneficial
Owners and Management 64
13 Certain Relationships and Related Transactions 64
PART IV
Item 14 Exhibits, Financial Statement Schedules 64
and Reports on Form 8-K
SIGNATURES 67
NORTHERN INDIANA PUBLIC SERVICE COMPANY
Part I
ITEM 1. BUSINESS.
Northern Indiana Public Service Company (Northern Indiana) is a public
utility operating company, incorporated in Indiana on August 2, 1912, that
supplies natural gas and electric energy to the public. It operates in 30
counties in the northern part of Indiana, serving an area of about 12,000
square miles with a population of approximately 2.2 million. At December 31,
1999, Northern Indiana served approximately 681,100 customers with gas and
approximately 425,800 customers with electricity.
See "Segments of Business" in the Notes to Consolidated Financial
Statements regarding financial information about industry segments.
HOLDING COMPANY STRUCTURE. Effective March 3, 1988, Northern Indiana
became a subsidiary of NiSource Inc. (NiSource), formerly NIPSCO Industries,
Inc., an Indiana corporation. NIPSCO Industries, Inc. changed its name to
NiSource Inc. on April 14, 1999 to reflect its new direction as a multi-state
supplier of energy and water resources and related services.
ELECTRIC OPERATIONS. Northern Indiana owns and operates four
coal-fired electric generating stations with net capabilities of 3,179,000
kilowatts (kw), two hydroelectric generating plants with net capabilities of
10,000 kw and four gas-fired combustion turbine generating units with net
capabilities of 203,000 kw, for a total system net capability of 3,392,000 kw.
During the year ended December 31, 1999, Northern Indiana generated 89.9% and
purchased 10.1% its electric requirements.
Northern Indiana's 1999 electric control area peak load (the highest
level of electrical utility usage in the control area) of 3,307,340 kw was
set on July 30, 1999. Northern Indiana's electric control area includes
Northern Indiana, Wabash Valley Power Association, Inc. (WVPA) and Indiana
Municipal Power Agency (IMPA). The 1999 peak established a new all time peak
exceeding the old peak of 3,161,200 kw previously set on July 14, 1995.
Northern Indiana's 1999 internal peak load, which excludes WVPA and IMPA, of
2,962,340 kw was also set on July 30, 1999. This also established a new
all-time internal peak load exceeding the old peak of 2,888,450 kw previously
set on August 6, 1996.
Northern Indiana's electric system is interconnected with the systems
of Ameren Services Corporation (formerly Central Illinois Public Service
Company), American Electric Power, Commonwealth Edison Company (ComEd),
Cinergy Services, Inc. and Consumers Energy. Electric energy is purchased from,
sold to, or exchanged with various other utilities and power marketers under
Northern Indiana's power sales and open access transmission tariffs.
Northern Indiana provides WVPA with transmission and distribution service,
operating reserve requirements and capacity deficiency service and provides
IMPA with transmission service, operating reserve requirements and capacity
deficiency service, in Northern Indiana's control area. Northern Indiana also
engages in sales and services under interconnection agreements with WVPA and
IMPA.
WVPA provides service to 12 Rural Electric Membership Corporations
(REMC's) located in Northern Indiana's control area. IMPA provides service to
the municipal electric system of the city of Rensselaer located in Northern
Indiana's control area.
Northern Indiana and WVPA have executed a supplemental agreement for unit
peaking capacity and energy. Unit peaking capacity is the capacity used to
serve peak demand from a specific peaking generating unit. Pursuant to this
agreement, which runs through December 2001, WVPA purchases 90,000 kw of
capacity per month.
Northern Indiana serves the Town of Argos as a full requirement customer
and provides network integration service to seven other municipal wholesale
customers.
Northern Indiana is a member of the East Central Area Reliability
Coordination Agreement (ECAR). ECAR is one of nine regional electric
reliability councils established to coordinate planning and operations of
member electric utilities regionally and nationally.
FUEL SUPPLY. The generating units of Northern Indiana are located at
Bailly, Mitchell, Michigan City and Schahfer Generating Stations. Northern
Indiana's 13 steam generating units have a net capability of 3,179,000 kw.
Coal is the primary source of fuel for all units, except for three, which
utilize natural gas. In addition, Northern Indiana's four combustion turbine
generating units with a net capability of 203,000 kw are fired by gas. Fuel
requirements for Northern Indiana's generation for 1999 was supplied as
follows:
Coal 97.9%.
Natural gas 2.1%
In 1999, Northern Indiana used approximately 9.0 million tons of coal
at its generating stations. Northern Indiana has established a normal level
of coal stock that is expected to provide adequate fuel supply during the year.
Annual coal requirements for Northern Indiana's electric generating
units through 2003 are estimated to range from 9.4 million tons to 9.7
million tons, depending from year to year upon anticipated sales levels,
scheduled maintenance and other variables. These requirements are being met
or will be met in part under long-term contracts as follows:
MILLION TONS/YEAR SULFUR CONTENT EXPIRATION
================= ============== ==========
1.300(a) Low 2001
1.600(b) Low 2002
1.000(c) Low 2001
0.500(d) Low 2000
0.432(e) Low 2002
1.000(f) High 2000
0.600 High 2004
0.500(g) High 2001
(a) 1.3 million tons in 2000; 0.25 million tons in 2001.
(b) 1.6 million tons in 2000; plus or minus 10% option years in 2001 and 2002.
Northern Indiana can terminate 12/31/2000 or 12/31/2001.
(c) 0.8 million to 1.2 million tons in 2000 and 2001.
(d) Option year in 2000.
(e) Option to purchase an additional 0.432 million tons in 2000 and 2001; 0.864
million tons in 2002.
(f) 1.0 million tons in 2000.
(g) 0.75 million tons in 2000 and 2001.
The average cost of coal consumed in 1999 was $26.13 per ton, or 1.47
cents per kilowatt-hour (kwh) generated as compared to $26.83 per ton, or
1.52 cents per kwh generated in 1998.
COAL RESERVES. Included in the previous table of coal contracts is a
coal mining contract with Cyprus Shoshone Coal Corporation (Cyprus) under
which Cyprus is mining Northern Indiana's coal reserves in the Cyprus mine
through the year 2001. The costs of such reserves are being recovered through
the rate-making process as such coal reserves are used to produce electricity.
FUEL ADJUSTMENT CLAUSE. Northern Indiana adjusts metered electric rates
through operation of a fuel adjustment clause to reflect changes in fuel costs.
See "Summary of Significant Accounting Policies-Fuel Adjustment Clause" in the
Notes to Consolidated Financial Statements.
GAS OPERATIONS. Northern Indiana supplies natural gas of about 1,000
British thermal units (Btu) per cubic foot. In a 24-hour period ended
January 5, 1999, Northern Indiana's 1999 maximum day send-out (the maximum
amount of gas delivered through Northern Indiana's distribution system to its
end customers) was 1.7 million dekatherms (dth). Northern Indiana's total
gas send-out for 1999 was 282.5 million dth, compared to 266.0 million dth in
1998.
Agreements have been negotiated with natural gas suppliers to replace
former pipeline supplier contracts pursuant to the requirements of Federal
Energy Regulatory Commission (FERC) Order No. 636. Northern Indiana also has
agreements which allow for the purchase of gas either from gas marketers or
producers.
Northern Indiana has firm transportation agreements with pipelines, which
allow Northern Indiana to move its gas through the pipelines' transmission
systems. In 1999, all of the gas supplied by Northern Indiana was transported
by ANR Pipeline Company (ANR), Crossroads Pipeline Company (Crossroads), a
subsidiary of NiSource, Midwestern Gas Transmission Company (Midwestern),
Natural Gas Pipeline Company of America (Natural), Panhandle Eastern Pipe Line
Company (Panhandle), Tennessee Gas Pipeline Company (Tennessee) and Trunkline
Gas Company (Trunkline). The transportation rates of Crossroads and the
transportation and storage rates of ANR, Midwestern, Natural, Panhandle,
Tennessee and Trunkline to Northern Indiana are subject to change in
accordance with rate proceedings filed with the FERC.
Approximately 77% of Northern Indiana's 1999 gas supply was purchased on
the spot market, generally on less than 30-day agreements. The average price
per dth (including FERC Order No. 636 transition charges) in 1999 was $2.56,
compared to $2.49 in 1998, and the average cost of purchased gas, after
adjustment for transition charges billed to transport customers, was $2.58 per
dth, as compared to $2.48 per dth in 1998.
Northern Indiana has a curtailment plan (a plan which outlines service
to be curtailed in the event of limited gas supply) that has been approved by
the Indiana Utility Regulatory Commission (IURC). There were no firm sales
curtailments in 1999 and none are expected during 2000.
Northern Indiana operates an underground gas storage field at Royal
Center, Indiana, which currently has a storage capacity of 6.75 million dth.
Withdrawals were made in the 1999-2000 winter of up to 103,126 dth per day.
In addition, Northern Indiana has several gas storage service agreements
which make possible the withdrawal of substantial quantities of gas from
other storage facilities. All of the storage agreements have limitations on
the volume and timing of daily withdrawals. These contracts provide in the
aggregate for approximately 29.6 million dth of annual stored volume and
allow for approximately 661,000 dth of maximum daily withdrawal.
Northern Indiana has a liquefied natural gas plant in LaPorte County
which is designed for peak shaving (the process of supplementing gas supply
during periods of high demand) and has the following capacities: maximum
storage of 4 million dth; maximum liquefaction rate (gas to liquid), 20,000
dth per day; maximum vaporization rate (output to distribution system),
300,000 dth per day.
GAS COST ADJUSTMENT CLAUSE. Metered gas sales are adjusted to reflect
the cost of purchased gas, contracted gas storage and storage transportation
charges. See "Summary of Significant Accounting Policies-Gas Cost Adjustment
Clause" in the Notes to Consolidated Financial Statements.
REGULATION. Northern Indiana is subject to regulation by the Commission
as to rates, service, accounts, issuance of securities, and in other respects.
It is also subject to limited regulation by local public authorities.
In 1999, about 7% of Northern Indiana's electric revenues were derived
from electric service it furnished at wholesale in interstate commerce to
other utility companies, power marketers, municipalities and WVPA (see "Item 1.
