-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TGBtzSpjA9hzOWsrGKen6OLfj0QmYxuqBAMCieHY2vCaD32eVTOIqXw2p+iVZC+O BOIRDo0t1IpkdFagkFLwhA== 0000823392-99-000005.txt : 19990517 0000823392-99-000005.hdr.sgml : 19990517 ACCESSION NUMBER: 0000823392-99-000005 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990514 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NISOURCE INC CENTRAL INDEX KEY: 0000823392 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 351719974 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-09779 FILM NUMBER: 99622326 BUSINESS ADDRESS: STREET 1: 801 E 86TH AVENUE CITY: MERRILLVILLE STATE: IN ZIP: 46410 BUSINESS PHONE: 2198535200 MAIL ADDRESS: STREET 1: 5265 HOHMAN AVENUE CITY: HAMMOND STATE: IN ZIP: 46320-1775 FORMER COMPANY: FORMER CONFORMED NAME: NIPSCO INDUSTRIES INC DATE OF NAME CHANGE: 19920703 10-Q 1 SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 1999 Commission file number 1-9779 NiSource Inc. (Exact name of registrant as specified in its charter) Indiana 35-1719974 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 801 East 86th Avenue, Merrillville, Indiana 46410 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (219) 853-5200 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes X No -------- -------- As of April 30, 1999, 124,885,481 common shares were outstanding. NiSource Inc. PART I. FINANCIAL INFORMATION Item 1. Financial Statements Report of Independent Public Accountants To The Board of Directors of NiSource Inc.: We have audited the accompanying consolidated balance sheets of NiSource Inc. (an Indiana corporation) and subsidiaries as of March 31, 1999, and December 31, 1998, and the related consolidated statements of income, common shareholders' equity and cash flows for the three and twelve month periods ended March 31, 1999 and 1998. These consolidated financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NiSource Inc. and subsidiaries as of March 31, 1999, and December 31, 1998, and the results of their operations and their cash flows for the three and twelve month periods ended March 31, 1999 and 1998, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP Chicago, Illinois April 28, 1999 PAGE>
Consolidated Balance Sheets March 31, December 31, Assets 1999 1998 ========== ========== (In thousands) Property, Plant and Equipment: Utility Plant, (including Construction Work in Progress of $257,307 and $197,112, respectively) Electric $ 4,171,978 $ 4,154,060 Gas 2,781,687 1,447,945 Water 690,877 663,355 Common 361,077 364,822 ----------------- ------------------- 8,005,619 6,630,182 Less -Accumulated depreciation and amortization 3,262,784 2,968,078 ----------------- ------------------- Net Utility Plant 4,742,835 3,662,104 ----------------- ------------------- Other property, at cost, net of accumulated depreciation 99,978 86,565 ----------------- ------------------- Net Property, Plant and Equipment 4,842,813 3,748,669 ----------------- ------------------- Investments: Investments, at equity 129,873 111,340 Investments, at cost 40,008 41,609 Other investments 36,287 28,702 ----------------- ------------------- Total Investments 206,168 181,651 ----------------- ------------------- Current Assets: Cash and cash equivalents 64,482 60,848 Accounts receivable, less reserve of $18,517 and $8,984, respectively 376,139 261,971 Other receivables 36,087 31,780 Gas cost adjustment clause - 45,738 Materials and supplies, at average cost 66,507 62,818 Electric production fuel, at average cost 25,179 32,402 Natural gas in storage 46,511 69,640 Prepayments and other 47,015 41,670 ----------------- ------------------- Total Current Assets 661,920 606,867 ----------------- ------------------- Other Assets: Regulatory assets 224,982 209,059 Intangible assets, net of accumulated amortization 80,597 65,039 Prepayments and other 209,924 175,218 ----------------- ------------------- Total Other Assets 515,503 449,316 ----------------- ------------------- $ 6,226,404 $ 4,986,503 ========== ==========
The accompanying notes to consolidated financial statements are an integral part of these statements.
Consolidated Balance Sheets March 31, December 31, Capitalization and Liabilities 1999 1998 =========== =========== (In thousands) Capitalization: Common shareholders' equity (See accompanying statement) $ 1,371,615 $ 1,149,708 Preferred stocks, excluding amounts due within one year- Series without mandatory redemption provisions 85,613 85,613 Series with mandatory redemption provisions 56,435 56,435 Company-obligated manditorily redeemable preferred securities of subsidiary trust holding solely Company debentures 345,000 - Long-term debt, excluding amounts due within one year 1,967,400 1,667,965 ----------------- ----------------- Total Capitalization 3,826,063 2,959,721 ----------------- ----------------- Current Liabilities: Current portion of long-term debt 39,122 6,790 Short-term borrowings 249,973 411,040 Accounts payable 255,003 251,399 Dividends declared on common and preferred stocks 33,202 31,072 Customer deposits 25,547 22,199 Taxes accrued 125,571 44,939 Interest accrued 29,743 21,202 Fuel adjustment clause 4,023 6,279 Gas cost adjustment clause 2,509 - Accrued employment costs 39,767 52,121 Other accruals 98,462 39,022 ----------------- ----------------- Total Current Liabilities 902,922 886,063 ----------------- ----------------- Other: Deferred income taxes 949,733 667,167 Deferred investment tax credits, being amortized over life of related property 100,750 98,177 Deferred credits 111,028 68,046 Customer advances and contributions in aid of construction 120,528 118,778 Accrued liability for postretirement benefits 147,559 143,870 Other noncurrent liabilities 67,821 44,681 ----------------- ----------------- Total Other Liabilities 1,497,419 1,140,719 ----------------- ----------------- Commitments and Contingencies $ 6,226,404 $ 4,986,503 ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements.
Consolidated Statements of Income (Dollars in thousands, except for per share amounts) Three Months Twelve Months Ended March 31, Ended March 31, -------------------- ------------------- 1999 1998 1999 1998 ======== ======== ======== ======== Operating Revenues: Gas $ 553,896 $ 398,916 $ 1,364,755 $ 1,198,305 Electric 264,330 322,912 1,368,018 1,246,857 Water 20,869 17,709 87,139 78,452 Products and Services 52,397 39,807 225,014 182,321 --------- --------- --------- --------- 891,492 779,344 3,044,926 2,705,935 --------- --------- --------- --------- Cost of Sales: Gas costs 379,590 294,607 1,010,021 889,165 Fuel for electric generation 58,298 55,594 253,353 235,734 Power purchased 22,050 90,277 344,063 270,513 Products and Services 25,589 19,932 110,047 93,090 --------- --------- --------- --------- 485,527 460,410 1,717,484 1,488,502 --------- --------- --------- --------- Operating Margin 405,965 318,934 1,327,442 1,217,433 --------- --------- --------- --------- Operating Expenses and Taxes: Operation 126,829 96,171 430,252 400,720 Maintenance 22,309 18,947 77,992 77,015 Depreciation and amortization 72,909 63,274 266,109 254,734 Taxes (except income) 28,009 23,428 92,788 85,883 --------- --------- --------- --------- 250,056 201,820 867,141 818,352 --------- --------- --------- --------- Operating Income 155,909 117,114 460,301 399,081 --------- --------- --------- --------- Other Income (Deductions): Interest expense, net (36,688) (30,330) (135,162) (125,033) Minority interests (2,708) -- (2,708) -- Dividend requirements on preferred stock of subsidiaries (2,116) (2,167) (8,487) (8,691) Other, net 7,084 8,448 9,220 14,813 --------- --------- --------- --------- (34,428) (24,049) (137,137) (118,911) --------- --------- --------- --------- Income before income taxes 121,481 93,065 323,164 280,170 --------- --------- --------- --------- Income Taxes 44,922 32,343 113,441 99,437 --------- --------- --------- --------- Net Income $ 76,559 $ 60,722 $ 209,723 $ 180,733 Average common shares outstanding - basic 122,646,186 123,872,613 120,475,670 125,021,821 Basic earnings per average common share $ 0.62 $ 0.49 $ 1.7 $ 1.44 ======== ======== ======== ======== Diluted earnings per average common share $ 0.62 $ 0.48 $ 1.72 $ 1.44 ======== ======== ======== ======== Dividends declared per common share $ 0.255 $ 0.240 $ 0.990 $ 0.930 ======== ======== ======== ======== The accompanying notes to consolidated financial statements are an integral part of these statements.
Consolidated Statement Of Common Shareholders' Equity Additional (Dollars in thousands) Common Treasury Paid-in Retained Three Months Ended Shares Shares Capital Earnings Other ======================== ========== ========== ========== ========== ========== Balance, January 1, 1998 $ 870,930 $(363,943) $ 89,768 $ 667,790 $ (2,624) Comprehensive Income: Net income 60,722 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $684) Realized Gain (loss) on foreign currency translation: Unrealized Realized Total Comprehensive Income Dividends: Common shares (29,929) Treasury shares acquired (23,298) 2 Issued: Employee stock purchase plan 57 120 Long-term incentive plan 3,175 (12) (34) Amortization of unearned compensation 499 Other (655) ---------- ---------- ---------- ---------- ---------- Balance, March 31, 1998 $ 870,930 $(384,009) $ 89,878 $ 697,928 $ (2,159) ========== ========== ========== ========== ========== Balance, January 1, 1999 $ 870,930 $(559,027) $ 94,181 $ 744,309 $ (1,815) Comprehensive Income: Net income 76,559 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $133) Realized (net of income tax of $78) Gain (loss) on foreign currency translation: Unrealized Realized Total Comprehensive Income Dividends: Common shares (32,107) Treasury shares acquired (107,658) Issued: Employee stock purchase plan 115 326 Long-term incentive plan 1,106 121 (382) Bay State Gas Acquisition 205,896 109,787 Amortization of unearned compensation 723 Equity contract costs (32,829) Other (210) ---------- ---------- ---------- ---------- ---------- Balance, March 31, 1999 $ 870,930 $(459,568) $ 171,586 $ 788,551 $ (1,474) ========== ========== ========== ========== ========== Accumulated Shares Other ------------------------ Three Months Ended Comprehensive Comprehensive Common Treasury (continued) Income Total Income Shares Shares ======================== ========== ========== ========== ========== ========== Balance, January 1, 1998 $ 2,867 $1,264,788 $147,784,218 $(23,471,554) Comprehensive Income: Net income 60,722 $ 60,722 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $684) 1,119 1,119 1,119 Realized Gain (loss) on foreign currency translation: Unrealized (210) (210) (210) Realized 186 186 186 ---------- Total Comprehensive Income $ 61,817 Dividends: ========== Common shares (29,929) Treasury shares acquired (23,296) (910,574) Issued: Employee stock purchase plan 177 7,158 Long-term incentive plan 3,129 197,044 Amortization of unearned compensation 499 Other (655) ---------- ---------- ---------- ---------- Balance, March 31, 1998 $ 3,962 $1,276,530 $147,784,218 $(24,177,926) ========== ========== ========== ========== Balance, January 1, 1999 $ 1,130 $1,149,708 $147,784,218 $(30,253,520) Comprehensive Income: Net income 76,559 $ 76,559 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $133) 217 217 217 Realized (net of income tax of $78) 127 127 127 Gain (loss) on foreign currency translation: Unrealized (70) (70) (70) Realized 186 186 186 ---------- Total Comprehensive Income $ 77,019 ========== Dividends: Common shares (32,107) Treasury shares acquired (107,658) (3,846,630) Issued: Employee stock purchase plan 441 14,484 Long-term incentive plan 845 58,417 Bay State Gas Acquisition 315,683 11,042,579 Amortization of unearned compensation 723 Equity contract costs (32,829) Other (210) ---------- ---------- ---------- ----------- Balance, March 31, 1999 $ 1,590 $1,371,615 $147,784,218 $(22,984,670) ========== ========== ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements. Additional (Dollars in thousands) Common Treasury Paid-in Retained Twelve Months Ended Shares Shares Capital Earnings Other ======================== ========== ========== ========== ========== ========== Balance, April 1, 1997 $ 870,930 $(295,980) $ 88,118 $ 635,900 $ (4,128) Comprehensive Income: Net income 180,733 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $1,699) Realized Gain (loss) on foreign currency translation: Unrealized Realized Total Comprehensive Income Dividends: Common shares (117,959) Treasury shares acquired (99,884) (33) Issued: Employee stock purchase plan 255 431 Long-term incentive plan 7,482 10 (126) NEM Acquisition 4,118 1,351 Amortization of unearned compensation 2,095 Other 1 (746) ---------- ---------- ---------- ---------- ---------- Balance, March 31, 1998 $ 870,930 $(384,009) $ 89,878 $ 697,928 $ (2,159) ========== ========== ========== ========== ========== Balance April 1, 1998 $ 870,930 $(384,009) $ 89,878 $ 697,928 $ (2,159) Comprehensive Income: Net income 209,723 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $322) Realized (net of income tax of $1,262) Gain (loss) on foreign currency translation: Unrealized Realized Total Comprehensive Income Dividends: Common shares (118,774) Treasury shares acquired (288,336) Issued: Employee stock purchase plan 399 1,095 Long-term incentive plan 6,482 708 (1,432) Bay State Gas Acquisition 205,896 109,787 Amortization of unearned compensation 2,117 Equity contract costs (32,829) Other 2,946 (325) ---------- ---------- ---------- ---------- ---------- Balance, March 31, 1999 $ 870,930 $(459,568) $ 171,585 $ 788,552 $ (1,474) ========== ========== ========== ========== ========== Accumulated Shares Other ------------------------ Twelve Months Ended Comprehensive Comprehensive Common Treasury (continued) Income Total Income Shares Shares ======================== ========== ========== ========== ========== ========== Balance, April 1, 1997 $ 2,276 $1,297,116 $147,784,218 $(20,363,752) Comprehensive Income: Net income 180,733 $ 180,733 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $1,699) 2,779 2,779 2,779 Realized Gain (loss) on foreign currency translation: Unrealized (1,279) (1,279) (1,279) Realized 186 186 186 ---------- Total Comprehensive Income $ 182,419 ========== Dividends: Common shares (117,959) Treasury shares acquired (99,917) (4,595,274) Issued: Employee stock purchase plan 686 32,026 Long-term incentive plan 7,366 479,010 NEM Acquisition 5,469 270,064 Amortization of unearned compensation 2,095 Other (745) ---------- ---------- ---------- ---------- Balance, March 31, 1998 $ 3,962 $1,276,530 $147,784,218 $(24,177,926) ========== ========== ========== ========== Balance April 1, 1998 $ 3,962 $1,276,530 $147,784,218 $(24,177,926) Comprehensive Income: Net income 209,724 $209,724 Other comprehensive income, net of tax: Gain/loss on available for sale securities: Unrealized (net of income tax of $322) 527 527 527 Realized (net of income tax of $1,262) (2,068) (2,068) (2,068) Gain (loss) on foreign currency translation: Unrealized (1,017) (1,017) (1,017) Realized 186 186 186 ---------- Total Comprehensive Income $207,352 ========== Dividends: Common shares (118,774) Treasury shares acquired (288,336) (10,245,962) Issued: Employee stock purchase plan 1,494 50,122 Long-term incentive plan 5,758 346,517 Bay State Gas Acquisition 315,683 11,042,579 Amortization of unearned compensation 2,117 Equity contract costs (32,829) Other 2,620 ---------- ---------- ---------- ---------- Balance, March 31, 1999 $ 1,590 $1,371,615 $147,784,218 $(22,984,670) ========== ========== ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements.
