TABLE OF CONTENTS
As Filed with the United States Securities and Exchange
Commission on March 27, 2001.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
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.)
801 East 86th Avenue
Merrillville, Indiana 46410
(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, and (2) has been subject to such filing requirements
for the past 90 days. Yes X No __.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of 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.
As of February 28, 2001, 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
TABLE OF CONTENTS
Page
Part I No.
Item 1. Business................................................................... 3
Item 2. Properties................................................................. 5
Item 3. Legal Proceedings.......................................................... 5
Item 4. Submission of Matters to a Vote of Security Holders........................ 5
Part II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters.. 5
Item 6. Selected Financial Data.................................................... 6
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 7
Item 8. Financial Statements and Supplementary Data................................ 19
Item 9. Change In and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 47
Part III
Item 10. Directors and Executive Officers of the Registrant......................... 48
Item 11. Executive Compensation..................................................... 50
Item 12. Security Ownership of Certain Beneficial Owners and Management............. 54
Item 13. Certain Relationships and Related Transactions............................. 54
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............ 55
Signatures.......................................................................... 58
Exhibits............................................................................ 59
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.
Northern Indiana's primary business segments are gas distribution and electric operations.
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. NiSource is an energy holding company that provides natural gas, electricity and other products and
services to 3.6 million customers located within the energy corridor that runs from the Gulf Coast through the
Midwest to New England. In connection with the acquisition of Columbia Energy Group (Columbia) on November 1,
2000, as discussed below, NiSource became a Delaware corporation. NiSource is a registered holding company under
the Public Utility Holding Company Act of 1935, as amended (1935 Act).
On November 1, 2000, NiSource completed its acquisition of Columbia for an aggregate consideration of
approximately $6 billion, with 30% of the consideration paid in common stock with the remaining 70% paid in cash
and Stock Appreciation Income Linked SecuritiesSM which are units each consisting of a zero coupon debt security
coupled with a forward equity contract in NiSource shares. NiSource also assumed approximately $2 billion in
Columbia debt. As a result of the acquisition, NiSource is the largest natural gas distribution company operating
east of the Rocky Mountains, as measured by number of customers.
Gas Distribution Operations
Northern Indiana's natural gas distribution operations serves 688,894 customers in the northern part of Indiana.
Northern Indiana has pursued initiatives that give residential and small commercial customers the opportunity to
choose their natural gas suppliers and to use Northern Indiana for transportation service. This ability to choose
a supplier was previously limited to larger commercial and industrial customers. See Item 2, page 5 and Item 7,
pages 12 through 14 for additional information.
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 2000 and none are expected during 2001.
Electric Operations
Northern Indiana distributes electricity to the public to 430,052 customers in 21 counties in the northern part
of Indiana. Northern Indiana owns and operates four coal-fired electric generating stations with a net capability
of 3,179 megawatts (mw), four gas fired combustion turbine generating units with a net capability of 203 mw and
two hydroelectric generating plants with a net capability of 10 mw. In total, these facilities provide for a
total system net capability of 3,392 mw. Northern Indiana is interconnected with five neighboring electric
utilities. During the year ended December 31, 2000, Northern Indiana generated 94.8% and purchased 5.2% of its
electric requirements. See Item 2, page 5 and Item 7, pages 15 through 17 for additional information.
Competition and Changes in the Regulatory Environment
The regulatory frameworks applicable to Northern Indiana's regulated operations, at both the 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 gas and
electric industries will create opportunities to compete for new customers and revenues. Management continually
seeks new ways to be 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.
Natural Gas Competition. Open access to natural gas supplies over interstate pipelines and the deregulation of
the commodity price of gas has led to tremendous change in the energy markets, which continue to evolve. During
the past few years, local distribution company (LDC) customers and marketers began to purchase gas directly from
producers and marketers and an open competitive market for gas supplies emerged. This separation or "unbundling"
of the transportation and other services offered by pipelines and LDCs allows customers to select the service
they want independent from the purchase of the commodity. Northern Indiana is involved in programs that provide
residential customers the opportunity to purchase their natural gas requirements from third parties and use
Northern Indiana for transportation services only. At the same time that the natural gas markets are evolving,
the markets for competing energy sources are also changing.
Electric Competition. In 1996, the FERC ordered that all public utilities owning, controlling or operating
electric 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. In December 1999, FERC issued a final rule addressing the formation
and operation of Regional Transmission Organizations. The rule was 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 its 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.
Northern Indiana meets these challenges through innovative programs aimed at providing energy products and
services at competitive prices while also providing new services that are responsive to the evolving energy
market and customer requirements.
For additional information, see Item 7.
Financing Flexibility
Northern Indiana may borrow under a $200 million 364-day revolving credit facility that expires in September
2001. At December 31, 2000, the facility supported $196.2 million of commercial paper borrowings that had a
weighted average interest rate of 7.03%. Northern Indiana also maintains multiple uncommitted lines of credit
totaling $178 million. At December 31, 2000, there were $174.9 million of borrowings outstanding under these
uncommitted lines of credit with a weighted average interest rate of 7.70%.
At December 31, 2000, Northern Indiana had an intercompany note payable of $36 million to NiSource Finance Corp.
at an interest rate of 7.71%.
Other Relevant Business Information
Northern Indiana's customer base is broadly diversified, with steel companies accounting for a significant
portion of revenues.
As of January 31, 2001, Northern Indiana had 2,848 full-time employees of which 2,072 were subject to collective
bargaining agreements.
Northern Indiana is subject to extensive federal, state and local laws and regulations relating to environmental
matters. These laws and regulations, which are constantly changing, require expenditures for corrective action at
various operating facilities, waste disposal sites and former gas manufacturing sites for conditions resulting
from past practices that have subsequently become subject to environmental regulation. Information relating to
environmental matters is detailed in Item 7, pages 14 through 15, and 16 through 17, and in Item 8, Note 15E on
pages 42 through 44.
ITEM 2. PROPERTIES
Discussed below are the principal properties held by Northern Indiana as of December 31, 2000.
Gas Distribution Operations. Northern Indiana's system has approximately 14,005 miles of gas mains. The physical
properties of Northern Indiana are located in northern Indiana. The distribution system of Northern Indiana is
primarily located on or under public streets, and other public places or on private property not owned by the
company, with easements from or consent of the respective owners.
Electric Operations. Northern Indiana owns and operates four coal-fired electric generating stations with net
capabilities of 3,179 mw, two hydroelectric generating plants with net capabilities of 10 mw and four gas-fired
combustion turbine generating units with net capabilities of 203 mw, for a total system net capability of 3,392
mw. It has 288 substations with an aggregate transformer capacity of 23,023,700 kilovolts (kva). Its transmission
system, with voltages from 34,500 to 345,000 volts, consists of 3,091 circuit miles of line. The electric
distribution system extends into 21 counties and consists of 7,800 circuit miles of overhead and 1,646 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 11,638,066 kva and 447,784
electric watt-hour meters.
Character of Ownership. Substantially all of the properties of Northern Indiana are subject to the lien of its
First Mortgage Indentures. The principal offices and properties of Northern Indiana 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 and mains 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 party to various pending proceedings, including suits and claims against them for personal
injury, death and property damage. The nature of such proceedings and suits and the amounts involved are routine
for the kinds of businesses conducted by Northern Indiana. No material legal proceedings against Northern Indiana
are pending or, to the knowledge of Northern Indiana, contemplated by governmental authorities or other parties.
Information relating to the IURC rate investigation is detailed in Item 7, Regulatory Matters on page 15.
Item 4. Submission of Matters to a Vote of Security Holders
None
PART II
ITEM 5. Market for Common Equity and Related Stockholder 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, 2000, Northern Indiana had approximately $186.4 million of retained earnings (earned surplus)
available for the payment of dividends. Future common share dividends by Northern Indiana will depend upon
adequate retained earnings, adequate future earnings and the absence of adverse developments.