Business-Electric Operations" regarding WVPA). Northern Indiana's wholesale
rates and operations are subject to the jurisdiction of the FERC. FERC
jurisdiction does not extend to the issuance of securities by Northern Indiana,
which are regulated by the IURC. The FERC on October 21, 1954, declared
Northern Indiana exempt from the provisions of the Natural Gas Act.
RATE MATTERS. For a description of Northern Indiana's Alternative
Regulatory Plan (ARP) see "Competition and Regulatory Changes" below.
On January 27, 2000, the Citizens Action Coalition (CAC), a private
consumer organization, filed a petition before the Indiana Utility Regulatory
Commission (IURC). The petition does not seek a specified amount of rate
reduction, but rather alleges that the existing electric rates are "unreasonable
and unsafe," and seeks to have the IURC force Northern Indiana to produce
detailed financial calculations that would justify its electric rates. Northern
Indiana intends to oppose the petition on both legal and factual grounds, and
believes that its current rates are just and reasonable as required by statue.
COMPETITION AND REGULATORY CHANGES -
The regulatory frameworks applicable to Northern Indiana, at both state
and federal levels, are undergoing fundamental changes. These changes have
impacted and will continue to have an impact on Northern Indiana's operations,
structure and profitability. At the same time, competition within the electric
and gas industries will create opportunities to compete for new customers and
revenues. Management has taken steps to become more competitive and profitable
in this changing environment, including converting some of its generating units
to allow use of lower cost, low sulfur coal, providing its gas customers with
increased customer choice for new products and services throughout the service
territory.
THE ELECTRIC INDUSTRY. At the Federal level, the FERC issued Order No.
888-A in 1996 which required all public utilities owning, controlling, or
operating transmission lines to file non-discriminatory open-access tariffs and
offer wholesale electricity suppliers and marketers the same transmission
service they provide themselves. In 1997, FERC approved Northern Indiana's
open-access transmission tariff. On December 20, 1999, FERC issued a final rule
addressing the formation and operation of Regional Transmission Organizations
(RTOs). The rule is intended to eliminate pricing inequities in the provision
of wholesale transmission service. Northern Indiana does not believe that
compliance with the new rules will be material to future earnings. Although
wholesale customers currently represent a small portion of Northern Indiana's
electricity sales, it intends to continue its efforts to retain and add
wholesale customers by offering competitive rates and also intends to expand the
customer base for which it provides transmission services.
At the state level, Northern Indiana announced in 1997 and 1998 that if a
consensus could be reached regarding electric utility restructuring legislation,
Northern Indiana would support a restructuring bill before the Indiana General
Assembly. During 1999, discussions were held with other investor-owned
utilities in Indiana regarding the technical and economic aspects of possible
legislation leading to greater customer choice. A consensus was not reached.
Therefore, Northern Indiana did not support legislation regarding electric
restructuring during the 2000 session of the Indiana General Assembly. During
2000, discussions will continue with all segments of the Indiana electric
industry in an attempt to reach a consensus on electric restructuring
legislation for introduction during the 2001 session of the Indiana General
Assembly.
THE GAS INDUSTRY. At the Federal level, gas industry deregulation began
in the mid-1980's when FERC required interstate pipelines to provide
nondiscriminatory transportation services pursuant to unbundled rates. This
regulatory change permitted large industrial and commercial customers to
purchase their gas supplies either from Northern Indiana or directly from
competing producers and marketers, which would then use Northern Indiana's
facilities to transport the gas. More recently, the focus of deregulation in
the gas industry has shifted to the states.
At the state level, the IURC approved in 1997 Northern Indiana's
Alternative Regulatory Plan (ARP), which implemented new rates and services that
included, among other things, unbundling of services for additional customer
classes (primarily residential and commercial users), negotiated services and
prices, a gas cost incentive mechanism, and a price protection program. The gas
cost incentive mechanism allows Northern Indiana to share any cost savings or
cost increases with its customers based upon a comparison of Northern Indiana's
actual gas supply portfolio cost to a market-based benchmark price. Phase I of
Northern Indiana's Customer Choice Pilot Program ended on March 31, 1999. This
pilot program offered 82,000 residential customers within St. Joseph County
and 10,000 commercial customers throughout the Northern Indiana service area the
right to choose alternative gas suppliers. Phase II of Northern Indiana's
Customer Choice Pilot Program commenced on April 1, 1999 and will continue for
a one-year period. During this phase, Northern Indiana is offering customer
choice to all 660,000 residential and 50,000 commercial customers throughout its
gas service territory. A limit of 150,000 residential and 20,000 commercial
customers are eligible to enroll in Phase II of the program. The IURC order
allows a specific NiSource natural gas marketing subsidiary to participate as a
supplier of choice to Northern Indiana customers. In addition, as Northern
Indiana has allowed residential and commercial customers to designate
alternative gas suppliers, it has also offered new services to all classes of
customers including, price protection, negotiated sales and services, gas
lending and parking, and new storage services.
To date, Northern Indiana 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. Northern
Indiana believes the steps that it has taken to deal with increased competition
have had and will continue to have significant positive effects in the next few
years.
EMPLOYEES. Northern Indiana had 3,077 employees at December 31, 1999.
Approximately 70% of Northern Indiana's employees (physical and clerical
workers) are represented by two local unions of the United Steelworkers of
America, AFL-CIO-CLC.
ENVIRONMENTAL MATTERS. The operations of Northern Indiana are subject
to extensive and evolving federal, state and local environmental laws and
regulations intended to protect the public health and the environment. Such
environmental laws and regulations affect Northern Indiana's operations as
they relate to impacts on air, water and land.
Refer to "Environmental Matters" in Notes to Consolidated Financial
Statements for more information regarding certain environmental issues.
In a March 3, 2000 decision, the United States Court of Appeals for the
D. C. Circuit ruled largely in favor of Environmental Protection Agency's
regional nitrogen oxides (NOx) plan. An appeal of this decision is expected.
The State of Indiana in February 2000 proposed a moderate NOx control plan
designed to address Indiana's ozone nonattainment areas and regional ozone
transport.
Northern Indiana's total capital expenditures from January 1, 1995,
through December 31, 1999 for pollution control facilities were approximately
$116 million and were financed in part by the sale of Northern Indiana's
Pollution Control Notes and Bonds-Jasper County. Northern Indiana anticipates
expenditures of approximately $244 million for pollution control equipment in
the 2000-2004 period which includes anticipated expenditures of $6 million in
2000 and $65 million in 2001.
YEAR 2000 COSTS. For a discussion of year 2000 costs see Management's
Discussion and Analysis of Financial Condition and Results of Operations-Year
2000 Costs.
FORWARD LOOKING STATEMENTS. This report contains forward looking
statements within the meaning of the securities laws. See Management's
Discussion and Analysis of Financial Condition and Results of Operations-
Forward Looking Statements.
ITEM 2. PROPERTIES.
The physical properties of Northern Indiana are located in the State
of Indiana.
ELECTRIC. Northern Indiana owns and operates four coal fired electric
generating stations with net capabilities of 3,179,000 kw, two hydroelectric
generating plants with net capabilities of 10,000 kw, and four gas fired
combustion turbine generating units with net capabilities of 203,000 kw, for
a total system net capability of 3,392,000 kw.
Northern Indiana has 291 substations with an aggregate transformer
capacity of 23,036,200 kilovolts (kva). Its transmission system with
voltages from 34,500 to 345,000 consists of 3,068 circuit miles of line. The
electric distribution system extends into 21 counties and consists of 7,800
circuit miles of overhead and 1,571 cable miles of underground primary
distribution lines operating at various voltages from 2,400 to 12,500 volts.
Northern Indiana has distribution transformers having an aggregate capacity of
11,367,093 kva and 445,377 electric watt-hour meters.
GAS. Northern Indiana has an underground storage field at Royal Center
and a liquefied natural gas plant in LaPorte County all of which are described
under "Item 1. Business-Gas Operations". Northern Indiana has 13,924 miles of
gas mains.
CHARACTER OF OWNERSHIP. Substantially all of the properties of Northern
Indiana are subject to the lien of its First Mortgage Indenture. The principal
properties are held in fee and are free from other encumbrances, subject to
minor exceptions, none of which are of such a nature as to impair substantially
the usefulness of such properties. All properties are subject to liens for
taxes, assessments and undetermined charges (if any) incidental to construction.
It is Northern Indiana's practice regularly to pay such amounts, as and when
due, unless contested in good faith. In general, the electric and gas lines and
mains are located on land not owned in fee but are covered by necessary consents
of various governmental authorities or by appropriate rights obtained from
owners of private property. Northern Indiana does not, however, generally have
specific easements from the owners of the property adjacent to public highways
over, upon, or under which its electric and gas lines are located. At the time
each of the principal properties was purchased a title search was made. In
general, no examination of titles as to rights-of-way for electric and gas lines
and mains was made, other than examination, in certain cases, to verify the
grantors' ownership and the lien status thereof.
ITEM 3. LEGAL PROCEEDINGS.
Northern Indiana is a party to various pending proceedings, including
suits and claims against it for personal injury, death and property damage.
Such proceedings and suits, and the amounts involved are routine for the kind
of business conducted by Northern Indiana, except as set forth above and under
"Environmental Matters," in the Notes to Consolidated Financial Statements.
No other material legal proceedings against Northern Indiana or its subsidiaries
are pending or, to the knowledge of Northern Indiana contemplated by
governmental authorities or other parties.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS.
Northern Indiana's common shares are wholly-owned by NiSource.
The following limitations on payment of dividends and issuance of
preferred stock apply to Northern Indiana:
When any bonds are outstanding under its First Mortgage Indenture,
Northern Indiana may not pay cash dividends on its stock (other than
preferred or preference stock) or purchase or retire common shares, except
out of earned surplus or net profits computed as required under the
provisions of the maintenance and renewal fund. At December 31, 1999,
Northern Indiana had approximately $136.1 million of retained earnings
(earned surplus) available for the payment of dividends. Future common
share dividends by Northern Indiana will depend upon adequate retained
earnings, adequate future earnings and the absence of adverse developments.