Consolidated Statements of Cash Flows
Three Months Twelve Months Ended March 31, Ended March 31, -------------------- ------------------------ 1999 1998 1999 1998 ======== ======== ======== ======== (In thousands) Cash flows from operating activities: Net income $ 76,559 $ 60,722 $ 209,723 $ 180,733 Adjustments to reconcile net income to net cash: Depreciation and amortization 72,909 63,274 266,109 254,734 Deferred federal and state income taxes, net (26,928) (30,040) (18,829) (19,345) Deferred investment tax credits, net (1,887) (1,821) (7,427) (7,395) Advance contract payment 475 475 1,900 1,900 Other, net (6,912) (5,522) (6,030) (9,263) Change in certain assets and liabilities -* Accounts receivable, net (18,978) (12,391) (33,224) (63,547) Other receivables (4,307) (20,590) 91,734 (45,626) Natural gas in storage 51,558 40,413 2,941 (3,005) Accounts payable (55,918) (13,470) (22,663) (87,687) Taxes accrued 94,139 80,313 3,993 5,940 Gas cost adjustment clause 74,347 52,019 66,581 50,014 Accrued employment costs (20,628) (16,296) (11,010) 660 Other accruals 31,450 (6,838) 26,548 (5,029) Other, net 21,340 (685) 440 59,818 --------- --------- -------- --------- Net cash provided by operating activities 287,219 189,563 570,786 312,902 --------- --------- -------- --------- Cash flows provided by (used in) investing activities: Utility construction expenditures (58,115) (48,203) (250,237) (220,553) Acquisition of businesses, net of cash acquired (562,266) 0 (562,266) 0 Acquisition of minority interest 0 0 0 (5,641) Proceeds from disposition of assets 25,416 9,705 28,299 16,198 Proceeds from settlement of litigation 0 0 0 41,069 Other, net (16,263) (25,916) (42,485) (61,384) --------- --------- -------- --------- Net cash used in investing activities (611,228) (64,414) (826,689) (230,311) --------- --------- -------- --------- Cash flows provided by (used in) financing activities: Issuance of long-term debt 78,255 6,371 119,264 528,301 Retirement of long-term debt (4,718) (2,547) (97,802) (325,682) Change in short-term debt (260,370) (69,752) 6,400 (133,233) Retirement of preferred shares 0 (1) (2,412) (2,408) Proceeds from Corporate Premium Income Equity Securities, net 334,650 0 334,650 0 Issuance of common shares 317,351 3,340 324,367 13,427 Acquisition of treasury shares (107,658) (23,296) (288,336) (99,789) Cash dividends paid on common shares (29,980) (29,789) (116,577) (114,610) Other, net 113 121 455 (497) --------- --------- -------- --------- Net cash provided by (used in) financing activities 327,643 (115,553) 280,009 (134,491) --------- --------- -------- --------- Net increase (decrease) in cash and cash equivalents 3,634 9,596 24,106 (51,900) Cash and cash equivalents at beginning of the period 60,848 30,780 40,376 92,276 --------- --------- -------- --------- Cash and cash equivalents at end of the period $ 64,482 $ 40,376 $ 64,482 $ 40,376 ========= ========= ======== ========= *Net of effect from acquisitions of businesses. The accompanying notes to consolidated financial statements are an integral part of these statements.
Notes to Consolidated Financial Statements (1) Holding Company Structure: NiSource Inc., formerly NIPSCO Industries, Inc. (NiSource), is an energy and utility-based holding company headquartered in Merrillville, Indiana that provides natural gas, electricity and water to the public for residential, commercial and industrial uses. NiSource was organized as an Indiana holding company in 1987 under the name "NIPSCO Industries, Inc.," and changed its name to NiSource Inc. on April 14, 1999 to reflect its new direction as a multi-state supplier of energy and water resources and related services. NiSource operates primarily in Indiana and New England through wholly-owned regulated subsidiaries, collectively called the "Utilities." NiSource's regulated gas and electric subsidiaries are collectively referred to as the "Energy Utilities." NiSource's regulated water subsidiaries are collectively called the "Water Utilities." The Utilities are subject to regulation with respect to rates, accounting and certain other matters, by the Indiana Utility Regulatory Commission (IURC), the Massachusetts Department of Telecommunications and Energy (MDTE), the New Hampshire Public Utilities Commission (NHPUC), the Maine Public Utilities Commission (MEPUC) and the Federal Energy Regulatory Commission (FERC), collectively called the "Commissions." NiSource also provides non-regulated energy and utility-related services to its customers through its wholly-owned "Products and Services" subsidiaries. Products and Services subsidiaries perform energy-related services and offer products in connection with these services, which include installing, repairing and maintaining underground gas pipelines and locating and marking utility lines. In addition to the services and products that it provides through the Utilities and the Products and Services subsidiaries, NiSource has a wholly-owned subsidiary, NiSource Capital Markets, Inc. (Capital Markets). Capital Markets engages in financing activities for NiSource and certain of its subsidiaries, excluding Northern Indiana Public Service Company (Northern Indiana). On April 1, 1999, NiSource acquired TPC Corporation, a Houston-based natural gas marketing and storage company for approximately $150 million. The acquisition will be accounted for as a purchase, with the purchase price allocated to the assets and liabilities acquired based on their estimated fair values. TPC Corporation owns a 66% equity interest in Market Hub Partners, L.P., which stores natural gas in salt caverns. (2) Summary of Significant Accounting Policies: Basis of Presentation. The Consolidated Financial Statements include the accounts of NiSource and its majority-owned subsidiaries after the elimination of significant intercompany accounts and transactions. Investments for which at least a 20% interest is owned and certain joint ventures are accounted for under the equity method. Investments with less than a 20% interest are accounted for under the cost method. Certain reclassifications were made to conform the prior years' financial statements to the current presentation. On February 12, 1999, NiSource acquired Bay State Gas Company (BSG). Accordingly, the Consolidated Financial Statements and disclosures include operating results from BSG from the date of acquisition through March 31, 1999. See Note 3 for additional information on this acquisition. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Operating Revenues. Utility revenues are recorded based on estimated service rendered, but are billed to customers monthly on a cycle basis. Electric and gas marketing revenues are recognized as the related commodity is delivered to customers. Effective January 1, 1999, revenues relating to electric and gas trading operations are recorded based upon changes in the fair values of the related energy trading contracts. Construction revenues are recognized on the percentage of completion method whereby revenues are recognized in proportion to costs incurred over the life of each project. NiSource records provisions for losses on construction contracts, if any, in the period in which such losses become probable. Depreciation and Maintenance. The Utilities provide depreciation on a straight-line method over the remaining service lives of the electric, gas, water and common properties. The approximate weighted average remaining lives for major components of electric, gas, and water plant are as follows:
Electric: Electric generation plant..................................... 24 years Transmission plant............................................ 26 years Distribution plant............................................ 25 years Other electric plant.......................................... 24 years Gas: Gas storage plant............................................. 21 years Transmission plant............................................ 27 years Distribution plant............................................ 30 years Other gas plant................................................21 years Water: Water source and treatment plant.............................. 34 years Distribution plant............................................ 68 years Other water plant............................................. 13 years
The depreciation provisions for utility plant, as a percentage of the original cost, for the three-month and twelve-month periods ended March 31, 1999 and 1998 were as follows:
Three Months Twelve Months Ended March 31, Ended March 31, ----------------------- ----------------------- 1999 1998 1999 1998 ======= ======= ======= ======= Electric 3.7% 3.6% 3.7% 3.6% Gas 4.6% 5.1% 4.6% 5.1% Water 2.0% 2.0% 2.0% 2.1%
The Utilities follow the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal less salvage, is charged to the accumulated provision for depreciation. Amortization of Software Costs. External and incremental internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of the project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis over a period of five to ten years which the FERC prescribes as reasonable useful life estimates for capitalized software. Plant Acquisition Adjustments. Net utility plant includes amounts allocated to utility plant in excess of the original cost as part of the purchase price allocation associated with the acquisition of utility businesses. These amounts were $722.8 million and $185.4 million at March 31, 1999 and December 31, 1998, respectively, and are being amortized over forty-year periods from the respective dates of acquisition. Intangible Assets. The excess of cost over the fair value of the net assets of non-utility businesses acquired are recorded as goodwill. Goodwill of $73.0 million and $61.9 million at March 31, 1999 and December 31, 1998, respectively, is being amortized over a weighted average period of 32 years. Other intangible assets, approximating $12.8 million and $7.7 million at March 31, 1999 and December 31, 1998, respectively, are being amortized over periods of four to eight years. The recoverability of intangible assets is assessed on a periodic basis to confirm that expected future cash flows will be sufficient to support the recorded intangible assets. Accumulated amortization of intangible assets at March 31, 1999 and December 31, 1998 was approximately $5.2 million and $4.6 million, respectively. Coal Reserves. The costs of reserves under a long-term mining contract to mine coal reserves through the year 2001 are being recovered through the rate-making process as such coal reserves are used to produce electricity. Accounts Receivable. At March 31, 1999, $100.0 million of accounts receivable had been sold under a sales agreement which expires on May 31, 2002. Customer Advances and Contributions in Aid of Construction. Certain developers install and provide for the installation of water main extensions, which will be transferred to NiSource upon completion. The cost of the main extensions and the amount of any funds advanced for the cost of water mains installed are included in customer advances for construction and are generally refundable to the customer over a period of ten years. Advances not refunded within ten years are permanently transferred to contributions in aid of construction. Comprehensive Income. Comprehensive income is reported in the Consolidated Statements of Common Shareholders' Equity. The components of accumulated other comprehensive income include unrealized gains (losses), net of income taxes, on available for sale securities ("securities") and unrealized gains (losses) on foreign currency translation adjustments ("foreign currency"). The accumulated amounts for these components are as follows:
April 1, January 1, March 31, January 1, March 31, (In millions) 1997 1998 1998 1999 1999 ---------- ------------- ------------- ------------ ----------- Securities $2.7 $ 4.4 $ 5.6 $ 3.6 $ 4.0 Foreign currency $(.5) $(1.6) $(1.6) $(2.5) $(2.4)
Statements of Cash Flows. Temporary cash investments with an original maturity of three months or less are considered to be cash equivalents. Cash paid during the periods reported for income taxes and interest was as follows:
Three Months Twelve Months Ended March 31, Ended March 31, ------------------ ------------------ (In thousands) 1999 1998 1999 1998 ======= ======= ======= ======= Income taxes $ 1,465 $ 0 $ 129,178 $ 116,849 Interest, net of amounts capitalized $ 31,351 $ 23,549 $ 125,881 $ 113,799
Fuel Adjustment Clause. All metered electric rates contain a provision for adjustment in charges for electric energy to reflect increases and decreases in the cost of fuel and the fuel cost of purchased power through operation of a fuel adjustment clause. As prescribed by order of the IURC applicable to metered retail rates, the adjustment factor has been calculated based on the estimated cost of fuel and the fuel cost of purchased power in a future three-month period. If two statutory requirements relating to expense and return levels are satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given three-month period will be included in a future filing. Under-recovery or over-recovery is recorded as a current asset or current liability until such time as it is billed or refunded to its customers. The fuel adjustment factor is subject to a quarterly hearing by the IURC and remains in effect for a three-month period. Gas Cost Adjustment Clause. All metered gas sales rates contain an adjustment factor, which reflects the increases and decreases in the cost of purchased gas, contracted gas storage and storage transportation charges. Each gas cost adjustment factor is subject to a quarterly or semi-annual hearing by the state Commissions and remains in effect for either a three- or six-month period. If the statutory requirement relating to the level of return for the Indiana gas utilities is satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given three-month or six-month period will be included in a future filing. Any under-recovery or over-recovery is recorded as a current asset or current liability until such time it is billed or refunded to customers. Northern Indiana's gas cost adjustment factor includes a gas cost incentive mechanism (GCIM) which allows the sharing of any cost savings or cost increases with customers based on a comparison of actual gas supply portfolio cost to a market-based benchmark price. Natural Gas in Storage. NiSource uses both the last-in, first-out (LIFO) inventory methodology and the weighted average methodology to value natural gas in storage. Based on the average cost of gas purchased under the LIFO method in March 1999 and December 1998, the estimated replacement cost of gas in storage (current and non-current) at March 31, 1999 and December 31, 1998 exceeded the stated LIFO cost by $21.5 million and $33.7 million, respectively.Inventory valued using LIFO was $19.6 million and $50.8 million at March 31, 1999 and December 31, 1998, respectively. Inventory valued using the weighted average methodology was $26.9 million and $18.8 million at March 31, 1999 and December 31, 1998, respectively. Derivatives. A variety of commodity-based derivative financial instruments are utilized to reduce (hedge) the price risk inherent in natural gas and electric operations. The gains and losses on these derivative financial instruments are deferred as assets or liabilities and are recognized in earnings concurrent with the disposition of the underlying physical commodity. In certain circumstances, a derivative financial instrument will serve to hedge the acquisition cost of natural gas injected into storage. In this situation, the gain or loss on the derivative financial instrument is deferred as part of the cost basis of gas in storage and recognized upon the ultimate disposition of the gas. If a derivative financial instrument contract is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If a derivative financial instrument is terminated for other economic reasons, any gain or loss as of the termination date is deferred and recorded when the associated transaction or forecasted transaction affects earnings. Accounting for Energy Trading Activities. Energy trading contracts are accounted for in accordance with the Emerging Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Such contracts are recorded at fair value on the balance sheet, with the changes in their fair values included in earnings, effective January 1, 1999. The change in accounting effective January 1, 1999 was insignificant. Impact of Accounting Standards. The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." This Statement standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, by requiring that a company recognize those items as assets or liabilities in the balance sheet and measure them at fair value. The Statement generally provides for matching of the timing of gain or loss recognition of derivative instruments designated as a hedge with the recognition of changes in the fair value of the hedged asset or liability through earnings. The Statement also provides that the effective portion of a hedging instrument's gain or loss on a forecasted transaction be initially reported in other comprehensive income and subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. The impact of adopting the Statement on January 1, 2000 is currently being assessed. Regulatory Assets. The Utilities' operations are subject to the regulation of the Commissions and, in the case of certain Energy Utilities, FERC. Accordingly, the Utilities' accounting policies are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The Utilities monitor changes in market and regulatory conditions and the resulting impact of such changes in order to continue to apply the provisions of SFAS No. 71 to some or all of their operations. As of March 31, 1999, and December 31, 1998, the regulatory assets identified below represent probable future revenues to the Utilities as these costs are recovered through the rate-making process. If a portion of the Utilities' operations becomes no longer subject to the provisions of SFAS No. 71, a write-off of certain regulatory assets might be required, unless some form of transition cost recovery is established by the appropriate regulatory body which would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets during such recovery period. Regulatory assets were comprised of the following items:
March 31, December 31, (In thousands) 1999 1998 ========= ========= Unamortized reacquisition premium on debt (see Note 16) $ 42,355 $ 43,233 Unamortized R. M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation (see below) 61,274 62,329 Bailly scrubber carrying charges and deferred depreciation (see below) 8,711 8,945 Deferral of SFAS No. 106 expense not recovered (see Note 8) 79,886 81,339 FERC Order No. 636 transition costs 18,864 22,093 Regulatory income tax asset, net 31,367 18,793 Other 11,906 4,936 --------- --------- 254,363 241,668 Less: Current portion of regulatory assets 29,381 32,609 --------- --------- $224,982 $209,059 ========= =========
Carrying Charges and Deferred Depreciation. Upon completion of R. M. Schahfer Units 17 and 18, carrying charges and deferred depreciation were capitalized in accordance with orders of the IURC until the cost of each unit was allowed in rates. Such carrying charges and deferred depreciation are being amortized over the remaining life of each unit. NiSource has capitalized carrying charges and deferred depreciation and certain operating expenses relating to its scrubber service agreement for its Bailly Generating Station in accordance with an order of the IURC. The accumulated balance of the deferred costs and related carrying charges is being amortized over the remaining life of the scrubber service agreement. Allowance for Funds Used During Construction. Allowance for funds used during construction (AFUDC) is charged to construction work in progress during the period of construction and represents the net cost of borrowed funds used for construction purposes and a reasonable rate upon other (equity) funds. Under established regulatory rate practices, after the construction project is placed in service, the Utilities are permitted to include in the rates charged for utility services (a) a fair return on and (b) depreciation of such AFUDC included in plant in service. AFUDC was calculated using a weighted average pretax rate as follows:
March 31, March 31, 1999 1998 ========= ========= Three months ended 8.79% 8.67% Twelve months ended 8.86% 8.97%
Foreign Currency Translation. Translation gains or losses are based upon the end-of-period exchange rate and are recorded as a separate component of other comprehensive income reflected in the Consolidated Statements of Shareholders' Equity. Investments In Real Estate. A series of affordable housing projects within the Indiana service territory are held as investments and accounted for using the equity method. These investments include certain tax benefits, including low-income housing tax credits and tax deductions for operating losses of the housing projects. Investments, at equity, include $33.5 million and $34.0 million relating to affordable housing projects at March 31, 1999 and December 31, 1998, respectively. Income Taxes. The liability method of accounting is used for income taxes under which deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the book and tax bases of assets and liabilities. (3) Acquisition of Bay State Gas Company: On February 12, 1999, the acquisition of BSG was completed for approximately $560.1 million. The $237.7 million cash portion was financed by the issuance of 6.9 million Corporate Premium Income Equity Securities (see Note 19). The acquisition was accounted for as a purchase, and the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values. Bay State Gas, one of the largest natural gas utilities in New England, provides natural gas distribution to more than 300,000 customers in Massachusetts and, through its wholly-owned subsidiary Northern Utilities, New Hampshire and Maine. The accompanying financial statements reflect a preliminary allocation of the purchase price since the purchase price allocation has not been finalized. Assets acquired and liabilities assumed in the acquisition of BSG were comprised of the following:
(In thousands) Assets acquired: Utility plant, net of accumulated depreciation $1,081,874 Intangible assets 16,264 Other current assets 177,148 Other noncurrent assets 75,126 --------- 1,350,412 Less: Liabilities assumed: Long-term debt 244,337 Short-term debt 100,295 Other current liabilities 122,408 Other noncurrent liabilities 323,242 --------- 790,282 --------- Net assets acquired $560,130 =========
On a pro forma basis, NiSource's consolidated results of operations for the three months and twelve months ended March 31, 1999, including BSG, would have been:
(In thousands,unaudited) UNAUDITED ---------------------- Three Months Twelve Months =========== =========== Operating revenue $ 966,113 $ 3,382,538 Operating Income $ 164,382 $ 443,153 Net Income $ 79,746 $ 182,342
Pro forma adjustments primarily reflect adjustments for the addition of the plant acquisition adjustment and intangible assets, the issuance of the applicable Corporate Premium Income Equity Securities and additional income taxes, as if the acquisition had occurred on January 1, 1999 for the three month results and on April 1, 1998 for the twelve month results. (4) NESI Energy Marketing Canada Ltd. Litigation: On October 31, 1996, Northern Indiana Energy Services Canada Ltd. (NESI Canada) acquired 70% of the outstanding shares of NESI Energy Marketing Canada Ltd. (NEMC). Between November 1 and November 27, 1996, gas prices in the Calgary market increased dramatically. As a result, NEMC was selling gas pursuant to contracts entered into prior to the acquisition date, at prices substantially below its costs to acquire such gas. On November 27, 1996, NEMC ceased doing business and sought protection from its creditors under the Companies' Creditors Arrangement Act, a Canadian corporate reorganization statute. NEMC was declared bankrupt as of December 12, 1996. Certain creditors of NEMC have filed claims in the Canadian courts against NiSource alleging certain misrepresentations relating to NEMC's financial condition and claiming damages. In addition, certain creditors of NEMC have, through the Canadian bankruptcy court, asserted fraudulent transfer and other claims against NiSource, Capital Markets, NI Energy Services, Inc., NI Energy Services Canada, Ltd. and the directors of NEMC. NiSource intends to vigorously defend against such claims and any other claims seeking to assert that any party other than NEMC is responsible for NEMC's liabilities. Management believes that any loss relating to NEMC would not be material to the financial position or results of operations. (5) Environmental Matters: General. The operations of NiSource are subject to extensive and evolving federal, state and local environmental laws and regulations intended to protect the public health and the environment. Such environmental laws and regulations affect operations as they relate to impacts on air, water and land. Superfund. Because NiSource is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) at several waste disposal sites, as well as at former manufactured-gas plant sites which it, or its corporate predecessors, own or owned or operated, it may be required to share in the cost of clean up of such sites. A program was instituted to investigate former manufactured-gas plant sites where it is the current or former owner, which investigation has identified forty-nine of these sites. Initial sampling has been conducted at thirty sites. Follow-up investigations have been conducted at nineteen sites and remedial measures have been selected at twelve sites. NiSource intends to continue to evaluate its facilities and properties with respect to environmental laws and regulations and take any required corrective action. In an effort to recover a portion of the remedial costs to be incurred at the manufactured gas plants, various companies that provided insurance coverage which NiSource believed covered costs related to actions taken and to be taken at former manufactured-gas plant sites were approached. NiSource has filed claims in Indiana state court against various insurance companies, seeking coverage for costs associated with several manufactured-gas plant sites and damages for alleged misconduct by some of the insurance companies. Cash settlements have been received from several insurance companies. Additionally, agreements have been reached with other utilities relating to cost sharing and management of the investigation and remediation of several former manufactured-gas plant sites at which NiSource and such utilities or their predecessors were operators or owners. Bay State Gas and Northern Utilities have rate recovery for environmental response costs in Maine, Massachusetts and New Hampshire. The rate treatment allows for the recovery of 100% of prudently incurred costs for investigation and remediation over a 5-7 year period from date of payment. Recoveries from third parties or insurance companies are allocated 50% to rate payers, 50% to shareholders in Maine and Massachusetts and 100% to rate payers in New Hampshire. As of March 31, 1999, a reserve of approximately $25 million has been recorded to cover probable corrective actions. The ultimate liability in connection with these sites will depend upon many factors, including the volume of material contributed to the site, the number of other PRPs and their financial viability, the extent of corrective actions required and rate recovery. Based upon investigations and management's understanding of current environmental laws and regulations, NiSource believes that any corrective actions required, after consideration of insurance coverages, contributions from other PRPs, and rate recovery will not have a significant impact on its financial position or results of operations. Clean Air Act. The Clean Air Act Amendments of 1990 (CAAA) imposed limits to control acid rain on the emission of sulfur dioxide and nitrogen oxides (NOx) which become fully effective in 2000. All of NiSource's facilities are already in compliance with the sulfur dioxide limits. NiSource has already taken most of the steps necessary to meet the NOx limits. The CAAA also contain other provisions that could lead to limitations on emissions of hazardous air pollutants and other air pollutants (including NOx as discussed below), which may require significant capital expenditures for control of these emissions. Until specific rules have been issued that affect NiSource's facilities, what these requirements will be or the costs of complying with these potential requirements can not be predicted. Nitrogen Oxides. During 1998, the Environmental Protection Agency (EPA) issued a final rule, the NOx State Implementation Plan (SIP) call, requiring certain states, including Indiana, to reduce NOx levels from several sources including industrial and utility boilers. The EPA stated that the intent of the rule is to lower regional transport of ozone impacting other states' ability to attain the federal ozone standard. According to the rule, the State of Indiana has until September 1999 to issue regulations implementing the control program. The State of Indiana, as well as some other states, filed a legal challenge in December 1998 to the EPA NOx SIP call rule. Lawsuits have also been filed against the rule by various groups, including industry, labor, cities and towns and chambers of commerce. NiSource will participate in the legal challenge as a member of a utility industry group. Any resulting NOx emission limitations could be more restrictive than those imposed on electric utilities under the acid rain NOx reduction program described above. NiSource is evaluating the EPA's final rule and any potential requirements that could result from the final rule as implemented by the State of Indiana. NiSource believes that the costs relating to compliance with the new standards may be substantial, but such costs depend upon the outcome of the current litigation and the ultimate control program agreed to by the targeted states and the EPA. NiSource will continue to closely monitor developments in this area. The EPA issued final rules revising the National Ambient Air Quality Standards for ozone and particulate matter in July 1997. The revised standards could require additional reductions in sulfur dioxide, particulate matter and NOx emissions from coal-fired boilers (including NiSource's generating stations) beyond measures discussed above. Final implementation methods will be set by the EPA as well as state regulatory authorities. NiSource believes that the costs relating to compliance with any new limits may be substantial but are dependent upon the ultimate control program agreed to by the targeted states and the EPA. NiSource will continue to closely monitor developments in this area and anticipates the exact nature of the impact of the new limits on its operations will not be known for some time. Carbon Dioxide. Initiatives are being discussed both in the United States and worldwide to reduce so-called "greenhouse gases" such as carbon dioxide which is a by-product of burning fossil fuels. Reduction of such emissions could result in significant capital outlays or operating expenses to NiSource. Clean Water Act and Related Matters. NiSource's wastewater and water operations are subject to pollution control and water quality control regulations, including those issued by the EPA and the State of Indiana. Under the Federal Clean Water Act and Indiana's regulations, NiSource must obtain National Discharge Elimination System permits for water discharges from various facilities, including electric generating and water treatment stations. These facilities either have permits for their water discharge or they have applied for a permit renewal of any expiring permits. These permits continue in effect pending review of the current applications. Under the Federal Safe Drinking Water Act (SDWA), the Water Utilities are subject to regulation by the EPA for the quality of water sold and treatment techniques used to make the water potable. The EPA promulgates nationally-applicable maximum contaminant levels (MCLs) for contaminants found in drinking water. Management believes that the Water Utilities are currently in compliance with all MCLs promulgated to date. The EPA has continuing authority, however, to issue additional regulations under the SDWA. In August 1996, Congress amended the SDWA to allow the EPA more authority to weigh the costs and benefits of regulations being considered in some, but not all, cases. In December 1998, EPA promulgated two National Primary Drinking Water rules, the Interim Enhanced Surface Water Treatment Rule and the Disinfectants and Disinfection Byproducts Rule. The Water Utilities must comply with these rules by December 2001. Management does not believe that significant changes will be required for the Water Utilities' operations to comply with these rules; however, some cost expenditures for equipment modifications or enhancements may be necessary to comply with the Interim Enhanced Surface Water Treatment Rule. Additional rules are anticipated to be promulgated under the 1996 amendments. Such rules could be costly and could require substantial changes in the Water Utilities' operations. Under a 1991 law enacted by the Indiana legislature, a water utility may petition the IURC for prior approval of its plans and estimated expenditures required to comply with the provisions of, and regulations under, the Federal Clean Water Act and SDWA. Upon obtaining such approval, a water utility may include such costs in its rate base for rate-making purposes, to the extent of its estimated costs as approved by the IURC, and recover its costs of developing and implementing the approved plans if statutory standards are met. The capital costs for such new systems, equipment or facilities or modifications of existing facilities may be included in a water utility's rate base upon completion of construction of the project or any part thereof. Such an addition to rate base, however, would effect a change in water rates. NiSource's principal water utility has agreed to a moratorium on water rate increases until 2002. Therefore, recovery of any increased costs discussed above may not be timely. (6) Income Taxes: Deferred income taxes are recognized as costs in the rate-making process by the Commissions having jurisdiction over the rates charged by the Utilities. Deferred income taxes are provided as a result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the Consolidated Financial Statements. These taxes are reversed by a debit or credit to deferred income tax expense as the temporary differences reverse. Investment tax credits have been deferred and are being amortized to income over the life of the related property. To the extent certain deferred income taxes of the Utilities are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets are primarily attributable to undepreciated AFUDC-equity and the cumulative net amount of other income tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities are primarily attributable to the Utilities' obligation to credit to ratepayers deferred income taxes provided at rates higher than the current federal income tax rate currently being credited to ratepayers using the average rate assumption method and unamortized deferred investment tax credits. The components of the net deferred income tax liability at March 31, 1999 and December 31, 1998, were as follows:
March 31, December 31, 1999 1998 (In thousands) ========= ========= Deferred tax liabilities- Accelerated depreciation and other property differences............... $1,088,623 $806,148 AFUDC-equity......................... 34,762 33,029 Adjustment clauses................... -- 14,965 Other regulatory assets.............. 29,306 29,739 Prepaid pension and other benefits.. 38,319 34,170 Reacquisition premium on debt........ 16,885 17,311 Deferred tax assets- Deferred investment tax credits...... (39,382) (37,236) Removal costs........................ (161,400) (157,728) Adjustment Clauses................... (4,135) 0 Other postretirement/postemployment benefits (47,864) (51,754) Other, net........................... (28,034) (29,353) -------- --------- 927,080 659,291 Less: Deferred income taxes related to current assets and liabilities............... (22,653) (7,876) --------- --------- Deferred income taxes-noncurrent........ $949,733 $667,167 ========= =========
Federal and state income taxes as set forth in the Consolidated Statements of Income were comprised of the following:
Three Months Twelve Months Ended March 31, Ended March 31, ------------ ------------ ------------ ------------ 1999 1998 1999 1998 ======= ======= ======= ======= (In thousands) Current income taxes - Federal $ 63,513 $ 55,917 $ 121,276 $ 107,709 State 10,224 8,287 18,421 18,468 -------- -------- -------- -------- 73,737 64,204 139,697 126,177 -------- -------- -------- -------- Deferred income taxes, net - Federal (24,789) (27,806) (17,409) (18,145) State (2,139) (2,234) (1,420) (1,200) -------- -------- -------- -------- (26,928) (30,040) (18,829) (19,345) -------- -------- -------- -------- Deferred investment tax credits, net (1,887) (1,821) (7,427) (7,395) -------- -------- -------- -------- Total income taxes $ 44,922 $ 32,343 $ 113,441 $ 99,437 ======= ======= ======= =======
A reconciliation of total income tax expense to an amount computed by applying the statutory federal income tax rate to pretax income is as follows:
Three Months Twelve Months Ended March 31, Ended March 31, ------------ ------------ ------------ ------------ (In thousands) 1999 1998 1999 1998 ======= ======= ======= ======= Net income $ 76,559 $ 60,722 $ 209,723 $ 180,733 Add - Income taxes 44,922 32,343 113,441 99,437 Dividend requirements on preferred stocks of subsidiaries 2,116 2,167 8,487 8,691 -------- -------- -------- -------- Income before preferred dividend requirements of subsidiaries and income taxes $ 123,597 $ 95,232 $ 331,651 $ 288,861 ======= ======= ======= ======= Amount derived by multiplying pre-tax income by the statutory rate $ 43,259 $ 33,331 $ 116,078 $ 101,101 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 969 998 3,963 4,026 Amortization of deferred investment tax credits (1,887) (1,821) (7,427) (7,395) State income taxes, net of federal income tax benefit 4,507 3,153 10,554 10,804 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (721) (1,271) (3,834) (3,816) Low-income housing credits (1,128) (960) (4,008) (3,252) Nondeductible amounts related to amortization of intangible assets and plant acquisition adjustments 619 629 2,506 2,173 Other, net (696) (1,716) (4,391) (4,204) -------- -------- -------- -------- Total income taxes $ 44,922 $ 32,343 $ 113,441 $ 99,437 ======= ======= ======= =======
(7) Pension Plans: Noncontributory, defined benefit retirement plans cover the majority of employees. Benefits under the plans reflect the employees' compensation, years of service and age at retirement. The change in the benefit obligation for 1998 and 1997 was as follows:
(In thousands) 1998 1997 ========= ========= Benefit obligation at beginning of year (January 1,)................. $875,756 $743,634 Service cost......................................................... 17,093 14,714 Interest cost........................................................ 60,686 57,938 Plan amendments...................................................... 14,655 25,096 Actuarial loss....................................................... 38,773 73,768 Acquisition of IWCR.................................................. - 15,772 Benefits paid........................................................ (57,924) (55,166) --------- --------- Benefit obligation at end of the year (December 31,)................. $949,039 $875,756 ========= =========
The change in the fair value of the plans' assets for the years 1998 and 1997 was as follows:
(In thousands) 1998 1997 ========= ========= Fair value of plan assets at beginning of year (January 1,).......... $924,857 $790,978 Actual return on plan assets......................................... 85,254 126,695 Employer contributions............................................... 34,843 46,440 Acquisition of IWCR.................................................. - 15,910 Benefits paid........................................................ (57,924) (55,166) --------- --------- Plan assets at fair value at end of the year (December 31,).......... $987,030 $924,857 ========= =========
The plans' assets are invested primarily in common stocks, bonds and notes. The plans' funded status as of December 31, 1998 and 1997 is as follows:
(In thousands) 1998 1997 ========= ========= Plan assets in excess of benefit obligation.......................... $ 37,991 $ 49,101 Unrecognized net actuarial loss...................................... (10,938) (46,959) Unrecognized prior service cost...................................... 57,193 47,114 Unrecognized transition amount....................................... 26,813 32,107 --------- --------- Prepaid pension costs................................................ $111,059 $81,363
The benefit obligation is the present value of future pension benefit payments and is based on a plan benefit formula that considers expected future salary increases. A discount rate of 7.00% and rate of increase in compensation levels of 4.5% were used to determine the benefit obligations at December 31, 1998 and 1997, respectively. BSG had noncontributory defined benefit pension plans covering substantially all of its employees. At the date of acquisition the benefit obligation was $83.9 million, the fair value of plan assets was $91.5 million and prepaid pension costs were $15.4 million. The benefit obligation is the present value of future pension benefit payments and was based on a plan benefit formula which considers expected future salary increases. A discount rate of 7.00% and rate of increase in compensation levels of 4.5% were used to determine the benefit obligations at the date of acquisition. NiSource prepaid pension cost amounts were $131.2 million at March 31, 1999, and are reported under the captions "Prepayments and Other" in the Consolidated Balance Sheets. The following items are the components of provisions for pensions for the three-month and twelve-month periods ended March 31, 1999 and March 31, 1998:
Three Months Twelve Months Ended March 31, Ended March 31, ------------ ------------ ------------ ------------ (In thousands) 1999 1998 1999 1998 ======= ======= ======= ======= Service costs $ 5,419 $ 4,934 $ 15,993 $14,799 Interest costs 17,214 19,324 56,116 60,433 Expected return on plan assets (22,995) (24,733) (76,413) (76,483) Amortization of transition obligation 1,479 1,760 4,940 5,498 Amortization of prior service costs 1,587 1,676 4,242 4,227 ------------ ------------ ------------ ------------ $ 2,704 $ 2,961 $4,878 $ 8,474 ======= ======= ======= =======
Assumptions used in the valuation and determination of 1999 and 1998 pension expense were as follows:
1999 1998 ========= ========= Discount rate...................................................7.00% 7.00% Rate of increase in compensation levels.........................4.50% 4.50% Expected long-term rate of return on assets.....................9.00% 9.00%
Certain union employees participate in industry-wide, multi-employer pension plans which provide for monthly benefits based on length of service. Specified amounts per compensated hour for each employee are contributed to the trustees of these plans. Contributions of $0.4 million and $2.1 million were made to these plans for the three-month and twelve-month periods ended March 31, 1999, respectively. The relative position of each employer participating in these plans with respect to the actuarial present value of accumulated plan benefits and net assets available for benefits is not available. (8) Postretirement Benefits: Certain health care and life insurance benefits for certain retired employees are provided. The majority of employees may become eligible for these benefits if they reach retirement age while working for NiSource. The expected cost of such benefits is accrued during the employee' years of service. Current rates include postretirement benefit costs on an accrual basis, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. Cash contributions are remitted to grantor trusts. The following table sets forth the change in the plans' accumulated postretirement benefit obligation (APBO) as of December 31, 1998 and 1997:
(In thousands) 1998 1997 ========= ========= Accumulated postretirement benefit obligation at beginning of year (January 1,) ................................ $223,908 $200,790 Service cost......................................................... 5,249 5,034 Interest cost........................................................ 15,793 16,215 Plan amendments..................................................... (283) 4,015 Actuarial (gain) loss................................................ 8,453 (10,242) Acquisition of IWCR.................................................. - 18,505 Benefits paid........................................................ (12,519) (10,409) --------- --------- Accumulated postretirement benefit obligation at end of the year (December 31,)................................. $240,601 $223,908 ========= =========
The change in the fair value of the plan assets for the years 1998 and 1997 was as follows:
(In thousands) 1998 1997 ========= ========= Fair value of plan assets at beginning of year (January 1,).......... $ 2,400 $ - Actual return of plan assets......................................... 1,103 - Employer contributions............................................... 10,637 12,809 Participant contributions............................................ 1,282 - Benefits paid........................................................ (12,519) (10,409) --------- --------- Plan assets at fair value at end of the year (December 31,).......... $ 2,903 $ 2,400 ========= =========
Following is the funded status for postretirement benefits as of December 31, 1998 and 1997:
(In thousands) 1998 1997 ========= ========= Funded status........................................................ $(237,698) $(221,508) Unrecognized net actuarial gain...................................... (87,087) (99,117) Unrecognized prior service cost...................................... 3,873 4,195 Unrecognized transition amount....................................... 164,436 176,464 Accrued liability for postretirement benefits........................ $(156,476) $(139,966) ========= =========
A discount rate of 7%, a pre-Medicare medical trend rate of 7% declining to a long-term rate of 5%; a discount rate of 7%, and a pre-Medicare medical trend rate of 8% declining to a long-term rate of 5%, were used to determine the APBO at December 31, 1998 and 1997, respectively. The accrued liability for postretirement benefits was $153.6 million at March 31, 1999. BSG has postretirement benefit plans covering certain employees. At the date of acquisition the APBO was $25.3 million, the fair value of plan assets was $26.2 million and prepaid postretirement costs were $13.3 million. A discount rate of 7% and a pre-Medicare medical trend rate of 5%, which is the ultimate trend rate, were used to determine the APBO. Net periodic postretirement benefit costs, before consideration of the rate-making discussed previously, for the three-month and twelve-month periods ended March 31, 1999 and March 31, 1998 include the following components:
Three Months Twelve Months Ended March 31, Ended March 31, ------------ ------------ ------------ ------------ (In thousands) 1999 1998 1999 1998 ======= ======= ======= ======= Service costs $ 996 $ 1,187 $ 5,058 $ 4,631 Interest costs 4,510 4,073 16,230 15,491 Expected return on plan assets (379) (50) (545) (50) Amortization of transition obligation 3,041 2,929 11,857 11,723 Amortization of prior service costs 86 75 333 354 Amortization of (gain) loss (1,176) (1,393) (5,530) (6,229) ------- ------- ------- ------- $ 7,078 $ 6,821 $ 27,403 $ 25,920 ======= ======= ======= =======
Assumptions used in the determination of 1999 and 1998 net periodic postretirement benefit costs were as follows:
1999 1998 ========= ========= Discount rate...................................................7.00% 7.00% Rate of increase in compensation levels.........................4.50% 4.50% Assumed annual rate of increase in health care benefits.........7.00% 8.00% Assumed ultimate trend rate.....................................5.00% 5.00%
The effect of a 1% increase in the assumed health care cost trend rates for each future year would increase the APBO at January 1, 1999 by approximately $30.6 million and increase the aggregate of the service and interest cost components of plan costs by approximately $.8 million for the three-month period ended March 31, 1999. The effect of a 1% decrease in the assumed health care cost trend rates for each future year would decrease the APBO at January 1, 1999 by approximately $23.9 million, and decrease the aggregate of the service and interest cost components of plan costs by approximately $.6 million for the three-month period ended March 31, 1999. Amounts disclosed above could be changed significantly in the future by changes in health care costs, work force demographics, interest rates or plan changes. (9) Authorized Classes of Cumulative Preferred and Preference Stocks: NiSource - 20,000,000 shares -Preferred -without par value 4,000,000 of NiSource's Series A Junior Participating Preferred Shares are reserved for issuance pursuant to the Share Purchase Rights Plan described in Note 14, Common Shares. Northern Indiana - 2,400,000 shares -Cumulative Preferred -$100 par value 3,000,000 shares -Cumulative Preferred -no par value 2,000,000 shares -Cumulative Preference -$50 par value(none outstanding) 3,000,000 shares -Cumulative Preference -no par value (none issued) Indianapolis Water Company (IWC) - 300,000 shares -Cumulative Preferred -$100 par value Note 10 sets forth the preferred stocks which are redeemable solely at the option of the issuer, and Note 11 sets forth the preferred stocks which are subject to mandatory redemption requirements or whose redemption is outside the control of the issuer. The preferred shareholders of Northern Indiana and IWC have no voting rights, except in the event of default on the payment of four consecutive quarterly dividends, or as required by Indiana law to authorize additional preferred shares, or by the Articles of Incorporation in the event of certain merger transactions. (10) Preferred Stocks, Redeemable Solely at the Option of the Issuer:
Redemption Price at March 31, December 31, March 31, (Dollars in thousands) 1999 1998 1999 =========== =========== =========== Northern Indiana Public Service Company: Cumulative preferred stock - $100 par value - 4-1/4% series - 209,051 shares outstanding $ 20,905 $ 20,905 $101.20 4-1/2% series - 79,996 shares outstanding 8,000 8,000 $100.00 4.22% series - 106,198 shares outstanding 10,620 10,620 $101.60 4.88% series - 100,000 shares outstanding 10,000 10,000 $102.00 7.44% series - 41,890 shares outstanding 4,189 4,189 $101.00 7.50% series - 34,842 shares outstanding 3,484 3,484 $101.00 Premium on preferred stock 254 254 N/A Cumulative preferred stock - no par value - Adjustable rate (6.00% at March 31, 1999), Series A (stated value $50 per share) 473,285 shares outstanding 23,664 23,664 $50.00 Indianapolis Water Company: Cumulative preferred stock- $100 par value 4.00% to 5.00%, 44,966 shares outstanding 4,497 4,497 $100- $105 - ------------------ ----------- ----------- $ 85,613 $ 85,613 =========== ===========
During the period April 1, 1998 to March 31, 1999, there were no additional issuances of the above preferred stocks. The foregoing preferred stocks are redeemable in whole or in part at any time upon thirty days' notice at the option of the issuer at the redemption prices shown. (11) Preferred Stocks, Redemption Outside Control of Issuer: Preferred stocks subject to mandatory redemption requirements or whose redemption is outside the control of issuer, excluding sinking fund payments due within one year were as follows:
March 31, December 31, (Dollars in thousands) 1999 1998 =========== =========== Northern Indiana Public Service Company: Cumulative preferred stock - par value - 8.85% series - 50,000 shares outstanding $ 5,000 $ 5,000 7-3/4% series - 33,352 shares outstanding 3,335 3,335 8.35% series - 51,000 shares outstanding 5,100 5,100 Cumulative preferred stock -no par value - 6.50% series - 430,000 shares outstanding 43,000 43,000 ---------- ---------- $ 56,435 $ 56,435 ========== ==========
The redemption prices at March 31, 1999, as well as sinking fund provisions for the cumulative preferred stocks subject to mandatory redemption requirements, or whose redemption is outside the control of issuer, were as follows:
Sinking Fund or Series Redemption Price Per Share Mandatory Redemption Provisions =========== ====================== ====================================== Cumulative preferred stock -$100 par value - 8.85% $100.74, reduced periodically 12,500 shares on or before April 1. 8.35% $103.44, reduced periodically 3,000 shares on or before July 1; increasing to 6,000 shares beginning in 2004; noncumulative option to double amount each year. 7-3/4% $104.06, reduced periodically 2,777 shares on or before December 1; noncumulative option to double amount each year. Cumulative preferred stock -no par value - 6.50% $100.00 on October 14, 2002 430,000 shares on October 14, 2002.
