nisource statistical summary book2003

2003 Statistical Summary

ProposedMillennium Pipeline

Gas Distribution

• 440,000 customers in Northern Indiana

Gas

Transmission & Storage

• 3.3 million customers in nine states• 55,000 miles of distribution pipeline• Customer choice in all states

• Over 16,000 miles of pipeline in 19 jurisdictions• One of the largest natural gas storage networks (Approx. 646 Bcf of storage)

• Owns and has the ability to operate 3,392 MW of generation capacity -3,059 MW of coal-fired generation -323 MW of gas-fired generation -10 MW of hydroelectric generation• Wholesale Power Sales

• NiSource Energy Technologies (Distributed Generation)• Whiting Clean Energy (525 MW combined-cycle cogeneration facility)

Electric Other

Electric Distribution

Generation

Other Operations

The NiSource Portfolio

NiSource Inc.

NiSource Inc. (NiSource) is an energy holding company whose subsidiaries provide natural gas, electricity andother products and services to approximately 3.7 million customers located within a corridor that runs from theGulf Coast through the Midwest to New England. NiSource’s primary business segments are: Gas DistributionOperations; Gas Transmission and Storage Operations; Electric Operations; and Other.

Gas Distribution OperationsNiSource’s natural gas distribution operations serve more than 3.3 million customers in 9 states and operate over55,000 miles of pipeline. Through its wholly owned subsidiary, Columbia, NiSource owns five distributionsubsidiaries that provide natural gas to approximately 2.2 million residential, commercial and industrialcustomers in Ohio, Pennsylvania, Virginia, Kentucky and Maryland. NiSource also distributes natural gas toapproximately 770,000 customers in northern Indiana through three subsidiaries: Northern Indiana, Kokomo Gasand Fuel Company and Northern Indiana Fuel and Light Company, Inc. Additionally, NiSource’s subsidiaries BayState and Northern Utilities, Inc. distribute natural gas to more than 329,000 customers in Massachusetts, Maineand New Hampshire.

Gas Transmission and Storage OperationsNiSource’s Gas Transmission and Storage Operations subsidiaries own and operate approximately 16,000 milesof interstate pipelines and operate one of the nation’s largest underground natural gas storage systems capable ofstoring approximately 646 billion cubic feet (Bcf) of natural gas. Through its subsidiaries, Columbia GasTransmission Corporation (Columbia Transmission), Columbia Gulf Transmission Company (Columbia Gulf),Crossroads Pipeline Company and Granite State Gas Transmission, Inc. (Granite State), it owns and operates aninterstate pipeline network extending from offshore in the Gulf of Mexico to New York and the eastern seaboard.Together, these companies serve customers in 19 northeastern, mid-Atlantic, midwestern and southern states andthe District of Columbia. The Gas Transmission and Storage Operations subsidiaries are engaged in severalprojects that will expand their facilities and throughput. The largest such project is the proposed MillenniumPipeline. The Millennium Pipeline is a project proposed by a partnership of energy companies including ColumbiaTransmission, which would replace parts of an existing Columbia Transmission pipeline.

Electric OperationsNiSource generates and distributes electricity through its subsidiary Northern Indiana to approximately 440,000 customersin 21 counties in the northern part of Indiana. Northern Indiana owns and has the ability to operate four coal-fired electric

generating stations with a net capability of3,059 megawatts (mw), six gas-fired generatingunits with a net capability of 323 mw and twohydroelectric generating plants with a netcapability of 10 mw. These facilities provide fora total system net capability of 3,392 mw.

OtherThe Other Operations segment participates inenergy-related services including gasmarketing, power trading and venturesfocused on distributed power generationtechnologies, including a cogeneration facility,fuel cells and storage systems. PEI operatesthe Whiting Clean Energy project, which is a525 mw cogeneration facility that uses naturalgas to produce electricity for sale in thewholesale markets and also provides steamfor industrial use.

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Regulated Gas

Distribution43%

Regulated Electric

Operations23%

RegulatedGas Transmission

& Storage34%

Business Segments% of 2003 Operating Income

Transmission & Storage

Electric OperationsOther/Corporate

Gas Distribution

$506$399

$268

$-57

2003

Op

erat

ing

Inco

me

(mill

ion

s)

Contents

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FINANCIAL

Consolidated Financial Data and Ratios.......................................................................................................4Statements of Consolidated Income .............................................................................................................5Consolidated Balance Sheets ........................................................................................................................6Statements of Consolidated Cash Flows ......................................................................................................8Statements of Consolidated Capitalization ..................................................................................................9Statements of Consolidated Long-Term Debt ............................................................................................10Income Taxes ..................................................................................................................................................11Statements of Consolidated Common Stockholders’ Equity ...................................................................12Current Security and Bond Ratings.............................................................................................................14

STOCKHOLDERS

Common Stockholders — State...................................................................................................................15Common Stockholders...................................................................................................................................15

BUSINESS SEGMENTS

Gas Distribution Statistics.............................................................................................................................16Gas Distribution Customers and Throughput Statistics by State .......................................................17

Gas Transmission and Storage Statistics...................................................................................................18Electric Distribution Statistics ......................................................................................................................19

Electric Generation and Production Statistics ......................................................................................20Fuel for Electric Generation......................................................................................................................21Capacity and Operating Margins.............................................................................................................22

Glossary of Selected Energy Terms.............................................................................................................23Board of Directors and NiSource Officers.................................................................................................24Shareholder Information/Contacts..............................................................................................back cover

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Consolidated Financial Data and RatiosYear Ended December 31, ($ in millions) 2003 2002 2001 2000 1999*

Return on average common equity 2.0% 9.7% 6.3% 6.3% 12.8%Times interest earned (pre-tax) 2.32 2.08 1.46 1.66 2.20Dividends paid per share 1.10 1.16 1.16 1.08 1.02Dividend payout ratio 333.3% 65.5% 110.5% 96.4% 79.1%Market values during the year:

High 21.97 24.99 32.55 31.50 30.50Low 16.39 14.51 18.25 12.81 16.56Close 21.94 20.00 23.06 30.75 17.88

Book value of common stock 16.81 16.78 16.72 16.59 10.90Market-to-book ratio at year end 130.5% 119.2% 137.9% 185.4% 164.0%Total Assets 16,623.8 17,942.6 18,826.6 20,570.5 7,006.5Capital Expenditures (1999 & 2000 include discontinued operations) 572.5 527.5 531.0 365.8 293.9Capitalization

Common stockholders’ equity 4,415.9 4,174.9 3,469.4 3,409.1 1,353.5Preferred and preference stock 81.1 84.9 88.6 132.7 139.6Company-obligated mandatorily redeemable preferred

securities of subsidiary trust holding solely Company debentures — 345.0 345.0 345.0 345.0Long-term debt 5,993.4 4,849.5 6,065.1 5,802.7 1,775.8

Total Capitalization 10,490.4 9,454.3 9,968.1 9,689.5 3,613.9Number of employees 8,614 9,307 12,501 14,674 7,399Operating Income (Loss)

Gas Distribution Operations $ 506.4 $ 459.1 $ 380.8 $ 241.0 $ 114.0Gas Transmission and Storage Operations 398.8 398.3 349.0 45.7 2.4Electric Operations 267.5 322.3 340.7 353.0 354.6Other Operations (43.8) (43.1) (69.6) 55.4 19.1Corporate (12.6) 4.3 (10.9) (114.9) (44.9)Adjustments and eliminations — 11.3 (22.1) 1.6 0.2Consolidated $ 1,116.3 $ 1,152.2 $ 967.9 $ 581.8 $ 445.4

Depreciation and AmortizationGas Distribution Operations $ 190.2 $ 189.2 $ 228.8 $ 146.7 $ 115.0Gas Transmission and Storage Operations 111.4 109.4 161.4 27.7 1.4Electric Operations 175.1 172.2 166.8 162.8 158.5Other Operations 11.2 10.3 8.7 22.4 15.5Corporate 9.1 10.3 10.4 4.5 4.6Adjustments and eliminations — (0.2) 0.6 — —Consolidated $ 497.0 $ 491.2 $ 576.7 $ 364.1 $ 295.0