So long as any shares of Northern Indiana's cumulative preferred stock are outstanding, no cash dividends shall
be paid on its common shares in excess of 75% of the net income available for the preceding calendar year, unless
the aggregate of the capital applicable to stocks subordinate as to assets and dividends, would equal or exceed
25% of the sum of all obligations evidenced by bonds, notes, debentures or other securities, plus the total
capital and surplus. At December 31, 2000, the sum of the capital applicable to stocks subordinate to the
cumulative preferred stock plus the surplus was equal to 42% of the total capitalization including surplus.
In connection with the foregoing discussion, see "Common Share Dividend" in the Notes to Consolidated Financial
Statements in Item 8.
ITEM 6. SELECTED FINANCIAL DATA
Year Ended December 31,($ in thousands) 2000 1999 1998 1997 1996
Operating revenues 1,986,508 1,752,219 1,648,603 1,752,382 1,754,105
Net income 226,059 222,111 220,180 196,620 197,310
Total assets 3,938,861 3,655,454 3,651,949 3,674,914 3,774,280
Long-term obligations
and redeemable preferred
stock 950,896 974,443 1,134,394 1,138,337 1,053,254
Cash dividends declared
on common shares 168,000 224,000 212,000 187,775 187,450
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Index Page
Consolidated Review.............................................................................. 7
Liquidity and Capital Resources.................................................................. 10
Gas Distribution Operations...................................................................... 12
Electric Operations.............................................................................. 15
Voluntary Early Retirement Program............................................................... 17
Impact of Accounting Standards................................................................... 18
The Management's Discussion and Analysis, including statements regarding market risk sensitive instruments,
contains "forward-looking statements," within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Investors and prospective investors
should understand that many factors govern whether any forward-looking statement contained herein will be or can
be realized. Any one of those factors could cause actual results to differ materially from those projected. These
forward-looking statements include, but are not limited to, statements concerning Northern Indiana's plans,
proposed dispositions, objectives, expected performance, expenditures and recovery of expenditures through rates,
stated on either a consolidated or segment basis, and any and all underlying assumptions and other statements
that are other than statements of historical fact. From time to time, Northern Indiana may publish or otherwise
make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether
written or oral and whether made by or on behalf of Northern Indiana, are also expressly qualified by these
cautionary statements. All forward-looking statements are based on assumptions that management believes to be
reasonable; however, there can be no assurance that actual results will not differ materially. Realization of
Northern Indiana's objectives and expected performance is subject to a wide range of risks and can be adversely
affected by, among other things, increased competition in deregulated energy markets, weather, fluctuations in
supply and demand for energy commodities, growth opportunities for Northern Indiana's regulated businesses,
dealings with third parties over whom Northern Indiana has no control, the regulatory process, regulatory and
legislative changes, changes in general economic, capital and commodity market conditions, and counter-party
credit risk, many of which are beyond the control of Northern Indiana. In addition, the relative contributions to
profitability by each segment, and the assumptions underlying the forward-looking statements relating thereto,
may change over time.
Acquisition of Columbia Energy Group
On November 1, 2000, NiSource completed its acquisition of Columbia Energy Group (Columbia) for an aggregate
consideration of approximately $6 billion, with 30% of the consideration paid in common stock and 70% of the
consideration paid in cash and Stock Appreciation Income Linked Securitiessm, referred to as SAILSsm, which are
units consisting of a zero coupon debt security coupled with a forward equity contract for NiSource shares.
NiSource also assumed approximately $2 billion of Columbia debt. As a result of the Columbia acquisition,
NiSource is a super-regional energy holding company that provides natural gas, electricity and other products and
services to 3.6 million customers located within the energy corridor that runs from the Gulf Coast through the
Midwest to New England.
Consolidated Review
Net Income. For 2000, net income of Northern Indiana increased to $226.1 million compared to $222.1 million for
1999. In 1998, net income was $220.2 million.
Gas Revenues. Gas revenues were $913.8 million in 2000, an increase of $269.1 million from 1999. This increase in
gas revenues was mainly due to increased gas costs per dekatherms (dth), which are a direct pass through to
customers, decreased deliveries to industrial and wholesale customers and decreased gas transition costs. During
2000, gas deliveries in dth, which include transportation services, decreased 5%. Gas deliveries to residential
customers increased 3% reflecting 6% higher heating degree-days than 1999. Gas deliveries to commercial increased
6% and gas deliveries to industrial customers decreased 5% reflecting decreased gas transportation services.
Northern Indiana had 688,894 gas customers at December 31, 2000.
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 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.
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
174.1, 184.9 and 173.2 million dth for others in 2000, 1999 and 1998, respectively. The basic steel industry
accounted for 37% of natural gas delivered (including volumes transported) during 2000.
The components of the changes in gas operating revenues are shown in the following table:
Year 2000 Year 1999
Compared To Compared To
(in millions) Year 1999 Year 1998
Gas Revenue Changes -
Pass through of net changes in purchased gas costs,
gas storage and storage transportation costs $ 268.3 $ 15.6
Gas transition costs (0.5) (4.5)
Changes in sales levels (9.4) 21.7
Gas transported (3.7) 6.2
Wholesale gas 14.4 33.2
Total Gas Revenue Change $ 269.1 $ 72.2
Gas Costs of Energy. Gas costs increased $249.4 million (66%) in 2000 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 2000, after adjustment for gas transition costs billed to transport customers, was $6.34 per dth as compared to
$2.58 per dth in 1999. 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 Operating Margins. The gas operating margin increased $19.7 million in 2000 due to increased deliveries to
residential and commercial customers reflecting colder weather during 2000, partially offset by decreased wholesale
sales and decreased deliveries of gas transported for others. 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.
Electric Revenues. Electric revenues for 2000 were $1.073 billion, a decrease of $34.8 million from 1999. Sales of
electricity in kilowatt-hours (kwh) decreased 4% from 1999. The decrease in electric revenues was mainly due to
decreased sales to residential customers due to cooler weather during the third quarter of 2000, decreased
wholesale transactions and decreased fuel cost per kwh partially offset by increased sales to commercial customers.
Sales to residential customers decreased 1% while sales to commercial customers increased 2% in kwh, respectively.
The basic steel industry accounted for 32% of electric sales during 2000. At December 31, 2000, Northern Indiana
had 430,052 electric customers.
In 1999, electric revenues were $1.107 billion, an increase of $31.4 million from 1998. Sales of electricity in 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. Sales to industrial customers increased 5% in 1999. At December
31, 1999, Northern Indiana had 425,835 electric customers.
The components of the changes in electric operating revenues are shown in the following table:
Year 2000 Year 1999
Compared To Compared To
(in millions) Year 1999 Year 1998
Electric Revenue Changes -
Pass through of net changes in fuel costs $ (17.3) $ 5.6
Changes in sales levels 3.0 38.3
Wholesale electric (20.5) (12.5)
Total Electric Revenue Change $ (34.8) $ 31.4
Electric Cost of Energy. Cost of fuel for electric generation in 2000 decreased $7.0 million compared to 1999
mainly as a result of decreased cost per kwh partially offset by increased production. The average cost per kwh
generated decreased 4% from 1999 to 1.41 cents per kwh. 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.
Power Purchased. Power purchased decreased $34.5 million in 2000 as a result of decreased bulk power purchases.
Power purchased increased $25.0 million in 1999 as a result of increased bulk power purchases.
Electric Operating Margins. Operating margin from electric sales in 2000 increased $6.7 million. This increase is
primarily due to increased operating margin from bulk power sales partially offset by decreased sales to
residential customers and lower operating margins from industrial customers. 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 Expenses. Operating expenses in 2000 increased $22.2 million from 1999 and in 1999 increased $17.6
million from 1998.