So long as any shares of Northern Indiana's cumulative preferred stock
are outstanding, no cash dividends shall be paid on its common shares in
excess of 75% of the net income available therefor for the preceding
calendar year unless the aggregate of the capital applicable to stocks
subordinate as to assets and dividends to the cumulative preferred stock
plus the surplus, after giving effect to such dividends, would equal or
exceed 25% of the sum of all obligations evidenced by bonds, notes,
debentures or other securities, plus the total capital and surplus. At
December 31, 1999, the sum of the capital applicable to stocks subordinate
to the cumulative preferred stock plus the surplus was equal to 43% of the
total capitalization including surplus.
In connection with the foregoing discussion, see "Common Share
Dividend" in the Notes to Consolidated Financial Statements.
ITEM 6. SELECTED FINANCIAL DATA.
Year Ended December 31,
(Dollars in thousands)
1999 1998 1997 1996 1995
========== ========== ========== ========== ==========
Operating revenues $1,752,219 $1,648,603 $1,752,382 $1,754,105 $1,664,278
Net income $ 222,111 $ 220,180 $ 196,620 $ 197,310 $ 194,321
Total assets $3,655,454 $3,651,949 $3,674,914 $3,774,280 $3,606,199
Long-term
obligations and
redeemable
preferred stock $ 974,443 $1,134,394 $1,138,337 $1,053,254 $1,122,392
Cash dividends
declared on
common shares $ 224,000 $ 212,000 $ 187,775 $ 187,450 $ 185,725
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
NET INCOME. For 1999, net income of Northern Indiana increased to
$222.1 million, compared to $220.2 million for 1998. In 1997, net income
was $196.6 million.
GAS REVENUES. Gas revenues were $644.7 million in 1999, an increase of
$72.2 million from 1998. This increase in gas revenues was mainly due to
increased deliveries to residential customers as a result of colder weather
during 1999, increased wholesale sales and increased gas costs per dekatherms
(dth), partially offset by decreased deliveries to commercial and industrial
customers and decreased gas transition costs. During 1999, gas deliveries in
dth, which include transportation services, increased 10%. Gas deliveries to
residential customers increased 13% reflecting 12% higher heating degree-days
than 1998. Gas deliveries to commercial and industrial customers increased 6%
and 4%, respectively, reflecting increased gas transportation services.
Northern Indiana had 681,120 gas customers at December 31, 1999.
Gas revenues were $572.5 million in 1998, a decrease of $162.8 million
from 1997. The decrease in gas revenues was mainly due to decreased gas sales
to residential and commercial customers, decreased gas costs per dth and
decreased gas transition costs. During 1998, gas deliveries in dth, which
include transportation services, decreased 1%. Gas deliveries to residential
and commercial customers decreased 20% and 16%, respectively, reflecting
heating degree-days 21% lower than 1997, partially offset by increased
deliveries to industrial customers of 4% and increased wholesale gas sales.
Large commercial and industrial customers continue to utilize
transportation services provided by Northern Indiana. 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 Northern
Indiana's system. Northern Indiana transported 184.9, 173.2 and 160.4 million
dth for others in 1999, 1998 and 1997, respectively. The basic steel industry
accounted for 39% of natural gas delivered (including volumes transported)
during 1999.
The components of the changes in gas operating revenues are shown in the
following table:
Year 1999 Year 1998
Compared To Compared To
Year 1998 Year 1997
============ ============
(Dollars in millions)
Gas Revenue Changes -
Pass through of net changes in
purchased gas costs, gas storage
and storage transportation costs $ 15.6 $ (63.0)
Gas transition costs (4.5) (21.7)
Changes in sales levels 21.7 (91.6)
Gas transported 6.2 6.8
Wholesale gas 33.2 6.7
------------ ------------
Total Gas Revenue Change $ 72.2 $ (162.8)
============ ============
GAS COSTS OF ENERGY. Gas costs increased $58.6 million (18%) in 1999 due
to increased gas purchases and increased purchased gas costs per dth, partially
offset by decreased gas transition costs. The average cost for purchased gas in
1999, after adjustment for gas transition costs billed to transport customers,
was $2.58 per dth as compared to $2.48 per dth in 1998. Gas costs decreased
$131.4 million (29%) in 1998 due to decreased gas purchases, decreased gas
transition costs and decreased gas costs per dth. The average cost for
purchased gas in 1998, after adjustment for gas transition costs billed to
transport customers, was $2.48 per dth as compared to $3.08 per dth in 1997.
GAS OPERATING MARGINS. The gas operating margin increased $13.7 million
in 1999 due to increased deliveries to residential customers reflecting colder
weather during 1999, increased wholesale sales and increased deliveries of
gas transported for others, partially offset by decreased deliveries to
commercial customers. The gas operating margin decreased $31.4 million in 1998
due to decreased deliveries to residential and commercial customers reflecting
the warmer heating season, partially offset by increased sales to wholesale
customers and increased deliveries of gas transported for others.
ELECTRIC REVENUES. Electric revenues were $1.107 billion, an increase of
$31.4 million from 1998. Sales of electricity in kilowatt-hours (kwh) increased
7% from 1998. The increase in electric revenues was mainly due to increased
sales to residential and commercial customers due to warmer weather during the
third quarter of 1999, increased industrial sales and increased wholesale
transactions. Sales to residential and commercial customers increased 2% and 4%
in kwh, respectively, reflecting the warmer summer in 1999. At December 31,
1999, Northern Indiana had 425,835 electric customers.
In 1998, electric revenues were $1.076 billion, an increase of $59.0
million from 1997. Sales of electricity in kwh increased 7% from 1997. The
increase in electric revenues was mainly due to increased sales to residential
and commercial customers (increases of 8% and 6% in kwh, respectively),
reflecting a significantly warmer summer in 1998. Wholesale power transactions
also increased significantly in a rapidly developing market. The increases were
partially offset by a 2% kwh reduction in sales to industrial customers,
reflecting a full year of operations at two cogeneration projects located at
major industrial customers' facilities. The basic steel industry accounted for
29% of electric sales during 1999.
The components of the changes in electric operating revenues are shown in
the following table:
Year 1999 Year 1998
Compared To Compared To
Year 1998 Year 1997
============ ============
(Dollars in millions)
Electric Revenue Changes -
Pass through of net changes
in fuel costs $ 5.6 $ (9.3)
Changes in sales levels 38.3 17.0
Wholesale electric (12.5) 51.3
------------ ------------
Total Electric Revenue Change $ 31.4 $ 59.0
============ ============
ELECTRIC COST OF ENERGY. Cost of fuel for electric generation in
1999 decreased $1.5 million compared to 1998 primarily due to decreased fuel
costs per kwh generated. The average cost per kwh generated decreased 3% from
1998 to 1.47 cents per kwh. Cost of fuel for electric generation in 1998
increased mainly as a result of increased production. The average cost per kwh
generated decreased 3% from 1997 to 1.50 cents per kwh.
POWER PURCHASED. Power purchased increased $25.0 million in 1999 as a
result of increased bulk power purchases. Power purchased decreased $4.7
million in 1998 as a result of decreased bulk power purchases.
ELECTRIC OPERATING MARGINS. Operating margin from electric sales
increased $7.9 million in 1999. This increase occurred mainly due to increased
sales to residential and commercial as a result of warmer weather during the
third quarter of 1999, increased industrial sales and increased wholesale
transactions. Operating margin from electric sales in 1998 increased $42.2
million due to increased sales to residential and commercial customers,
reflecting a significantly warmer summer in 1998 than in 1997, and increased
wholesale transactions, partially offset by decreased sales to industrial
customers.
OPERATING EXPENSES AND TAXES (EXCEPT INCOME). Operating expenses and
taxes (except income) in 1999 increased $17.6 million from 1998 and in 1998
decreased $20.9 million from 1997.
Operation expenses increased $10.6 million in 1999 over 1998 due to
increased employee related costs of $15.6 million, increased expenses for
distributed generation and fuel cell research and development of $1.9 million
and other increased operating costs partially offset by a $13 million insurance
settlement related to manufactured gas plants site cleanup costs. Operation
expenses decreased $23.4 million in 1998 over 1997 due to decreased employee
related costs of $11.7 million, decreased sales and marketing activities of $5.7
million and decreased electric production operating costs of $4.3 million.
Maintenance expenses remained relatively unchanged in 1999 from 1998.
Maintenance expenses decreased $3.6 million in 1998 from 1997 mainly reflecting
decreased maintenance activity for electric production and distribution
facilities.
Depreciation and amortization expenses increased $5.0 million in 1999
from 1998 resulting from plant additions. Depreciation and amortization
expenses increased $5.5 million in 1998 from 1997 resulting from plant
additions.
Utility income taxes increased $6.5 million and $10.7 million in 1999 and
1998, respectively, when compared to the prior period mainly as a result of
increased pre-tax income.
Other Income (Deductions) increased $1.3 million in 1999 from 1998 mainly
as a result of increased power trading activities, partially offset by Northern
Indiana deciding to abandon certain business facilities that were not consistent
with its strategic direction. Other Income (Deductions) remained relatively
unchanged in 1998 from 1997.
Interest charges decreased $3.2 million and $2.5 million in 1999 and 1998,
respectively. The 1999 and 1998 decreases reflect decreased short-term
borrowing during the year.
LIQUIDITY AND CAPITAL RESOURCES. Generally, cash flow from operations
has provided sufficient liquidity to meet current operating requirements.
Because the utility and utility construction business is seasonal in nature,
commercial paper is issued for short-term financing. As of December 31, 1999
and December 31, 1998, $62.6 million and $85.6 million in commercial paper was
outstanding, respectively. The weighted average interest rate on commercial
paper outstanding as of December 31, 1999 was 6.53%.
Northern Indiana entered into a five-year $100 million credit agreement
and a 364-day $100 million revolving credit agreement with several banks.
These agreements terminate on September 23, 2003 and September 23, 2000,
respectively. The 364-day agreement may be extended at expiration for
additional periods of 364-days. Under these agreements, funds are borrowed at
a floating rate of interest or, under certain circumstances, at a fixed rate
of interest for short-term periods. These agreements provide financing
flexibility and may be used to support the issuance of commercial paper. At
December 31, 1999 and 1998, there were no borrowings outstanding under these
agreements.
