nisource statistical summary book2002

Gas Distribution

• 437,000 customers in Northern Indiana • NiSource Energy Technologies (Distributed Generation)

• Nearly 1,000 MW of cogeneration capacity

Gas

Transmission & Storage

• 3.2 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 (more than 670 Bcf of storage)

• Based in Appalachia• Proved gas reserves of 1.2 Tcf• Interest in 8,300 wells• Over 6,200 miles of gathering facilities

• 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

Electric Other

Exploration & Production

Electric Distribution

Generation

Wholesale Power Sales

Primary Energy

Other Operations

The NiSource Portfolio

NiSource Inc.

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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; Exploration and ProductionOperations; and Other.

Gas Distribution OperationsNiSource’s natural gas distribution operations serve more than 3.2 million customers in 9 states and operate over55,216 miles of pipeline. Through its wholly owned subsidiary, Columbia, NiSource owns five distributionsubsidiaries that provide natural gas to approximately 2.1 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 subsidiaries own and operate approximately 16,062 miles of interstatepipelines and operate one of the nation’s largest underground natural gas storage systems, capable of storingapproximately 670 billion cubic feet (Bcf ) of natural gas.

Electric OperationsNiSource generates and distributes electricity through its subsidiary Northern Indiana to approximately 437,000customers in 21 counties in the northern part of Indiana. Northern Indiana owns and has the ability to operate fourcoal-fired electric generating stations with a net capability of 3,179 megawatts (mw), four gas-fired combustionturbine generating units with a net capability of 203 mw and two hydroelectric generating plants with a net capabilityof 10 mw. (D. H. Mitchell Generating Station taken out of service January, 2002, 502 mw.)

Exploration and Production OperationsNiSource’s exploration and production subsidiary, Columbia Energy Resources, Inc. (Columbia Resources), is oneof the largest independent natural gas and oil producers in the Appalachian Basin. NiSource acquired ColumbiaResources as part of the Columbia acquisition on November 1, 2000. Columbia Resources produced nearly 55.4 billion cubic feet equivalent (Bcfe) of natural gas and oil for the twelve months ended December 31, 2002.Columbia Resources has financial interests in over 8,300 wells, and has net proven gas and oil reserve holdings of1.2 trillion cubic feet equivalent (Tcfe). Columbia Resources also owns and operates approximately 6,200 miles ofgathering pipelines.

OtherThe Other segment participates in energy-related services including gas marketing, power trading and venturesfocused on distributed power generation technologies, including cogeneration facilities, fuel cells and storagesystems.

GasDistribution

38%

ElectricOperations

27%

Gas Transmission& Storage

33%

Other/E&P<2%

2002 Business Segment Operating Income

Contents

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FINANCIAL

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

SHAREHOLDERS

Common Shareholders — State ..................................................................................................................15Common Shareholders ..................................................................................................................................15

BUSINESS SEGMENTS

Gas Distribution Statistics.............................................................................................................................16Gas Distribution Customers and Throughput Statistics by State .......................................................17Gas Transmission and Storage Statistics...............................................................................................18Gas Exploration and Production Statistics.............................................................................................19Gas and Oil Acreage ..................................................................................................................................19Production and Drilling Wells...................................................................................................................19

Electric Distribution Statistics ......................................................................................................................20Electric Generation and Production Statistics ......................................................................................21Fuel for Electric Generation......................................................................................................................22Capacity and Operating Margins.............................................................................................................23

Glossary of Selected Energy Terms.............................................................................................................24Board of Directors, NiSource Officers and Business Unit Officers.......................................................25Shareholder Information/Contacts..............................................................................................back cover

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Consolidated Financial Data and RatiosYear Ended December 31, ($ in millions) 2002 2001 2000 1999 1998

Return on average common equity 9.7% 6.3% 6.3% 12.8% 16.1%Times interest earned (pre-tax) 2.13 1.52 1.75 2.20 3.26 Dividends paid per share $ 1.16 $ 1.16 $ 1.08 $ 1.02 $ 0.96Dividend payout ratio 65.5% 110.5% 96.4% 79.1% 60.0%Market values during the year:

High $ 24.99 $ 32.55 $ 31.50 $ 30.50 $ 33.63 Low $ 14.51 $ 18.25 $ 12.81 $ 16.56 $ 24.75Close $ 20.00 $ 23.06 $ 30.75 $ 17.88 $ 30.44

Book value of common shares $ 16.78 $ 16.72 $ 16.59 $ 10.90 $ 9.78Market-to-book ratio at year end 119.2% 137.9% 185.4% 164.0% 311.2%Capitalization

Common shareholders’ equity $ 4,174.9 $ 3,469.4 $ 3,409.1 $ 1,353.5 $ 1,149.7Preferred and preference stock 84.9 88.6 132.7 139.6 142.0Company-obligated mandatorily redeemable preferred

securities of subsidiary trust holding solely Company debentures 345.0 345.0 345.0 345.0 —Long-term debt 5,018.0 6,301.0 5,802.7 1,775.8 1,555.8

Total Capitalization* $ 9,622.8 $10,204.5 $ 9,689.5 $ 3,613.9 $ 2,847.5Number of employees 9,307 12,501 14,674 7,399 6,035Operating Income (Loss)

Gas Distribution $ 459.1 $ 380.8 $ 241.0 $ 114.0 $ 65.1Gas Transmission and Storage 398.3 349.0 45.7 2.4 1.0Electric 322.3 340.7 353.0 354.6 365.0Exploration and Production 41.7 51.9 5.4 — —Other (34.3) (53.8) 80.4 19.1 (10.5)Corporate 4.3 (10.9) (114.9) (44.9) (13.1)Adjustments and eliminations 11.3 (24.8) 1.7 0.2 (0.1)Consolidated $ 1,202.7 $ 1,032.9 $ 612.3 $ 445.4 $ 407.4

Depreciation, Amortization and DepletionGas Distribution $ 189.2 $ 228.8 $ 146.7 $ 115.0 $ 74.7Gas Transmission and Storage 109.4 161.4 27.7 1.4 —Electric 172.2 166.8 162.8 158.5 156.8Exploration and Production 66.7 63.1 11.0 — —Other 26.4 10.2 23.4 15.5 9.3Corporate 10.3 10.4 4.5 4.6 0.9Adjustments and eliminations (0.2) 0.6 — — 0.1Consolidated $ 574.0 $ 641.3 $ 376.1 $ 295.0 $ 241.8

AssetsGas Distribution $ 5,391.9 $ 5,368.6 $ 5,792.7 $ 2,559.4 $ 1,192.2Gas Transmission and Storage 2,849.6 2,911.8 3,026.2 — —Electric 2,882.3 3,012.5 3,251.2 2,595.4 2,592.8Exploration and Production 1,173.4 1,181.3 946.6 — —Other* 1,440.4 1,309.7 2,474.9 1,023.5 526.1Corporate 9,581.6 13,249.4 13,275.0 1,615.6 672.3Adjustments and eliminations (6,422.3) (9,198.9) (9,079.5) (1,365.3) (388.0)Consolidated $16,896.9 $17,834.4 $19,687.1 $ 6,428.6 $ 4,595.4