AssetsGas Distribution Operations $ 6,096.4 $ 5,967.0 $ 5,889.0 $ 6,224.8 $ 2,879.2Gas Transmission and Storage Operations 2,913.0 2,940.1 2,990.5 3,094.2 —Electric Operations 3,079.7 2,968.8 3,102.0 3,522.2 2,851.3Other Operations 1,411.3 1,727.1 1,579.6 2,695.1 1,023.5Corporate 9,729.1 10,607.6 14,319.0 13,927.4 1,617.8Adjustments and eliminations (6,605.7) (6,268.0) (9,053.5) (8,893.2) (1,365.3)Consolidated $16,623.8 $17,942.6 $18,826.6 $20,570.5 $ 7,006.5

Capital ExpendituresGas Distribution Operations $ 195.1 $ 196.4 $ 211.3 $ 138.3 $ 145.2Gas Transmission and Storage Operations 120.5 128.0 137.4 50.3 —Electric Operations 225.1 197.8 134.7 132.2 134.0Other Operations (1999 and 2000 include

discontinued operations) 31.8 5.3 47.6 45.0 14.7Consolidated $ 572.5 $ 527.5 $ 531.0 $ 365.8 $ 293.9

*1999 has not been adjusted for the effects of discontinued operations and the consensus reached at the October 25, 2002 Emerging Issues Task Force (EITF) meeting regarding EITFIssue No. 02-03 “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.”Information for those periods is not available.

The results in the table above for years prior to 2001 are not comparable as a result of the Columbia acquisition in 2000. Also, in 2002, NiSource discontinued the amortization of goodwill consistent with SFAS No. 142, “Goodwill and Other Intangible Assets.”

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Statements of Consolidated IncomeYear Ended December 31, (in millions, except per share amounts) 2003 2002 2001

Net RevenuesGas Distribution $3,619.4 $2,890.4 $3,849.9Gas Transportation and Storage 1,033.5 1,014.1 997.1Electric 1,115.9 1,103.6 1,060.2 Other 477.8 311.7 363.5Gross Revenues 6,246.6 5,319.8 6,270.7Cost of Sales 3,186.3 2,248.9 3,143.9

Total Net Revenues 3,060.3 3,070.9 3,126.8

Operating ExpensesOperation and maintenance 1,185.9 1,185.0 1,308.0Depreciation and amortization 497.0 491.2 576.7Loss (Gain) on sale or impairment of assets (24.9) (27.5) (0.1)Other taxes 286.0 270.0 274.3

Total Operating Expenses 1,944.0 1,918.7 2,158.9Operating Income 1,116.3 1,152.2 967.9

Other Income (Deductions)Interest expense, net (464.7) (516.4) (592.0)Minority interest (2.5) (20.4) (20.4)Preferred stock dividends of subsidiaries (4.5) (6.7) (7.5)Other, net 15.3 8.3 9.6

Total Other Income (Deductions) (456.4) (535.2) (610.3)Income From Continuing Operations Before Income Taxes

and Change in Accounting 659.9 617.0 357.6Income Taxes 234.2 218.9 166.6Income From Continuing Operations Before Change in Accounting 425.7 398.1 191.0Income (Loss) from Discontinued Operations — net of taxes (0.5) 18.2 21.2Loss on Disposition of Discontinued Operations — net of taxes (331.2) (43.8) —Change in Accounting — net of taxes (8.8) — 4.0Net Income $ 85.2 $ 372.5 $ 216.2

Basic Earnings (Loss) Per Share ($)Continuing operations $ 1.64 $ 1.89 $ 0.93Discontinued operations (1.28) (0.12) 0.10Change in accounting (0.03) — 0.02

Basic Earnings Per Share $ 0.33 $ 1.77 $ 1.05

Diluted Earnings (Loss) Per Share ($)Continuing operations $ 1.63 $ 1.87 $ 0.91Discontinued operations (1.27) (0.12) 0.10Change in accounting (0.03) — 0.02

Diluted Earnings Per Share $ 0.33 $ 1.75 $ 1.03Basic Average Common Shares Outstanding (millions) 259.6 211.0 205.3Diluted Average Common Shares (millions) 261.6 212.8 209.8

Certain amounts in periods prior to 2003 have been reclassified to conform with the 2003 presentation.

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Consolidated Balance SheetsAs of December 31, (in millions) 2003 2002 2001

ASSETS

Property, Plant and EquipmentUtility Plant $15,991.5 $15,579.7 $15,161.3Accumulated depreciation and amortization (7,095.9) (6,813.7) (6,513.2)

Net utility plant 8,895.6 8,766.0 8,648.1

Other property, at cost, less accumulated depreciation 409.3 415.3 420.9

Net Property, Plant and Equipment 9,304.9 9,181.3 9,069.0

Investments and Other AssetsAssets of discontinued operations

and assets held for sale 6.5 1,571.0 2,018.3Unconsolidated affiliates 113.2 125.1 124.4Other investments 67.4 51.6 47.5

Total Investments 187.1 1,747.7 2,190.2

Current AssetsCash and cash equivalents 27.3 31.1 72.4Restricted cash 22.8 24.2 38.9Accounts receivable 511.1 545.5 631.5Unbilled revenue 303.2 305.2 262.7Gas inventory 429.4 255.3 377.7Underrecovered gas and fuel costs 203.2 206.1 169.3Materials and supplies, at average cost 71.5 68.6 73.0Electric production fuel, at average cost 29.0 39.0 29.1Price risk management assets 74.3 66.4 237.5Exchange gas receivable 174.8 120.1 186.8Regulatory assets 114.5 99.5 75.4Prepayments and other 101.8 111.8 132.9

Total Current Assets 2,062.9 1,872.8 2,287.2

Other AssetsPrice risk management assets 114.4 115.1 69.2Regulatory assets 575.5 608.8 517.0Goodwill 3,704.0 3,722.1 3,753.3Intangible assets 527.2 552.2 508.7Deferred charges and other 147.8 142.6 432.0

Total Other Assets 5,068.9 5,140.8 5,280.2

Total Assets $16,623.8 $17,942.6 $18,826.6


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Consolidated Balance SheetsAs of December 31, (in millions) 2003 2002 2001

CAPITALIZATION AND LIABILITIES

CapitalizationCommon Stock Equity $ 4,415.9 $ 4,174.9 $ 3,469.4 Preferred Stocks —

Series without mandatory redemption provisions 81.1 81.1 83.6Series with mandatory redemption provisions — 3.8 5.0

Company-obligated mandatorily redeemable preferred securities of subsidiary trust holding solely Company debentures — 345.0 345.0

Long-term debt, excluding amounts due within one year 5,993.4 4,849.5 6,065.1

Total Capitalization 10,490.4 9,454.3 9,968.1

Current LiabilitiesCurrent portion of long-term debt 118.3 1,224.9 411.3Short-term borrowings 685.5 913.1 1,854.3Accounts payable 496.6 536.7 587.2Dividends declared on common and preferred stocks 1.8 1.1 1.8Customer deposits 80.4 65.2 10.0Taxes accrued 210.8 222.8 227.3Interest accrued 82.4 76.6 68.0Overrecovered gas and fuel costs 29.2 13.1 49.3Price risk management liabilities 36.5 39.7 243.1Exchange gas payable 290.8 411.9 287.2Current deferred revenue 28.2 17.5 15.3Regulatory liabilities 73.7 13.5 21.1Accrued liability for postretirement and postemployment benefits 56.8 48.9 34.2Other accruals 418.0 391.8 629.1