Operation expenses increased $13.1 million in 2000 over 1999 due to increased costs of $16.8 million related to the
termination of an outsourcing agreement for all data center, application development and maintenance, and desktop
management and a $13 million insurance settlement in 1999 related to manufactured gas plants site cleanup costs
partially offset by decreased employee related costs of $11.0 million. 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.
Maintenance expenses increased $7.0 million in 2000 from 1999 mainly reflecting increased maintenance activity for
electric production and distribution facilities. Maintenance expenses remained relatively unchanged in 1999 from
1998.
Depreciation and amortization expenses increased $8.3 million in 2000 from 1999 and increased $5.0 million in 1999
from 1998, in each period resulting from plant additions.
Other taxes decreased $6.2 million in 2000 from 1999 mainly as a result of a decrease in real estate taxes. Other
taxes remained relatively unchanged in 1999 and 1998.
Utility income taxes decreased $4.3 million in 2000 when compared to 1999, as a result of a lower effective income
tax rate. Utility income taxes increased $6.5 million in 1999 when compared to the prior period mainly as a result
of increased pre-tax income.
Other Income (Deductions) increased $3.5 million in 2000 from 1999 mainly as a result of the charge in 1999 related
to the abandonment of certain business facilities that were not consistent with its strategic direction, increased
power trading activities, partially offset by increased costs related to sale of accounts receivable as a result of
increased interest rates. Other Income (Deductions) increased $1.3 million in 1999 from 1998 mainly as a result of
increased power trading activities, partially offset by the abandonment of certain business facilities that were
not consistent with its strategic direction.
Interest charges increased $8.1 million during 2000 primarily due to increased short term debt borrowings during
the period and increased interest rates. Interest charges decreased $3.2 million in 1999 as a result of decreased
short-term borrowings during the year.
Liquidity and Capital Resources
Generally, cash flow from operations has provided sufficient liquidity to meet current operating requirements. A
significant portion of Northern Indiana ' s operations, most notably in the gas and electric distribution
businesses, are subject to seasonal fluctuations in cash flow. During the heating season, which is primarily from
November through March, cash receipts from gas sales and transportation services typically exceed cash
requirements. In the summer months, cash receipts for electric sales normally exceed requirements. During other
periods of the year, cash on hand, together with external short-term and long-term financing, is used to purchase
gas to place in storage for heating season deliveries, perform necessary maintenance of facilities, make capital
improvements in plant and expand service into new areas.
Northern Indiana may borrow under a $200 million 364-day revolving credit facility that expires in September 2001.
At December 31, 2000, the facility supported $196.2 million of commercial paper borrowings that had a weighted
average interest rate of 7.03%. Northern Indiana also maintains multiple uncommitted lines of credit totaling $178
million. At December 31, 2000, there were $174.9 million of borrowings outstanding under these uncommitted lines of
credit with a weighted average interest rate of 7.70%.
As of December 31, 2000, Northern Indiana had an intercompany note payable of $36 million from NiSource Finance
Corp. at an interest rate of 7.71%.
Capital Expenditures
Construction expenditures by Northern Indiana for 2000, 1999 and 1998 were approximately $193 million, $193 million
and $182 million, respectively.
For 2001, Northern Indiana's estimated capital expenditure program is $186.4 million.
Future commitments, with respect to the construction program, are expected to be met through internally generated
funds.
Market Risk Sensitive Instruments and Positions
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 its
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.
Non-Trading Risks
Currently, commodity price risk resulting from non-trading activities at Northern Indiana is limited, since current
regulations allow recovery of prudently incurred purchased power, fuel and gas costs through the rate-making
process. As the utility industry undergoes deregulation, however, these operations may be providing services
without the benefit of the traditional rate-making process 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.
Northern Indiana is exposed to interest rate risk as a result of changes in interest rates on borrowings under
revolving credit agreements and lines of credit. These instruments have interest rates that are indexed to
short-term market interest rates. At December 31, 2000, and December 31, 1999, the combined borrowings outstanding
under these facilities totaled $407.1 million and $96.3 million, respectively. Based upon average borrowings under
these agreements during 2000 and 1999, an increase in short-term interest rates of 100 basis points (1%) would have
increased interest expense by $2.0 million and $0.7 million for the twelve months ending December 31, 2000, and
December 31, 1999, respectively.
Due to the nature of the industry, credit risk is a factor 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.
Trading Risks
Northern Indiana employs a VaR model to assess the market risk of its energy trading portfolios. 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 estimates the one-day VaR across all trading groups that utilize derivatives using either Monte Carlo
simulation or variance/covariance at a 95% confidence level. Based on the results of the VaR analysis, the daily
market exposure for power trading on an average, high and low basis was $0.8 million, $2.7 million and effectively
zero, respectively, at December 31, 2000. Northern Indiana implemented a VaR methodology in 1999 to introduce
additional market sophistication and to recognize the developing complexity of its businesses.
See Statements of Consolidated Long-Term Debt for additional information related to Northern Indiana's long-term
debt outstanding and "Fair Value of Financial Instruments" in Note 14 of the Notes to the Consolidated Financial
Statements for current market valuation of long-term debt. Refer to "Summary of Significant Accounting
Policies-Accounting for Risk Management Activities" and "Risk Management Activities" in Notes 2N and 6,
respectively, of the Notes to the Consolidated Financial Statements for further discussion of Northern Indiana's
risk management.
Other Information
Presentation of Segment Information
Northern Indiana reports its business segment information as gas distribution and electric operations.
Competition
The regulatory environment applicable to Northern Indiana continues to undergo fundamental changes. These changes
have previously had, and will continue to have, an impact on Northern Indiana's operations, structure and
profitability. At the same time, competition within the energy industry will create opportunities to compete for
new customers and revenues. Management has taken steps to become more competitive and profitable in this changing
environment. These initiatives include providing its customers with increased choice for new products and services.
Gas Distribution Operations
Northern Indiana's natural gas distribution operations serves 688,894 customers in the northern part of Indiana.
Regulatory Matters
At the Federal level, gas industry deregulation began in the mid-1980s when the Federal Energy Regulatory
Commission (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 a local distribution company (LDC) or directly from competing producers and marketers, which
would then use the LDC's facilities to transport the gas. More recently, the focus of deregulation in the gas
industry has shifted to retail customers at the state level.
Northern Indiana pursues initiatives that give retail customers the opportunity to purchase natural gas directly
from marketers and to use Northern Indiana's facilities for transportation services. These opportunities are being
pursued through regulatory initiatives. Once fully implemented, these programs would reduce Northern Indiana's
commodity sales function and provide all customer classes with the opportunity to obtain gas supplies from
alternative merchants. As these programs expand to all customers, regulations will have to be implemented to
provide for the recovery of transition capacity costs and other transition costs incurred by a utility serving as
the supplier of last resort if the marketing company cannot supply the gas. Transition capacity costs are created
as customers enroll in these programs and purchase their gas from other suppliers, leaving Northern Indiana with
pipeline capacity it has contracted for, but no longer needs. Northern Indiana is currently recovering, or has
the opportunity to recover, the costs resulting from the unbundling of its services and believes that most of such
future costs and costs resulting from being the supplier of last resort will be mitigated or recovered.
In 1997, the Indiana Utility Regulatory Commission (IURC) approved 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. The gas cost incentive mechanism was reviewed with the
Office of Utility Consumer Counselor (OUCC) in December 2000, and an agreement to extend the program in phases
through 2004 was reached. During the phase-in period, Northern Indiana offered customer choice to all 660,000
residential and 50,000 commercial customers throughout its gas service territory. 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. As of the end of 2000, 16,434 customers were enrolled in Northern Indiana's
customer choice program.