In addition, Northern Indiana has $11.4 million in lines of credit which
run until May 31, 2000. The credit pricing of each of the lines varies from
either the lending banks' commercial prime or market rates. As of
December 31, 1999, there were no borrowings under these lines of credit. The
credit agreements and lines of credit are also available to support the
issuance of commercial paper.
Northern Indiana also has $220 million of money market lines of credit.
As of December 31, 1999 and December 31, 1998, $33.7 million and $40.5
million of borrowings were outstanding, respectively, under these lines of
credit.
Construction expenditures by Northern Indiana for 1999, 1998 and 1997
were approximately $193 million, $182 million and $174 million, respectively.
Northern Indiana's total utility plant investment on December 31, 1999, was
$5.9 billion. 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.
On January 27, 2000, the Citizens Action Coalition (CAC), a private
consumer organization, filed a petition before the Indiana Utility Regulatory
Commission (IURC). The petition does not seek a specified amount of rate
reduction, but rather alleges that the existing electric rates are "unreasonable
and unsafe," and seeks to have the IURC force Northern Indiana to produce
detailed financial calculations that would justify its electric rates. Northern
Indiana is opposing the petition on both legal and factual grounds, and believes
that its current rates are just and reasonable as required by statue.
MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS -
RISK MANAGEMENT
Risk is an inherent part of Northern Indiana's energy businesses and
activities. The extent to which Northern Indiana properly and effectively
identifies, assesses, monitors and manages each of the various types of risk
involved in its businesses is critical to its profitability. Northern Indiana
seeks to identify, assess, monitor and manage, in accordance with defined
policies and procedures, the following principal risks involved in Northern
Indiana's energy businesses: commodity market risk, interest rate risk and
credit risk. Risk management at Northern Indiana is a multi-faceted process
with independent oversight that requires constant communication, judgment and
knowledge of specialized products and markets. Northern Indiana's senior
management takes an active role in the risk management process and has
developed policies and procedures that require specific administrative and
business functions to assist in the identification, assessment and control of
various risks. In recognition of the increasingly varied and complex nature
of the energy business, Northern Indiana's risk management policies and
procedures are evolving and subject to ongoing review and modification.
Northern Indiana is exposed to risk through various daily business
activities, including specific trading risks and non-trading risks. The non-
trading risks to which Northern Indiana is exposed include interest rate risk
and commodity price risk. The market risk resulting from trading activities
consists primarily of commodity price risk. Northern Indiana's risk
management policy permits the use of certain financial instruments to manage
its market risk, including futures, forwards, options and swaps. Risk
management at Northern Indiana is defined as the process by which the
organization ensures that the risks to which it is exposed are the risks to
which it desires to be exposed to achieve its primary business objectives.
Northern Indiana employs various analytic techniques to measure and monitor
its market risks, including value-at-risk (VaR) and instrument sensitivity to
market factors. VaR represents the potential loss for an instrument or
portfolio from adverse changes in market factors, for a specified time period
and at a specified confidence level.
TRADING RISKS
COMMODITY MARKET RISK. Market risk refers to the risk that a change in
the level of one or more market prices, rates, indices, volatilities,
correlations or other market factors, such as liquidity, will result in losses
for a specified position or portfolio. Northern Indiana employs a VaR model
to assess the market risk of all open derivative financial instruments.
Northern Indiana estimates the one-day VaR across all trading groups which
utilize derivatives using either Monte Carlo simulation or variance/covariance
at a 95 percent confidence level. Based on the results of the VaR analysis,
the daily market risk exposure for power trading on an average, high, and low
basis was $0.4, $1.2 and $0.014 million during 1999, respectively.
Northern Indiana implemented a VaR methodology in 1999 to introduce
additional market sophistication and to recognize the developing complexity of
its businesses.
NON-TRADING RISKS
COMMODITY MARKET RISK. Currently, commodity price risk resulting from
non-trading activities is relatively limited, since current regulations allow
Northern Indiana to recoup any prudently incurred fuel and gas costs through
rate-making. As the utility industry undergoes deregulation, however,
Northern Indiana will be providing services without the benefit of the
traditional rate-making and, therefore, will be more exposed to commodity
price risk. Additionally, Northern Indiana 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.
Northern Indiana utilizes derivative financial instruments to reduce the
commodity price risk based on modeling techniques to anticipate these future
supply requirements.
INTEREST RATE RISK. Long-term debt is utilized as a primary source of
capital. A significant portion of this long-term debt consists of medium-term
notes. In addition, longer term fixed-price debt instruments have been used
that in the past have been refinanced when interest rates decreased. To the
extent that such refinancing is economical, refinancing these fixed-price
instruments will continue.
CREDIT RISK. Credit risk arises in many of Northern Indiana's business
activities. In sales and trading activities, credit risk arises because of
the possibility that a counterparty will not be able or willing to fulfill
its obligations on a transaction on or before settlement date. In derivative
activities, credit risk arises when counterparties to derivative contracts,
such as interest rate swaps, are obligated to pay Northern Indiana the
positive fair value or receivable resulting from the execution of contract
terms. Exposure to credit risk is measured in terms of both current and
potential exposure. Current credit exposure is generally measured by the
notional or principal value of financial instruments and direct credit
substitutes, such as commitments and standby letters of credit and guarantees.
Current credit exposure includes the positive fair value of derivative
instruments. Because many of Northern Indiana's exposures vary with changes in
market prices, Northern Indiana also estimates the potential credit exposure
over the remaining term of transactions through statistical analyses of market
prices. In determining exposure, Northern Indiana considers collateral and
master netting agreements, which are used to reduce individual counterparty
risk, primarily in connection with derivative products.
Refer to Consolidated Statement of Long-Term Debt for detailed information
related to Northern Indiana's long-term debt outstanding and "Fair Value of
Financial Instruments" in Notes to Consolidated Financial Statements for current
market valuation of long-term debt. Refer to "Summary of Significant Accounting
Policies-Accounting for Price Risk Management Activities" for further discussion
of Northern Indiana's risk management.
YEAR 2000 COSTS -
RISKS. "Year 2000 issues" were concerned with the ability of electronic
processing equipment to process date sensitive information and recognize the
last two digits of a date as occurring in or after the year 2000. Any failure
in any system could have resulted in material operational and financial risks.
Possible scenarios included a system failure in a generating plant, an operating
disruption or delay in transmission or distribution of gas, electricity, or an
inability to interconnect with the systems of other utilities. Failure to
achieve year 2000 readiness could have had a material adverse effect on results
of operations, financial position and cash flow.
The program to address risks associated with the year 2000 on both
information technology (IT) and non-IT systems was completed in a timely manner.
STATE OF READINESS. The Northern Indiana year 2000 program consisted of
four phases: inventory (identifying systems potentially affected by the year
2000),assessment(testing identified systems), remediation (correcting or
replacing non-compliant systems) and validation (evaluating and testing
remediated systems to confirm compliance). All phases were completed in a
timely manner.
Because Northern Indiana depends on outside suppliers and vendors with
similar year 2000 issues, the ability of those suppliers and vendors to provide
an uninterrupted supply of goods and services was assessed. Critical vendors and
suppliers were contacted in order to investigate their year 2000 efforts. In
addition, electricity and gas industry groups such as the North American
Electric Reliability Council, the Electric Power Research Institute and the
American Gas Association were helpful in evaluating the potential impact of year
2000 problems upon the electric grid systems and pipeline networks.
COSTS. The total cost of the Northern Indiana year 2000 program was
approximately $19 million. These costs were funded from operations. Costs
related to the maintenance or modification of existing systems were expensed as
incurred. Costs related to the acquisition of replacement systems were
capitalized. These costs did not have a material impact on results of
operations.
CONTINGENCY PLANS. Northern Indiana developed its contingency plans to
address the possibility that any mission-critical system would be non-compliant.
This includes identifying alternative suppliers and vendors, conducting staff
training and developing communication plans. In addition, Northern Indiana
evaluated the ability to maintain or restore service in the event of a power
failure or operating disruption or delay, along with the limited ability to
mitigate the effects of a network failure by isolating its own network from the
non-compliant segments of the greater network. These contingency plans were
completed during the second quarter 1999. They were not needed for the century
rollover.
RESULTS. Northern Indiana did not experience any system failures a result
of the year 2000 issue.
COMPETITION AND REGULATORY CHANGES -
The regulatory frameworks applicable to Northern Indiana, at both state
and federal levels, are undergoing fundamental changes. These changes have
impacted and will continue to have an impact on Northern Indiana's operations,
structure and profitability. At the same time, competition within the electric
and gas industries will create opportunities to compete for new customers and
revenues. Management has taken steps to become more competitive and profitable
in this changing environment, including converting some of its generating units
to allow use of lower cost, low sulfur coal and providing its gas customers
with increased customer choice for new products and services throughout the
service territory.
THE ELECTRIC INDUSTRY. At the Federal level, the FERC issued Order No.
888-A in 1996 which required all public utilities owning, controlling, or
operating transmission lines to file non-discriminatory open-access tariffs and
offer wholesale electricity suppliers and marketers the same transmission
service they provide themselves. In 1997, FERC approved Northern Indiana's
open-access transmission tariff. On December 20, 1999, FERC issued a final rule
addressing the formation and operation of Regional Transmission Organizations
(RTOs). The rule is intended to eliminate pricing inequities in the provision
of wholesale transmission service. Northern Indiana does not believe that
compliance with the new rules will be material to future earnings. Although
wholesale customers currently represent a small portion of Northern Indiana's
electricity sales, it intends to continue its efforts to retain and add
wholesale customers by offering competitive rates and also intends to expand
the customer base for which it provides transmission services.
At the state level, Northern Indiana announced in 1997 and 1998 that if a
consensus could be reached regarding electric utility restructuring legislation,
Northern Indiana would support a restructuring bill before the Indiana General
Assembly. During 1999, discussions were held with other investor-owned
utilities in Indiana regarding the technical and economic aspects of possible
legislation leading to greater customer choice. A consensus was not reached.
Therefore, Northern Indiana did not support legislation regarding electric
restructuring during the 2000 session of the Indiana General Assembly. During
2000, discussions will continue with all segments of the Indiana electric
industry in an attempt to reach a consensus on electric restructuring
legislation for introduction during the 2001 session of the Indiana General
Assembly.