Capital ExpendituresGas Distribution $ 196.4 $ 211.3 $ 138.3 $ 145.2 $ 63.0Gas Transmission and Storage 128.0 137.4 50.3 — —Electric 197.8 134.7 132.2 134.0 124.0Exploration and Production 90.8 118.8 22.7 — —Other 5.9 77.0 22.3 14.7 11.3Consolidated $ 618.9 $ 679.2 $ 365.8 $ 293.9 $ 198.3

*The change in the characterization of four Primary Energy projects from synthetic leases to two owned assets and two capital leases for financial reporting purposes is not included in 1998, 1999 and 2000 amounts. The balance sheet effect for these projects is to record fixed assets and the associated debt in the following amounts (in millions): $196.1 in 1998; $247.9 in 1999; and $460.4 in 2000.

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Consolidated Statement of IncomeYear Ended December 31, (in millions, except per share amounts) 2002 2001 2000 1999 1998

Net RevenuesGas Distribution $2,890.4 $3,849.9 $1,879.6 $ 883.8 $ 572.6 Gas Transportation and Storage 1,011.9 996.6 375.8 150.0 103.8 Electric 1,103.6 1,862.4 1,557.4 1,014.4 1,426.6 Exploration and Production 155.7 156.9 37.4 — —Other 1,330.7 2,595.2 2,179.2 1,230.2 740.9 Gross Revenues 6,492.3 9,461.0 6,029.4 3,278.4 2,843.9Cost of Sales 3,163.3 6,054.1 4,081.7 1,885.7 1,691.3

Total Net Revenues $3,329.0 $3,406.9 $1,947.7 $1,392.7 $1,152.6

Operating ExpensesOperation and maintenance 1,288.2 1,438.2 810.4 564.3 427.4Depreciation, depletion and amortization 574.0 641.3 376.1 295.0 241.8 Loss (gain) on sale or impairment of assets (27.2) (0.1) 10.3 (7.5) (4.7) Other taxes 291.3 294.6 138.6 95.5 80.7

Total Operating Expenses 2,126.3 2,374.0 1,335.4 947.3 745.2 Operating Income $1,202.7 $1,032.9 $ 612.3 $ 445.4 $ 407.4

Other Income (Deductions)Interest expense, net (526.1) (598.0) (304.5) (155.4) (120.2)Minority interest (20.4) (20.4) (20.4) (17.7) (0.7)Dividend requirements on preferred stock of subsidiaries (6.8) (7.5) (7.8) (8.1) (8.3)Other, net 10.2 10.2 (11.4) (28.1) 4.8

Total Other Income (Deductions) $ (543.1) $ (615.7) $ (344.1) $ (209.3) $ (124.4)Income From Continuing Operations before Income Taxes 659.6 417.2 268.2 236.1 283.0 Income Taxes 233.9 190.8 126.3 82.2 94.4 Income from Continuing Operations 425.7 226.4 141.9 153.9 188.6 Income (loss) from Discontinued Operations — net of taxes (9.4) (14.2) 9.0 6.5 5.3 Net loss on the Disposition of Discontinued

Operations — net of taxes (43.8) — — — — Change in accounting — net of taxes — 4.0 — — —Net Income $ 372.5 $ 216.2 $ 150.9 $ 160.4 $ 193.9

Basic Earnings (Loss) Per Share ($)Continuing operations $ 2.02 $ 1.10 $ 1.05 $ 1.24 $ 1.56 Discontinued operations (0.25) (0.07) 0.07 0.05 0.04 Change in accounting — 0.02 — — —

Basic Earnings Per Share $ 1.77 $ 1.05 $ 1.12 $ 1.29 $ 1.60

Diluted Earnings (Loss) Per Share ($)Continuing operations $ 2.00 $ 1.08 $ 1.04 $ 1.23 $ 1.55Discontinued operations (0.25) (0.07) 0.07 0.05 0.04Change in accounting — 0.02 — — —

Diluted Earnings Per Share $ 1.75 $ 1.03 $ 1.11 $ 1.28 $ 1.59Basic Average Common Shares Outstanding (millions) 211.0 205.3 134.5 124.3 120.8Diluted Average Common Shares (millions) 212.8 209.8 135.8 125.3 121.3

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

Years are not directly comparable due to the acquisition of Bay State Gas Co. in February 1999, EnergyUSA-TPC in April 1999, and Columbia Energy in November 2000. Also, in 2002,NiSource has discontinued the amortization of goodwill conistent with the Financial Accounting Standard Board No. 142.

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Consolidated Balance SheetsASSETS as of December 31, (in millions) 2002 2001 2000 1999 1998

Property, Plant and EquipmentUtility Plant $16,435.0 $15,991.4 $15,686.1 $ 7,490.7 $ 5,966.8Accumulated depreciation and amortization (7,998.2) (7,616.5) (7,299.3) (3,318.5) (2,860.0)

Net utility plant 8,436.8 8,374.9 8,386.8 4,172.2 3,106.8

Gas and oil producing properties, successful efforts method United States cost center 1,056.3 1,011.5 904.4 — —Canadian cost center 5.9 22.4 19.7 — —

Accumulated depletion (122.7) (74.6) (11.0) — —

Net gas and oil producing properties 939.5 959.3 913.1 — —

Other property, at cost, less accumulated depreciation 691.7 679.0 86.6 424.2 86.0

Net Property, Plant and Equipment 10,068.0 10,013.2 9,386.5 4,596.4 3,192.8

Investments and Other AssetsNet assets of discontinued operations 79.2 509.2 712.5 245.4 288.8Unconsolidated affiliates 118.8 124.0 96.1 151.7 152.9Assets held for sale 26.1 15.4 33.5 — —Other investments 50.7 47.8 54.0 32.7 28.7

Total Investments 274.8 696.4 896.1 429.8 470.4

Current AssetsCash and cash equivalents 54.3 118.1 141.5 34.2 57.2Restricted cash 1.9 9.8 51.1 7.3 1.5Accounts receivable, (less reserve

of $53.7 and $52.7 respectively) 580.1 667.5 1,450.7 307.6 158.1Unbilled revenue (less reserve of $3.5 and $3.8, respectively) 305.2 262.7 62.6 76.3 76.3Gas inventory 255.3 377.7 322.5 63.7 69.6Underrecovered gas and fuel costs 149.9 134.6 396.1 90.9 45.7Materials and supplies, at average cost 65.9 73.3 68.7 62.0 56.0Electric production fuel, at average cost 39.0 29.1 15.6 32.0 32.4Price risk management assets 66.6 249.7 1,558.5 90.7 —Exchange gas receivable 120.8 186.8 615.9 — —Prepayments and other 229.5 228.1 225.8 41.4 41.2

Total Current Assets 1,868.5 2,337.4 4,909.0 806.1 538.0

Other AssetsPrice risk management assets 116.9 69.3 32.6 — —Regulatory assets 608.8 517.1 517.1 206.4 157.4Goodwill 3,707.6 3,735.7 3,605.8 105.1 —Intangible assets 57.3 2.2 4.9 20.7 5.2Deferred charges and other 195.0 463.1 335.1 264.1 231.6

Total Other Assets 4,685.6 4,787.4 4,495.4 596.3 394.2

Total Assets* $16,896.9 $17,834.4 $19,687.1 $ 6,428.6 $ 4,595.4


Years are not directly comparable due to the acquisition of Bay State Gas Co. in February 1999, EnergyUSA-TPC in April 1999, and Columbia Energy in November 2000.