Sinking fund requirements with respect to redeemable preferred stocks for the next five years and thereafter, not reflecting redemptions made after March 31, 1999, were as follows:
Twelve Months Ended March 31, ============================= (In thousands) 2000 ......................................................$1,828 2001 ...................................................... 1,828 2002 ...................................................... 1,828 2003 ......................................................44,828 2004 ...................................................... 1,828 Thereafter..................................................... 6,123 --------- Total preferred stocks, redemption outside control of issuer $58,263 =========
Sinking fund payments due within one year are reported under the caption "Other accruals" in the Consolidated Balance Sheets. (12) Common Dividend: During the next few years, NiSource's ability to pay dividends will depend upon dividends it receives from Northern Indiana. Northern Indiana's Indenture dated August 1, 1939, as amended and supplemented (Indenture), provides that it will not declare or pay any dividends on any class of capital stock (other than preferred or preference stock) except out of earned surplus or net profits of Northern Indiana. At March 31, 1999, Northern Indiana had approximately $158.5 million of retained earnings (earned surplus) available for the payment of dividends. Future dividends will depend upon adequate retained earnings, adequate future earnings and the absence of adverse developments. (13) Earnings Per Share: Earnings per share were determined in accordance with the provisions of SFAS No. 128 "Earnings per Share," which requires the presentation of basic earning per share and diluted earnings per share. Basic earnings per share were computed by dividing net income, reduced for preferred dividends, by the average number of common shares outstanding during the period. The diluted earnings per share calculation assumes the conversion of nonqualified stock options into common shares. The net income, preferred dividends and shares used to compute basic and diluted earnings per share are presented in the following table:
Three Months Twelve Months Ended March 31, Ended March 31, ---------------- ---------------- (Dollars in thousands, except per share amounts) 1999 1998 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------------- Basic Weighted Average Number of Common Shares Outstanding 122,646,186 123,872,613 120,475,670 125,021,821 Net Income to be Used to Compute Basic Earnings per Share: Net Income $ 76,559 $ 60,722 $ 209,723 $ 180,733 Basic Earnings per Average Common Share $ 0.62 $ 0.49 $ 1.74 $ 1.44 Diluted Weighted Average Number of Common Shares Outstanding 122,646,186 123,872,613 120,475,670 125,021,821 Dilutive effect for Nonqualified Stock Options 699,796 511,358 770,512 304,907 Weighted Average Shares 123,345,982 124,383,971 121,246,182 125,326,728 Net Income to be Used to Compute Diluted Earnings per Share: Net Income $ 76,559 $ 60,722 $ 209,723 $ 180,733 Diluted Earnings per Average Common Share $ 0.62 $ 0.48 $ 1.72 $ 1.44
(14) Common Shares: On April 8, 1998, shareholders approved an increase in the number of authorized common shares without par value from 200,000,000 shares to 400,000,000 shares. All references to number of common shares reported, including per share amounts and stock option date, reflect a two-for-one stock split as if it had occurred at the beginning of the earliest period. Share Purchase Rights Plan. On February 27, 1990, the Board of Directors (Board) declared a dividend distribution of one Right for each outstanding common share to shareholders of record on March 12, 1990. The Rights are not currently exercisable. Each Right, when exercisable, would initially entitle the holder to purchase from NiSource one two-hundredth of a share of Series A Junior Participating Preferred Share, without par value, at a price of $30 per one two-hundredth of a share. In certain circumstances, if an acquirer obtained 25% of NiSource's outstanding shares, or merged into NiSource or merged NiSource into the acquirer, the Rights would entitle the holders to purchase NiSource's or the acquirer's common shares for one-half of the market price. The Rights will not dilute NiSource's common shares nor affect earnings per share unless they become exercisable for common shares. The Plan was not adopted in response to any specific attempt to acquire control of NiSource. Common Share Repurchases. The Board has authorized the repurchase of 62.1 million common shares, subject to certain limits. At March 31, 1999, approximately 55.2 million shares had been repurchased at an average price of $16.94 per share. (15) Long-Term Incentive Plans: There are two long-term incentive plans for key management employees that were approved by shareholders on April 13, 1988 (1988 Plan) and April 13, 1994 (1994 Plan), each of which provides for the issuance of up to 5.0 million common shares to key employees through April 1998 and April 2004, respectively. The 1988 Plan, as amended and restated, and the 1994 Plan, as amended and restated, were re-approved by shareholders at the 1999 Annual Meeting of Shareholders held on April 14, 1999. At March 31, 1999, there were 2,495,350 shares reserved for future awards under the 1994 Plan. The Plans permit the following types of grants, separately or in combination: nonqualified stock options, incentive stock options, restricted stock awards, stock appreciation rights and performance units. No incentive stock options or performance units were outstanding at March 31, 1999. Under the Plans, the exercise price of each option equals the market price of common stock on the date of grant. Each option has a maximum term of ten years and vests one year from the date of grant. In connection with the acquisition of BSG (see Note 3), all outstanding BSG non-qualified stock options were replaced with NiSource non-qualified stock options. The replacement of such options did not change their original vesting provisions, terms or fair values. Information regarding these options can be found in the following tables about changes in non-qualified stock options under the caption "converted". Stock appreciation rights (SARs) may be granted only in tandem with stock options on a one-for-one basis and are payable in cash, common shares, or a combination thereof. There were no SARs outstanding at March 31, 1999. Restricted stock awards are restricted as to transfer and are subject to forfeiture for specific periods from the date of grant. Restrictions on shares awarded in 1995 lapse five years from date of grant, and vesting varies from 0% to 200% of the number awarded, subject to specific earnings per share and stock appreciation goals. Restrictions on shares awarded in 1998 and 1999 lapse two years from date of grant and vesting varies from 0% to 100% of the number awarded, subject to specific performance goals. If a participant's employment is terminated prior to vesting other than by reason of death, disability or retirement, restricted shares are forfeited. There were 537,166 and 534,666 restricted shares outstanding at March 31, 1999 and December 31, 1998, respectively. The Nonemployee Director Stock Incentive Plan, which was approved by shareholders, provides for the issuance of up to 200,000 common shares to nonemployee directors. The Plan provides for awards of common shares which vest in 20% per year increments, with full vesting after five years. The Plan also allows for the award of nonqualified stock options. If a director's service on the Board is terminated for any reason other than death or disability, any common shares not vested as of the date of termination are forfeited. As of April 14, 1999, 75,500 shares had been issued under the Plan. These plans are accounted for under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized for nonqualified stock options. The compensation cost that was charged against net income for restricted stock awards was $0.7 million and $0.5 million for the three-month and $2.9 million and $1.9 million for the twelve-month periods ended March 31, 1999 and 1998, respectively. Had compensation cost for non-qualified stock options been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," net income and earnings per average common share would have been reduced to the following pro forma amounts:
Three Months Twelve Months Ended March 31, Ended March 31, -------------------- -------------------- 1999 1998 1999 1998 ====== ====== ====== ====== (Dollars in thousands, except per share data) Net Income: As reported $ 76,559 $ 60,722 $ 209,723 $ 180,733 Pro forma $ 76,152 $ 60,501 $ 208,408 $ 179,869 Earnings Per Average Common Share: Basic: As reported $ 0.62 $ 0.49 $ 1.74 $ 1.44 Pro forma $ 0.62 $ 0.49 $ 1.72 $ 1.43 Diluted: As reported $ 0.62 $ 0.48 $ 1.72 $ 1.43 Pro forma $ 0.61 $ 0.48 $ 1.71 $ 1.43
The fair value of each option granted as used to determine pro forma net income is estimated as of the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in the twelve-month periods ended March 31, 1999 and March 31, 1998: risk-free interest rate of 5.29% and 6.19%, respectively; expected dividend yield per share of $0.96 and $0.90, respectively; expected option term of 5.4 and 5.5 years, respectively; and expected volatilities of 13.09% and 12.2%, respectively. Changes in outstanding shares under option and SARs for the three-month and twelve-month periods ended March 31, 1999 and March 31, 1998 were as follows:
NONQUALIFIED STOCK OPTIONS ------------------------------------------- Weighted Weighted Average Average Option Option Three Months Ended March 31, 1999 Price 1998 Price ============================ ========== ======= ========= ======== Balance, beginning of period 2,651,300 $ 19.61 2,535,400 $ 16.41 Converted 740,780 15.04 - - Exercised (44,417) 16.61 (200,800) 12.55 Canceled (1,500) 29.22 - ---------- --------- Balance, end of period 3,346,163 $ 18.69 2,334,600 $ 16.74 ========== ========= Shares exercisable 2,742,663 $ 16.37 1,806,000 $ 15.60 ========== =========
NONQUALIFIED STOCK OPTIONS ------------------------------------------- Weighted Weighted Average Average Option Option Twelve Months Ended March 31, 1999 Price 1998 Price ============================ ========== ======= ========= ======== Balance, beginning of period 2,334,600 $ 16.73 2,284,100 $ 15.33 Converted 740,780 15.04 - Granted 607,000 29.22 533,600 20.64 Exercised (312,517) 16.69 (478,100) 14.28 Canceled (23,700) 22.55 (5,000) 20.64 ---------- --------- Balance, end of period 3,346,163 $ 18.69 2,334,600 $ 16.74 ========== ========= Shares exercisable 2,742,663 $ 16.37 1,806,000 $ 15.60 ========== ========= Weighted average fair value of options granted $ 4.28 $ 2.66 ========== =========
The following table summarizes information about non-qualified stock options at March 31, 1999:
OPTIONS OUTSTANDING - -------------------------------------------------------------------------------- Number Weighted Average Range of Outstanding at Remaining Weighted Average Option Price March 31, 1999 Contractual Life Option Price ============= =============== =============== =============== $ 8.53 to $12.31 249,457 1.4 years $ 10.66 $13.03 to $19.77 2,008,548 5.0 years 16.05 $20.64 to $29.22 1,088,158 8.8 years 25.41 - ------------------ ---------------- ---------------- ---------------- $ 8.53 to $29.22 3,346,163 5.9 years $ 18.69 ================ OPTIONS EXERCISABLE - -------------------------------------------------------------------------------- Number Range of Exercisable at Weighted Average Option Price March 31, 1999 Option Price ============= =============== ============== $ 8.53 to $ 12.31 249,457 $ 10.66 $13.03 to $ 19.77 2,008,548 16.05 $20.64 484,658 20.64 - --------------------- ------------- --------- $ 8.53 to $20.64 2,742,663 $ 16.37 =============== ==============
(16) Long-Term Debt:
March 31, December 31, (Dollars in thousands) 1999 1998 ========== ========== First mortgage bonds - Interest rates between 5.05% and 9.83% with a weighted average interest rate of 6.62% and various maturities between May 1, 2001 and July 15, 2028 $ 186,600 $ 186,600 Pollution control notes and bonds- Interest rates between 3.05% and 5.70% with a weighted average interest rate of 3.85% and various maturities between October 1, 2003 and April 1, 2019 239,500 239,500 Medium-term notes - Interest rates between 5.99% and 9.70% with a weighted average interest rate of 7.12% and various maturities between March 20, 2000 and August 4, 2027 1,341,301 1,048,025 Subordinated Debentures -7-3/4%, due March 31, 2026 75,000 75,000 Senior Notes Payable - 6.78%, due December 1, 2027 75,000 75,000 Notes payable - Interest rates between 6.31% and 9.00% with a weighted average interest rate of 7.26% and various maturities between October 1, 1999 and January 1, 2008 47,800 41,807 Variable bank loan - 6.63%, due August, 2003 5,600 5,600 Unamortized premium and discount on long-term debt, net (3,401) (3,567) ---------- ---------- Total long-term debt, excluding amounts due within one year $1,967,400 $1,667,965 ========== ==========
The sinking fund requirements and maturities of long-term debt for the next five years and thereafter were as follows as of March 31, 1999:
Twelve Months Ended March 31, ============================= (In thousands) 2000 ..................................................$ 39,122 2001 ................................................... 186,546 2002 ................................................... 49,124 2003 ................................................... 137,010 2004 ................................................... 135,552 Thereafter..................................................1,459,168 --------- Total long-term debt (including current portion)...........$2,006,522 =========
Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the lives of such bonds. Reacquisition premiums are being deferred and amortized. These premiums are not earning a return during the recovery period. The first mortgage bonds constitute a direct first mortgage lien upon certain utility property and franchises. Certain trust indentures require annual sinking or improvement payments amounting to .50% of the maximum aggregate amount outstanding. As permitted, this requirement has been satisfied by substituting a portion of permanent additions to utility plant. NiSource is authorized to issue and sell up to $217,692,000 Medium-Term Notes, Series E, with various maturities, for purposes of refinancing certain first mortgage bonds and medium-term notes. As of March 31, 1999, $139.0 million of these medium-term notes had been issued with various interest rates and maturities. The proceeds from these issuances were used to pay short-term debt incurred to redeem its First Mortgage Bonds, Series N, and to pay at maturity various issues of Medium-Term Notes, Series D. $40.0 million in 5.05% medium-term notes due July 15, 2028 were issued on July 15, 1998, with the proceeds being used to redeem 7 7/8% Bonds. In February 1999, $35.0 million of ten-year medium term notes were issued at a rate of 5.99% with a maturity date of February 1, 2009 and $45.0 million of twenty-year medium term notes were issued at a rate of 6.61% with a maturity date of February 1, 2019. The majority of the proceeds were used to reduce existing credit facilities and the remaining proceeds were used for general corporate purposes. The financial obligations of Capital Markets are subject to a Support Agreement between NiSource and Capital Markets, under which NiSource has committed to make payments of interest and principal on Capital Markets' obligations in the event of a failure to pay by Capital Markets. Restrictions in the Support Agreement prohibit recourse on the part of Capital Markets' creditors against the stock and assets of Northern Indiana that are owned by NiSource. Under the terms of the Support Agreement, in addition to the cash flow of cash dividends paid to NiSource by any of its consolidated subsidiaries, the assets of NiSource, other than the stock and assets of Northern Indiana, are available as recourse for the benefit of Capital Markets' creditors. The carrying value of the assets of NiSource, other than the assets of Northern Indiana, were approximately $2.6 billion at March 31, 1999. (17) Current Portion of Long-Term Debt: At March 31, 1999 and December 31, 1998, the current portion of long-term debt due within one year was as follows:
March 31, December 31, (In thousands) 1999 1998 ========= ========= Medium-term notes- Interest rates between 5.83% and 6.93% with a weighted average interest rate of 6.00% ......................................... $ 7,289 $ - Notes payable- Interest rates between 5.75% and 9.00% with a weighted average interest rate of 6.08% ......................................... 29,833 4,790 Sinking funds due within one year.................................... 2,000 2,000 --------- --------- Total current portion of long-term debt........................... $ 39,122 $ 6,790 ========= =========
(18) Short-Term Borrowings: There are two five-year, $100 million revolving credit agreements that terminate on September 23, 2003 and two 364-day $100 million revolving credit agreements that terminate on September 23, 1999. The 364-day agreements may be extended at expiration for additional periods of 364 days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. At March 31, 1999, there were no borrowings outstanding under these agreements. In addition, various lines of credit are maintained, as well as a $50 million uncommitted finance facility. At March 31, 1999 there were no borrowings under the uncommitted finance facility. Lines of credit for up to $214.1 million are held with lenders at either their commercial prime or market lending rates. As of March 31, 1999, there were $35.0 million of borrowings outstanding under these lines of credit with a weighted average interest rate of 5.71%. As of December 31, 1998, there were $84.1 million of borrowings outstanding under these lines of credit. Money market lines of credit for up to $403.5 million are maintained. As of March 31, 1999, there was $86.0 million outstanding under these money market lines of credit with a weighted average interest rate of 5.99%. At December 31, 1998, there were $127.3 million of borrowings outstanding under these money market lines of credit. At March 31, 1999 and December 31, 1998, short-term borrowings were as follows:
March 31, December 31, (In thousands) 1999 1998 ========= ========= Commercial paper- Weighted average interest rate of 4.99% at March 31, 1999......... $114,200 $ 193,700 Notes payable- Weighted average interest rate of 5.58% at March 31, 1999......... 135,773 217,340 --------- --------- Total short-term borrowings....................................... $249,973 $411,040 ========= =========
(19) Corporate Premium Income Equity Securities and Company-Obligated Manditorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely Company Debentures: In February 1999 an underwritten public offering of 6.9 million Corporate Premium Income Equity Securities (PIES) was completed. The net proceeds of approximately $334.7 million were primarily used to fund the cash portion of the consideration payable in the acquisition of BSG, and to repay short-term indebtedness. Each PIES consists of (i) a stock purchase contract to purchase, four years from the date of issuance, common shares at a face value of $50 and (ii) a Preferred Security issued by a wholly-owned subsidiary trust. Each Preferred Security is pledged as collateral, for the benefit of NiSource, in support of the holder's obligation to purchase common shares under the stock purchase contract. The face value of the PIES is not recorded in the Consolidated Balance Sheets. A $22.2 million present value contract fee payable to the PIES holders has been recorded as a liability and as reduction to paid-in capital. In addition, paid-in capital has been reduced by $10.4 million for the issuance costs of the PIES. The Preferred Securities represent undivided beneficial interests in the assets of NIPSCO Capital Trust I (Capital Trust), with liquidation amounts of $50 per security. The sole assets of Capital Trust are subordinated debentures (Debentures) of NiSource that bear interest at the same rates as the Preferred Securities to which they relate, and certain rights under related guarantees by NiSource. The dividends paid on Preferred Securities are presented under the caption "minority interests" in NiSource's Consolidated Statements of Income. The amounts outstanding are presented under the caption, "Company-obligated manditorily redeemable preferred securities of subsidiary trust holding solely company debentures," in NiSource's Consolidated Balance Sheets. At March 31, 1999, there were 6.9 million, 5.9% Preferred Securities outstanding with Capital Trust assets of $345.0 million. (20) Operating Leases: The following is a schedule, by year, of future minimum rental payments, excluding those to associated companies, required under operating leases that have initial or remaining noncancelable lease terms in excess of one year as of March 31, 1999:
(In thousands) 2000 ............................................................ $ 32,020 2001 ............................................................ 31,205 2002 ............................................................ 31,142 2003 ............................................................ 60,632 2004 ............................................................ 76,742 Later years.......................................................... 231,309 --------- Total minimum payments required...................................... $463,050 =========
The Consolidated Financial Statements include rental expense for all operating leases as follows:
March 31, March 31, (In thousands) 1999 1998 ======== ======== Three months ended $ 9,307 $ 4,949 Twelve months ended $ 27,968 $ 11,540
(21) Commitments: Approximately $1.3 billion will be expended for construction purposes for the period from January 1, 1999 to December 31, 2003. Substantial commitments have been made in connection with this construction program. Northern Indiana has entered into a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and Mitsubishi Heavy Industries America, Inc., under which Pure Air provides scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at its Bailly Generating Station. Services under this contract commenced on June 15, 1992 with annual charges approximating $20.0 million. The agreement provides that, assuming various performance standards are met by Pure Air, a termination payment would be due if Northern Indiana terminated the agreement prior to the end of the twenty-year contract period. During 1995, Northern Indiana entered into a ten-year agreement with IBM to have IBM perform all data center, application development and maintenance, and desktop management. Annual fees under the agreement are estimated at $20.0 million. Primary Energy, Inc. ("Primary") arranges energy-related projects for large energy-intensive customers and offers such customers nationwide expertise in managing the engineering, construction, operation and maintenance of such projects. Through its subsidiaries, Primary has entered into partnering agreements with several of NiSource's largest industrial customers, principally steel mills, to service a portion of their energy needs. In order to serve its customers under the partnering agreements, Primary, through its subsidiaries, has entered or expects to enter into certain operating lease commitments to lease these energy-related projects which have a combined capacity of 393 megawatts. NiSource, principally through Capital Markets, guarantees certain of Primary's obligations under each lease, which are including in the Operating Leases in Note 20. Primary has advanced approximately $36.1 million and $31.8 million, at March 31, 1999 and December 31, 1998, respectively, to the lessors of the energy related projects discussed above. These net advances are included in "Other Receivables" in the Consolidated Balance Sheets and as a component of operating activities in the Consolidated Statements of Cash Flows. (22) Financial Instruments and Risk Management: A variety of commodity-based derivative financial instruments are utilized to reduce the price risk inherent in natural gas and electric operations, as well as for energy trading activities. The use of these derivative financial instruments is governed by a risk management policy, which includes as its objective that commodity-based derivative financial instruments will be used primarily for hedging. The risk management policy also governs energy trading activities and is generally designed to allow for such activities within defined risk limits. Natural Gas Commodity Risk Management. Commodity futures, options and swaps are used to hedge the impact of natural gas price fluctuations related to business activities, including price risk related to the physical location of the natural gas (basis risk). As of March 31, 1999, open derivative financial instruments represented hedges of natural gas sales of 23.0 Bcf, and natural gas purchases and inventories of 1.6 Bcf. The net deferred gains or losses on these derivative financial instruments was not material. Energy Trading Activities. Energy trading contracts, which include forwards, futures, options and swaps are used in connection with energy trading activities and may involve the delivery of energy. The net open positions for these energy trading contracts were not significant as of March 31, 1999. (23) Fair Value of Financial Instruments: The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value: Cash and cash equivalents. The carrying amount approximates fair value due to the short maturity of those instruments. Investments. Where feasible, the fair value of investments is estimated based on market prices for those or similar investments. Long-term debt, Preferred stock and Preferred Securities. The fair values of these securities are estimated based on the quoted market prices for the same or similar issues or on the rates offered to NiSource for securities of the same remaining maturities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. The carrying values and estimated fair values of financial instruments were as follows:
March 31, 1999 December 31, 1998 Estimated Estimated Carrying Fair Carrying Fair (In thousands) Amount Value Amount Value =========== ========= ========== ========== Investments................................. $ 43,891 $ 56,523 $ 36,594 $ 36,028 Long-term debt (including current portion).. $ 2,006,522 $2,027,788 $1,674,755 $1,769,934 Preferred stock (including current portion)..... $ 144,220 $ 134,561 $ 143,876 $ 140,420 Preferred securities............................ $ 345,000 $ 348,450 N/A N/A
A substantial portion of the long-term debt relates to utility operations. The Utilities are subject to regulation and gains or losses may be included in rates over a prescribed amortization period, if in fact settled at amounts approximating those above. (24) Customer Concentrations: The Utilities supply natural gas, electric energy and water. Natural gas and electric energy are supplied to the northern third of Indiana and portions of Massachusetts, New Hampshire and Maine. The Water Utilities serve Indianapolis, Indiana, and surrounding areas. Although the Energy Utilities have a diversified base of residential and commercial customers, a substantial portion of their electric and gas industrial deliveries are dependent upon the basic steel industry. The following table shows the basic steel industry percentage of gas revenue (including transportation services) and electric revenue for 1999 and 1998.
Twelve Months Twelve Months Ended March 31, Ended March 31, 1999 1998 ========= ========= Basic Steel Industry Gas revenue percentage.............................................3% 2% Electric revenue percentage.......................................14% 16%
(25) Segments of Business: SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information," was adopted during 1998. SFAS No. 131 establishes standards for reporting information about operating segments in financial statements and disclosures about products and services, and geographic areas. Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. There are four reportable operating segments: Gas, Electric, Water and Gas Marketing. The Gas segment includes regulated gas utilities which provide natural gas distribution and transportation services. The Electric segment is comprised principally of Northern Indiana, a regulated electric utility, which generates, transmits and distributes electricity. In addition, the Electric segment includes a wholesale power marketing operation which until early 1999 marketed wholesale power to other utilities and electric power marketers. The Water segment includes regulated water utilities which provide distribution of water supply to the public. The Gas Marketing segment provides natural gas marketing and sales to wholesale and industrial customers. Reportable segments are operations that are managed separately and meet the quantitative thresholds required by SFAS No. 131. The Other Products and Services column includes a variety of businesses, such as installation, repair and maintenance of underground pipelines, utility line locating and marking, the arrangement of energy-related projects for large energy-intensive facilities, and other products and services, which collectively do not constitute a segment for reporting purposes. Revenues for each segment are principally attributable to customers in the United States. Additional revenues, which are insignificant to consolidated revenues, are attributable to customers in Canada and the United Kingdom. The following tables provide information about business segments. In addition, adjustments have been made to the segment information to arrive at information included in the results of operations and financial position. These adjustments include unallocated corporate assets, revenues and expenses and the elimination of intercompany transactions. The accounting policies of the operating segments are the same as those described in Note 2, "Summary of Significant Accounting Policies."
Other (In thousands) Gas Products For the three months ended March 31, 1999 Gas Electric Water Marketing &Services Adjustments Total - ----------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 393,258 $ 265,188 $ 20,898 $ 215,360 $ 66,674 $ (69,886) $ 891,492 Other, net $ 1,419 $ 128 $ 196 $ 402 $ 6,712 $ (1,773) $ 7,084 Depreciation and amortization $ 26,376 $ 39,655 $ 3,200 $ 84 $ 3,247 $ 347 $ 72,909 Segment profit (loss) $ 88,150 $ 73,634 $ 3,990 $ 892 $ 3,916 $ (7,589) $ 162,993 Assets $2,539,841 $2,700,678 $ 632,832 $ 107,420 $ 369,939 $(124,306) $6,226,404 Capital Expenditures $ 26,844 $ 26,638 $ 27,788 $ 29 $ 5,140 $ 0 $ 86,439 Investments in equity-method investees $ 0 $ 0 $ 4,476 $ 7,365 $ 118,032 $ 0 $ 129,873 Other (In thousands) Gas Products For the three months ended March 31, 1998 Gas Electric Water Marketing &Services Adjustments Total - ----------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 242,735 $ 323,834 $ 17,709 $ 174,866 $ 53,846 $ (33,646) $ 779,344 Other, net $ 605 $ 89 $ (111) $ 517 $ 7,551 $ (203) $ 8,448 Depreciation and amortization $ 18,714 $ 38,768 $ 2,793 $ 66 $ 2,880 $ 53 $ 63,274 Segment profit (loss) $ 48,727 $ 73,760 $ 3,673 $ 133 $ 2,977 $ (3,708) $ 125,562 Assets $1,080,989 $2,701,962 $ 568,453 $ 88,156 $ 549,295 $ (88,363) $4,900,492 Capital Expenditures $ 9,213 $ 24,097 $ 14,198 $ 0 $ 2,794 $ 0 $ 50,302 Investments in equity-method investees $ 0 $ 0 $ 3,802 $ 6,331 $ 101,676 $ 0 $ 111,809 Other (In thousands) Gas Products For the twelve months ended March 31, 1999 Gas Electric Water Marketing & Services Adjustments Total - ----------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 787,621 $1,371,340 $ 87,257 $ 698,187 $ 275,897 $(175,376) $3,044,926 Other, net $ 2,534 $ 592 $ 806 $ 1,902 $ 4,038 $ (652) $ 9,220 Depreciation and amortization $ 83,208 $ 157,730 $ 11,991 $ 350 $ 12,323 $ 507 $ 266,109 Segment profit (loss) $ 106,592 $ 341,306 $ 23,655 $ 5,835 $ 7,883 $ (15,750) $ 469,521 Assets $2,539,841 $2,700,678 $ 632,832 $ 107,420 $ 369,939 $(124,306) $6,226,404 Capital Expenditures $ 79,048 $ 128,120 $ 72,878 $ 400 $ 25,166 $ 0 $ 305,612 Investments in equity-method investees $ 0 $ 0 $ 4,476 $ 7,365 $ 118,032 $ 0 $ 129,873 Other (In thousands) Gas Products For the twelve months ended March 31, 1998 Gas Electric Water Marketing & Services Adjustments Total - ----------------------------------------------------------------------------------------------------------------------------------- Operating revenues $ 716,574 $1,249,508 $ 78,452 $ 567,066 240,501 $(146,166) $2,705,935 Other, net $ 1,008 $ 519 $ 1,354 $ 2,989 $ 9,520 $ (577) $ 14,813 Depreciation and amortization $ 73,703 $ 154,332 $ 11,033 $ 284 $ 15,179 $ 202 $ 254,733 Segment profit (loss) $ 78,643 $ 316,105 $ 23,766 $ 3,741 $ 7,582 $ (15,943) $ 413,894 Assets $1,080,989 $2,701,962 $ 568,453 $ 88,156 $ 549,295 $ (88,363) $4,900,492 Capital Expenditures $ 54,203 $ 120,245 $ 54,795 $ 23 $ 24,113 $ 0 $ 253,379 Investments in equity-method investees $ 0 $ 0 $ 3,802 $ 6,331 $ 101,676 $ 0 $ 111,809
The following table reconciles total reportable segment income before interest and other charges and income taxes to net income for three and twelve months ended March 31, 1999 and 1998:
Three Months Ended Twelve Months Ended March 31, March 31, March 31, March 31, (In thousands) 1999 1998 1999 1998 --------- --------- --------- --------- Total Segment profit (loss) $162,993 $125,562 $ 469,521 $ 254,733 Interest expense, net (36,688) (30,330) (135,162) (125,033) Minority interests (2,708) - (2,708) - Dividends requirements on preferred stock of subsidiaries (2,116) (2,167) (8,487) (8,691) --------- --------- --------- --------- Income before income taxes 121,481 93,065 323,164 Less Income taxes 44,922 32,343 113,441 99,437 --------- --------- --------- --------- Net Income $ 76,559 $ 60,722 $ 209,723 $180,733