FERC Order 637
The Federal Energy Regulatory Commission (FERC) issued Order 637 on February 9, 2000. The order sets forth
revisions to FERC regulations governing short-term natural gas transportation services and policies governing the
regulation of interstate natural gas pipelines. Among other things, the order lifts the price cap for short-term
capacity release by pipeline customers for an experimental period ending September 1, 2002.
Northern Indiana is actively engaged in settlement discussions with all of its pipeline suppliers as well as with
other major customers on those pipeline systems in an effort to resolve issues raised by the pipelines' pro forma
compliance filings regarding FERC Orders 637 and subsequent Orders 637A and 637B (collectively referred to as Order
637). Participants in these discussions reflect all segments of the industry.
Based on the progress of those discussions to date, Northern Indiana believes that implementation of FERC Order 637
initiatives will generally not take place prior to the winter of 2001-2002. Also given the degree of compromise
that will be required of all segments of the industry, management believes that implementation will not have a
material affect upon Northern Indiana costs, operations or income. Northern Indiana is currently in the process of
evaluating the potential changes and impact Order 637 may have on operations; however, it is not anticipated that
the implementation of Order 637 will have a material impact on Northern Indiana's results.
Environmental Matters
Remediation. Northern Indiana is a "potentially responsible party" (PRP) at waste disposal sites under the
Comprehensive Environmental Response Compensation and Liability Act (CERCLA) (commonly known as Superfund) and
similar state laws, including at former manufactured gas plant (MGP) sites it, or its corporate predecessors, own
or owned and operated. Northern Indiana may be required to share in the cost of clean-up of such sites.
Northern Indiana is party to or otherwise involved in clean-up of two waste disposal sites under Superfund or
similar state laws. The final costs of clean-up have not yet been determined. As site investigations and clean-ups
proceed, waste disposal site liability is reviewed periodically and adjusted as additional information becomes
available.
A program has been instituted to identify and investigate former MGP sites where it is the current or former owner.
The investigation has identified 24 such sites. Initial investigation has been conducted at 20 sites. Investigation
activities have been completed at 14 of the 20 sites and remedial measures have been selected or implemented at 13
sites. Only those site investigation, characterization and remediation costs currently known and determinable can
be considered "probable and reasonably estimable" under Statement of Financial Accounting Standards No. 5,
"Accounting for Contingencies" (SFAS No. 5).
As costs become probable and reasonably estimable, the associated reserves will be adjusted as appropriate.
Northern Indiana is unable, at this time, to accurately estimate the time frame and potential costs of the entire
program. Management expects that as characterization is completed and approved by the Environmental Protection
Agency (EPA), additional remediation work is performed and more facts become available, Northern Indiana will
be able to develop a probable and reasonable estimate for the entire program or a major portion thereof consistent
with Securities and Exchange Commission's Staff Accounting Bulletin No. 92, SFAS No. 5, and American Institute of
Certified Public Accountants Statement of Position 96-1.
Northern Indiana intends to continue to evaluate its facilities and properties with respect to environmental laws
and regulations and take any required corrective action. To the extent site investigations have been conducted,
remediation plans developed and the responsibility for remediation established, the appropriate estimated
liabilities have been recorded.
As of December 31, 2000, a reserve of approximately $15.1 million has been recorded to cover probable environmental
response actions. The ultimate liability in connection with these sites will depend upon many factors, including
the volume of material contributed to the site, years of ownership or operation, the number of other PRPs and their
financial viability and the extent of environmental response actions required. Based upon investigations and
management's understanding of current environmental laws and regulations, Northern Indiana believes that any
environmental response actions required, after consideration of insurance coverage and contributions from other
PRPs, will not have a material effect on its financial position or results of operations.
Mercury Program. Until the 1960s, gas regulators containing small quantities of mercury were installed in homes on
some natural gas systems. The purpose of these regulators was to reduce the pressure of the natural gas flowing
from the service line for use inside of the home.
In 2000, several gas distribution companies not affiliated with Northern Indiana were involved in highly publicized
testing and clean-up programs resulting from mercury spills associated with the removal of gas regulators
containing mercury. Northern Indiana historically utilized gas regulators that contained small quantities of
mercury. Northern Indiana has implemented a program for reviewing its procedures for managing gas regulators
containing mercury. While this program is currently underway, it has not identified any significant problems
associated with past or current use or removal of mercury regulators.
On December 7, 2000, the EPA Region V sent a letter to Northern Indiana asking Northern Indiana to "review its
records and address any concerns or issues associated with mercury regulators manometers, or any other
mercury-containing measuring devices." Northern Indiana believes that the program described in the preceding
paragraph will be sufficient to satisfy the EPA's request.
Electric Operations
Northern Indiana generates and distributes electricity to 430,052 customers in 21 counties in the northern part of
Indiana. Northern Indiana owns and operates four coal-fired electric generating stations with a net capability of
3,179 megawatts, four gas-fired combustion turbine generating units with a net capability of 203 megawatts and two
hydroelectric generating plants with a net capability of 10 megawatts. These facilities provide for a total system
net capability of 3,392 megawatts. Northern Indiana is interconnected with five neighboring electric utilities.
Market Conditions
The regulatory frameworks applicable to electric operations are undergoing fundamental changes. These changes have
previously had, and will continue to have an impact on Northern Indiana's electric operations, structure and
profitability. At the same time, competition within the industry 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
improving the transmission interconnections with neighboring electric utilities.
Regulatory Matters
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. On June 30, 2000, the D.C. Circuit Court of
Appeals upheld FERC's open access orders in all major respects. The U.S. Supreme Court on February 26, 2001 granted
certiorari, agreeing to review the case. In 1997, FERC approved Northern Indiana's open-access transmission tariff.
On December 20, 1999, FERC issued Order 2000 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. On October 16, 2000, Northern Indiana filed with the FERC indicating that it is committed to
joining an RTO and on February 28, 2001 executed the documents to join the Alliance RTO. 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, during 1999 and 2000, discussions were held with the other investor-owned utilities in Indiana
and with other segments of the Indiana electric industry 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, or in
the most recent session, now in progress. Discussions are ongoing with all segments of the Indiana electric
industry in an attempt to reach a consensus on electric restructuring legislation.
During the course of a regularly scheduled review, referred to as a Level 1 review, the staff of the Indiana
Utility Regulatory Commission (IURC) made a preliminary determination, based on unadjusted historical financial
information filed by Northern Indiana, that Northern Indiana was earning returns that were in excess of its last
rate order and generally established standards. Despite holding meetings with the IURC staff during 2000 to explain
several adjustments that needed to be made to the filed information to make such an analysis meaningful, the staff
has recommended that a formal investigation be performed. The IURC has ordered that an investigation begin.
Management is unable at this time to determine if a broader analysis, which would be performed through a formal
investigation, could result in a rate adjustment that would be higher or lower than currently allowed rates.
Management intends to vigorously oppose any efforts to reduce rates that may result from this investigation.
Environmental Matters
Air. 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 became fully effective in 2000. All of Northern Indiana's facilities are in
compliance with the sulfur dioxide and 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 are issued that affect Northern Indiana's facilities, what these
requirements will be or the costs of complying with these requirements cannot be predicted.
During 1998, the 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. In a March 3, 2000 decision, the United States Court of Appeals for the D.C. Circuit ruled largely in
favor of the EPA's regional NOx plan and on June 22, 2000, the court extended the deadline for the state plan
submittals implementing the EPA NOx SIP call to October 30, 2000. A petition for a hearing before the United States
Supreme Court was denied on March 5, 2001. In anticipation of this outcome, the State of Indiana superceded its
February 2000 proposed NOx control plan designed to address Indiana's ozone nonattainment areas and regional ozone
transport, by initiating rulemaking on a more stringent rule compliant with the EPA's NOx SIP call rule. That
rulemaking is expected to be finalized by mid-summer 2001. Northern Indiana is actively involved in the review of
and comment on the proposed Indiana rules.