*The change in the characterization of four Primary Energy projects from synthetic leases to two owned assets and two capital leases for financial reporting purposes is not includedin 1998, 1999 and 2000 amounts. The balance sheet effect for these projects is to record fixed assets and the associated debt in the following amounts (in millions): $196.1 in 1998;$247.9 in 1999; and $460.4 in 2000.

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Consolidated Balance SheetsCAPITALIZATION AND LIABILITIES as of December 31, (in millions) 2002 2001 2000 1999 1998

Capitalization

Common Stock Equity $ 4,174.9 $ 3,469.4 $ 3,409.1 $1,353.5 $1,149.7

Preferred Stocks —

Series without mandatory redemption provisions 81.1 83.6 83.6 85.6 85.6

Series with mandatory redemption provisions 3.8 5.0 49.1 54.0 56.4

Company-obligated mandatorily redeemable preferred

securities of subsidiary trust holding solely Company

debentures 345.0 345.0 345.0 345.0 —

Long-term debt, excluding amounts due within one year 5,018.0 6,301.5 5,802.7 1,775.8 1,555.8

Total Capitalization $ 9,622.8 $10,204.5 $ 9,689.5 $3,613.9 $2,847.5

Current Liabilities

Current redeemable preferred stock subject to mandatory

redemption — 43.0 — — —

Current portion of long-term debt 1,232.6 423.6 64.8 173.5 93.4

Short-term borrowings 913.1 1,854.3 2,496.7 656.5 244.8

Accounts payable 521.6 613.4 1,119.3 255.8 245.0

Dividends declared on common and preferred stocks 1.1 1.8 1.0 34.5 31.1

Customer deposits 65.2 50.3 32.1 27.1 20.9

Taxes accrued 242.1 247.5 187.7 33.6 38.4

Interest accrued 88.3 79.6 78.0 29.9 19.1

Overrecovered gas and fuel costs 13.1 49.3 0.2 — —

Price risk management liabilities 44.9 243.1 1,529.2 113.0 —

Exchange gas payable 411.9 287.2 360.5 — —

Current deferred revenue 130.2 89.0 451.5 — —

Other accruals 513.3 669.1 549.4 144.9 93.1

Total Current Liabilities $ 4,177.4 $ 4,651.2 $ 6,870.4 $1,468.8 $ 785.8

Other Liabilities and Deferred Credits

Price risk management liabilities 3.2 10.8 39.4 — —

Deferred income taxes 1,861.7 1,725.0 1,798.2 962.3 632.6

Deferred investment tax credits 96.3 105.3 114.2 90.6 93.7

Deferred credits 145.0 133.5 318.4 92.0 63.8

Noncurrent deferred revenue 305.4 435.4 498.0 — —

Accrued liability for postretirement and pension benefits 417.2 288.9 272.5 143.5 132.1

Liabilities of discontinued operations 2.1 18.3 27.5 — —

Other noncurrent liabilities 265.8 261.5 59.0 57.5 39.9

Total Other 3,096.7 2,978.7 3,127.2 1,345.9 962.1

Commitments and Contingencies — — — — —

Total Capitalization and Liabilities* $16,896.9 $17,834.4 $19,687.1 $6,428.6 $4,595.4



*The change in the characterization of four Primary Energy projects from synthetic leases to two owned assets and two capital leases for financial reporting purposes is not includedin 1998, 1999 and 2000 amounts. The balance sheet effect for these projects is to record fixed assets and the associated debt in the following amounts (in millions): $196.1 in 1998;$247.9 in 1999; and $460.4 in 2000.

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Consolidated Statement of Cash FlowsYear Ended December 31, (in millions) 2002 2001 2000 1999 1998

Operating ActivitiesNet Income $ 372.5 $ 216.2 $ 150.9 $ 160.4 $ 193.9 Adjustments to reconcile net income to net cash from

continuing operations:Depreciation, depletion, and amortization 574.0 641.3 376.1 295.0 241.8Net changes in price risk management activities (22.3) (42.0) (89.8) 10.4 —Asset impairment — 0.1 65.8 28.3 —Deferred income taxes and investment tax credits 114.1 (37.0) 35.2 (17.3) (31.2)Deferred revenue (88.9) (425.1) (8.0) — —Stock compensation expense 27.1 30.0 6.8 3.5 1.9Gain on sale of assets (27.2) (11.0) (55.4) (7.5) (4.6)Income from change in accounting — (4.0) — — —Gain on sale of discontinued operations 43.8 — — — —Income from discontinued operations 9.4 14.2 (9.0) (6.5) (5.3)Other, net 20.5 (24.6) 27.0 (11.6) (2.1)

Changes in assets and liabilities, net of effect from acquisitions of businesses:Accounts receivable, net 102.7 551.5 (754.3) 52.7 (31.3)Inventories 66.8 (73.3) 13.0 46.4 (20.2)Accounts payable (91.6) (495.5) 629.4 (128.6) 13.3Taxes accrued (5.4) 142.1 (51.1) (6.4) (10.7)(Under) Overrecovered gas and fuel costs (51.5) 312.3 (198.5) (12.8) 53.2Exchange gas receivable/payable 190.7 355.8 58.6 — —Other accruals (136.5) 157.0 (131.5) 3.8 (14.6)Other working capital 90.4 (213.7) (95.9) 2.5 62.4

Net Cash Flows from Continuing Operations 1,188.6 1,094.3 (30.7) 412.3 446.5Net Cash Flows from Discontinued Operations (16.2) (34.0) (28.7) — —Net Cash Flows from Operating Activities $ 1,172.4 $ 1,060.3 $ (59.4) $ 412.3 $ 446.5Investing Activities

Capital expenditures (621.9) (644.1) (357.3) (313.0) (219.1)Acquisition of businesses — — (5,654.5) (725.8) —Proceeds from disposition of assets 419.2 227.9 535.2 29.8 10.4Other investing activities — (7.0) 9.2 (49.1) (16.2)