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Results of Operations Holding Company NiSource Inc., formerly NIPSCO Industries, Inc., is an energy and utility-based holding company headquartered in Merrillville, Indiana that provides natural gas, electricity and water to the public for residential, commercial and industrial uses. NiSource was organized as an Indiana holding company in 1987 under the name "NIPSCO Industries, Inc." and changed its name to NiSource Inc. on April 14, 1999. NiSource operates primarily in Indiana and New England through seven wholly-owned regulated Energy Utility subsidiaries and four Water Utility subsidiaries. Operating Revenues Twelve months ended March 31, 1999. Total operating revenues for the twelve months ended March 31, 1999 were $339.0 million higher than total operating revenues for the twelve months ended March 31, 1998, representing a 13% increase. Gas revenues were $1,364.8 million, which represented a $166.5 million increase from the comparable period ended March 31, 1998. This increase was primarily due to the inclusion of $110.0 of gas revenues from BSG and increased gas marketing activity, partially offset by decreased gas sales to residential and commercial customers as a result of warmer weather than normal during the fourth quarter of 1998 and decreased gas costs per dth and decreased gas transition costs. Electric revenues were $1,368.0 million, which represented a $121.2 million increase from electric revenues for the comparable period ended March 31, 1998. This increase was mainly due to increased electric sales to residential and commercial customers due to warmer weather during the second and third quarters of 1998 and increased wholesale electric transactions, partially offset by decreased electric sales to industrial customers and decreased fuel costs. Water revenues were $87.1 million, which represented a $8.7 million increase from water revenues for the comparable period ended March 31, 1998. This increase was primarily due to increased water volumes sold and to increased water rates for IWC that became effective on April 8, 1998. Products and Services revenues were $225.0 million, which represented a $42.7 million increase from Products and Services revenues for the comparable period ended March 31, 1998. This increase reflected increased sales at Primary, SM&P Utility Resources, Inc. (SM&P) and Miller Pipeline Corporation (Miller). Three months ended March 31, 1999. Total operating revenues for the three months ended March 31, 1999 were $112.1 million higher than total operating revenues for the three months ended March 31, 1998, representing a 14% increase. Gas revenues were $553.9 million, which represented a $155.0 million increase from gas revenues for the comparable period ended March 31, 1998. This increase was primarily due to the inclusion of $110.0 million of operating revenues from BSG, increased gas marketing activities, increased sales to residential and commercial customers due to colder weather during the period and increased deliveries of gas transported for others partially offset by decreased gas costs per dth and decreased gas transition costs. Electric revenues were $264.3 million, which represented a $58.6 million decrease from electric revenues for the comparable period ended March 31, 1998. This decrease represents fewer wholesale electric transactions in the 1999 period, compared to the 1998 period, partially offset by increased sales to residential and commercial customers and increased fuel costs. Water revenues were $20.9 million, which represented a $3.2 million increase from water revenues for the comparable period ended March 31, 1998. This increase was primarily due to increased water volumes sold and increased water rates for IWC that became effective on April 8, 1998. Products and Services revenues were $52.4 million, which represented a $12.6 million increase from Products and Services revenues for the comparable period ended March 31, 1998. This increase reflected increased sales at Primary, Miller and SM&P. The basic steel industry accounted for 27% of all natural gas delivered (including volumes transported) and 18% of all electric sales during the twelve months ended March 31, 1999. The components of the variations of operating revenues for gas, electric, water and Products and Services are shown in the following table:
Variations from Prior Periods -------------------------------------------------------------------- March 31, 1999 Compared to March 31, 1998 -------------------------------------------------------------------- Three Twelve (In thousands) Months Months ======= ======= Gas Revenue - Pass through of net changes in purchased gas costs, gas storage, and storage transportation costs $ (18,977) $ (41,568) Gas transition costs (1,093) (16,026) Changes in sales levels 23,064 (40,209) Gas transported 4,353 11,389 Bay State Acquisition 109,997 109,997 Gas Marketing 37,636 142,867 ------------ ------------ Gas Revenue Change 154,980 166,450 ------------ ------------ Electric Revenue - Pass through of net changes in fuel costs 862 (4,617) Changes in sales levels 6,975 30,573 Wholesale electric (66,419) 95,205 ------------ ------------ Electric Revenue Change (58,582) 121,161 ------------ ------------ Water Revenue Change 3,160 8,687 ------------ ------------ Products and Services Revenues - Pipeline construction 1,594 4,847 Locate and marking 628 6,705 Other 10,368 31,141 ------------ ------------ Products and Services Revenue Change 12,590 42,693 ------------ ------------ Total Revenue Change $ 112,148 $ 338,991 ======= =======
Cost of Sales Cost of Sales consists of gas costs, costs of fuel for electric generation, costs of power purchased and Products and Services cost of sales. Gas Costs. Total gas costs for the twelve months ended March 31, 1999 increased $120.9 million, or by 14%. This increase reflects the inclusion of gas costs of $58.7 million for BSG and increased gas purchases for gas marketing activities, partially offset by decreased gas costs per dth and decreased gas transition costs. The average cost for the Energy Utilities purchased gas for the twelve months ended March 31, 1999, after adjusting for gas transition costs billed to transport customers, decreased from $2.60 per dth, to $2.51 per dth for the comparable period ended March 31, 1998. The gas costs for the three months ended March 31, 1999 increased by $85.0 million, or by 29%, from gas costs for the three months ended March 31, 1998. This increase reflects the inclusion of gas costs of $58.7 million for BSG and increased gas purchases for gas marketing activities, partially offset by decreased gas costs per dth and gas transition costs. The average cost for the Energy Utilities purchased gas for the three months ended March 31, 1999, after adjusting for gas transition costs billed to transport customers, decreased from $2.60 per dth to $2.37 per dth for the comparable period ended March 31, 1998. Fuel and Purchased Power. The cost of fuel used for electric generation during the twelve months ended March 31, 1999 was $17.6 million higher than the cost of fuel used during the twelve months ended March 31, 1998, mainly due to increased electric generation of 8.7%. The average cost per kilowatt-hour (kwh) generated decreased by 1.1% from 1.54 cents per kwh during the twelve months ended March 31, 1998 to 1.52 cents per kwh for the comparable period ended March 31, 1999. The cost of fuel used for electric generation during the three months ended March 31, 1999 was $2.7 million higher than the cost of fuel used during the twelve months ended March 31, 1998, mainly due to increased electric generation of 5.2%. The average cost per kwh generated during the three months ended March 31, 1999 remained relatively unchanged from the comparable period ended March 31, 1998. Purchased power was $73.5 million higher during the twelve months ended March 31, 1999 than for the twelve months ended March 31, 1998, primarily due to increased power purchased for wholesale electric activity and higher costs per kwh. Purchased power for the three months ended March 31, 1999 decreased $68.2 million primarily due to decreased power purchased for wholesale electric activity and lower costs per kwh. Cost of Sales: Products and Services. The cost of sales for the Products and Services subsidiaries during the twelve and three months ended March 31, 1999 were $17.0 and $5.7 million higher, respectively, than in the comparable periods ended March 31, 1998. This increase reflected inclusion of cost of sales for other Products and Services subsidiaries acquired in the BSG acquisition and increased activity at SM&P and Miller. Operating Margins Twelve months ended March 31, 1999. Operating margins for the twelve months ended March 31, 1999 were $1.3 billion, an increase of $110.0 million from the twelve months ended March 31, 1998. Gas operating margin was $45.6 million higher than in the comparable period ended March 31, 1998. This increase reflected the February 1999 acquisition of BSG and increased deliveries of gas transported for others partially offset by decreased sales to residential and commercial customers reflecting unusually warm weather during the fourth quarter of 1998 and decreased sales to industrial customers. Electric operating margin was $30.0 million higher than in the comparable period ended March 31, 1998. This increase occurred mainly due to increased sales to residential and commercial customers due to warmer weather during the second and third quarters of 1998 partially offset by lower wholesale electric margins. Water operating margin was $8.7 million higher than in the comparable period ended March 31, 1998, due to increased volumes sold and increased water rates for Indianapolis Water Company that became effective on April 8, 1998. Products and Services operating margin was $25.7 million higher than in the comparable period ended March 31, 1998, reflecting higher margins at Primary, Miller, SM&P and the inclusion of Products and Services subsidiaries at BSG. Three months ended March 31, 1999. Operating margins for the three months ended March 31, 1999 were $406.0 million, an increase of $87.0 million from operating margins for the three months ended March 31, 1998. Gas operating margin was $70.0 million higher than gas operating margins for the comparable period ended March 31, 1998. This increase is primarily due to the inclusion of gas operating margin for BSG and increased gas marketing activities. Electric operating margin was $6.9 million higher than the electric operating margin for the comparable period ended March 31, 1998. This increase was mainly due to increased sales to residential and commercial customers. Water operating margin was $3.2 million higher than water operating margins for the comparable period ended March 31, 1998, due to increased water volumes sold and increased water rates for IWC that became effective on April 8, 1998. Products and Services operating margin was $6.9 million higher than Products and Services margins for the comparable period ended March 31, 1998, reflecting higher margins at Primary Energy, Miller and SM&P and the inclusion of Products and Services subsidiaries at BSG. Operating Expenses and Taxes Operating expenses and taxes (except income) consists of operation expenses, maintenance expenses, depreciation and amortization expenses and taxes (except income). Operation expenses. Operation expenses for the twelve months ended March 31, 1999 were $29.5 million higher than operation expenses for the comparable period ended March 31, 1998. This increase reflects the inclusion of $17.6 million of operation expenses at BSG and increased operation expenses at Primary. Operation expenses for the three months ended March 31, 1999 were $30.7 million higher than operation expenses for the comparable period ended March 31, 1998. This increase reflects the inclusion of $17.6 million of operating expenses at BSG, increased operating expenses at Primary and increased employee related costs. Maintenance expenses. Maintenance expenses for the twelve months and three months ended March 31, 1999 were $1.0 and $3.4 million higher, respectively, than maintenance expenses for the comparable periods ended March 31, 1998. These increases were primarily due to maintenance expenses for BSG. Depreciation and amortization expenses. Depreciation and amortization expenses for the twelve months and three months ended March 31, 1999 were $11.4 and $9.6 million higher, respectively, than depreciation and amortization expenses for the comparable periods ended March 31, 1998. These higher expenses reflect the inclusion of depreciation and amortization expenses of BSG and property additions. Other Income (Deductions) Interest charges for the twelve months and three months ended March 31, 1999 were $10.1 and $6.4 million higher than interest charges in the comparable periods ended March 31, 1998. These increases reflect the inclusion of interest charges of BSG and increased short-term borrowings.Additionally, minority interests reflects dividends paid on Preferred Securities in connection with the PIES offering during the three month period ended March 31, 1999. Other, net for the twelve months and three months ended March 31, 1999 were $5.6 and $1.4 million lower, respectively, than Other, net in the comparable periods ended March 31, 1998. These decreases reflect lower equity earnings in equity investees during the current periods and higher net gains on disposition of businesses and properties in prior periods. Net Income Net income for the twelve months ended March 31, 1999 was $209.7 million, compared to net income of $180.7 million for the twelve months ended March 31, 1998. Net income for the three months ended March 31, 1999 was $76.6 million, compared to net income of $60.7 million for the three months ended March 31, 1998. Liquidity and Capital Resources During the next few years, NiSources's ability to pay dividends will depend upon dividends it receives from Northern Indiana. More information about common share dividends can be found in Note 12, "Common Dividend," to the Consolidated Financial Statements. Generally, cash flow from operations has provided sufficient liquidity to meet current operating requirements. But because the utility and utility construction business is seasonal in nature, commercial paper for short-term financing is occasionally issued. As of March 31, 1999 and December 31, 1998, $114.2 million and $193.7 million of commercial paper was outstanding, respectively. The weighted average interest rate of commercial paper outstanding as of March 31, 1999 was 4.99%. There are two five-year, $100 million revolving credit agreements that terminate on September 23, 2003 and two 364-day $100 million revolving credit agreements that terminate on September 23, 1999. The 364-day agreements may be extended at expiration for additional periods of 364 days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. At March 31, 1999, there were no borrowings outstanding under these agreements. In addition, various lines of credit are maintained, as well as a $50 million uncommitted finance facility. At March 31, 1999 there were no borrowings under the uncommitted finance facility. Lines of credit for up to $214.1 million are held with lenders at either their commercial prime or market lending rates. As of March 31, 1999, there were $35.0 million of borrowings outstanding under these lines of credit with a weighted average interest rate of 5.71%. As of December 31, 1998, there were $84.1 million of borrowings outstanding under these lines of credit. Money market lines of credit for up to $403.5 million are maintained. As of March 31, 1999 there were $86.0 million was outstanding under these money market lines of credit with a weighted average interest rate of 5.99%. At December 31, 1998, there were $127.3 million of borrowings outstanding under these money market lines of credit. $40.0 million in revenue bonds were issued in July 1998 and an aggregate of $80.0 million in medium-term notes in February 1999. The revenue bonds, which were used to redeem previously existing revenue bonds, bear interest at 5.95% per annum and mature on July 15, 2028. The medium-term notes, which were used in part to reduce existing credit facilities, consist of $35.0 million in ten-year notes that bear interest at 5.99% interest per annum and $45.0 million in twenty-year notes that bear interest at 6.61% per annum. In February 1999 an underwritten public offering of 6.9 million Corporate Premium Income Equity Securities (PIES) was completed. The net proceeds of approximately $334.7 million were primarily used to fund the cash paid in the acquisition of BSG, and to repay short-term indebtedness. Construction Program. NiSource expects that it will continue to meet its future commitments with respect to its construction program through internally generated funds. Market Risk Sensitive Instruments and Positions See Note 22, "Financial Instruments and Risk Management," to the Consolidated Financial Statements for a discussion of commodity-based derivative financial instruments and risk management. Two primary market risks, commodity price risk and interest rate risk, are addressed by a risk management policy. Commodity price risk. Price risk management activities are designed to address price fluctuations in electricity and natural gas commodity prices that are sensitive to changes in supply and demand. These changes are actively monitored and derivative financial and commodity instruments are used to reduce, or hedge, exposure to price risks. Part of these price risks includes differences in price based on geography. Geographic price differentials result primarily from transportation costs and local supply and demand factors. To hedge a portion of this exposure, basis swaps are used from time to time. However, all basis exposure is not hedged. A portion of customer sales contracts are based upon a fixed sales price with varying volumes that ultimately depend on a customer's supply requirements. Financial derivatives are used based on modeling techniques in order to anticipate future supply requirements. Nonetheless, NiSource remains exposed to price risk for the difference between a customer's actual supply requirements and those requirements predicted by the models. Currently, commodity price risk of the Energy Utilities business is relatively limited, since current regulations allow the Energy Utilities to recoup any prudently incurred fuel and gas costs through rate-making. As the utility industry undergoes deregulation, however, the Energy Utilities will be providing services without the benefit of the traditional rate-making and, therefore, will be more exposed to commodity price risk. Because derivative financial and commodity instruments are substantially the same commodities that are bought and sold in the physical market, NiSource believes that its price management activities do not require any special correlation studies, other than monitoring the degree of convergence between the derivative and cash markets. The daily net commodity