Total Current Liabilities 2,609.0 3,976.8 4,439.2

Other Liabilities and Deferred CreditsPrice risk management liabilities 0.2 3.2 10.8Deferred income taxes 1,595.9 1,517.8 1,397.2Deferred investment tax credits 87.3 96.3 105.3Deferred credits 72.7 100.9 173.4Noncurrent deferred revenue 113.0 130.1 147.5Accrued liability for postretirement and postemployment benefits 406.9 419.2 283.5Preferred stock liabilities with mandatory redemption provisions 2.4 — —Liabilities of discontinued operations and liabilities held for sale — 959.9 1,124.8Regulatory liabilities and other removal costs 1,061.6 1,073.2 963.3Other noncurrent liabilities 184.4 210.9 213.5

Total Other 3,524.4 4,511.5 4,419.3

Commitments and Contingencies — — —

Total Capitalization and Liabilities $16,623.8 $17,942.6 $18,826.6


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Statements of Consolidated Cash FlowsYear Ended December 31, (in millions) 2003 2002 2001

Operating ActivitiesNet Income $ 85.2 $ 372.5 $ 216.2Adjustments to reconcile net income to net cash from continuing operations:

Depreciation and amortization 497.0 491.2 576.7Net changes in price risk management assets and liabilities (4.3) (43.3) 22.4Deferred income taxes and investment tax credits 77.9 95.8 (52.5)Deferred revenue (6.4) (15.2) (416.1)Stock compensation expense 12.9 7.3 30.0Loss (Gain) on the sale or impairment of assets (24.9) (27.5) (0.1)Change in accounting, net of tax 8.8 — (4.0)Loss (Income) from unconsolidated affiliates 5.4 (2.6) (10.3)Loss (Gain) on sale of discontinued operations 331.2 43.8 —Loss (Income) from discontinued operations 0.5 (18.2) (21.2)Amortization of Discount/Premium on Debt 18.9 21.0 20.5

Changes in assets and liabilities Restricted cash 1.4 14.7 12.7Accounts receivable and unbilled revenue 67.3 43.6 533.0Inventories (166.9) 117.0 (73.2)Accounts payable (41.4) (50.6) (443.8)Customer deposits 15.2 55.2 14.7Taxes accrued (89.5) (8.1) 25.7Interest accrued 5.9 8.6 (10.0)(Under) Overrecovered gas and fuel costs 18.9 (107.6) 275.9Exchange gas receivable/payable (196.0) 191.3 355.8Other accruals (55.5) (203.1) (94.1)Prepayments and other current assets 9.9 25.9 18.5Regulatory assets/liabilities 3.3 (13.7) 7.8Postretirement and postemployment benefits 82.6 (19.2) 16.9Deferred credits (28.1) (11.8) (87.8)Deferred charges and other noncurrent assets 14.2 243.5 (134.1)Other noncurrent liabilities (29.1) (39.5) 124.2

Net Cash Flows from Continuing Operations 614.4 1,171.0 903.8Net Cash Flows from Discontinued Operations (141.5) (133.3) 6.8Net Cash Flows from Operating Activities 472.9 1,037.7 910.6Investing Activities

Capital expenditures (574.6) (531.9) (525.3)Proceeds from disposition of assets 586.5 419.2 227.9Other investing activities (17.6) (2.2) (7.4)

Net Cash Flows for Investing Activities (5.7) (114.9) (304.8)Financing Activities

Issuance of long-term debt 1,401.5 — 300.0Retirement of long-term debt (1,366.9) (462.8) (93.0)Change in short-term debt (227.6) (941.2) (642.5)Retirement of preferred shares (346.2) (46.7) (1.1)Issuance of common stock 354.7 734.9 15.1Acquisition of treasury stock (2.5) (6.9) —Dividends paid — common shares (284.0) (241.5) (239.0)

Net Cash Flows from Financing Activities (471.0) (964.2) (660.5)Decrease in cash and cash equivalents (3.8) (41.4) (54.7)Cash and cash equivalents at beginning of year 31.1 72.5 127.2Cash and cash equivalents at end of period $ 27.3 $ 31.1 $ 72.5Supplemental Disclosures of Cash Flow Information

Cash paid for interest, net of amounts capitalized $ 442.3 $ 493.8 $ 518.0Interest capitalized 2.5 2.4 4.3Cash paid for income taxes 256.8 118.8 250.2


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Statements of Consolidated CapitalizationAs of December 31, (in millions, except shares outstanding and par value) 2003 2002 2001

Common shareholders’ equity $ 4,415.9 $4,174.9 $3,469.4

Preferred Stocks, which are redeemable solely at option of issuer:

Northern Indiana Public Service Company—

Cumulative preferred stock — $100 par value —

41⁄4% series — 209,035 shares outstanding 20.9 20.9 20.9

41⁄2% series — 79,996 shares outstanding 8.0 8.0 8.0

4.22% series — 106,198 shares outstanding 10.6 10.6 10.6




Premium on preferred stock and other 0.3 0.3 2.8

Cumulative preferred stock — no par value —

Adjustable rate series A (stated value —

$50 per share), 473,285 shares outstanding 23.6 23.6 23.6

Series without mandatory redemption provisions 81.1 81.1 83.6

Redeemable Preferred Stocks, subject to mandatory

redemption requirements or whose redemption is

outside the control of issuer:

Northern Indiana Public Service Company—

Cumulative preferred stock — $100 par value —

73⁄4% series — 0; 11,136; and 16,690 shares

outstanding, respectively — 1.1 1.7

8.35% series — 0; 27,000; and 33,000 shares

outstanding, respectively — 2.7 3.3

Series with mandatory redemption provisions — 3.8 5.0

Company-obligated mandatorily redeemable

preferred securities of subsidiary trust

holding solely Company debentures — 345.0 345.0

Long-term debt 5,993.4 4,849.5 6,065.1

Total Capitalization $10,490.4 $9,454.3 $9,968.1


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Statements of Consolidated Long-Term DebtAs of December 31, (in millions) 2003 2002 2001

NiSource Inc.:Debentures due November 1, 2006, with interest imputed at 7.77% (SAILSSM) $ 135.8 $ 126.0 $ 116.9

Bay State Gas Company: Medium-Term Notes —

Interest rates between 6.26% and 9.20% with a weighted average interest rate of 6.90% and maturities between June 21, 2005 and February 15, 2028 68.5 80.5 95.5

Northern Utilities: Medium-Term Note — Interest rate of 6.93% and maturity of September 1, 2010 5.0 5.8 5.8Medium-Term Note — Interest rate of 9.70% and maturity of September 1, 2031 — — 13.0Total long-term debt of Bay State Gas Company 73.5 86.3 114.3

Columbia Energy Group:Debentures —

6.80% Series C — due November 28, 2005 281.5 281.5 281.57.05% Series D — due November 28, 2007 281.5 281.5 281.57.32% Series E — due November 28, 2010 281.5 281.5 281.57.42% Series F — due November 28, 2015 281.5 281.5 281.57.62% Series G — due November 28, 2025 229.2 229.2 229.2

Fair value adjustment of debentures for interest rate swap agreements 11.2 30.6 —Unamortized discount on long-term debt (98.2) (108.0) (118.7)Subsidiary debt — Capital lease obligations 1.7 2.0 2.2

Total long-term debt of Columbia Energy Group 1,269.9 1,279.8 1,238.7PEI Holdings, Inc.:

Long-Term Notes —Whiting Clean Energy, Inc.— Interest rates between 6.73% and 8.58% with a weighted average

interest rate of 8.30% and maturity of June 20, 2011 301.5 302.5 284.3Total long-term debt of PEI Holdings, Inc. 301.5 302.5 284.3

NiSource Capital Markets, Inc.:Senior Unsecured Notes — 4.25%, due February 19, 2005 0.3 — —Subordinated Debentures —Series A, 73⁄4%, due March 31, 2026 — 75.0 75.0Senior Notes — 6.78%, due December 1, 2027 75.0 75.0 75.0Medium-term notes —