Net Cash Flows from Investing Activities $ (202.7) $ (423.2) $(5,467.4) $(1,058.1) $(224.9)Financing Activities

Issuance of long-term debt — 300.0 2,629.3 189.2 47.4Retirement of long-term debt (532.1) (93.0) (488.1) (201.0) (94.6)Change in short-term debt (941.2) (642.5) 1,655.4 229.1 166.1Retirement of preferred shares (46.7) (1.1) (6.9) (2.4) (2.4)Proceeds from Corporate Premium Income Equity

Securities, net — — — 334.7 —Issuance of common stock 734.9 15.1 2,042.1 324.9 10.4Acquisition of treasury stock (6.9) — (65.9) (126.5) (204.0)Dividends paid — common shares (241.5) (239.0) (131.8) (125.2) (116.9)

Net Cash Flows from Financing Activities (1,033.5) (660.5) 5,634.1 622.8 (194.0)Increase (decrease) in cash and cash equivalents (63.8) (23.4) 107.3 (23.0) 27.6Cash and cash equivalents at beginning of year 118.1 141.5 34.2 57.2 29.6Cash and cash equivalents at end of period $ 54.3 $ 118.1 $ 141.5 $ 34.2 $ 57.2Supplemental Disclosures of Cash Flow Information

Cash paid for interest, net of amounts capitalized $ 496.6 $ 518.0 $ 244.5 $ 152.7 $ 112.5Interest capitalized $ 4.3 $ 4.3 $ 3.9 $ 0.7 $ 0.6Cash paid for income taxes $ 118.8 $ 250.2 $ 227.0 $ 115.8 $ 115.1



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Consolidated Statement of CapitalizationAs of December 31, (in millions) 2002 2001 2000

Common shareholders’ equity $4,174.9 $ 3,469.4 $3,409.1

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 2.8 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 83.6 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 — 11,136 and 16,690 shares

outstanding, respectively 1.1 1.7 2.2

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

outstanding, respectively 2.7 3.3 3.9

Cumulative preferred stock — no par value —

6.5% series — 0, 0 and 430,000 shares outstanding — — 43.0

Series with mandatory redemption provisions 3.8 5.0 49.1

Company-obligated mandatorily redeemable

preferred securities of subsidiary trust

holding solely Company debentures 345.0 345.0 345.0

Long-term debt 5,018.0 6,301.5 5,802.7

Total Capitalization* $9,622.8 $10,204.5 $9,689.5


Years are not directly comparable due to the acquisition of Columbia Energy in November 2000.

*The change in the characterization of four Primary Energy projects from synthetic leases to two owned assets and two capital leases for financial reportingpurposes is not included in the 2000 amounts. The balance sheet effect for these projects is to record fixed assets and the associated debt in the followingamount (in millions): $460.4 in 2000.

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Consolidated Statement of Long-Term DebtAs of December 31, (in millions) 2002 2001 2000

NiSource Inc.:Debentures due November 1, 2006, with interest imputed at 5.88% (SAILSSM) $ 126.0 $ 116.9 $ 108.5

Bay State Gas Company: Medium-Term Notes —

Interest rates between 6.26% and 9.20% with a weighted average interest rate of 7.08% and maturities between June 21, 2005 and February 15, 2028 80.5 95.5 168.5

Northern Utilities: Medium-Term Note — Interest rate of 6.93% and maturity of September 1, 2010 5.8 5.8 7.5Medium-Term Note — Interest rate of 9.70% and maturity of September 1, 2031 — 13.0 13.0

Total long-term debt of Bay State Gas Company 86.3 114.3 189.0Columbia Energy Group:

Debentures —6.61% Series B — due November 28, 2002 — — 281.56.80% 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 229.2 229.2 229.2Fair value adjustment of debentures for interest rate swap agreements 30.6 — —

Total 1,385.8 1,355.2 1,636.7Unamortized discount on long-term debt (108.0) (118.7) (130.5)Subsidiary debt — Capitalized lease obligations 2.0 2.2 2.4

Total long-term debt of Columbia Energy Group 1,279.8 1,238.7 1,508.6EnergyUSA, Inc. and Subsidiaries:

Notes PayableInterest rates between 6.12% and 12.00% with a weighted average interest rate

of 8.72% and various maturities between September 6, 2003 and February 6, 2010 — — 2.3Total long-term debt of EnergyUSA, Inc. — — 2.3

Primary Energy, Inc.*Long-Term Notes —

Whiting Clean Energy, Inc.— Interest rate of 8.18% and maturity of June 20, 2011 302.4 284.4 —Ironside — Interest rate of 8.00% and maturity of September 30, 2012 — 60.7 —

Capital Lease Obligation—Portside Energy Corporation 51.0 52.5 —Cokenergy, Inc. 117.6 123.1 —

Total long-term debt of Primary Energy, Inc. 471.0 520.7 —NiSource Capital Markets, Inc.:

Subordinated Debentures —Series A, 73⁄4%, due March 31, 2026 75.0 75.0 75.0Senior Notes Payable — 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 1, 2004 and May 5, 2027 300.0 300.0 300.0

Total long-term debt of NiSource Capital Markets, Inc. 450.0 450.0 450.0Indianapolis Water Company:

Medium-term notes —Medium-Term Notes —Interest rates of 5.99% and 6.61% with a weighted average

interest rate of 6.34% and maturities of February 1, 2009 and February 1, 2019 — 80.0 —Total 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 8.11% and maturities between January 1, 2004 and January 1, 2008 5.1 8.2 16.9

Total long-term debt of NiSource Development Company, Inc. 5.1 8.2 16.9NiSource Finance Corp.:

Long-Term Notes —53⁄4% — due April 15, 2003 — 300.0 —71⁄2% — due November 15, 2003 — 750.0 750.075⁄8% — due November 15, 2005 900.0 900.0 900.077⁄8% — due November 15, 2010 1,000.0 1,000.0 1,000.0

Unamortized discount on long-term debt (13.6) (20.4) (24.4)Total long-term debt of NiSource Finance Corp., Inc. 1,886.4 2,929.6 2,625.6

Northern Indiana Public Service Company: First mortgage bonds —

Series T, 71⁄2% — due April 1, 2002 — — 38.0Series NN, 7.10%— due July 1, 2017 55.0 55.0 55.0

Pollution control notes and bonds —Issued at interest rates between 1.14% and 1.40%, with a weighted average interest rate of 1.28%

and various maturities between November 1, 2007 and April 1, 2019 223.0 229.0 233.5Medium-term notes—

Issued at interest rates between 6.50% and 7.69%, with a weighted average interest rate of 7.19% and various maturities between July 8, 2004 and August 4, 2027 437.5 561.5 578.0

Unamortized premium and discount on long-term debt, net (2.1) (2.4) (2.7)Total long-term debt of Northern Indiana Public Service Company 713.4 843.1 901.8

Total long-term debt, excluding amount due within one year $5,018.0 $6,301.5 $5,802.7


*The change in the characterization of four Primary Energy projects from synthetic leases to two owned assets and two capital leases for financial reportingpurposes is not included in the 2000 amounts. The balance sheet effect for these projects is to record fixed assets and the associated debt in the followingamount (in millions): $460.4 in 2000.