In spite of the state's efforts, on December 18, 2000, the EPA sent Indiana and 10 other NOx SIP call states and
the District of Columbia deficiency notices for their failure to submit final rules by the October 30, 2000
deadline. Because Indiana has been working with the EPA and is expected to finalize its rule by mid-summer 2001, no
additional adverse requirements are expected. Any NOx emission limitations resulting from the Indiana rules are
expected to be more restrictive than those imposed on electric utilities under the CAAA's acid rain NOx reduction
program described above. Northern Indiana is evaluating any potential requirements that could result from the rules
as implemented by the State of Indiana. Northern Indiana believes that the costs relating to compliance with any
new standards may be substantial, but such costs are dependent upon the ultimate control program agreed to by the
targeted states and the EPA and are not currently reasonably estimable. Northern Indiana is continuing its programs
to reduce NOx emissions at its electric facilities and will continue to closely monitor developments in this area.
In a matter related to the 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
the EPA's decisions on these petitions and existing litigation to determine the impact of these developments on
programs to reduce NOx emissions at its electric facilities.
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 matters to the EPA. The Court of Appeals decision was appealed to the Supreme Court, which
heard oral arguments on November 7, 2000. The Supreme Court rendered a complex ruling on February 27, 2001 that
will require some issues to be resolved by the D.C. Circuit Court and EPA before final rulemaking occurs.
Consequently, final rules specifying a compliance level, deadline and controls necessary for compliance are not
expected in the near future. Resulting rules could require additional reductions in sulfur dioxide, particulate
matter and NOx emissions from coal-fired boilers (including Northern Indiana's electric 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 and are currently
not reasonably estimable. Northern Indiana will continue to closely monitor developments in this area: however, the
exact nature of the impact of the new standards 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 these
allegations, it does not believe that the alleged modifications required pre-construction review under the PSD
program and believes that all appropriate permits were acquired.
Initiatives are being discussed both in the United States and worldwide to reduce so-called "greenhouse gases" such
as carbon dioxide, a by-product of burning fossil fuels. Reduction of such emissions could result in significant
capital outlays or operating expenses for Northern Indiana.
On December 20, 2000, by notice in the Federal Register, the EPA issued a finding that the regulation of emissions
of mercury and other air toxics from coal and oil-fired electric steam generating units is necessary and
appropriate. The EPA expects to issue proposed regulations by December 15, 2003, and finalized regulations by
December 15, 2004. The potential impact, if any, to Northern Indiana's financial results that may occur because of
any potential new regulations concerning emissions of mercury and other air toxics is unknown at this time.
Remediation. Northern Indiana is a PRP at four waste disposal sites under CERCLA and similar state laws, and may be
required to share in the cost of clean-up of such sites. In addition, Northern Indiana has corrective action
liability under the Resource Conservation and Recovery Act for closure and clean-up costs associated with
treatment, storage, and disposal units. As of December 31, 2000, a reserve of approximately $2 million has been
recorded to cover probable environmental response actions at these sites. The ultimate liability in connection with
these sites will depend upon many factors, including the volume of material contributed to the site, years of
ownership of operations, the number of other PRPs and their financial viability and the extent of environmental
response required. Based upon investigations and management's understanding of current environmental laws and
regulations, Northern Indiana believes that any environmental response required will not have a material effect on
its financial position or results of operations.
Voluntary Early Retirement Program
As a result of NiSource's ongoing review of its various business units, the acquisition of Columbia, the
utilization of improved technologies and process improvement initiatives, management has identified a number of
ways to improve efficiency. As discussed below, NiSource implemented a Voluntary Early Retirement Program (VERP) to
reduce staffing levels.
In September 2000, NiSource announced the introduction of a VERP for certain of its subsidiaries. Approximately 89
Northern Indiana employees were eligible. During the acceptance period that began on October 12, 2000 and closed
on November 25, 2000, 68 Northern Indiana employees elected early retirement. The majority of the retirements
occurred on January 1, 2001. Northern Indiana recorded expense of $6.9 million in the fourth quarter of 2000
related to this VERP.
Retirement costs for these employees are funded through the pension plan.
Impact of Accounting Standards
Refer to "Summary of Significant Accounting Policies - Impact of Accounting Standards" in the Notes to the
Consolidated Financial Statements in Item 8 for information regarding impact of accounting standards not yet
adopted.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Northern Indiana Public Service Company:
We have audited the accompanying consolidated balance sheets and statements of consolidated 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, 2000 and 1999, and the related statements of consolidated
income, retained earnings and cash flows for each of the three years in the period ended December 31, 2000. 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, 2000 and
1999, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2000, 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 55, 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
January 30, 2001
Statements of Consolidated Income
Year Ended December 31, (in thousands) 2000 1999 1998
Operating Revenues:
Gas $ 913,836 $ 644,687 $ 572,485
Electric 1,072,672 1,107,532 1,076,118
1,986,508 1,752,219 1,648,603
Cost of Energy:
Gas costs 629,025 379,609 321,033
Fuel for electric generation 242,123 249,164 250,649
Power purchased 32,450 66,964 41,990
903,598 695,737 613,672
Operating Margin 1,082,910 1,056,482 1,034,931
Operating Expenses:
Operation 269,542 256,474 245,920
Maintenance 72,467 65,462 65,302
Depreciation and amortization 241,900 233,555 228,547
Other taxes 67,917 74,163 72,227
651,826 629,654 611,996
Utility Operating Income Before Utility
Income Taxes 431,084 426,828 422,935
Utility Income Taxes 122,958 127,267 120,786
Utility Operating Income 308,126 299,561 302,149
Other Income (Deductions) 1,249 (2,248) (3,589)
Interest:
Interest on long-term debt 63,241 67,695 69,672
Other interest 15,373 3,352 4,524
Amortization of premium, reacquisition
premium, discount and expense on debt, net 4,702 4,155 4,184
83,316 75,202 78,380
Net Income 226,059 222,111 220,180
Dividend requirements on preferred stocks 7,817 8,131 8,335
Balance available for common shares $ 218,242 $ 213,980 $ 211,845
Common dividends declared $ 168,000 $ 224,000 $ 212,000
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Consolidated Balance Sheets
Year Ended December 31, (in thousands) 2000 1999
ASSETS
Utility Plant, at original cost
Electric $ 4,342,989 $ 4,237,427
Gas 1,377,634 1,323,528
Common 362,558 381,486
6,083,181 5,942,441
Less - Accumulated provision for depreciation
and amortization 3,177,350 2,993,412
Total Utility Plant 2,905,831 2,949,029
Other Property and Investments 2,679 2,668
Current Assets:
Cash and cash equivalents 17,889 6,145
Accounts receivable, less reserve of $10,454
and $7,804, respectively 259,663 141,537
Fuel adjustment clause - 4,201
Gas cost adjustment clause 146,255 36,787
Materials and supplies, at average cost 47,000 52,735
Electric production fuel, at average cost 15,591 31,968
Natural gas in storage, at last-in,
first-out cost 109,746 22,966
Price risk management assets 23,221 31,677
Prepayments and other 32,264 28,608
Total Current Assets 651,629 356,624
Other Assets:
Regulatory assets 179,124 186,080
Prepayments and other 199,598 161,053
Total Other Assets 378,722 347,133
$ 3,938,861 $ 3,655,454
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Consolidated Balance Sheets
December 31, (in thousands) 2000 1999