Issued at interest rates between 7.38% and 7.99%, with a weighted average interest rate of 7.66% and various maturities between April 15, 2005 and May 5, 2027 220.0 300.0 300.0Total long-term debt of NiSource Capital Markets, Inc. 295.3 450.0 450.0

Indianapolis Water Company:Medium-term notes —

Medium-Term Notes — Interest rates of 5.99% and 6.61%, with a weighted average interest rateof 6.34% and maturities between February 1, 2009 and February 1, 2019 — — 80.0Total long-term debt of Indianapolis Water Company — — 80.0

NiSource Development Company, Inc.:NDC Douglas Properties, Inc. — Notes Payable —

Interest rate between 7.69% and 8.38% with a weighted average interest rate of 8.22% and various maturities between January 1, 2005 and January 1, 2008 2.6 5.1 8.2Total long-term debt of NiSource Development Company, Inc. 2.6 5.1 8.2

NiSource Finance Corp.:Long-Term Notes —

53⁄4% — due April 15, 2003 — — 300.071⁄2% — due November 15, 2003 — — 750.0Floating Rate Notes — 1.93% at December 31, 2003, due May 4, 2005 250.0 — —75⁄8% — due November 15, 2005 900.0 900.0 900.03.20% — due November 1, 2006 250.0 — —77⁄8% — due November 15, 2010 1,000.0 1,000.0 1,000.0Senior Unsecured Notes — 6.15%, due March 1, 2013 345.0 — —5.40% — due July 15, 2014 500.0 — —

Fair value adjustment of notes for interest rate swap agreements 3.3 — —Unamortized discount on long-term debt (15.5) (13.6) (20.4)

Total long-term debt of NiSource Finance Corp., Inc. 3,232.8 1,886.4 2,929.6Northern Indiana Public Service Company:

First mortgage bonds —Series NN, 7.10%— due July 1, 2017 — 55.0 55.0

Pollution control notes and bonds —Issued at interest rates between 1.00% and 1.125%, with a weighted average interest rate of 1.07%

and various maturities between November 1, 2007 and April 1, 2019 278.0 223.0 229.0Medium-term notes—

Issued at interest rates between 6.59% and 7.69%, with a weighted average interest rate of 7.24% and various maturities between June 9, 2005 and August 4, 2027 405.5 437.5 561.5

Unamortized premiums and discount on long-term debt, net (1.5) (2.1) (2.4)Total long-term debt of Northern Indiana Public Service Company 682.0 713.4 843.1

Total long-term debt, excluding amount due within one year $5,993.4 $4,849.5 $6,065.1


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Income TaxesYear Ended December 31, (in millions) 2003 2002 2001

Income TaxesCurrent

Federal $132.0 $126.4 $189.7State 24.3 (3.3) 29.4

Total Current 156.3 123.1 219.1Deferred

Federal 82.4 74.8 (44.9)State 4.4 29.9 1.4

Total Deferred 86.8 104.7 (43.5)Deferred Investment Credits (8.9) (8.9) (9.0)Income Taxes Included in Continuing Operations $234.2 $218.9 $166.6

Total income taxes from continuing operations were different from the amount that would be computed byapplying the statutory Federal income tax rate book income before income tax. The major reasons for thisdifference were as follows:Year Ended December 31, (in millions) 2003 2002 2001

Book income from Continuing Operations before income taxes $659.9 $617.0 $357.6

Tax expense at statutory Federal income tax rate 231.0 35.0% 216.0 35.0% 125.2 35.0%Increases (reductions) in taxes resulting from:

State income taxes, net of federal income tax benefit 18.6 2.8 17.1 2.8 19.8 5.5

Book depreciation over related tax depreciation 1.2 0.2 (2.2) (0.4) (0.1) —Amortization of deferred investment tax credits (8.9) (1.3) (8.9) (1.4) (9.0) (2.5)Low-income housing/Section 42 credits (5.1) (0.8) (5.1) (0.8) (4.8) (1.3)Nondeductible amounts related to amortization of

intangible assets and plant acquisition adjustments — — — — 32.8 9.2Other, net (2.6) (0.4) 2.0 0.3 2.7 0.7

Income Taxes from Continuing Operations $234.2 35.5% $218.9 35.5% $166.6 46.6%

Deferred income taxes resulted from temporary differences between the financial statement carrying amountsand the tax basis of existing assets and liabilities. The principal components of NiSource’s net deferred tax liabilitywere as follows:At December 31, (in millions) 2003 2002 2001

Deferred tax liabilitiesAccelerated depreciation and other property differences $1,521.2 $1,482.0 $1,502.0Unrecovered gas and fuel costs 67.2 46.7 28.1Other regulatory assets 217.9 238.4 193.0SFAS No. 133 and price risk adjustments 49.0 42.7 18.8Premiums and discounts associated with long-term debt 58.1 60.7 56.0

Total Deferred Tax Liabilities 1,913.4 1,870.5 1,797.9Deferred tax assets

Deferred investment tax credits and other regulatory liabilities (54.0) (62.4) (63.6)Pension and other postretirement/postemployment benefits (151.7) (163.4) (93.7)Environmental liabilities (18.8) (41.2) (44.6)Other accrued liabilities (33.1) (52.3) (62.5)Other, net (2.9) (38.2) (117.0)

Total Deferred Tax Assets (260.5) (357.5) (381.4)Less: Deferred income taxes related to current assets and liabilities 57.0 (4.8) 19.3Non-Current Deferred Tax Liability $1,595.9 $1,517.8 $1,397.2

Notes to Consolidated Financial Statements are an integral part of these statements.

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Statements of Consolidated Common Stockholders’ Equity

AccumulatedAdditional Other

Common Treasury Paid-In Retained Comprehensive Comprehensive(in millions) Stock Stock Capital Earnings Other Income Total IncomeBalance January 1, 2001 $2.0 $ 0.0 $2,597.3 $ 823.7 $(18.3) $ 4.4 $3,409.1Comprehensive Income:

Net Income 216.2 216.2 $216.2Other comprehensive income, net of tax:

Gain/loss on available for sale securities:Unrealized (3.2) (3.2) (3.2)Realized 0.8 0.8 0.8

Gain/loss on foreign currency translation:Unrealized (0.9) (0.9) (0.9)

Net unrealized gains on derivatives qualifying as cash flow hedges 50.1 50.1 50.1

Total comprehensive income $263.0Dividends:

Common stock (239.7) (239.7)Treasury stock acquiredIssued:

Employee stock purchase plan 1.3 1.3Long-term incentive plan 0.1 40.6 (31.5) 9.2

Amortization of unearned compensation 30.0 30.0Equity contract costs (1.9) (1.9)Other (1.6) (1.6)Balance December 31, 2001 $2.1 $ 0.0 $2,637.3 $ 798.6 $(19.8) $ 51.2 $3,469.4Comprehensive Income:

Net Income 372.5 372.5 $372.5Other comprehensive income, net of tax:

Gain/loss on available for sale securities:Unrealized (6.0) (6.0) (6.0)Realized 0.3 0.3 0.3


Minimum pension liability adjustment (203.7) (203.7) (203.7)Total comprehensive income $180.8Dividends:

Common stock (240.8) (240.8)Treasury stock acquired (6.9) (6.9)Issued:

Common stock issuance 0.4 734.3 734.7Employee stock purchase plan 0.9 0.9Long-term incentive plan 17.0 (0.7) 16.3

Amortization of unearned compensation 19.9 19.9Other 0.6 0.6Balance December 31, 2002 $2.5 $(6.9) $3,389.5 $ 930.9 $ (0.6) $(140.5) $4,174.9Comprehensive Income:

Net Income 85.2 85.2 $ 85.2Other comprehensive income, net of tax:

Gain/loss on available for sale securities:Unrealized 1.4 1.4 1.4

Gain/loss on foreign currency translationUnrealized 0.7 0.7 0.7


Minimum pension liability adjustment 53.5 53.5 53.5Total comprehensive income $164.7Dividends:

Common stock (284.8) (284.8)Treasury stock acquired (2.5) (2.5)Issued:

Common stock issuance 0.1 344.9 345.0Employee stock purchase plan 0.6 0.6Long-term incentive plan 21.6 (4.5) 17.1

Amortization of unearned compensation 0.9 0.9Balance December 31, 2003 $2.6 $(9.4) $3,756.6 $ 731.3 $ (4.2) $ (61.0) $4,415.9

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

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Statements of Consolidated Common Stockholders’ Equity

Common TreasuryShares (in thousands) Shares SharesBalance January 1, 2001 205,553 —Issued:

Employee stock purchase plan 46 —Long-term incentive plan 1,893 —

Balance December 31, 2001 207,492 —Treasury stock acquired (350)Issued:

Stock issuance 41,400 —Employee stock purchase plan 43 —Long-term incentive plan 275 —

Balance December 31, 2002 249,210 (350)Treasury stock acquired (128)Issued:

Stock issuance 13,111 —Employee stock purchase plan 33 —Long-term incentive plan 754 —

Balance December 31, 2003 263,108 (478)

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Current Security and Bond Ratings

Columbia Energy Group

Description Moody’s S & P Fitch

Senior Unsecured Baa2 BBB BBB+

Northern Indiana Public Service Company


Senior Unsecured Baa2 BBB BBB+

Preferred Stock Baa3 BB+ BBB+

NiSource Inc.


Senior Unsecured Baa3 BBB BBB

Commercial Paper Prime-3 A-2 F-2

Common Stockholders—State

Common Stockholders

Geographical Breakdown of Shareholders by State:

Percent PercentState Holders of Total *Shares of TotalAlabama 164 0.39% 71,474 0.03% Alaska 23 0.05% 6,772 0.00%Arizona 465 1.11% 242,999 0.09%Arkansas 126 0.30% 48,984 0.02%California 1,876 4.46% 983,104 0.37%Colorado 361 0.86% 307,729 0.12%Connecticut 751 1.79% 346,930 0.13%Delaware 93 0.22% 29,303 0.01%Dist. of Columbia 77 0.18% 67,757 0.03%Florida 2,041 4.86% 1,038,324 0.39%Georgia 373 0.89% 208,138 0.08%Hawaii 67 0.16% 30,981 0.01%Idaho 45 0.11% 18,709 0.01%Illinois 3,438 8.18% 1,905,289 0.72%Indiana 11,587 27.57% 8,990,438 3.42%Iowa 276 0.66% 144,080 0.05%Kansas 159 0.38% 56,933 0.02%Kentucky 474 1.13% 218,904 0.08%Louisiana 224 0.53% 70,662 0.03%Maine 240 0.57% 68,048 0.03%Maryland 773 1.84% 300,650 0.11%Massachusetts 2,038 4.85% 1,835,245 0.70%Michigan 1,397 3.32% 1,068,202 0.41%Minnesota 484 1.15% 226,392 0.09%Mississippi 91 0.22% 29,544 0.01%Missouri 427 1.02% 259,883 0.10%Montana 66 0.16% 24,566 0.01%Nebraska 102 0.24% 62,225 0.02%Nevada 149 0.35% 119,981 0.05%

Percent PercentState Holders of Total Shares of TotalNew Hampshire 253 0.60% 118,824 0.05%New Jersey 1,349 3.21% 8,729,662 3.32%New Mexico 94 0.22% 64,425 0.02%New York 2,388 5.68% 231,182,560 87.87%North Carolina 451 1.07% 171,720 0.07%North Dakota 39 0.09% 20,080 0.01%Ohio 2,318 5.51% 1,023,828 0.39%Oklahoma 126 0.30% 45,566 0.02%Oregon 202 0.48% 73,943 0.03%Pennsylvania 1,569 3.73% 705,813 0.27%Rhode Island 128 0.30% 63,341 0.02%South Carolina 204 0.49% 76,613 0.03%South Dakota 56 0.13% 27,286 0.01%Tennessee 249 0.59% 113,504 0.04%Texas 986 2.35% 422,837 0.16%Utah 70 0.17% 18,521 0.01%Vermont 79 0.19% 31,201 0.01%Virginia 987 2.35% 503,031 0.19%Washington 311 0.74% 140,918 0.05%West Virginia 610 1.45% 248,650 0.09%Wisconsin 1,012 2.41% 490,633 0.19%Wyoming 36 0.09% 12,410 0.00%Canada 36 0.09% 13,781 0.01%Other Foreign 94 0.22% 26,419 0.01%

Totals 42,034 100.00% 263,107,812 100.00%Less Treasury Shares 477,403Total Shares Outstanding 262,630,409

December 31, 2003 Number Percent Number PercentHolder Category of Holders of Holders of Shares of Shares

Joint Tenants—Survivorship Rights 11,194 26.63% 6,594,452 2.51%Individual—Female 10,599 25.22% 4,545,064 1.73%Individual—Male 13,130 31.24% 7,690,826 2.92%Corporations 513 1.22% 9,250,932 3.52%Depositories 4 0.01% 230,247,533 87.51%Nominee 10 0.02% 8,193 0.00%Trusts 6,410 15.25% 4,654,581 1.77%Miscellaneous 174 0.41% 116,231 0.04%Total 42,034 100.00% 263,107,812 100.00%Less Treasury Shares 477,403Total Shares Outstanding 262,630,409Share Size %3,331 to 33.9 Shares 6,749 16.06% 91,240 0.03%3, 34 to 49.9 Shares 1,824 4.34% 74,846 0.03%3, 50 to 99.9 Shares 4,340 10.32% 314,183 0.12%3,100 to 300.9 Shares 12,815 30.49% 2,363,123 0.90%3,301 to 500.9 Shares 5,092 12.11% 2,124,660 0.81%3,501 to 1,000.9 Shares 5,652 13.45% 4,074,303 1.55%1,001 and over 5,562 13.23% 254,065,457 96.56Total 42,034 100.00% 263,107,812 100.00%Less Treasury Shares 477,403Total Shares Outstanding 262,630,409

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Gas Distribution Statistics

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Year Ended December 31, (in millions) 2003 2002 2001 2000 1999

Net RevenuesSales Revenues $3,659.9 $2,905.4 $3,890.5 $1,980.5 $ 966.6Less: Cost of gas sold 2,625.3 1,921.6 2,887.9 1,415.9 588.8

Net Sales Revenues 1,034.6 983.8 1,002.6 564.6 377.8Transporation Revenues 442.0 405.0 389.8 171.4 75.1

Net Revenues 1,476.6 1,388.8 1,392.4 736.0 452.9

Operating ExpensesOperation and maintenance 615.4 589.6 638.1 280.2 189.1Depreciation and amortization 190.2 189.2 228.8 146.7 115.0Other taxes 164.6 150.9 144.7 68.1 34.8

Total Operating Expenses 970.2 929.7 1,011.6 495.0 338.9Operating Income $ 506.4 $ 459.1 $ 380.8 $ 241.0 $ 114.0

Revenues ($ in Millions)Residential 2,356.2 1,790.7 2,231.0 1,250.4 572.1Commercial 841.3 625.8 842.4 446.5 207.5Industrial 194.0 101.9 131.8 92.2 58.5Transportation 442.0 405.0 389.8 171.4 75.1Off System Sales 86.1 191.5 636.8 97.2 101.9Other 182.3 195.5 47.9 94.2 26.6

Total $4,101.9 $3,310.4 $4,279.7 $2,151.9 $1,041.7

Sales and Transportation (MMDth)Residential sales 230.4 223.4 220.3 142.4 94.2Commercial sales 89.7 83.6 92.8 57.3 39.2Industrial sales 21.8 17.3 15.3 15.2 13.3Transportation 522.9 536.9 507.7 304.6 263.1Off System Sales 10.5 62.8 170.4 25.0 40.2Other 3.6 0.2 0.3 (5.1) 0.6