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Income TaxesYear Ended December 31, (in millions) 2002 2001 2000

Income TaxesCurrent

Federal $122.6 $195.5 $ 81.2State (2.8) 32.3 14.2

Total Current 119.8 227.8 95.4Deferred

Federal 84.2 (34.2) 35.6State 38.9 6.2 3.1

Total Deferred 123.1 (28.0) 38.7Deferred Investment Credits (9.0) (9.0) (7.8)Income Taxes Included in Continuing Operations $233.9 $190.8 $126.3

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) 2002 2001 2000

Book income from Continuing Operations before income taxes $659.6 $417.2 $268.2

Tax expense at statutory Federal income tax rate 230.9 35.0% 146.0 35.0% 93.9 35.0%Increases (reductions) in taxes resulting from:

Book depreciation over related tax depreciation (2.2) (0.3) (0.1) — (1.6) (0.6)Amortization of deferred investment tax credits (9.0) (1.3) (9.0) (2.2) (7.8) (2.9)State income taxes, net of federal income tax benefit 23.4 3.5 25.0 6.0 10.2 3.8Low-income housing/Section 29 credits (7.0) (1.1) (7.0) (1.7) (5.8) (2.2)Nondeductible amounts related to amortization of

intangible assets and plant acquisition adjustments — — 33.1 7.9 8.8 3.3Basis and stock sale differences — — — — 19.2 7.2Other, net (2.2) (0.3) 2.8 0.7 9.4 3.5

Income Taxes from Continuing Operations $233.9 35.5% $190.8 45.7% $126.3 47.1%

Deferred income taxes result 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 liabilityare as follows:At December 31, (in millions) 2002 2001 2000

Deferred tax liabilitiesAccelerated depreciation and other property differences $1,842.0 $1,829.9 $1,768.1Unrecovered gas and fuel costs 46.7 28.1 138.1Other regulatory assets 238.4 193.0 23.4SFAS No. 133 and price risk adjustments 40.6 18.8 63.9Premiums and discounts associated with long-term debt 48.4 56.0 58.8

Total Deferred Tax Liabilities 2,216.1 2,125.8 2,052.3Deferred tax assets

Deferred investment tax credits and other regulatory liabilities (62.4) (63.6) (69.0)Pension and other postretirement/postemployment benefits (167.7) (93.7) (63.0)Environmental liabilities (41.2) (44.6) (15.9)Other accrued liabilities (53.2) (62.5) (32.7)Other, net (37.8) (117.1) (59.3)

Total Deferred Tax Assets (362.3) (381.5) (239.9)Less: Deferred income taxes related to current assets and liabilities (7.9) 19.3 14.2Non-Current Deferred Tax Liability $1,861.7 $1,725.0 $1,798.2


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Consolidated Statement of Common Shareholders’ Equity

AccumulatedAdditional Other

Common Treasury Paid-In Retained Comprehensive Comprehensive(in millions) Stock Stock Capital Earnings Other Income Total Income

Balance January 1, 2000 $ 870.9 $(472.5) $ 174.4 $ 774.4 $ 1.1 $ 5.1 $1,353.4Comprehensive Income:

Net Income 150.9 150.9 $150.9Other comprehensive income, net of tax:

Gain/loss on available for sale securities:Unrealized (3.2) (3.2) (3.2)Realized 2.1 2.1 2.1

Gain/loss on foreign currency translation:Unrealized 0.4 0.4 0.4

Total comprehensive income $150.2Dividends:

Common stock (98.3) (98.3)Treasury stock acquired (65.9) (65.9)Issued:

Columbia acquisition 0.7 1,760.5 1,761.2Reduction of credit facility 0.1 280.8 280.9Long-term incentive plan — 22.7 14.4 (26.2) 10.9Formation of new NiSource (869.7) 515.1 354.6 —

Amortization of unearned compensation 6.8 6.8Equity contract costs 7.7 7.7Other 0.6 4.9 (3.3) 2.2Balance December 31, 2000 $ 2.0 $ 0.0 $2,597.3 $ 823.7 $(18.3) $ 4.4 $3,409.1Comprehensive Income:



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 unrealized gains on derivatives qualifying as cash flow hedges 17.7 17.7 17.7

Minumum 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) $ 4,174.9


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Consolidated Statement of Common Shareholders’ Equity (Continued)

Common TreasuryShares (in thousands) Shares Shares

Balance January 1, 2000 147,784 (23,645)Treasury stock acquired (3,971)Issued:

Columbia aquisition 72,453 —Stock issuance 11,500 —Employee stock purchase plan — 62Long-term incentive plan 226 1,144

Treasury stock cancelled (26,410) 26,410Balance December 31, 2000 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 41,400Employee stock purchase plan 43 —Long-term incentive plan 275 —

Balance December 31, 2002 249,210 (350)


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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 A–

Preferred Stock Baa3 BB+ BBB+

NiSource Inc.


Senior Unsecured Baa3 BBB BBB

Commercial Paper Prime-3 A-2 F-2

Common Shareholders—State

Common Shareholders

Geographical Breakdown of Shareholders by State:

Percent PercentState Holders of Total *Shares of TotalAlabama 194 0.41% 79,595 0.03% Alaska 30 0.06% 7,385 0.00%Arizona 545 1.15% 249,684 0.10%Arkansas 145 0.31% 49,499 0.02%California 2,122 4.47% 1,047,737 0.42%Colorado 400 0.84% 238,573 0.10%Connecticut 866 1.82% 368,156 0.15%Delaware 108 0.23% 32,487 0.01%Dist. of Columbia 80 0.17% 66,900 0.03%Florida 2,315 4.88% 1,090,208 0.44%Georgia 412 0.87% 220,536 0.09%Hawaii 74 0.16% 31,750 0.01%Idaho 58 0.12% 25,446 0.01%Illinois 3,877 8.17% 1,972,863 0.79%Indiana 13,236 27.88% 9,418,680 3.78%Iowa 312 0.66% 146,816 0.06%Kansas 186 0.39% 60,577 0.02%Kentucky 519 1.09% 254,672 0.10%Louisiana 251 0.53% 76,090 0.03%Maine 267 0.56% 104,639 0.04%Maryland 870 1.83% 330,505 0.13%Massachusetts 2,288 4.82% 1,878,888 0.75%Michigan 1,566 3.30% 821,394 0.33%Minnesota 538 1.13% 233,269 0.09%Mississippi 93 0.20% 29,057 0.01%Missouri 488 1.03% 259,832 0.10%Montana 69 0.15% 20,302 0.01%Nebraska 120 0.25% 62,934 0.03%Nevada 166 0.35% 111,200 0.04%New Hampshire 280 0.59% 126,524 0.05%