Capitalization and Liabilities
Common shareholder's equity $ 1,058,373 $ 1,008,131
Preferred stocks-
Series without mandatory
redemption provisions 81,114 81,114
Series with mandatory
redemption provisions 49,124 54,030
Long-term debt, excluding amounts due
within one year 901,772 920,413
Total capitalization 2,090,383 2,063,688
Current portion of long-term debt 19,000 158,000
Short-term borrowings 407,100 96,290
Accounts payable 349,863 129,532
Dividends declared on common and preferred stocks 860 59,017
Customer deposits 28,571 24,264
Taxes accrued 57,060 115,761
Interest accrued 10,304 7,392
Fuel adjustment clause 202 -
Accrued employment costs 58,780 51,393
Price risk management liabilities 21,982 54,001
Other accruals 22,145 22,162
Total current liabilities 975,867 717,812
Deferred income taxes 562,527 592,022
Deferred investment tax credits, being amortized over
life of related property 78,479 85,566
Deferred credits 49,065 47,105
Accrued liability for post-retirement benefits 149,163 137,211
Other non-current liabilities 33,377 12,050
Total other 872,611 873,954
Commitments and Contingencies:
$ 3,938,861 $ 3,655,454
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Statements of Consolidated Capitalization
December 31, (in thousands) 2000 1999
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 12,525
Retained earnings 186,360 136,118
Total common shareholder's equity 1,058,373 1,008,131
Preferred Stocks, Which Are Redeemable Solely
at Option of Northern Indiana
Cumulative preferred stock -
$100 par value -
4-1/4% series - 209,035 shares outstanding 20,903 20,903
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, 2000) -
Series A (stated value - $50 per share),
473,285 shares outstanding 23,664 23,664
81,114 81,114
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 - 0 and 37,500 shares outstanding,
respectively - 3,750
7-3/4% series - 22,244 and 27,798 shares
outstanding, respectively 2,224 2,780
8.35% series - 39,000 and 45,000 shares
outstanding, respectively 3,900 4,500
Cumulative preferred stock -
no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
49,124 54,030
Long-Term Debt 901,772 920,413
Total capitalization $ 2,090,383 $ 2,063,688
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Statements of Consolidated Long-Term Debt
December 31, (in thousands) 2000 1999
First Mortgage Bonds -
Series T, 7-/2%, due April 1, 2002 $ 38,000 $ 38,500
Series NN, 7.10%, due July 1, 2017 55,000 55,000
Total 93,000 93,500
Pollution Control Notes and Bonds -
Series A Note -
City of Michigan City, 5.70% due October 1, 2003 10,500 14,000
Series 1988 Bonds - Jasper County - Series A, B and C -
4.79% weighted average at December 31, 2000,
due November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County - Series D - 4.55%
weighted average at December 31, 2000, due
November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County - Series A - 4.85%
at December 31, 2000 due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County - Series B - 4.85%
at December 31, 2000, due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County - Series C - 4.60%
at December 31, 2000, due April 1, 2019 41,000 41,000
Total 233,500 237,000
Medium-Term Notes -
Interest rates between 6.50% and 7.69% with a weighted
average interest rate of 7.06% and various maturities
between June 3, 2002 and August 4, 2027 578,025 593,025
Unamortized Premium and Discount on
Long-Term Debt, Net (2,753) (3,112)
Total long-term debt, excluding amounts due in one year $ 901,772 $ 920,413
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Statements of Consolidated Cash Flows
Year Ended December 31, (in thousands) 2000 1999 1998
Operating Activities:
Net income $ 226,059 $ 222,111 $ 220,180
Adjustments to reconcile net income to net cash:
Depreciation and amortization 241,900 233,555 228,547
Net changes in price risk management activities (23,563) 22,324 -
Deferred income taxes (16,530) (19,496) (32,574)
Amortization of deferred investment tax credits (7,087) (7,126) (7,160)
Other, net 10,459 (4,905) 1,900
431,238 446,463 410,893
Changes in components of working capital:
Accounts receivable, net (124,697) (31,165) (4,194)
Electric production fuel 16,377 434 (13,565)
Materials and supplies 5,735 (1,181) 2,112
Natural gas in storage (86,780) 27,893 (4,979)
Accounts payable 161,382 (10,240) 16,247
Taxes accrued (23,609) 36,540 24,119
Fuel adjustment clause 4,403 (10,480) 8,958
Gas cost adjustment clause (109,468) 7,257 42,476
Accrued employment costs 7,387 7,170 (6,872)
Other accruals 933 (34,408) (5,505)
Other, net 10,488 18,253 (11,380)
Net Cash From Operating Activities 293,389 456,536 458,310
Investing Activities:
Construction expenditures (193,413) (192,838) (182,123)
Other investing activities, net (1,634) (6,155) (7,195)
Net Investing Activities (195,047) (198,993) (189,318)
Financing Activities:
Retirement of long-term debt (159,000) (3,000) (51,509)
Change in short-term debt 310,810 (29,810) 7,100
Retirement of preferred stock (4,906) (2,407) (2,413)
Dividends paid - common shares (226,000) (228,000) (205,000)
Dividends paid - preferred shares (7,861) (8,176) (8,392)
Other financing activities, net 359 454 963
Net cash used in financing activities (86,598) (270,939) (259,251)
Increase (decrease) in cash and cash equivalents 11,744 (13,396) 9,741
Cash and cash equivalents at beginning of year 6,145 19,541 9,800
Cash and cash equivalents at end of year $ 17,889 $ 6,145 $ 19,541
Supplemental Disclosures of Cash Flow Information
Cash paid for interest, net of amounts capitalized 69,438 71,735 71,645
Cash paid for income taxes 164,861 125,580 135,145
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Statements of Consolidated Retained Earnings
Year Ended December 31, (in thousands) 2000 1999 1998
Balance at Beginning of Period $ 136,118 $ 146,138 $ 146,293
Add:
Net Income 226,059 222,111 220,180
362,177 368,249 366,473
Less:
Dividends:
Cumulative Preferred stock -
4-1/4% series 888 888 889
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 240 461 571
7-3/4% series 233 276 319
8.35% series 372 422 472
6.50% series 2,795 2,795 2,795
Adjustable Rate, series A 1,420 1,420 1,420
Common shares 168,000 224,000 212,000
175,817 232,131 220,335
Balance at End of Period $ 186,360 $ 136,118 $ 146,138
The accompanying Notes to Consolidated Financial Statements are an integral part of this statement.
Notes to Consolidated Financial Statements
1. Holding Company Structure. Effective March 3, 1988, Northern Indiana Public Service Company (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. NiSource is an energy
holding company that provides natural gas, electricity and other products and services to 3.6 million customers
located within the energy corridor that runs from the Gulf Coast through the Midwest to New England. In
connection with the acquisition of Columbia Energy Group (Columbia) on November 1, 2000, NiSource became a
Delaware corporation. NiSource is a registered holding company under the Public Utility Holding Company Act of
1935, as amended, (1935 Act).
2. Summary of Significant Accounting Policies
A. Principles of Consolidation. 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.
B. Cash and Cash Equivalents. Northern Indiana considers all highly liquid short-term investments to be
cash equivalents.
C. Basis of Accounting for Rate-Regulated Subsidiaries. Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), provides that Northern Indiana account
for and report assets and liabilities consistent with the economic effect of the way in which regulators
establish rates, if the rates established are designed to recover the costs of providing the regulated service
and if the competitive environment makes it probable that such rates can be charged and collected. Northern
Indiana follows the accounting and reporting requirements of SFAS No. 71. Certain expenses and credits subject to
utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are
recognized in income as the related amounts are included in service rates and recovered from or refunded to
customers. In the event that regulation significantly changes the opportunity for Northern Indiana to recover its
costs in the future, all or a portion of Northern Indiana's regulated operations may no longer meet the criteria
for the application of SFAS No. 71. In such event, a write-down of all or a portion of Northern Indiana's
existing regulatory assets and liabilities could result, 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. If Northern
Indiana will not be able to continue to apply the provisions of SFAS No. 71, it will have to apply the provisions
of SFAS No. 101 "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No.