Total 878.9 924.2 1,006.8 539.4 450.6

Heating Degree Days 5,134 4,757 4,500 4,965 5,593Normal Heating Degree Days 4,949 5,129 5,144 5,173 6,104% Colder (Warmer) than Normal 4% (7)% (13)% (4)% (8)%

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Customers and Throughput Statistics by State

Customers (as of December 31, 2003) 2003 2002 2001 2000 1999

Residential 2,278,768 2,318,862 2,294,395 2,352,219 939,426Commercial 210,967 216,024 213,052 216,346 85,632Industrial 6,009 5,818 5,835 5,952 3,788Transportation 779,802 705,430 720,993 637,075 42,306Other 135 146 150 24 69Total Customers 3,275,681 3,246,280 3,234,425 3,211,616 1,071,221

Customers by State RResidential Commercial Industrial Transportation Other Total

Indiana 669,168 53,579 3,417 49,862 132 776,158Ohio 762,270 57,047 1,387 566,040 — 1,386,744Kentucky 85,500 9,288 112 46,303 2 141,205Pennsylvania 263,319 32,677 346 104,876 — 401,218Maryland 26,627 3,604 23 1,534 — 31,788Virginia 182,748 18,763 285 7,353 1 209,150New Hampshire 19,910 5,833 46 165 — 25,954Maine 17,330 6,942 14 194 — 24,480Massachussets 251,896 23,234 379 3,475 — 278,984Total NiSource 2,278,768 210,967 6,009 779,802 135 3,275,681

Throughput by State (MMDth) Residential Commercial Industrial Transportation Off-syst Sales Other Total

Indiana 66.7 27.0 15.0 153.6 0.7 3.5 266.5Ohio 79.2 20.0 0.8 211.3 7.5 0.1 318.9Kentucky 7.5 3.7 0.4 23.4 0.9 — 35.9Pennsylvania 29.1 13.4 0.4 47.3 1.3 — 91.5Maryland 2.6 1.8 — 2.8 — — 7.2Virginia 15.3 10.3 1.7 49.8 0.1 — 77.2New Hampshire 1.8 2.6 0.4 2.1 — — 6.9Maine 1.1 2.8 0.3 3.1 — — 7.3Massachussets 27.1 8.1 2.8 29.5 — — 67.5Total NiSource 230.4 89.7 21.8 522.9 10.5 3.6 878.9

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Gas Transmission and Storage StatisticsYear Ended December 31, (in millions) 2003 2002 2001 2000

Operating Revenues

Transportation revenues $ 663.2 $ 730.4 $ 756.7 $ 199.9

Storage revenues 177.9 178.9 178.9 29.9

Other revenues 12.2 12.9 28.1 1.8

Total Operating Revenues 853.3 922.2 963.7 231.6

Less: Cost of gas sold 16.0 47.8 80.1 62.5

Net Revenues 837.3 874.4 883.6 169.1

Operating Expenses

Operation and maintenance 278.3 316.2 321.0 68.8

Depreciation and amortization 111.4 109.4 161.4 27.7

Gain on sale or impairment of assets (1.8) (2.2) — 16.9

Other taxes 50.6 52.7 52.2 10.0

Total Operating Expenses 438.5 476.1 534.6 123.4

Operating Income $ 398.8 $ 398.3 $ 349.0 $ 45.7

Throughput (MMDth)

Columbia Transmission

Market Area 1,018.9 1,043.8 970.2 285.0

Columbia Gulf

Mainline 612.6 614.4 626.3 114.2

Short-haul 124.4 146.9 184.7 28.8

Columbia Pipeline Deep Water 7.4 0.7 2.9 0.1

Crossroads Gas Pipeline 34.3 29.2 37.4 40.7

Granite State Pipeline 33.4 33.2 29.1 36.4

Intrasegment eliminations (592.1) (553.9) (609.3) (109.8)

Total 1,238.9 1,314.3 1,241.3 395.4

Years are not comparable due to the acquisition of Columbia Energy Group on November 1, 2000.

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Electric Distribution StatisticsYear Ended December 31, (in millions) 2003 2002 2001 2000 1999

Net RevenuesSales revenues $1,092.8 $1,137.4 $1,064.5 $1,072.7 $1,107.5Less: Cost of sales 364.2 369.0 277.6 274.6 316.1

Net Revenues 728.6 768.4 786.9 798.1 791.4

Operating ExpensesOperation and maintenance 224.7 222.8 223.3 234.3 225.2Depreciation and amortization 175.1 172.2 166.8 162.8 158.5Other taxes 61.3 51.1 56.1 48.0 53.1

Total Operating Expenses 461.1 446.1 446.2 445.1 436.8Operating Income $ 267.5 $ 322.3 $ 340.7 $ 353.0 $ 354.6

Revenues ($ in millions)Residential $ 294.9 $ 309.5 $ 295.7 $ 291.1 $ 294.2Commercial 289.8 297.2 292.9 282.2 275.4Industrial 380.2 393.6 404.0 413.8 416.2Wholesale 92.8 92.9 29.6 51.1 73.8Other 35.1 44.2 42.3 34.5 47.9

Total $1,092.8 $1,137.4 $1,064.5 $1,072.7 $1,107.5

Sales (Gigawatt Hours)Residential 3,122.5 3,228.4 2,956.9 2,953.3 2,996.7Commercial 3,579.7 3,618.3 3,446.3 3,375.9 3,293.9Industrial 8,972.2 8,822.4 8,935.5 9,494.9 9,198.3Wholesale 2,623.2 2,983.5 845.0 1,546.9 2,587.0Other 141.6 123.3 127.6 121.9 138.7

Total 18,439.2 18,775.9 16,311.3 17,492.9 18,214.6

Cooling Degree Days 572 1,015 801 693 1,022Normal Cooling Degree Days 808 792 792 792 791% Warmer (Colder) than Normal (29)% 28% 1% (13)% 29%

Revenue per KWH (cents):Residential 9.44 9.59 10.00 9.86 9.82Commercial 8.10 8.21 8.50 8.36 8.36Industrial 4.24 4.46 4.52 4.36 4.52

Residential CustomersAverage annual KWH use per customer 8,045 8,388 7,752 7,774 7,960Average annual electric bill $ 759.81 $ 804.12 $ 775.22 $ 766.24 $ 781.44

Electric CustomersResidential 388,123 384,891 381,440 379,908 376,483Commercial 49,252 48,286 47,286 46,638 45,822Industrial 2,543 2,577 2,643 2,663 2,678Wholesale 21 22 23 37 37Other 794 799 801 806 815

Total 440,733 436,575 432,193 430,052 425,835

On June 20, 2002 a settlement agreement was filed with IURC regarding the electric rate review. The settlement agreement provides electric customers will receive a credit of $55Meach year for 49 months, beginning July 1, 2002.