THE GAS INDUSTRY. At the Federal level, gas industry deregulation began
in the mid-1980's when FERC required interstate pipelines to provide
nondiscriminatory transportation services pursuant to unbundled rates. This
regulatory change permitted large industrial and commercial customers to
purchase their gas supplies either from Northern Indiana or directly from
competing producers and marketers, which would then use Northern Indiana's
facilities to transport the gas. More recently, the focus of deregulation in
the gas industry has shifted to the states.
At the state level, the IURC approved in 1997 Northern Indiana's
Alternative Regulatory Plan (ARP), which implemented new rates and services that
included, among other things, unbundling of services for additional customer
classes (primarily residential and commercial users), negotiated services and
prices, a gas cost incentive mechanism, and a price protection program. The gas
cost incentive mechanism allows Northern Indiana to share any cost savings or
cost increases with its customers based upon a comparison of Northern Indiana's
actual gas supply portfolio cost to a market-based benchmark price. Phase I of
Northern Indiana's Customer Choice Pilot Program ended on March 31, 1999. This
pilot program offered 82,000 residential customers within St. Joseph County
and 10,000 commercial customers throughout the Northern Indiana service area the
right to choose alternative gas suppliers. Phase II of Northern Indiana's
Customer Choice Pilot Program commenced on April 1, 1999 and will continue for
a one-year period. During this phase, Northern Indiana is offering customer
choice to all 660,000 residential and 50,000 commercial customers throughout its
gas service territory. A limit of 150,000 residential and 20,000 commercial
customers are eligible to enroll in Phase II of the program. The IURC order
allows a specific NiSource natural gas marketing subsidiary to participate as a
supplier of choice to Northern Indiana customers. In addition, as Northern
Indiana has allowed residential and commercial customers to designate
alternative gas suppliers, it has also offered new services to all classes of
customers including, price protection, negotiated sales and services, gas
lending and parking, and new storage services.
To date, Northern Indiana 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. Northern
Indiana believes the steps that it has taken to deal with increased competition
have had and will continue to have significant positive effects in the next few
years.
IMPACT OF ACCOUNTING STANDARDS. Refer to "Summary of Significant
Accounting Policies-Impact of Accounting Standards" in the Notes to the
Consolidated Financial Statements for information regarding impact of accounting
standards not yet adopted.
FORWARD LOOKING STATEMENTS. This report contains forward looking
statements within the meaning of the securities laws. Forward looking
statements include terms such as "may," "will," "expect," "believe," "plan"
and other similar terms. Northern Indiana cautions that, while it believes
such statements to be based on reasonable assumptions and makes such statements
in good faith, you cannot be assured 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.
You should be aware of important factors that could have a material impact on
future results. These factors include, weather, the federal and state
regulatory environment, the economic climate, regional, commercial, industrial
and residential growth in the service territories served by Northern Indiana,
customers' usage patterns and preferences, the speed and degree to which
competition enters the utility industry, 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 Northern Indian's control.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For a discussion of primary market risks and risk management policy,
see "Management's Discussion and Analysis of Financial Condition and Results
of Operations-Market Risk Sensitive Instruments and Positions."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pages
=========
Report of Independent Public Accountants 19-20
Consolidated Statement of Income for the years
ended December 31, 1999, 1998, and 1997 20-21
Consolidated Balance Sheet - December 31, 1999
and 1998 21-23
Consolidated Statement of Capitalization -
December 31, 1999 and 1998 23-25
Consolidated Statement of Long-term Debt -
December 31, 1999 and 1998 25-26
Consolidated Statement of Cash Flows for the
years ended December 31, 1999, 1998, and 1997 26-27
Consolidated Statement of Retained Earnings for
the years ended December 31, 1999, 1998, and 1997 27-28
Notes to Consolidated Financial Statements 28-53
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO THE BOARD OF DIRECTORS OF
NORTHERN INDIANA PUBLIC SERVICE COMPANY:
We have audited the accompanying consolidated balance sheet and
consolidated statements of capitalization and long-term debt of Northern
Indiana Public Service Company (an Indiana corporation and a wholly-owned
subsidiary of NiSource Inc.) and subsidiaries as of December 31, 1999 and 1998,
and the related consolidated statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1999. These
consolidated financial statements and the schedule referred to below are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements and schedule based on our
audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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 consolidated financial statements referred to
above present fairly, in all material respects, the financial position of
Northern Indiana Public Service Company and subsidiaries as of December 31,
1999 and 1998, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1999, in conformity
with accounting principles generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed on page 64,
Item 14(a)(2) is presented for purposes of complying with the Securities and
Exchange Commission's rules and is not part of the basic financial statements.
This schedule has been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion, fairly states
in all material respects the financial data required to be set forth therein
in relation to the basic financial statements taken as a whole.
/s/ Arthur Andersen LLP
Chicago, Illinois
February 19, 2000
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31, 1999 1998 1997
========== ========== ==========
(Dollars in thousands)
Operating Revenues:
(Notes 2 and 20)
Gas $ 644,687 $ 572,485 $ 735,299
Electric 1,107,532 1,076,118 1,017,083
---------- ---------- ----------
1,752,219 1,648,603 1,752,382
---------- ---------- ----------
Cost of Energy: (Note 2)
Gas costs 379,609 321,033 452,436
Fuel for electric generation 249,164 250,649 238,548
Power purchased 66,964 41,990 37,274
---------- ---------- ----------
695,737 613,672 728,258
---------- ---------- ----------
Operating Margin 1,056,482 1,034,931 1,024,124
---------- ---------- ----------
Operating Expenses and
Taxes (except income):
Operation 256,474 245,920 269,275
Maintenance (Note 2) 65,462 65,302 68,853
Depreciation and
amortization (Note 2) 233,555 228,547 223,025
Taxes (except income) 74,163 72,227 71,752
---------- ---------- ----------
629,654 611,996 632,905
---------- ---------- ----------
Operating Income Before
Utility Income Taxes 426,828 422,935 391,219
---------- ---------- ----------
Utility Income Taxes (Note 4) 127,267 120,786 110,099
---------- ---------- ----------
Operating Income 299,561 302,149 281,120
---------- ---------- ----------
Other Income (Deductions)(Note 2) (2,248) (3,589) (3,659)
---------- ---------- ----------
Interest:
Interest on long-term debt 67,695 69,672 69,427
Other interest 3,352 4,524 7,220
Amortization of premium, reacquisition
premium, discount and expense on
debt, net 4,155 4,184 4,194
---------- ---------- ----------
75,202 78,380 80,841
---------- ---------- ----------
Net Income 222,111 220,180 196,620
Dividend requirements on
preferred stocks 8,131 8,335 8,539
---------- ---------- ----------
Balance available
for common shares $ 213,980 $ 211,845 $ 188,081
========== ========== ==========
Common dividends declared $ 224,000 $ 212,000 $ 187,775
========== ========== ==========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 1998
=========== ===========
(Dollars in thousands)
ASSETS
UTILITY PLANT, at original cost (including
construction work in progress of
$200,011 and $149,426, respectively)
(Note 2):
Electric $ 4,237,427 $ 4,154,060
Gas 1,323,528 1,272,483
Common 381,486 364,822
----------- -----------
5,942,441 5,791,365
Less - Accumulated provision for
depreciation and amortization 2,993,412 2,804,720
----------- -----------
Total Utility Plant 2,949,029 2,986,645
----------- -----------
OTHER PROPERTY AND INVESTMENTS 2,668 519
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents 6,145 19,541
Accounts receivable, less reserve of
$7,804 and $4,458, respectively (Note 2) 141,537 104,445
Fuel adjustment clause (Note 2) 4,201 0
Gas cost adjustment clause (Note 2) 36,787 44,044
Materials and supplies, at average cost 52,735 51,554
Electric production fuel, at average cost 31,968 32,402
Natural gas in storage, at last-in,
first-out cost (Note 2) 22,966 50,859
Prepayments and other 60,285 31,056
----------- -----------
Total Current Assets 356,624 333,901
----------- -----------
OTHER ASSETS:
Regulatory assets (Note 2) 186,080 203,722
Prepayments and other (Note 6) 161,053 127,162
----------- -----------
Total Other Assets 347,133 330,884
----------- -----------
$ 3,655,454 $ 3,651,949
=========== ===========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1999 1998
=========== ===========
(Dollars in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common shareholder's equity $ 1,008,131 $ 1,018,150
Preferred stocks (Note 7) -
Series without mandatory
redemption provisions (Note 8) 81,114 81,116
Series with mandatory
redemption provisions (Note 9) 54,030 56,435
Long-term debt, excluding amounts due
within one year (Note 13) 920,413 1,077,959
----------- -----------
Total capitalization 2,063,688 2,233,660
----------- -----------
CURRENT LIABILITIES:
Current portion of long-term debt 158,000 2,000
(Note 14)
Short-term borrowings (Note 15) 96,290 126,100
Accounts payable 129,532 142,414
Dividends declared on common and
preferred stocks 59,017 63,101
Customer deposits 24,264 20,178
Taxes accrued 115,761 88,401
Interest accrued 7,392 9,118
Fuel adjustment clause 0 6,279
Accrued employment costs 51,393 44,223
Other accruals 76,163 28,546
----------- -----------
Total current liabilities 717,812 530,360
----------- -----------
OTHER:
Deferred income taxes (Note 4) 592,022 608,935
Deferred investment tax credits, being
amortized over life of related property
(Note 4) 85,566 92,693
Deferred credits 47,105 48,084
Accrued liability for postretirement
benefits (Note 6) 137,211 127,115
Other noncurrent liabilities 12,050 11,102
----------- -----------
Total other 873,954 887,929
----------- -----------
COMMITMENTS AND CONTINGENCIES:
(Notes 3, 16 and 17)
$ 3,655,454 $ 3,651,949
=========== ===========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31, 1999 1998
=========== ===========
(Dollars in thousands)
COMMON SHAREHOLDER'S EQUITY:
Common shares - without par
value - authorized 75,000,000
shares - issued and outstanding
73,282,258 shares $ 859,488 $ 859,488
Additional paid-in capital 12,525 12,524
Retained earnings 136,118 146,138
----------- -----------
Total common shareholder's
equity 1,008,131 48.9% 1,018,150 45.6%
----------- -----------
PREFERRED STOCKS, WHICH ARE
REDEEMABLE SOLELY AT OPTION
OF NORTHERN INDIANA:
Cumulative preferred stock -
$100 par value -
4-1/4% series - 209,035 and
209,051 shares outstanding,
respectively 20,903 20,905
4-1/2% series - 79,996
shares outstanding 8,000 8,000
4.22% series - 106,198
shares outstanding 10,620 10,620
4.88% series - 100,000
shares outstanding 10,000 10,000
7.44% series - 41,890
shares outstanding 4,189 4,189
7.50% series - 34,842
shares outstanding 3,484 3,484
Premium on preferred stock 254 254
Cumulative preferred stock -
no par value -
Adjustable Rate (6.00% at
December 31, 1999) -
Series A (stated value -
$50 per share), 473,285
shares outstanding 23,664 23,664
----------- -----------
81,114 3.9% 81,116 3.6%
----------- -----------
REDEEMABLE PREFERRED STOCKS,
SUBJECT TO MANDATORY REDEMPTION
REQUIREMENTS OR WHOSE
REDEMPTION IS OUTSIDE THE
CONTROL OF NORTHERN INDIANA:
Cumulative preferred stock -
$100 par value -
8.85% series - 37,500 and
50,000 shares outstanding,
respectively 3,750 5,000
7-3/4% series - 27,798 and
33,352 shares outstanding,
respectively 2,780 3,335
8.35% series - 45,000 and
51,000 shares outstanding,
respectively 4,500 5,100
Cumulative preferred stock -
no par value -
6.50% series - 430,000
shares outstanding 43,000 43,000
----------- -----------
54,030 2.6% 56,435 2.5%
----------- -----------
LONG-TERM DEBT 920,413 44.6% 1,077,959 48.3%
----------- ------ ----------- ------
Total capitalization $ 2,063,688 100.0% $ 2,233,660 100.0%
=========== ====== =========== ======
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED STATEMENT OF LONG-TERM DEBT
DECEMBER 31, 1999 1998
=========== ===========
(Dollars in thousands)
FIRST MORTGAGE BONDS -
Series T, 7-1/2%, due April 1, 2002 $ 38,500 $ 39,000
Series NN, 7.10%, due July 1, 2017 55,000 55,000
----------- -----------
Total 93,500 94,000
----------- -----------
POLLUTION CONTROL NOTES AND BONDS -
Series A Note -
City of Michigan City, 5.70% due
October 1, 2003 14,000 16,500
Series 1988 Bonds - Jasper County -
Series A, B and C - 4.06% weighted
average at December 31, 1999, due
November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County -
Series D - 4.04% weighted average at
December 31, 1999, due November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County -
Series A - 4.80% at December 31, 1999
due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County -
Series B - 4.80% at December 31, 1999,
due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County -
Series C - 4.80% at December 31, 1999,
due April 1, 2019 41,000 41,000
----------- -----------
Total 237,000 239,500
----------- -----------
MEDIUM-TERM NOTES -
Interest rates between 6.50% and 7.69%
with a weighted average interest rate of
7.05% and various maturities between
August 15, 2001 and August 4, 2027 593,025 748,025
----------- -----------
UNAMORTIZED PREMIUM AND DISCOUNT
ON LONG-TERM DEBT, NET (3,112) (3,566)
----------- -----------
Total long-term debt, excluding
amounts due in one year $ 920,413 $ 1,077,959
=========== ===========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 1999 1998 1997
=========== =========== ===========
(Dollars in thousands)
CASH FLOWS FROM
OPERATING ACTIVITIES:
Net income $ 222,111 $ 220,180 $ 196,620
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 233,555 228,547 223,025
Deferred federal and state
operating income taxes, net (19,496) (32,574) (8,414)
Deferred investment tax
credits, net (7,126) (7,160) (7,205)
Other, net (4,905) 1,900 1,900
Change in certain assets and
liabilities -
Accounts receivable, net (31,165) (4,194) 10,678
Electric production fuel 434 (13,565) 7,646
Materials and supplies (1,181) 2,112 3,130
Natural gas in storage 27,893 (4,979) 4,529
Accounts payable (10,240) 16,247 (51,273)
Taxes accrued 36,540 24,119 21,488
Fuel adjustment clause (10,480) 8,958 6,470
Gas cost adjustment clause 7,257 42,476 11,647
Accrued employment costs 7,170 (6,872) 10,180
Other accruals 19,593 (5,505) 6,117
Other, net (13,424) (11,380) 21,799
----------- ----------- -----------
Net cash provided by
operating activities 456,536 458,310 458,337
----------- ----------- -----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (192,838) (182,123) (174,231)
Other, net (6,155) (7,195) (3,191)
----------- ----------- -----------
Net cash used in investing
activities (198,993) (189,318) (177,422)
----------- ----------- -----------
CASH FLOWS PROVIDED BY
(USED IN) FINANCING
ACTIVITIES:
Issuance of long-term debt 0 500 139,000
Issuance of short-term debt 657,047 622,200 534,430
Net change in commercial paper (23,035) 14,100 (122,405)
Retirement of long-term debt (3,000) (51,509) (67,247)
Retirement of short-term debt (663,822) (629,200) (565,930)
Retirement of preferred stock (2,407) (2,413) (2,408)
Cash dividends paid on
common shares (228,000) (205,000) (185,775)
Cash dividends paid on
preferred shares (8,176) (8,392) (8,556)
Other, net 454 463 (503)
----------- ----------- -----------
Net cash used in
financing activities (270,939) (259,251) (279,394)
----------- ----------- -----------
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS (13,396) 9,741 1,521
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 19,541 9,800 8,279
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 6,145 $ 19,541 $ 9,800
=========== =========== ===========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
YEAR ENDED DECEMBER 31, 1999 1998 1997
========= ========= =========
(Dollars in thousands)
BALANCE AT BEGINNING OF PERIOD $ 146,138 $ 146,293 $ 145,987
ADD:
NET INCOME 222,111 220,180 196,620
--------- --------- ---------
368,249 366,473 342,607
--------- --------- ---------
LESS:
DIVIDENDS:
Cumulative Preferred stock -
4-1/4% series 888 889 889
4-1/2% series 360 360 360
4.22% series 448 448 448
4.88% series 488 488 488
7.44% series 312 312 312
7.50% series 261 261 261
8.85% series 461 571 682
7-3/4% series 276 319 362
8.35% series 422 472 522
6.50% series 2,795 2,795 2,795
Adjustable Rate, series A 1,420 1,420 1,420
Common shares 224,000 212,000 187,775
--------- --------- ---------
232,131 220,335 196,314
--------- --------- ---------
BALANCE AT END OF PERIOD $ 136,118 $ 146,138 $ 146,293
========= ========= =========
The accompanying notes to consolidated financial statements are an
integral part of this statement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) HOLDING COMPANY STRUCTURE: NiSource Inc.(NiSource), formerly NIPSCO
Industries, Inc., was incorporated in Indiana on September 22, 1987 and became
the parent of Northern Indiana Public Service Company (Northern Indiana) on
March 3, 1988. NIPSCO Industries, Inc. changed its name to NiSource Inc.
on April 14, 1999 to reflect its new direction as a multi-state supplier
of energy and water resources and related services. Northern Indiana is a
public utility operating company supplying electricity and gas to the public
in the northern third of Indiana.
Northern Indiana is subject to regulation with respect to rates,
accounting and certain other matters which are governed by the Indiana
Utility Regulatory Commission (IURC) and the Federal Energy Regulatory
Commission (FERC), collectively called the "Commissions."
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION. The Consolidated Financial Statements include
the accounts of Northern Indiana and subsidiaries, after the elimination of all
significant intercompany items. Certain reclassifications were made to conform
the prior years' financial statements to the current presentation.
USE OF ESTIMATES. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities 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.
OPERATING REVENUES. Revenues are recorded based on service rendered,
but are billed to customers monthly on a cycle basis.
DEPRECIATION AND MAINTENANCE. Northern Indiana provides depreciation
on a straight-line method over the remaining service lives of the electric,
gas and common properties. The approximate weighted average remaining lives
for major components of electric and gas plant are as follows:
Electric:
--------
Electric generation plant 24 years
Transmission plant 26 years
Distribution plant 25 years
Other electric plant 24 years
Gas:
----
Gas storage plant 18 years
Transmission plant 34 years
Distribution plant 27 years
Other gas plant 24 years
The depreciation provision for electric utility plant, as a percentage
of the original cost, was 3.7% for 1999 and 3.6% for 1998 and 1997.
The depreciation provision for gas utility plant, as a percentage
of the original cost, was 5.4% for 1999, 1998 and 1997.
Northern Indiana follows the practice of charging maintenance and
repairs, including the cost of removal of minor items of property, to expense
as incurred. When property that represents a retirement unit is replaced or
removed, the cost of such property is credited to utility plant, and such cost,
together with the cost of removal less salvage, is charged to the accumulated
provision for depreciation.
AMORTIZATION OF SOFTWARE COSTS. External and incremental internal costs
associated with computer software developed for internal use are capitalized.
Capitalization of such costs commences upon the completion of the preliminary
stage of the project. Once the installed software is ready for its intended
use, such capitalized costs are amortized on a straight-line basis over a
period of five to ten years which the FERC prescribes as reasonable useful
life estimates for capitalized software.
COAL RESERVES. The costs of reserves under a long-term mining contract
to mine coal reserves through the year 2001 are being recovered through the
rate-making process as such coal reserves are used to produce electricity.
ACCOUNTS RECEIVABLE. At December 31, 1999, $100 million of accounts
receivable had been sold under a sales agreement, which expires May 31, 2002.
The December 31, 1999 and 1998 accounts receivable balance include approximately
$14.0 million and $11.6 million respectively, due from associated companies.
COMPREHENSIVE INCOME. Northern Indiana adopted Statement of Financial
Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income"
effective January 1, 1998. This statement established standards for reporting
and display of comprehensive income and its components in a financial
statement that is displayed with the same prominence as other financial
statements. The adoption of this statement did not impact Northern
Indiana's consolidated financial statements for the periods presented.