71." In management's opinion, Northern Indiana will be subject to SFAS No. 71 for the foreseeable future.
Regulatory assets were comprised of the following items:
At December 31, (in thousands) 2000 1999
Assets
Reacquisition premium on debt (see Note 12) $ 36,035 $ 39,499
R. M. Schahfer Unit 17 and Unit 18 carrying charges and deferred
depreciation (see Note 2E) 49,677 53,894
Bailly scrubber carrying charges and deferred depreciation (see
(Note 2E) 6,372 7,308
Postemployment and other postretirement costs (see Note 8) 61,574 67,171
FERC Order No. 636 transition costs 7,936 13,728
Net regulatory effects of accounting for income taxes (see Note 2O) 25,466 18,208
Underrecovered gas and fuel costs 138,117 27,260
Total Assets $ 325,177 $ 227,068
Regulatory assets of approximately $275.5 million are not presently included in the rate base and consequently
are not earning a return on investment. These regulatory assets are being recovered through cost of service. The
remaining recovery periods generally range from one to fourteen years. Regulatory assets of approximately $129.5
million require specific rate action. All regulatory assets are probable of recovery.
D. Utility Plant and Related Depreciation and Maintenance. Property plant and equipment are stated at cost.
The cost of utility includes an allowance for funds used during construction (AFUDC). The 2000 before-tax rates
for AFUDC was 6.2%. The 1999 and 1998 before-tax rates for AFUDC were 4.25% and 6.0%, respectively.
Northern Indiana provides depreciation on a straight-line method over the remaining service lives of the
electric, gas and common properties.
The depreciation provisions for utility plant, as a percentage of the original cost, for the periods ended,
December 31, 2000, 1999 and 1998 were as follows:
2000 1999 1998
Electric 3.7% 3.7% 3.6%
Gas 5.4% 5.4% 5.4%
Northern Indiana charges maintenance and repairs, including the cost of removal of minor items of property, to
expense as incurred. When property that represents a retired 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.
E. 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 Indiana
Utility Regulatory Commission (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.
F. 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.
G. Revenue Recognition. Except as discussed below, revenues are recorded as services are delivered.
However, utility revenues are billed to customers monthly on a cycle basis. Revenues are recorded on the accrual
basis and include an estimate for electric and gas delivered. Effective January 1, 1999, revenues relating to
energy trading operations are recorded based upon changes in the fair values, net of reserves, of the related
energy trading contracts.
H. Accounts Receivable Sales Program. Northern Indiana enters into agreements with third parties to sell
certain accounts receivable without recourse. These sales are reflected as reductions of accounts receivable in
the accompanying consolidated balance sheets and as operating cash flows in the accompanying statements of
consolidated cash flows. The costs of this program, which are based upon the purchasers' level of investment and
borrowing costs, are charged to other income in the accompanying statements of consolidated income.
I. Use of Estimates. The preparation of financial statements in conformity with accounting principles
generally accepted in the United States requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
J. 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 fuel 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 regulatory asset or 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.
K. Gas Cost Adjustment Clause. Northern Indiana defers differences between gas purchase costs and the
recovery of such costs in revenues, and adjusts future billings for such deferrals on a basis consistent with
applicable state approved tariff provisions.
L. 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 using the LIFO method in December 2000 and December 1999, the
estimated replacement cost of gas in storage at December 31, 2000 and December 31, 1999, exceeded the stated LIFO
cost by $261.4 million and $48.9 million, respectively.
M. Affiliated Company Transactions. Northern Indiana receives executive, financial, gas supply, sales and
marketing, and administrative and general services from an affiliate, NiSource Corporate 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 $21.2 million for the year 2000, $17.8
million for the year 1999 and $21.4 million for the year 1998, consist primarily of employee compensation and
benefits.
Northern Indiana purchased natural gas and transportation services from affiliated companies in the amount of
$69.4 million, $16.3 million and $20.8 million, representing 10.5%, 4.8% and 6.8% of Northern Indiana's total gas
costs for years 2000, 1999 and 1998, 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.
The December 31, 2000, and 1999 accounts receivable balance include approximately $30.4 million and $14.0
million, respectively, due from associated companies.
As of December 31, 2000, Northern indiana had an intercompany note payable of $36.0 million to NiSource Finance
Corp. at an interest rate of 7.71%.
N. Accounting for Risk Management Activities. 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,or other retail customer activity, gains and losses on these
derivative financial instruments are deferred as assets and 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 gains or losses as of the termination date are 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 trading activities started in 1999, the impact of adopting EITF Issue No.
98-10 on January 1, 1999 was insignificant. Transactions related to electric 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
Indiana refers to this activity as Power Management.
O. Income Taxes and Investment Tax Credits. Northern Indiana records income taxes to recognize full
interperiod tax allocations. Under the liability method of income tax accounting, deferred income taxes are
recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable
to future years to differences between the financial statement carrying amounts and the tax basis of existing
assets and liabilities.
Previously recorded investment tax credits of Northern Indiana were deferred and are being amortized over the
life of the related properties to conform with regulatory policy.
P. Environmental Expenditures. Northern Indiana accrues for costs associated with environmental remediation
obligations when such costs are probable and can be reasonably estimated, regardless of when expenditures are
made. The undiscounted estimated future expenditures are based on currently enacted laws and regulations,
existing technology and, when possible, site-specific costs. The reserve is adjusted as further information is
developed or circumstances change.
3. Restructuring Activities
During 2000, NiSource developed and began the implementation of a plan to restructure its operations as a result
of the Columbia acquisition. The restructuring plan included an involuntary severance program, a transition plan
to implement operational efficiency throughout NiSource's operations and a voluntary early retirement program.
As a result of the restructuring plan, it is estimated that approximately 37 management, professional,
administrative and technical positions have been or will be eliminated at Northern Indiana. In October 2000,
Northern Indiana recorded pre-tax charges of $2.5 million in operating expense representing severance and related
benefits costs. This charge included $1.3 million of estimated termination benefits. As of December 31, 2000,
approximately 25 employees have been terminated as a result of the restructuring plan. At December 31, 2000, the
consolidated balance sheets reflected an accrual of $1.2 million related to the restructuring plan.
4. Impact of Accounting Standards
A. SFAS No. 133 - Accounting for Derivative Instruments and Hedging Activities. The Financial Accounting
Standards Board (FASB) has issued Statement of Financial Accounting Standards (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 and
SFAS No. 138, "Accounting for Certain Derivatives Instruments and Certain Hedging Activities- an amendment of
FASB No. 133" in June 2000. Statement No. 133 as amended standardizes the accounting for derivative instruments,
including certain derivative instruments embedded in hybrid contracts, by requiring that a company recognize
those items as assets or liabilities in the balance sheet and measure them at fair value. The standard also
suggests in certain circumstances commodity based contracts may qualify as derivatives. 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 provides 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.
Northern Indiana is a party to a number of contracts that have elements of a derivative instrument. These
contracts include, among others, binding purchase orders, contracts which provide for the delivery of natural
gas, and service contracts that require the counterparty to provide commodity storage, transportation or capacity
service to meet normal sales commitments. Although many of these contracts have the requisite elements of a
derivative instrument, Northern Indiana believes these contracts are not subject to the accounting requirements
of SFAS 133 because they provide for the delivery of products or services in quantities that are expected to be
used in the normal course of operating the business or the value of the contract is directly associated with the
price or value of a service. Other contracts do not meet the definition of a derivative instrument because these
represent requirements-based commitments.
The adoption of this statement on January 1, 2001 is estimated to result in a cumulative after-tax increase to
other comprehensive income of approximately $4 million. The adoption is also estimated to result in approximately
$14 million of derivatives to be recognized on the balance sheet as assets and approximately $8 million of
derivatives to be recognized as liabilities.