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Electric Generation and Production StatisticsYear in Net KW

Unit Service Capability 2003 2002 2001 2000 1999

(Kilowatt-hours in Thousands)

Megawatt-hours Generated by Conventional Coal Fired Steam Turbine—Michigan City Generating Station:Units 2 and 3(a) 1951 120,000 (1725) (2,002) (1,210) 7,761 73,282Unit 12 1974 469,000 2,405,676 2,486,543 2,413,036 2,738,298 2,232,294

Station total 589,000 2,403,951 2,484,541 2,411,826 2,746,059 2,305,576

Dean H. Mitchell Generating Station:(b)

Unit 4 1956 125,000 0 (674) 374,324 230,560 255,785Unit 5 1959 125,000 0 (388) 321,140 513,071 455,982Unit 6 1959 125,000 0 (735) 555,396 564,095 612,514Unit 11 1970 110,000 0 32,114 520,028 567,465 502,649

Station total 485,000 0 30,317 1,770,888 1,875,191 1,826,930

Bailly Generating Station:Unit 7 1962 160,000 1,013,047 911,943 950,482 958,691 1,042,212Unit 8 1968 320,000 1,289,827 1,918,972 1,706,284 1,862,584 1,807,002

Station total 480,000 2,302,874 2,830,915 2,656,766 2,821,275 2,849,214

R. M. Schahfer Generating Station:Unit 14 1976 431,000 2,657,685 1,619,597 2,049,614 2,350,089 2,537,934Unit 15 1979 472,000 3,001,038 2,602,456 3,017,124 2,873,483 2,956,818Unit 17 1983 361,000 2,107,624 2,138,528 1,671,071 2,165,151 2,158,119Unit 18 1986 361,000 2,238,720 2,388,925 2,171,866 2,356,513 2,267,635

Station total 1,625,000 10,005,067 8,749,506 8,909,675 9,745,236 9,920,506

Total conventional steam generating stations 3,179,000 14,711,892 14,095,279 15,749,155 17,187,761 16,902,226

Megawatt-hours Generated by Gas Turbine—Dean H. Mitchell Generating Station:

Unit 9A 1966 17,400 0 0 969 805 3,559

Bailly Generating Station:Unit 10 1968 30,900 806 336 1,071 955 7,202

R. M. Schahfer Generating Station:Units 16A and 16B 1979 155,000 5,064 6,924 12,339 18,292 53,291

Total gas turbine generating stations 203,300 5,870 7,260 14,379 20,052 64,052

Megawatt-hours Generated by Hydroelectric—Oakdale 1925 6,000 32,253 22,827 40,280 24,932 23,537Norway 1923 4,000 22,355 24,855 30,196 17,208 22,118

Total hydroelectric 10,000 54,608 47,682 70,476 42,140 45,655

Total all generating stations 3,392,300 14,772,370 14,150,221 15,834,010 17,249,953 17,011,933

(a)Units 2 and 3 are fired on gas only.

(b)D. H. Mitchell Generating Station taken out of service January 2002.

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Fuel for Electric Generation

Coal Consumed by Generating Station for Electric Production (tons)2003 2002 2001 2000 1999

Michigan City 1,351,752 1,389,568 1,331,813 1,525,548 1,266,348Dean H. Mitchell(1) 0 22,560 1,094,636 1,123,902 1,048,459Bailly 1,084,259 1,358,927 1,290,955 1,342,092 1,395,161R. M. Schahfer 5,465,003 4,703,826 5,037,711 5,230,952 5,339,954

Total 7,901,014 7,474,881 8,755,115 9,222,494 9,049,922

Average Cost Per Ton of Coal Consumed(2) by Generating Station 2003 2002 2001 2000 1999

Michigan City $26.71 $26.97 $24.23 $25.15 $26.37Dean H. Mitchell(1) N/A.00 N/A0 $23.92 $21.94 $26.34Bailly $30.38 $30.00 $32.74 $28.73 $29.60R. M. Schahfer $27.13 $27.79 $25.49 $24.70 $25.12Average of all stations $27.50 $27.93 $26.17 $25.02 $26.13

Mills Per Net KWH Generated for all Fuels, Total M Therms Burned all Fuels, and Btu Per Net KWHGenerated

2003 2002 2001 2000 1999

Mills/net KWH generated 15.25 14.96 15.01 14.07 14.69Total M therms 1,630,234 1,567,534 1,770,762 1,900,768 1,865,170Btu/net KWH generated 11,091 11,039 11,440 11,138 11,117*

*Changed to net heat rate from net operating heat rate.

Fuel Mix for Electric Generation Including Purchased Power2003 2002 2001 2000 1999

Coal 76.9 72.4% 92.5% 93.9% 88.3%Oil 0.0 0.0 0.0 0.0 0.0Gas 0.0(3) 0.0 0.3 0.7 1.4Hydro 0.3 0.2 0.4 0.2 0.2Purchased Power 22.8 27.4 6.8 5.2 10.1

100.0% 100.0% 100.0% 100.0% 100.0%

(1)D. H. Mitchell Generating Station taken out of service January 2002.

(2)Includes the delivered cost of coal, fuel stock expense, ash handling and sale of slag.

(3)Gas usage was only .02% of total and rounded to 0.0%.

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Capacity and Operating Margins

Capacity and Operating Margins provide a method by which electrical resources are displayed to show thefuture electrical demands and energy requirements of the Northern Indiana Public Service Company’scustomers. Analyses are conducted in order to determine the optimum outcome of various electric resourceplans, which are necessary for customer demand and electric system reliability.

2003 2002 2001 2000 1999

Resources Available (at time of peak)

Net demonstrated capacity of units (MW) 3,392 3,392 3,392 3,392 3,392

Purchased power (MW) 827 774 98 282 322

Total resources of system (MW) 4,219 4,166 3,490 3,674 3,714

Scheduled outage (MW)* (502) (502) 0 0 0

Random unavailability (MW) (207) (245) (258) (316) (520)

Resources available to meet peak load (MW) 3,510 3,419 3,232 3,358 3,194

Total internal system peak demand (MW) 3,054 2,978 2,998 2,870 2,962

Capacity MarginsCapacity margin expresses the difference between total demonstrated resources and the internal system peakdemand, as a fraction of the total demonstrated resources. Capacity margin permits examination andcalculation of operating needs.

2003 2002 2001 2000 1999

Total resources of system (MW) 4,219 4,166 3,490 3,674 3,714


Capacity margin (MW) 1,165 1,188 492 804 752

Capacity margin (percent) 27.6% 28.5% 14.1% 21.9% 20.2%

Operating MarginsOperating margin is capacity margin less the demonstrated resources unavailable because of predictableevents such as scheduled outages and variable events such as random unavailability. Consideration of thesevariables explicitly incorporates the dimension of generation reliability into both utility operational and capacityplanning needs. The total internal system peak demand is subtracted from the resources available to meet peakdemand. This difference, divided by the total demonstrated resources and expressed as a percentage, is theoperating margin.

2003 2002 2001 2000 1999

Resources available to meet peak load (MW) 3,510 3,419 3,232 3,358 3,194


Operating margin (MW) 456 441 234 488 232

Operating margin (percent) 10.8% 10.6% 6.7% 13.3% 6.2%

Annual Load Factor 61.8% 66.3% 61.6% 66.2% 63.1%

*D.H. Mitchell Generating Station taken out of service January 2002 and is on indefinite shutdown.

Glossary of Selected Energy TermsBbl: (barrel or barrels) For petroleum, a unit of volume equal to 42

U.S. gallons. One barrel of crude oil is roughly equivalent to 6million Btu, or 6 thousand cubic feet of natural gas.

Bcf: (billions of cubic feet) A common measurement of a largevolume of natural gas. Gas volume is denominated in cubic feetby the thousands (Mcf), millions (MMcf), billions (Bcf) andtrillions (Tcf).

Block: Offshore area identified numerically.

Btu: Abbreviation for British thermal unit, a measure of heatingvalue — the quantity of heat required to raise the temperature ofone pound of water one degree Fahrenheit at sea level.

Cogeneration: A process that produces electrical and thermalenergy simultaneously from a single source, often natural gas.

Condensate: Hydrocarbons that exist in gaseous form inunderground formations that condense to liquids when broughtto the surface.

Cost Tracker Revenue: A special revenue provision approved bystate regulatory commissions to recover operating and capitalexpenses not contained in rate base.

Deferred Taxes: Income taxes resulting from the use of income taxlaw provisions which allow recognition of certain items ofrevenue and expense in the tax return prior to their beingrecorded on the books of the company. Deferred taxes do notconstitute earnings available to pay dividends to investors.

Degree-Day, Cooling: A measure of the need for air conditioning(cooling) based on temperature. A cooling degree-day measuresthe variations to the daily mean temperature above a referencetemperature. NiSource measures cooling degree-days relativeto a reference temperature of 65 degrees

Degree-Day, Heating: A measure of the coldness of the weatherbased on temperature. A heating degree-day measures thevariations to the daily mean temperature below a referencetemperature (estimated temperature at which heating loadbegins). NiSource uses a reference temperature that variesslightly across the region, resulting in a compositemeasurement based on 62 degrees.