STATEMENT OF CASH FLOWS. Temporary cash investments with an original
maturity of three months or less are considered to be cash equivalents.
Cash paid during the periods reported for income taxes and interest
was as follows:
1999 1998 1997
======== ======== ========
(Dollars in thousands)
Income taxes $125,580 $135,145 $104,809
Interest, net of amounts capitalized $ 71,735 $ 71,645 $ 75,085
FUEL ADJUSTMENT CLAUSE. All metered electric rates contain a provision
for adjustment in charges for electric energy to reflect increases and
decreases in the cost of fuel and the cost of purchased power through operation
of a fuel adjustment clause. As prescribed by order of the IURC applicable to
metered retail rates, the adjustment factor has been calculated based on the
estimated cost of fuel and the fuel cost of purchased power in a future
three-month period. If two statutory requirements relating to expense and
return levels are satisfied, any under-recovery or over-recovery caused by
variances between estimated and actual cost in a given three-month period will
be included in a future filing. Northern Indiana records any under-recovery or
over-recovery as a current liability until such time as it is billed or refunded
to its customers. The fuel adjustment factor is subject to a quarterly hearing
by the IURC and remains in effect for a three-month period.
On August 18, 1999, the IURC issued a generic order which established
new guidelines for the recovery of purchased power costs through fuel
adjustment clauses. The IURC ruled that each utility had to establish a
"benchmark" which is the utility's highest on-system fuel cost per kilowatt-
hour (kwh) during the most recent annual period. The IURC stated that if the
weekly average of a utility's purchased power costs were less than the
"benchmark," these costs per kwh should be considered net energy costs which
are presumed "fuel costs included in purchased power." If the weekly average
of a utility's purchased power costs exceeded the "benchmark," the utility
would need to submit additional evidence demonstrating the reasonableness of
these costs. The Office of Utility Consumer Counselor has appealed the
August 18 order to the Indiana Court of Appeals.
GAS COST ADJUSTMENT CLAUSE. All metered gas sales rates contain an
adjustment factor, which reflects the increases and decreases in the cost of
purchased gas, contracted gas storage and storage transportation charges. The
gas cost adjustment factor is subject to a quarterly hearing by the IURC and
remains in effect for a three-month period. On August 11, 1999, the IURC
approved a flexible gas cost adjustment mechanism for Northern Indiana. Under
the new procedure, the demand component of the adjustment factor will be
determined, after hearings and IURC approval, and made effective on November 1
of each year. The demand component will remain in effect for one year until a
new demand component is approved by the IURC. The commodity component of the
adjustment factor will be determined by monthly filings, which will become
effective on the first day of each calendar month, subject to refund. The
monthly filings do not require IURC approval but will be reviewed by the IURC
during the annual hearing that will take place regarding the demand component
filing.
If the statutory requirement relating to the level of return is satisfied,
any under-recovery or over-recovery caused by variances between estimated and
actual cost in a given monthly period will be allocated over a twelve-month
period beginning with the next monthly filing. Any under-recovery or over-
recovery is recorded as a current asset or current liability until such time it
is billed or refunded to its customers.
Northern Indiana's gas cost adjustment factor includes a gas cost
incentive mechanism (GCI) which allows for the sharing of any cost savings or
cost increases with customers based upon a comparison of actual gas supply
portfolio cost to a market-based benchmark price.
NATURAL GAS IN STORAGE. Natural gas in storage is valued using the
last-in, first-out (LIFO) inventory methodology. Based on the average cost of
gas purchased under the LIFO method in December 1999 and 1998, the estimated
replacement cost of gas in storage (current and non-current) at December 31,
1999 and 1998 exceeded the stated LIFO cost by approximately $48.9 million and
$33.7 million, respectively.
AFFILIATED COMPANY TRANSACTIONS. Northern Indiana receives executive,
financial, gas supply, sales and marketing, and administrative and general
services from an affiliate, NiSource Management Services Company (NSC), a
wholly-owned subsidiary of NiSource.
The costs of these services are charged to Northern Indiana based on
payroll costs and expenses incurred by NSC employees for the benefit of
Northern Indiana. These costs, which totaled $17.8 million for the year 1999,
$21.4 million for the year 1998 and $28.8 million for the year 1997, consist
primarily of employee compensation and benefits.
Northern Indiana purchased natural gas and transportation services
from affiliated companies in the amount of $16.3 million, $20.8 million and
$10.2 million, representing 4.8%, 6.8% and 2.2% of Northern Indiana's total gas
costs for years 1999, 1998 and 1997, respectively.
Northern Indiana subleases a portion of its office facilities to
affiliated companies for a monthly fee, which includes operating expenses, based
on space utilization.
ACCOUNTING FOR PRICE RISK MANAGEMENT. Northern Indiana is exposed to
commodity price risk in its natural gas and electric operations. A variety of
commodity-based derivative financial instruments are utilized to reduce this
price risk. When these derivatives are used to reduce price risk in non-trading
operations such as activities in gas supply for regulated gas utilities and
certain customer choice programs, gains and losses on these derivative financial
instruments are deferred as assets or liabilities and are recognized in earnings
concurrent with the disposition of the underlying physical commodity. In
certain circumstances, a derivative financial instrument will serve to hedge the
acquisition cost of natural gas injected into storage. In this situation, the
gain or loss on the derivative financial instrument is deferred as part of the
cost basis of gas in storage and recognized upon the ultimate disposition of the
gas. If a derivative financial instrument contract is terminated early because
it is probable that a transaction or forecasted transaction will not occur, any
gain or loss as of such date is immediately recognized in earnings. If a
derivative financial instrument is terminated for other economic reasons, any
gain or losses as of the termination date is deferred and recorded when the
associated transaction or forecasted transaction affects earnings.
Northern Indiana also uses derivative financial instruments in connection
with trading activities at its power trading operations. These derivatives,
along with the related physical contracts, are recorded at fair value pursuant
to Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities." Because the majority of our trading
activities started in 1999, the impact of adopting EITF Issue No. 98-10 on
January 1, 1999, was insignificant. Transactions related to utility system load
management do not qualify as a trading activity under EITF Issue No. 98-10 and
are accounted for on an accrual basis. Northern refers to this activity as
Power Marketing.
IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards
Board (FASB) has issued SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," in June 1998 and SFAS No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date
of FASB Statement No. 133" in June 1999." Statement No. 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts, by requiring that a company recognize those items
as assets or liabilities in the balance sheet and measure them at fair value.
Special accounting within this Statement generally provides for matching of the
timing of gain or loss recognition of derivative instruments qualifying as a
hedge with the recognition of changes in the fair value of the hedged asset or
liability through earnings, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting treatment. The Statement also provide that the effective portion of
hedging instrument's gain or loss on a forecasted transaction be initially
reported in other comprehensive income and subsequently reclassified into
earnings when the hedged forecasted transaction affects earnings. Unless those
specific hedge accounting criteria are met, SFAS No. 133 requires that changes
in derivatives' fair value be recognized currently in earnings.
SFAS No. 133, as amended by SFAS No. 137, is not effective for Northern
Indiana until January 1, 2001. SFAS No. 133 must be applied to (a) derivative
instruments and (b) certain derivative instruments embedded in hybrid
contracts. With respect to hybrid instruments, a company may elect to apply
SFAS No. No. 133, as amended, to (1) all hybrid instruments, (2) only those
hybrid instruments that were issued, acquired or substantively modified after
December 31, 1997, or (3) only those hybrid instruments that were issued,
acquired or substantively modified after December 31, 1998.
Northern Indiana anticipates adopting SFAS No. 133 on January 1, 2001,
but has not determined the impact or method of adoption. The fair value of
derivatives used in price risk management are described in "Risk Management
Activities."
The fair value of these derivatives would be recognized as assets or
liabilities on the balance sheet consistent with the current accounting
treatment for certain freestanding derivatives. Northern Indiana has not yet
quantified the other effects of adopting SFAS No. 133 on its financial
statements. However, the Statement could increase volatility in earnings and
other comprehensive income.
REGULATORY ASSETS. Northern Indiana's operations are subject to the
regulation of the Commissions. Accordingly, Northern Indiana's accounting
policies are subject to the provisions of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." Northern Indiana monitors changes in
market and regulatory conditions and the resulting impact of such changes in
order to continue to apply the provisions of SFAS No. 71 to some or all of its
operations. As of December 31, 1999 and December 31, 1998, the regulatory
assets identified below represent probable future revenue to Northern Indiana
as these costs are recovered through the rate-making process. If a portion of
Northern Indiana's operations becomes no longer subject to the provisions of
SFAS No. 71, a write-off of certain regulatory assets might be required, unless
some form of transition cost recovery is established by the appropriate
regulatory body which would meet the requirements under generally accepted
accounting principles for continued accounting as regulatory assets during such
recovery period. Regulatory assets were comprised of the following items:
December 31, December 31,
1999 1998
============= =============
(Dollars in thousands)
Unamortized reacquisition premium on
debt (Note 13) $ 39,499 $ 42,962
Unamortized R. M. Schahfer Unit 17 and
Unit 18 carrying charges
and deferred depreciation (See below) 58,111 62,329
Bailly scrubber carrying charges and
deferred depreciation (See below) 8,010 8,945
Deferral of SFAS No. 106 expense not
recovered (Note 6) 72,769 78,367
FERC Order No. 636 transition costs 13,728 22,093
Regulatory income tax asset, net (Note 4) 18,208 21,635
------------- -------------
210,325 236,331
------------- -------------
Less: Current portion of regulatory assets 24,245 32,609
------------- -------------
$ 186,080 $ 203,722
============= =============
CARRYING CHARGES AND DEFERRED DEPRECIATION. Upon completion of R. M.
Schahfer Units 17 and 18, Northern Indiana capitalized the carrying charges and
deferred depreciation in accordance with orders of the IURC until the
cost of each unit was allowed in rates. Such carrying charges and deferred
depreciation are being amortized over the remaining life of each unit.