B. SFAS No. 140 - Accounting for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities. In September 2000, the Financial Accounting Standards Board issued Statement of Financial Accounting
Standards No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of
Liabilities". This statement replaces FASB Statement No. 125, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities" (SFAS No. 125). It revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and requires certain disclosures, but it
carries over most of SFAS No. 125's provisions without reconsideration.
This statement provides accounting and reporting standards for transfers and servicing of financial assets and
extinguishments of liabilities. Those standards are based on consistent application of a financial-components
approach that focuses on control. Under that approach, after a transfer of financial assets, an entity recognizes
the financial and servicing assets it controls and the liabilities it has incurred, derecognizes financial assets
when control has been surrendered, and derecognizes liabilities when extinguished. This Statement provides
consistent standards for distinguishing transfers of financial assets that are sales from transfers that are
secured borrowings.
C. SAB No. 101 - Revenue Recognition in Financial Statements. In December 1999, the SEC issued Staff
Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements". This SAB summarizes certain of
the SEC Staff's views in applying generally accepted accounting principles to revenue recognition in financial
statements. In June 2000, the SEC issued SAB No. 101B, which delayed the implementation of SAB 101 until no later
than the fourth fiscal quarter of fiscal years beginning after December 15, 1999. See Item 8, Note 6, "Risk
Management Activities" on pages 32 through 34 with respect to disclosure of northern Indiana's power trading
operations on a gross revenue and gross cost of energy basis.
5. Regulatory Matters
Fuel Adjustment Clause. On August 18, 1999, the IURC issued a generic order (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 (OUCC) appealed the Generic Order to the Indiana Court of
Appeals. Northern Indiana applied the Generic Order's guidelines to purchased power transactions sought to be
recovered for February, March and April 2000.
By an order issued February 23, 2000, the IURC approved the recovery of Northern Indiana's purchased power
transactions during the months of July, August and September 1999. Northern Indiana and the OUCC filed petitions
for reconsideration of the February 23, 2000 Order.
On June 30, 2000, Northern Indiana and the OUCC filed a joint motion to withdraw petitions for reconsideration
and requested IURC approval of a Stipulation and Agreement (Agreement). The Agreement establishes a recovery
mechanism for certain purchase power transactions for the months of July, August and September 2000 that will be
utilized in lieu of the IURC's Generic Order guidelines. The Agreement calls for Northern Indiana to return, by
an adjustment to fuel adjustment clause factors, $1.8 million to retail ratepayers during the period from
November 2000 through April 2001. Northern Indiana has established a reserve for these amounts. By its order
issued August 9, 2000, the IURC approved the Agreement. On September 5, 2000, the Indiana Court of Appeals issued
an order approving a joint stipulation for dismissal, with prejudice, of the OUCC's appeal of the Generic Order.
Gas Cost Adjustment Clause. 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. Northern Indiana made
its annual filing on September 1, 2000.
Northern Indiana's gas cost adjustment factor also includes a gas cost incentive mechanism (GCIM) which allows
the sharing of any cost savings or cost increases with customers based on a comparison of actual gas supply
portfolio cost to a market-based benchmark price.
Other. During the course of a regularly scheduled review, referred to as a Level 1 review, the staff of the IURC
made a preliminary determination, based on unadjusted historical financial information filed by Northern
Indiana's electric operations, that Northern Indiana was earning returns that were in excess of its last rate
order and generally established standards. Despite holding meetings with the IURC staff during 2000 to explain
several adjustments that needed to be made to the filed information to make such an analysis meaningful, the
staff has recommended that a formal investigation be performed. The IURC has ordered that an investigation begin.
Management is unable at this time to determine if a broader analysis, which would be performed through a formal
investigation, could result in a rate adjustment that would be higher or lower than currently allowed
rates. Management intends to vigorously oppose any efforts to reduce rates that may result from this investigation.
6. Risk Management Activities
Northern Indiana uses certain commodity-based derivative financial instruments to manage certain risks inherent
in its business. 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. The open positions resulting from risk management
activities are managed in accordance with strict policies which limit exposure to market risk and require daily
reporting to management of potential financial exposure.
Northern Indiana uses futures contracts, options and swaps to hedge a portion of its price risk associated with
its non-trading activities in gas supply for its regulated gas utility and other retail customer activity. At
December 31, 2000, Northern Indiana had futures contracts representing the hedge of natural gas sales in the
notional amount of 1.7 billion cubic feet (Bcf) resulting in a deferred gain of $4.4 million.
Northern Indiana's trading operations include the activities of its power trading business. Northern Indiana
employs a value-at-risk (VaR) model to assess the market risk of its energy trading portfolios. 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% confidence level. Based on the results of the VaR analysis, the daily market
exposure for power trading on an average, high and low basis was $0.8 million, $2.7 million and effectively zero
million and $0.4 million, $1.2 million and effectively zero million during 2000 and 1999, respectively. Northern
Indiana implemented a VaR methodology in 1999 to introduce additional market sophistication and to recognize the
developing complexity of its businesses.
The fair market value of Northern Indiana power trading assets and liabilities were $30.9 million and $42.6
million, respectively, at December 31, 2000, and $31.7 million and $54 million, respectively, at December 31,
1999. The average fair market value of power trading assets and liabilities were $36.6 million and $60
million, respectively at December 31, 2000, and $20.9 million and $32.4 million, respectively at December 31,
1999.
Unrealized gains and losses on Northern Indiana's trading portfolio are recorded as price risk management assets
and liabilities. The market prices used to value price risk management activities reflect the best estimate of
market prices considering various factors, including closing exchange and over-the-counter quotations and price
volatility factors underlying the commitments. The accompanying Consolidated Balance Sheets reflect price risk
management assets of $30.9 million and $31.7 million at December 31, 2000 and December 31, 1999, respectively, of
which $23.2 million and $31.7 million were included in "Price risk management assets" and $7.7 million and $0
million were included under the caption "Prepayments and other" included in the Current Assets at December 31,
2000 and December 31, 1999, respectively. The accompanying Consolidated Balance Sheets also reflect price risk
management liabilities (including net option premiums) of $42.6 million and $54.0 million of which $22.0 million
and $54.0 million were included in "Price risk management liabilities" and $20.6 million and $0 million were
included in "Other noncurrent liabilities" at December 31, 2000 and December 31, 1999, respectively.
Northern Indiana has recorded power trading revenues and cost of sales of $ 485.2 million and $ 472.9 million,
respectively, at December 31, 2000. Northern Indiana has recorded power trading revenues and cost of sales of
$ 237.8 million and $ 230.4 million, respectively, at December 31, 1999. These revenues and costs are included in
Other Income (Deductions) in the Statements of Consolidated Income.
Other Income (Deductions) in the Statement of Consolidated Income were comprised of the following items:
($ in thousands) Gas Electric Other Adjustments Total
2000
Power trading revenues - 485,195 - - 485,195
Power trading cost of sales - (472,888) - - (472,888)
Power trading administrative
expenses - (3,387) - - (3,387)
Power trading unrealized gains - 2,044 - - 2,044
Other 1,158 (8,298) (2,513) (62) (9,715)
Total other income (deductions) 1,158 2,666 (2,513) (62) 1,249
1999
Power trading revenues - 237,755 - - 237,755
Power trading cost of sales - (230,420) - - (230,420)
Power trading administrative
expenses - (2,152) - - (2,152)
Power trading unrealized gains - 3,643 - - 3,643
Other 1,872 (8,093) (4,806) (47) (11,074)
Total other income (deductions) 1,872 733 (4,806) (47) (2,248)
7. Income Taxes
The components of income tax expense are as follows:
Year Ended December 31, (in thousands) 2000 1999 1998
Income Taxes
Current
Federal $ 129,103 $ 135,787 $ 140,364
State 17,472 18,102 20,156
Total