Dekatherm: (Dt or Dth) A measure of heating value equal to onemillion Btus (MMBtu). One dekatherm is roughly equivalent toone thousand cubic feet (1 Mcf) of natural gas; specifically, for1998, the conversion factor for the production of dry natural gasis 1 Mcf equals 1.026 MMBtu (or, 1.026 dekatherm).

Derivatives: A financial instrument whose value is based on acommodity or other security, e.g., futures, options, swaps, andforwards. A derivative’s value changes with changes in one ormore underlying market variables, such as commodity prices,interest rates or foreign exchange rates.

Distributed Generation: A system of energy production that islocated at the point of use. It typically involves less than 500kilowatts of capacity and often includes provision for thermalenergy recovery and electric production.

Exchange Gas: Gas that is received from (or delivered to) anotherparty in exchange for gas delivered to (or received from) thatparty.

Exposure: A firm’s vulnerability to loss from unanticipated events.These events might include movement in financial marketvariables, such as foreign exchange rates, interest rates orcommodity prices.

Federal Energy Regulatory Commission (FERC): An independentfive-member commission within the Department of Energyresponsible for setting rates and charges for the wholesaletransportation and sale of natural gas and electricity; thelicensing of hydroelectric power projects; and for establishingrates or charges for the transportation of oil by pipeline, as wellas the valuation of such pipelines.

Firm Power, Electric: Power or power-producing capacity intendedto be available at all times during the period covered by acommitment, even under adverse conditions.

Firm Service: Service offered to customers under tariff authorityand associated contracts. It anticipates no interruptions otherthan unexpected and uncontrollable events.

Gigawatt: One billion watts.

Gigawatt Hour: (Gwh) the energy of one gigawatt supplied for onehour.

Interruptible Service: A reduced-cost gas transportation serviceoffered to customers that anticipates and permitsinterruptions on short notice.

Kilowatt (kw): 1,000 watts. A watt is a measure of the rate atwhich electricity is generated or consumed.

Liquefied Natural Gas (LNG): Natural gas that is converted to aliquid state by reducing its temperature to minus 260°F atatmospheric pressure. As a liquid, LNG takes up one six-hundredth of the space that the comparable gas vapor wouldrequire, allowing it to be stored economically in cryogenictanks, or transported in cryogenic ships.

MMBtu: One million Btu.

Market Center or Market Hub: An interchange where a shippercan gain access to multiple transportation paths, flexiblesupply/delivery points and, as a general rule, other servicessuch as imbalance protection, short-term storage (“parkingservice”) and gas lending or borrowing services.

Mark to Market: The daily adjustment of the value of derivativepositions to reflect profits and losses resulting from pricemovements occurring during the last trading session.

Megawatt (mw): The generating capacity of utility plants isexpressed in megawatts; a megawatt is 1,000 kilowatts or 1million watts.

Operating Margin: The difference between operating revenuesand the cost of sales. It is the contribution made to cover allother operating costs, fixed costs and profit margin.

Peak Day: The day of greatest total gas sendout.

Peak Load Demand: Electricity or gas supplied during a period ofthe greatest demand.

Rate Base: The amounts invested on which a regulatory agencyallows utilities to earn a return.

Risk Management: The process of identifying the risk-returntradeoffs available to a company in the course of its businessactivities and the process of developing and implementingplans which limit or reduce risks while simultaneouslyproviding an acceptable return.

Short-haul Transportation: A gas transportation service providedby a transmission company over short distances along itspipeline system.

Spot Market Gas: Natural gas purchased under short-termagreement by a gas utility or end user from sources otherthan pipeline companies.

Therm: A quantity of heat equivalent to 100,000 British thermal units (Btus).

Throughput: Total volume of gas delivered.

Transportation Rates: Rates charged by a gas utility when itsimply moves gas owned by a third party through its system.

Transportation Volumes: The volume of gas owned by othersreceived and transported through any part of thetransmission and distribution systems under a transportationtariff.

Underground Storage: A service that permits the injection oflarge quantities of natural gas into underground rockformations during periods of low market demand andwithdrawal during periods of peak market demand.

Utility Plant: All property and equipment used for the generation,transmission, and distribution of electricity and storage,transmission and distribution of gas.

Value at Risk: A commonly accepted probabilistic framework formeasuring market risk. It measures maximum estimatedlosses in market value of a position that can be expected tobe incurred until the position can be neutralized, liquidated orreassessed.

Volatility: The degree to which the price of a commodity orsecurity fluctuates around some mean value. It is usuallymeasured as the variance or standard deviation of the price.

Wheeling: Electric utility operation wherein transmissionfacilities of one system are used to transmit power producedby another system.

Board of Directors

Gary L. NealeChairman, President andChief Executive OfficerNiSource Inc.Merrillville, Indiana

Stephen P. AdikRetired Vice ChairmanNiSource Inc.Merrillville, Indiana

Dr. Steven C. BeeringPresident EmeritusPurdue UniversityWest Lafayette, Indiana

Arthur J. DecioChairman of the Board and DirectorSkyline CorporationElkhart, Indiana

Dennis E. FosterRetired Vice ChairmanALLTEL CorporationLittle Rock, Arkansas

Ian M. RollandRetired Chairman andChief Executive OfficerLincoln NationalCorporationFort Wayne, Indiana

John W. ThompsonChairman and Chief Executive OfficerSymantec Corp.Cupertino, California

Robert J. WelshChairman and Chief Executive OfficerWelsh Holdings, LLCMerrillville, Indiana

Dr. Carolyn Y. WooMartin J. Gillen Deanand Ray and Milann SiegfriedProfessor of Entrepreneurial StudiesUniversity of Notre DameMendoza College of BusinessNotre Dame, Indiana

Roger A. YoungRetired ChairmanBay State Gas CompanyWestborough, Massachusetts

NiSource Officers

Gary L. NealeChairman, President andChief Executive Officer

Samuel W. Miller, Jr.Executive Vice President and ChiefOperating Officer

Robert C. Skaggs, Jr.Executive Vice President, Regulated Revenue

Michael W. O’DonnellExecutive Vice President andChief Financial Officer

S. LaNette ZimmermanExecutive Vice President,Human Resources andCommunications

Peter V. Fazio, Jr.Executive Vice President and General Counsel

Mark D. WyckoffSenior Vice President

Arthur E. Smith, Jr.Senior Vice President and Environmental Counsel

Jeffrey W. GrossmanVice President and Controller

Barbara S. McKayVice President, Communications

Arthur A. PaquinVice President, Audit

Dennis E. SenchakVice President, Investor Relations,Assistant Treasurer and AssistantSecretary

David J. VajdaVice President and Treasurer

Gary W. PottorffSecretary

801 E. 86th AvenueMerrillville, Indiana 46410-6272

Security Contacts:Transfer Agent, Registrar, Shareholder Records and Dividend Disbursing Agent

Account Maintenance:Mellon Investor ServicesPO Box 3315South Hackensack, NJ 07606-1916

Registered/Overnight Delivery:Mellon Investor Services Stock Transfer Department 85 Challenger Road Overpeck Centre Ridgefield Park, NJ 07660

Phone Contact:(888) 884-7790

Web Site:www.melloninvestor.com

Investor Relations Contacts:Investor RelationsNiSource Inc.801 E. 86th Ave.Merrillville, IN 46410

Dennis E. SenchakVice President, Investor Relations,Assistant Treasurer and Assistant Secretary

[email protected](219) 647-6085

Randy G. HulenDirector, Investor Relations


Rae KozlowskiManager, Investor Relations


Internet: http://www.nisource.com

Shareholder Information:Shareholder ServicesNiSource Inc.801 E. 86th Ave.Merrillville, IN 46410

www.nisource.com

nisource statistical summary book2003

Economy & Finance