Percent PercentState Holders of Total Shares of TotalNew Jersey 1,489 3.14% 9,161,469 3.68%New Mexico 110 0.23% 63,669 0.03%New York 2,743 5.78% 216,071,582 86.70%North Carolina 518 1.09% 209,053 0.08%North Dakota 46 0.10% 31,292 0.01%Ohio 2,615 5.51% 1,123,919 0.45%Oklahoma 146 0.31% 44,364 0.02%Oregon 202 0.43% 73,943 0.03%Pennsylvania 1,727 3.64% 720,137 0.29%Rhode Island 138 0.29% 65,987 0.03%South Carolina 227 0.48% 78,923 0.03%South Dakota 65 0.14% 32,008 0.01%Tennessee 269 0.57% 117,646 0.05%Texas 1,112 2.34% 432,692 0.17%Utah 78 0.16% 20,963 0.01%Vermont 80 0.17% 30,807 0.01%Virginia 1,096 2.31% 547,896 0.22%Washington 353 0.74% 140,931 0.06%West Virginia 660 1.39% 265,041 0.11%Wisconsin 1,138 2.40% 507,849 0.20%Wyoming 38 0.08% 15,601 0.01%Canada 44 0.09% 14,712 0.01%Other Foreign 103 0.22% 23,154 0.01%

Totals 47,472 100.00% 249,209,836 100.00%Less Treasury Shares 349,658Total Shares Outstanding 248,860,178

December 31, 2002 Number Percent Number PercentHolder Category of Holders of Holders of Shares of Shares

Joint Tenants—Survivorship Rights 12,656 26.66% 6,945,370 2.79%Individual—Female 12,135 25.56% 4,985,982 2.00%Individual—Male 14,790 31.16% 8,103,492 3.25%Corporations 668 1.41% 9,220,312 3.70%Depositories 6 0.01% 215,015,530 86.27%Nominee 10 0.02% 11,533 0.00%Trusts 7,022 14.79% 4,815,286 1.93%Miscellaneous 185 0.39% 112,331 0.05%Total 47,472 100.00% 249,209,836 100.00%Share Size %3,331 to 33.9 Shares 8,977 18.91% 119,833 0.05%3, 34 to 49.9 Shares 2,342 4.93% 95,765 0.04%3, 50 to 99.9 Shares 5,400 11.38% 390,003 0.16%3,100 to 300.9 Shares 13,500 28.44% 2,491,666 1.00%3,301 to 500.9 Shares 5,706 12.02% 2,244,826 0.90%3,501 to 1,000.9 Shares 6,016 12.67% 4,325,425 1.74%1,001 and over 5,531 11.65% 239,542,316 96.12Total 47,472 100.00% 249,209,836 100.00%

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Year Ended December 31, (in millions) 2002 2001 2000 1999 1998

Net RevenuesSales revenues $2,905.4 $3,890.5 $1,980.5 $ 966.6 $611.4Less: Cost of gas sold 1,921.6 2,887.9 1,415.9 588.8 376.1Net Sales Revenues 983.8 1,002.6 564.6 377.8 235.3Net Transporation Revenues 405.0 389.8 171.4 75.1 39.9

Net Revenues 1,388.8 1,392.4 736.0 452.9 275.2

Operating ExpensesOperation and maintenance 589.6 638.1 280.2 189.1 113.1Depreciation and amortization 189.2 228.8 146.7 115.0 74.7Other taxes 150.9 144.7 68.1 34.8 22.3

Total Operating Expenses 929.7 1,011.6 495.0 338.9 210.1Operating Income $ 459.1 $ 380.8 $ 241.0 $ 114.0 $ 65.1

Revenues ($ in Millions)Sales

Residential 1,785.8 2,231.6 1,250.4 572.1 385.0Commercial 629.2 842.4 446.5 207.5 124.9Industrial and Other 490.4 816.5 283.6 187.0 101.5

Total Sales 2905.4 3,890.5 1,980.5 966.6 611.4Transportation 405.0 389.8 171.4 75.1 39.9Total $3,310.4 $4,280.3 $2,151.9 $1,041.7 $651.3

Throughput (MDth)Sales

Residential 223.4 220.3 142.4 94.2 62.2Commercial 84.1 92.8 57.3 39.2 23.5Industrial and Other 79.6 186.0 35.1 54.1 44.1

Total Sales 387.1 499.1 234.8 187.5 129.8Transportation 536.7 507.7 304.6 263.1 177.8Total Throughput 923.8 1,006.8 539.4 450.6 307.6

Heating Degree DaysActual 4,757 4,500 4,965 5,593 5,097Normal 5,129 5,144 5,173 6,104 6,104% Colder (Warmer) than Normal (7)% (13)% (4)% (8)% (16)%

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Customers and Throughput Statistics by State

Customers (as of December 31, 2002) 2002 2001 2000 1999 1998

Residential 2,319,656 2,294,395 2,352,219 939,426 675,782Commercial 216,170 213,099 216,346 85,632 53,061Industrial and Other 5,884 5,856 5,976 3,857 3,872Transportation 705,514 721,075 637,075 42,306 6,685Total Customers 3,247,224 3,234,425 3,211,616 1,071,221 739,4000

Customers by State Indiana Ohio Kentucky Pennsylvania Maryland

Residential 669,994 829,193 82,002 250,572 26,100Commercial 54,531 63,181 9,344 31,730 3,450Industrial and Other 3,672 1,426 116 351 23Transportation 42,395 483,490 49,893 114,221 2,073Total 770,592 1,377,290 141,355 396,874 31,646

NewCustomers by State, cont. Virginia Hampshire Maine Massachussets Total

Residential 172,877 19,730 17,535 251,654 2,319,656Commercial 18,347 5,761 7,026 22,800 216,170Industrial and Other 296 — — — 5,884Transportation 8,938 110 178 4,215 705,514Total 200,458 25,601 24,739 278,669 3,247,224

Throughput by State (MDth) Indiana Ohio Kentucky Pennsylvania Maryland

Residential 71,050 79,497 6,631 24,657 2,274Commercial 25,300 17,175 3,086 11,717 1,510Industrial and Other 14,110 620 212 396 18Transportation 157,680 205,964 27,254 49,034 3,041Off System Sales 6,180 39,168 5,796 7,827 1,441Total 274,320 342,424 42,979 93,631 8,284

NewThroughput by State (MDth), cont. Virginia Hampshire Maine Massachussets Total