Northern Indiana has capitalized carrying charges and deferred
depreciation and certain operating expenses relating to its scrubber service
agreement for its Bailly Generating Station in accordance with an order of
the IURC. The accumulated balance of the deferred costs and related carrying
charges is being amortized over the remaining life of the scrubber service
agreement.
INCOME TAXES. The liability method of accounting is used for income
taxes under which deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
book and tax bases of assets and liabilities. Deferred investment tax credits
are being amortized over the life of the related property.
(3) ENVIRONMENTAL MATTERS:
GENERAL. The operations of Northern Indiana are subject to extensive and
evolving federal, state and local environmental laws and regulations intended
to protect the public health and the environment. Such environmental laws
and regulations affect Northern Indiana's operations as they relate to impacts
on air, water and land.
SUPERFUND. Because Northern Indiana is a "potentially responsible
party" (PRP), under Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), at several waste disposal sites, as well as at former
manufactured-gas plant sites which it, or its corporate predecessors, own or
owned or operated, it may be required to share in the costs of clean up of
such sites. A program was instituted to investigate former manufactured-gas
plant sites where it is the current or former owner, which investigation has
identified twenty-four of such sites. Initial sampling has been conducted at
nineteen sites. Investigation activities have been completed at fourteen sites
and remedial measures have been selected or implemented at nine sites. Northern
Indiana intends to continue to evaluate its facilities and properties with
respect to environmental laws and regulations and take any required corrective
action.
In an effort to recover a portion of the costs related to the former
manufactured gas plants, various companies that provided insurance coverage
which Northern Indiana believed covered costs related to former
manufactured-gas plant sites were approached. Northern Indiana filed claims
in Indiana state court against various insurance companies, seeking coverage
for costs associated with several manufactured-gas plant sites and damages
for alleged misconduct by some of the insurance companies. Settlements have
been reached with all insurance companies. Additionally, agreements have been
reached with other Indiana utilities relating to cost sharing and management of
the investigation and remediation of several former manufactured-gas plant sites
at which Northern Indiana and such utilities or their predecessors were
operators or owners.
As of December 31, 1999, a reserve of approximately $17.3 million has
been recorded to cover probable corrective actions. The ultimate liability in
connection with these sites will depend upon many factors, including the
volume of material contributed to the site, the number of other PRP's and
their financial viability, the extent of corrective actions required and rate
recovery. Based upon investigations and management's understanding of current
environmental laws and regulations, Northern Indiana believes that any
corrective actions required, after consideration of insurance coverages
and contributions from other PRP's and rate recovery will not have a material
effect on its financial position or results of operations.
CLEAN AIR ACT. The Clean Air Act Amendments of 1990 (CAAA) impose
limits to control acid rain on the emission of sulfur dioxide and nitrogen
oxides (NOx) which become fully effective in 2000. All of Northern Indiana's
facilities are already in compliance with sulfur dioxide limits. Northern
Indiana has already taken most of the steps necessary to meet the NOx limits.
The CAAA also contain other provisions that could lead to limitations
on emissions of hazardous air pollutants and other air pollutants (including
NOx as discussed below), which may require significant capital expenditures
for control of these emissions. Until specific rules have been issued that
affect Northern Indiana's facilities, what these requirements will be or the
costs of complying with these potential requirements cannot be predicted.
NITROGEN OXIDES. During 1998, the Environmental Protection Agency (EPA)
issued a final rule, the NOx State Implementation Plan (SIP) call, requiring
certain states, including Indiana, to reduce NOx levels from several sources,
including industrial and utility boilers. The EPA stated that the intent of
the rule is to lower regional transport of ozone impacting other states'
ability to attain the federal ozone standard. According to the rule, the
State of Indiana must issue regulations implementing the control program. The
State of Indiana, as well as some other states, filed a legal challenge in
December 1998 to the EPA NOx SIP call rule. Lawsuits have also been filed
against the rule by various groups, including utilities. On May 25, 1999, the
United States Circuit Court of Appeals for the D. C. Circuit issued an order
staying the NOx SIP call rule's September 30, 1999 deadline for the state
submittals until further order of the court. Any resulting NOx emissions
limitations could be more restrictive than those imposed on electric utilities
under the CAAA's acid rain NOx reduction program described above. Northern
Indiana is evaluating the EPA's final rule and any potential requirements that
could result from the final rule as implemented by the State of Indiana.
Northern Indiana believes that the costs relating to compliance with the new
standards may be substantial, but such costs depend upon the outcome of the
current litigation and the ultimate control program agreed to by the targeted
states and the EPA. Northern Indiana is continuing its programs to reduce NOx
emissions and will continue to closely monitor developments in this area.
In a related matter to EPA's NOx SIP call, several Northeastern states
have filed petitions with the EPA under Section 126 of the Clean Air Act. The
petitions allege harm and request relief from sources of emissions in the
Midwest that allegedly cause or contribute to ozone nonattainment in their
states. Northern Indiana is monitoring EPA's decisions on these petitions and
existing litigation to determine the impact of these developments on Northern
Indiana's programs to reduce NOx emissions.
The EPA issued final rules revising the National Ambient Air Quality
Standards for ozone and particulate matter in July 1997. On May 14, 1999,
the United States Court of Appeals for the D.C. Circuit remanded the new rules
for both ozone and particulate matter standards to the EPA. Once rectified,
the revised standards could require additional reductions in sulfur dioxide,
particulate matter and NOx emissions from coal-fired boilers (including
Northern Indiana's generating stations) beyond measures discussed above.
Final implementation methods will be set by the EPA as well as state
regulatory authorities. Northern Indiana believes that the costs relating to
compliance with any new limits may be substantial but are dependent upon the
ultimate control program agreed to by the targeted states and the EPA.
Northern Indiana will continue to closely monitor developments in this area
and anticipates the exact nature of the impact of the new limits on its
operations will not be known for some time.
In a letter dated September 15, 1999, the Attorney General of the State
of New York alleged that Northern Indiana violated the Clean Air Act by
constructing a major modification of one of its electric generating stations
without obtaining pre-construction permits required by the Prevention of
Significant Deterioration (PSD) program. The major modification allegedly
took place at the R. M. Schahfer Station when, "in approximately 1995-1997,
Northern Indiana upgraded the coal handling system at Unit 14 at the plant."
While Northern Indiana is investigating the allegations, Northern Indiana does
not believe that the modifications required pre-construction review under the
PSD program and believes that all appropriate permits were acquired.
CARBON DIOXIDE. Initiatives are being discussed both in the United
States and worldwide to reduce so-called "greenhouse gases" such as carbon
dioxide, and other by-products of burning fossil fuels. Reduction of such
emissions could result in significant capital outlays or operating expenses
to Northern Indiana.
CLEAN WATER ACT AND RELATED MATTERS. Northern Indiana's wastewater and
water operations are subject to pollution control and water quality control
regulations, including those issued by the EPA and the State of Indiana.
Under the Federal Clean Water Act and Indiana's regulations, Northern
Indiana must obtain National Pollutant Discharge Elimination System permits for
water discharges from various facilities, including electric generating and
water treatment stations. These facilities either have permits for their water
discharge or they have applied for a permit renewal of any expiring permits.
These permits continue in effect pending review of the current applications.
(4) INCOME TAXES: Deferred income taxes are recognized as costs in the
rate-making process by the Commissions having jurisdiction over rates charged
by Northern Indiana. Deferred income taxes are provided as a result of
provisions in the income tax law that either require or permit certain items
to be reported on the income tax return in a different period than they are
reported in the consolidated financial statements. These taxes are reversed
by a debit or credit to deferred income tax expense as the temporary
differences reverse. Investment tax credits have been deferred and are being
amortized to income over the life of the related property.
To the extent certain deferred income taxes are recoverable or payable
through future rates, regulatory assets and liabilities have been established.
Regulatory assets are primarily attributable to undepreciated allowance for
funds used during construction-equity (AFUDC) and the cumulative net amount of
other income tax timing differences for which deferred taxes had not been
provided in the past, when regulators did not recognize such taxes as costs in
the rate-making process. Regulatory liabilities are primarily attributable to
Northern Indiana's obligation to credit to ratepayers deferred income taxes
provided at rates higher than the current federal income tax rate currently
being credited to ratepayers using the average rate assumption method and
unamortized deferred investment tax credits.
Northern Indiana joins in the filing of consolidated tax returns with
NiSource and currently pays to NiSource its separate return tax liability
as defined in the Tax Sharing Agreement between NiSource and its subsidiaries.
The components of the net deferred income tax liability at December 31,
1999 and 1998 were as follows:
1999 1998
=========== ===========
(Dollars in thousands)
Deferred tax liabilities -
Accelerated depreciation
and other property differences $ 714,246 $ 735,589
AFUDC-equity 30,748 33,029
Adjustment clauses 15,545 14,322
Other regulatory assets 27,598 29,721
Prepaid pension and other benefits 56,227 34,170
Reacquisition premium on debt 14,980 16,293
Deferred tax assets -
Deferred investment tax credits (32,451) (35,154)
Removal costs (171,645) (157,728)
Other postretirement/postemployment
benefits (53,061) (48,208)
Other, net (27,928) (23,682)
----------- -----------
574,259 598,352
Less: Deferred income taxes related to
current assets and liabilities (17,763) (10,583)
----------- -----------
Deferred income taxes - noncurrent $ 592,022 $ 608,935
=========== ===========
Federal and state income taxes as set forth in the Consolidated
Statement of Income are comprised of the following:
1999 1998 1997
========= ========= =========
(Dollars in thousands)
Current income taxes -
Federal $ 135,787 $ 140,364 $ 108,902
State 18,102 20,156 16,816
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153,889 160,520 125,718
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Deferred income taxes, net -
Federal (18,191) (30,290) (7,998)
State (1,305) (2,284) (416)
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(19,496) (32,574) (8,414)
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Deferred investment tax credits, net (7,126) (7,160) (7,205)
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Total utility income taxes 127,267 120,786 110,099
Income tax applicable to non-operating
activities and income of subsidiaries (1,585) (1,937) (3,536)
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Total income taxes $ 125,682 $ 118,849 $ 106,563
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A reconciliation of total tax expense to an amount computed by applying
the statutory federal income tax rate to pretax income is as follows:
1999 1998 1997
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