Residential 12,867 1,589 992 23,826 223,384Commercial 8,835 2,840 3,167 10,629 84,259Industrial and Other 1,399 — — — 16,755Transportation 5,530 1,732 3,250 33,141 536,396Off System Sales 2,658 — — — 63,070Total 81,059 6,161 7,409 67,596 923,864

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

Operating Revenues

Transportation revenues $ 730.4 $ 756.7 $ 199.9

Storage revenues 178.9 178.9 29.9

Other revenues 12.9 28.1 1.8

Total Operating Revenues 922.2 963.7 231.6

Less: Cost of gas sold 47.8 80.1 62.5

Net Revenues 874.4 883.6 169.1

Operating Expenses

Operation and maintenance 316.2 321.0 68.8

Depreciation and amortization 109.4 161.4 27.7

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

Other taxes 52.7 52.2 10.0

Total Operating Expenses 476.1 534.6 123.4

Operating Income $ 398.3 $ 349.0 $ 45.7

Throughput (MDth)

Columbia Transmission

Market Area 1,043.8 970.2 285.0

Columbia Gulf

Mainline 614.4 626.3 114.2

Short-haul 146.9 184.7 28.8

Columbia Deep Water 0.7 2.9 0.1

Crossroads Gas Pipeline 29.2 37.4 40.7

Granite State Pipeline 33.2 29.1 36.4

Intrasegment eliminations (553.9) (609.3) (109.8)

Total 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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Gas Exploration and Production StatisticsYear Ended December 31, (in millions) 2002 2001 2000

Operating RevenuesGas revenues $185.7 $219.3 $37.4Gathering revenues 10.6 10.4 1.8Other revenues 10.4 3.0 1.4

Total Operating Revenues 206.7 232.7 40.6Operating Expenses

Operation and maintenance 82.1 100.2 21.2Depreciation and depletion 66.7 63.1 11.0Loss on sale or impairment of assets 0.3 — —Other taxes 15.9 17.5 3.0

Total Operating Expenses 165.0 180.8 35.2Operating Income $ 41.7 $ 51.9 $ 5.4Gas Production StatisticsAverage Sales Price ($ per Mcf)

U.S. 3.45 4.04 3.98Canada 2.52 3.99 4.52

Production (Bcf)U.S. 54.2 54.0 9.5Canada — 0.1 —

Total 54.2 54.1 9.5Oil and Liquids Production StatisticsAverage Sales Price ($ per Bbl)

U.S. 19.01 22.52 29.16Canada 22.81 23.63 36.28

Production (000 Bbls)U.S. 201.60 212.90 24.90Canada 4.80 11.40 1.60

Total 206.40 224.30 26.50

Gas and Oil Acreage Developed Acreage% Undeveloped Acreage%as of December 31, (thousands) Gross Net% Gross Net%United States

Kentucky 504 447% 130 117%New York 170 165% 411 373%Ohio 196 167% 105 93%Pennsylvania 193 185% 17 16%Virginia 191 173% 96 43%West Virginia 1,151 915% 749 324%Other 21 15% 6 5

Canada 0 0% 1,408 703Total Acreage 2,425 2,068 2,922 1,674

Productive Wells% Wells Drilling%Production and Drilling Wells **Gross* Netas of December 31, Gas Oil Gas Oil Gross Net

United States 8,215 111 7,740 72 10 8Canada 0 4 3 3 0 0Total 8,215 115 7,743 75 10 8*Includes 641 multiple completion gas wells and 1 oil well, all of which are included as single wells in the table.

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) 2002 2001 2000 1999 1998

Net Revenues:Sales revenues $1,137.4 $1,064.5 $1,072.7 $1,107.5 $1,076.1Less: Cost of sales 369.0 277.6 274.6 316.1 292.6

Net Revenues 768.4 786.9 798.1 791.4 783.5

Operating Expenses:Operation and maintenance 222.8 223.3 234.3 225.2 210.1Depreciation and amortization 172.2 166.8 162.8 158.5 156.8Other taxes 51.1 56.1 48.0 53.1 51.6

Total Operating Expenses 446.1 446.2 445.1 436.8 418.5Operating Income $ 322.3 $ 340.7 $ 353.0 $ 354.6 $ 365.0

Revenues ($ in millions):Residential $ 309.5 $ 295.7 $ 291.1 $ 294.2 $ 290.7Commercial 297.2 292.9 282.2 275.4 268.0Industrial 393.6 404.0 413.8 416.2 405.3Wholesale 92.9 29.6 51.1 73.8 76.6Other* 44.2 42.3 34.5 47.9 35.5

Total $1,137.4 $1,064.5 $1,072.7 $1,107.5 $1,076.1

Sales (Gigawatt Hours):Residential 3,228.4 2,956.9 2,953.3 2,996.7 2,936.8Commercial 3,618.3 3,446.3 3,375.9 3,293.9 3,162.5Industrial 8,822.4 8,935.5 9,494.9 9,198.3 8,794.4Wholesale 2,983.5 845.0 1,546.9 2,587.0 2,046.6Other 123.3 127.6 121.9 138.7 121.7

Total 18,775.9 16,311.3 17,492.9 18,214.6 17,062.0

Customers Served at Year End:Residential 384,891 381,440 379,908 376,483 372,383Commercial 48,286 47,286 46,638 45,822 44,961Industrial 2,577 2,643 2,663 2,678 2,737Wholesale 22 23 37 37 —Other 799 801 806 815 868

Total 436,575 432,193 430,052 425,835 420,949

Revenue per KWH (cents):Residential 9.59 10.00 9.85 9.81 9.90Commercial 8.21 8.50 8.36 8.38 8.47Industrial 4.46 4.52 4.37 4.53 4.61

Residential Customers Average annual KWH use per customer 8,439 7,757 7,817 8,009 7,931Average annual electric bill $809.03 $769.51 $770.49 $786.31 $ 785.14

Cooling Degree DaysActual 1015 801 693 1,022 1,014Normal 792 792 792 791 791% Warmer (colder) than Normal 28% 1% (13%) 29% 28%

**Includes deferred fuel cost revenue.

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 $55M

each year for 49 months, beginning July 1, 2002.

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Electric Generation and Production StatisticsYear in Net KW

Unit Service Capability 2002 2001 2000 1999 1998

(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 (2,002) (1,210) 7,761 73,282 98,066Unit 12 1974 469,000 2,486,543 2,413,036 2,738,298 2,232,294 2,378,065

Station total 589,000 2,484,541 2,411,826 2,746,059 2,305,576 2,476,131

Dean H. Mitchell Generating Station:(b)

Unit 4 1956 125,000 (674) 374,324 230,560 255,785 382,206Unit 5 1959 125,000 (388) 321,140 513,071 455,982 427,671Unit 6 1959 125,000 (735) 555,396 564,095 612,514 564,975Unit 11 1970 110,000 32,114 520,028 567,465 502,649 516,045

Station total 485,000 30,317 1,770,888 1,875,191 1,826,930 1,890,897

Bailly Generating Station:Unit 7 1962 160,000 911,943 950,482 958,691 1,042,212 899,546Unit 8 1968 320,000 1,918,972 1,706,284 1,862,584 1,807,002 1,869,017

Station total 480,000 2,830,915 2,656,766 2,821,275 2,849,214 2,768,581

R. M. Schahfer Generating Station:Unit 14 1976 431,000 1,619,597 2,049,614 2,350,089 2,537,934 2,359,318Unit 15 1979 472,000 2,602,456 3,017,124 2,873,483 2,956,818 2,417,815Unit 17 1983 361,000 2,138,528 1,671,071 2,165,151 2,158,119 2,164,154Unit 18 1986 361,000 2,388,925 2,171,866 2,356,513 2,267,635 2,321,317

Station total 1,625,000 8,749,506 8,909,675 9,745,236 9,920,506 9,262,604

Total conventional steam generating stations 3,179,000 14,095,279 15,749,155 17,187,761 16,902,226 16,398,213

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

Unit 9A 1966 17,400 0 969 805 3,559 3,687

Bailly Generating Station:Unit 10 1968 30,900 336 1,071 955 7,202 4,549

R. M. Schahfer Generating Station:Units 16A and 16B 1979 155,000 6,924 12,339 18,292 53,291 64,692

Total gas turbine generating stations 203,300 7,260 14,379 20,052 64,052 72,928

Megawatt-hours Generated by Hydroelectric—Oakdale 1925 6,000 22,827 40,280 24,932 23,537 46,716Norway 1923 4,000 24,855 30,196 17,208 22,118 34,806

Total hydroelectric 10,000 47,682 70,476 42,140 45,655 81,522

Total all generating stations 3,392,300 14,150,221 15,834,010 17,249,953 17,011,933 16,552,663

(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)2002 2001 2000 1999 1998

Michigan City 1,389,568 1,331,813 1,525,548 1,266,348 1,378,956Dean H. Mitchell(1) 22,560 1,094,636 1,123,902 1,048,459 1,062,239Bailly 1,358,927 1,290,955 1,342,092 1,395,161 1,355,987R. M. Schahfer 4,703,826 5,037,711 5,230,952 5,339,954 5,014,968

Total 7,474,881 8,755,115 9,222,494 9,049,922 8,812,150

Average Cost Per Ton of Coal Consumed(2) by Generating Station

2002 2001 2000 1999 1998

Michigan City $26.97 $24.23 $25.15 $26.37 $26.66Dean H. Mitchell(1) N/A.00 $23.92 $21.94 $26.34 $26.29Bailly $30.00 $32.74 $28.73 $29.60 $31.02R. M. Schahfer $27.79 $25.49 $24.70 $25.12 $25.85Average of all stations $27.93 $26.17 $25.02 $26.13 $26.83

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

2002 2001 2000 1999 1998

Mills/net KWH generated 14.96 15.01 14.07 14.69 15.22Total M therms 1,567,534 1,770,762 1,900,768 1,865,170 1,830,147Btu/net KWH generated 11,039 11,440 11,138 11,117* 10,964

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

Fuel Mix for Electric Generation Including Purchased Power

2002 2001 2000 1999 1998

Coal 72.4% 92.5% 93.9% 88.3% 91.2%Oil 0.0 0.0 0.0 0.0 0.0Gas 0.0(3) 0.3 0.7 1.4 1.8Hydro 0.2 0.4 0.2 0.2 0.5Purchased Power 27.4 6.8 5.2 10.1 6.5

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 .03% 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.

2002 2001 2000 1999 1998)

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) 774 98 282 322 0

Total resources of system (MW) 4,166 3,490 3,674 3,714 3,392

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

Random unavailability (MW) (245) (258) (316) (520) (444)

Resources available to meet peak load (MW) 3,419 3,232 3,358 3,194 2,948

Total internal system peak demand (MW) 2,978 2,998 2,870 2,962 2,811

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.

2002 2001 2000 1999 1998)

Total resources of system (MW) 4,166 3,490 3,674 3,714 3,392


Capacity margin (MW) 1,188 492 804 752 581

Capacity margin (percent) 28.5% 14.1% 21.9% 20.2% 17.1%

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.

2002 2001 2000 1999 1998)

Resources available to meet peak load (MW) 3,419 3,232 3,358 3,194 2,948


Operating margin (MW) 441 234 488 232 137

Operating margin (percent) 10.6% 6.7% 13.3% 6.2% 4.0%

Annual Load Factor 66.3% 61.6% 66.2% 63.1% 64.0%

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

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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.

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: A measure of how cold the weather is. A degree day iscalculated by subtracting the mean daily outdoor temperaturefrom 65°F. Degree days would total 25 at a mean temperature of40°F. The colder the weather, the greater the number of degreedays.

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.

Gross Acres/Gross Wells: Total acreage or the total number of wellsin which a company holds participating interests.

Horizontal Drilling: Drilling that deviates from the vertical andexposes a greater portion of the underground producing rockformation to the well bore than would occur with a vertical well.Horizontal drilling generally improves the well’s productivity.

Interruptible Service: A reduced-cost gas transportation serviceoffered to customers that anticipates and permits interruptionson 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.

Net Acres/Net Wells: A company’s share or total acreage ofnumber of wells in which it has participating interests.

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.

Tract: Leased area.

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: Elecric utility operation wherein transmission facilitiesof one system are used to transmit power produced byanother system.

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page 25

Board of Directors

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

Stephen P. AdikVice 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 ManagementUniversity of Notre DameMendoza College of BusinessNotre Dame, Indiana

Roger A. YoungChairmanBay State Gas CompanyWestborough, Massachusetts

NiSource Officers

Gary L. NealeChairman, President andChief Executive Officer

Stephen P. AdikVice Chairman

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

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. WyckoffPresident, Energy Technologies

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

Jeffrey W. GrossmanVice President and Controller

David A. KellyVice President, Real Estate

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

Business Unit Officers

Barrett HatchesPresidentNorthern Indiana Public Service

Company

Glen L. KetteringPresidentColumbia Gas Transmission

CorporationColumbia Gulf Transmission

Company

Robert C. Skaggs, Jr.President Bay State Gas CompanyColumbia Gas of Kentucky, Inc.Columbia Gas of Maryland, Inc. Columbia Gas of Ohio, Inc.Columbia Gas of Pennsylvania, Inc.Columbia Gas of Virginia, Inc. Northern Utilities, Inc.

Stephen M. WarnickPresidentColumbia Natural Resources, Inc.

Mark D. WyckoffPresident NiSource Energy Technologies, Inc.Primary Energy, Inc.

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 book2002

Economy & Finance