position consists of natural gas inventories, commodity purchase and sales contracts and derivative financial and commodity instruments. The fair market value of this portfolio is a summation of the fair market values calculated for each commodity, whose net values are measured by quotes from energy exchange markets and over-the-counter markets. Based upon the fair market value of this portfolio as of March 31, 1999, if the electric and natural gas market prices dropped by 10 percent, this change would reduce NiSource's net income by approximately $1.1 million. Any such movements in prices, however, are not indicative of actual results and are subject to change. Interest rate risk. Long-term debt is utilized as a primary source of capital. A significant portion of this long-term debt consists of medium-term notes. In addition, longer term fixed-price debt instruments have been used that in the past have been refinanced when interest rates decreased. To the extent that such refinancing is economical, refinancing these fixed-price instruments will continue. Information about long-term debt is in Note 16 to the Consolidated Financial Statements, "Long-Term Debt." Information about the current market valuation of long-term debt is in Note 23 to the Consolidated Financial Statements, "Fair Value of Financial Instruments." Information about the use of derivatives and risk management policy is in Note 2 to the Consolidated Financial Statements, "Summary of Significant Accounting Policies- Derivatives." Year 2000 Costs Risks. Year 2000 issues address the ability of electronic processing equipment to process date sensitive information and recognize the last two digits of a date as occurring in or after the year 2000. Any failure in any system may result in material operational and financial risks. Possible scenarios include a system failure in a generating plant, an operating disruption or delay in transmission or distribution, or an inability to interconnect with the systems of other utilities. In addition, while it is anticipated that mission-critical systems will be year 2000 compliant in a timely fashion, it cannot guarantee the compliance of systems operated by other companies upon which it depends. For example, the ability of an electric company to provide electricity to its customers depends upon a regional electric transmission grid, which connects the systems of neighboring utilities to support the reliability of electric power within the region. If one company's system is not year 2000 compliant, then a failure could affect the reliability of all providers within the grid, including NiSource. Similarly, gas operations depend on natural gas pipelines that are not owned or controlled, and any non-compliance by a company owning or controlling those pipelines may affect NiSource's ability to provide gas to its customers. Failure to achieve year 2000 readiness could have a material adverse affect on results of operations, financial position and cash flows. The program to address risks associated with the year 2000 is continuing. The focus is on both information technology (IT) and non-IT systems, and substantial progress has been made in preparing these systems for proper functioning in the year 2000. State of Readiness. The year 2000 program consists of four phases: inventory (identifying systems potentially affected by the year 2000), assessment (testing identified systems), remediation (correcting or replacing non-compliant systems) and validation (evaluating testing remediated systems to confirm compliance). Northern Indiana has completed the remediation and validation phases for all its mission-critical systems. BSG completion is expected in the fourth quarter of 1999. IWC completion is expected in June 1999. NiSource, except for BSG, has completed the inventory and assessment phases for all of its non-IT mission-critical systems and has scheduled remediation (including replacement) and validation for its non-IT mission-critical systems throughout 1999. Substantially completion of mission-critical year 2000 efforts is expected by June 30, 1999, with the year 2000 program concluding in the fourth quarter of 1999. Because outside suppliers and vendors with similar year 2000 issues are depended upon, the ability of those suppliers and vendors to provide it with an uninterrupted supply of goods and services is being assessed. Critical vendors and suppliers have been contacted in order to investigate their year 2000 efforts. In addition, electricity and gas industry groups such as the North American Electric Reliability Council, the Electric Power Research Institute, and the American Gas Association are being worked with to discuss and evaluate the potential impact of year 2000 problems upon the electric grid systems and pipeline networks that interconnect within each of those industries. Costs. The total cost of the year 2000 program is estimated to be $28 million. These costs have been, and will continue to be, funded from operations. Costs related to the maintenance or modification of existing systems are expensed as incurred. Costs related to the acquisition of replacement systems are capitalized. These costs are not anticipated to have a material impact on results of operations. Contingency Plans. NiSource currently is in the process of structuring its contingency plans to address the possibility that any mission-critical system upon which it depends, including those controlled by outside parties, will be non-compliant. This includes identifying alternate suppliers and vendors, conducting staff training and developing communication plans. In addition, the ability to maintain or restore service in the event of a power failure or operating disruption or delay is being evaluated, along with the limited ability to mitigate the effects of a network failure by isolating its own network from the non-compliant segments of the greater network. These contingency plans are expected to be completed during the second quarter of 1999; however, the contingency plans will be under review during the third and fourth quarters of 1999. Competition and Regulatory Changes The regulatory frameworks applicable to the Energy Utilities, at both the state and federal levels, are in the midst of a period of fundamental change. These changes have impacted and will continue to impact operations, structure and profitability. At the same time, competition within the electric and gas industries will create opportunities for to compete for new customers and revenues. Management has taken steps to make the company more competitive and profitable in this changing environment, including partnering on energy projects with major industrial customers, converting some of its generating units to allow use of lower cost, low sulfur coal, providing its gas customers with increased customer choice for new products and services throughout the service territory, and establishing subsidiaries that provide gas and develop new energy-related products for residential, commercial and industrial customers. The Electric Industry. At the Federal level, FERC issued Order No. 888-A in 1996 which required all public utilities owning, controlling or operating transmission lines to file non-discriminatory open-access tariffs and offer wholesale electricity suppliers and marketers the same transmission service they provide themselves. In 1997, FERC approved Northern Indiana's open-access transmission tariff. Although wholesale customers currently represent a small portion of Northern Indiana's electricity sales, it intends to continue its efforts to retain and add wholesale customers by offering competitive rates and also intends to expand the customer base for which it provides transmission services. At the state level, it was announced in 1997 that if a consensus could be reached regarding electric utility restructuring legislation, a restructuring bill during the 1999 session of the Indiana General Assembly would be supported. During 1998, discussions were held with the other investor-owned utilities in Indiana regarding the technical and economic aspects of possible legislation leading to greater customer choice. A consensus was not reached. Therefore, no legislation was supported regarding electric restructuring during the 1999 session of the Indiana General Assembly. During 1999, discussions will continue with all segments of the Indiana electric industry in an attempt to reach a consensus on electric restructuring legislation for introduction during the 2000 session of the Indiana General Assembly. The Gas Industry. At the Federal level, gas industry deregulation began in the mid-1980s when FERC required interstate pipelines to provide nondiscriminatory transportation services pursuant to unbundled rates. This regulatory change permitted large industrial and commercial customers to purchase their gas supplies either from the Energy Utilities or directly from competing producers and marketers, which would then use the Energy Utilities' facilities to transport the gas. More recently, the focus of deregulation in the gas industry has shifted to the states. At the state level, the Indiana Utility Regulatory Commission (IURC) approved in 1997 Northern Indiana's Alternative Regulatory Plan (ARP) which implemented new rates and services that included, among other things, unbundling of services for additional customer classes (primarily residential and commercial users), negotiated services and prices, a gas cost incentive mechanism, and a price protection program. The gas cost incentive mechanism allows Northern Indiana to share any cost savings or cost increases with its customers based upon a comparison of Northern Indiana's actual gas supply portfolio cost to a market-based benchmark price. Phase I of Northern Indiana's Customer Choice Pilot Program ended on March 31, 1999. This pilot program offered a limit of 82,000 residential customers within St. Joseph County and 10,000 commercial customers throughout the NiSource service area the right to choose alternative gas suppliers. Phase II of Northern Indiana's Customer Choice Pilot Program will commence on April 1, 1999 and continue for a one-year period. During this phase, Northern Indiana plans to offer customer choice to all 660,000 residential and 50,000 commercial customers throughout its gas service territory. A limit of 150,000 residential and 20,000 commercial customers are eligible to enroll in Phase II of the program. The IURC order allows NiSource's natural gas marketing subsidiary to participate as a supplier of choice to Northern Indiana customers. In addition, as Northern Indiana has allowed residential and commercial customers to designate alternative gas suppliers, it has also offered new services to all classes of customers including, but not limited to, price protection, negotiated sales and services, gas lending and parking, and new storage services. To date, the Energy Utilities have not been materially affected by competition and management does not foresee substantial adverse affects in the near future unless the current regulatory structure is substantially altered. NiSource believes the steps that it has taken to deal with increased competition has had and will continue to have significant positive effects in the next few years. Impact of Accounting Standards Information about the impact of anticipated accounting standards that have not yet been adopted upon accounting policy can be found in Note 2, "Summary of Significant Accounting Policies- Impact of Accounting Standards" to the Consolidated Financial Statements. Forward Looking Statements This report contains forward looking statements within the meaning of the securities laws. Forward looking statements include terms such as "may," "will," "expect," "believe," "plan" and other similar terms. NiSource cautions that, while it believes such statements to be based on reasonable assumptions and makes such statements in good faith, you can not be assured that the actual results will not differ materially from such assumptions or that the expectations set forth in the forward looking statements derived from these assumptions will be realized. You should be aware of important factors that could have a material impact on future results. These factors include, but are not limited to, weather, the federal and state regulatory environment, year 2000 issues, the economic climate, regional, commercial, industrial and residential growth in the service territories served by NiSource's subsidiaries, customers' usage patterns and preferences, the speed and degree to which competition enters the utility industry, the timing and extent of changes in commodity prices, changing conditions in the capital and equity markets and other uncertainties, all of which are difficult to predict, and many of which are beyond NiSource's control. Item 3. Quantitative and Qualitative Disclosures About Market Risk. For a discussion of primary market risks and risk management policy, see "Management's Discussion and Analysis of Financial Condition and Results of Operations- Market Risk Sensitive Instruments and Positions." PART II. OTHER INFORMATION Item 1. Legal Proceedings. NiSource and its subsidiaries are parties to various pending proceedings, including suits and claims against them for personal injury, death and property damage. Such proceedings and suits, and the amounts involved, are routine litigation and proceedings for the kinds of businesses conducted by NiSource and its subsidiaries, except as described under Note 4 (NESI Energy Marketing Canada Ltd. Litigation) and Note 5 (Environmental Matters) in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Report on Form 10-Q, which Notes are incorporated by reference. No other material legal proceedings against NiSource or its subsidiaries are pending or, to the knowledge of NiSource, contemplated by governmental authorities or other parties. Item 2. Changes in Securities and Use of Proceeds. None Item 3. Defaults Upon Senior Securities. None Item 4. Submission of Matters to a Vote of Security Holders. On April 14, 1999, at the Annual Meeting of Shareholders, shareholders elected Ian M. Rolland, John W. Thompson and Roger A. Young to serve as directors until the 2002 Annual Meeting of Shareholders. Directors whose terms of office continue after the 1999 Annual Meeting of Shareholders are Arthur J. Decio, Gary L. Neale and Robert J. Welsh, whose terms expire at the 2000 Annual Meeting of Shareholders, and Steven C. Beering, James T. Morris, Denis E. Ribordy and Carolyn Y. Woo, whose terms expire at the 2001 Annual Meeting of Shareholders. There were no abstentions or broker non-votes for any of the nominees for directors. The number of votes cast for, or withheld, for each nominee for director was as follows: Votes Votes Received Withheld Ian M. Rolland 105,542,370 1,003,313 John W. Thompson 105,637,428 908,254 Roger A. Young 105,636,513 909,169 Additionally at the Annual Meeting of Shareholders, shareholders approved a proposal to change the company's name from "NIPSCO Industries, Inc. to "NiSource Inc." by a vote of 100,509,285 shares in favor of the proposal and 6,036,388 shares voted against the proposal or withheld. The name change was intended to reflect the company's new direction as a multi-state supplier of energy and water resources and related services. Also at the Annual Meeting of Shareholders, shareholders approved an Amended and Restated 1994 Long-Term Incentive Plan by a vote of 96,025,133 shares in favor of the proposal, with 10,520,549 shares voted against or withheld and an Amended and Restated 1988 Long-Term Incentive Plan by a vote of 96,042,263 shares in favor of the proposal, with 10,503,419 shares voted against the proposal or withheld. Item 5. Other Information. None Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits. Exhibit 23 - Consent of Arthur Andersen LLP Exhibit 27 - Financial Data Schedule Pursuant to Item 601(b)(4)(iii) of Regulation S-K, NiSource hereby agrees to furnish the IURC, upon request, any instrument defining the rights of holders of long-term debt of NiSource not filed as an exhibit herein. No such instrument authorizes long-term debt securities in excess of 10% of the total assets of NiSource and its subsidiaries on a consolidated basis. (b) Reports on Form 8-K. A report on Form 8-K was filed February 8, 1999. All events were reported under Item 5, Other Events. A report on Form 8-K was filed April 14, 1999. All events were reported under Item 5, Other Events. Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NiSource Inc. (Registrant) /s/ STEPHEN P. ADIK -------------------------------------------------- Stephen P. Adik Executive Vice President, Chief Financial Officer, Treasurer and Chief Accounting Officer Date: May 13, 1999 EX-23 2 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-Q, into NiSource Inc.'s (formerly known as NIPSCO Industries, Inc.) previously filed Form S-8 Registration Statement No. 33-30619; Form S-8 Registration Statement No. 33-30621; Forms S-8 Registration Statement No. 333-08263; Form S-8 Registration Statement No. 333-19981; Form S-8 Registration Statement No. 333-19983; Form S-8 Registration Statement No. 333-19985; Form S-3 Registration Statement No. 333-26847; Form S-8 Registration Statement No. 333-59151; Form S-8 Registration Statement No. 333-59153; Form S-3 Registration Statement No. 333-69279; Form S-8 Registration Statement No. 333-72367; Form S-8 Registration Statement No. 333-72401; Form S-3 Registration Statement No. 333-76645 and Form S-3 Registration Statement No. 333-76909. /s/ Arthur Andersen LLP Chicago, Illinois May 13, 1999 EX-27 3
UT This schedule contains summary financial information extracted from the financial statements of Northern Indiana NiSource Inc. for three months ended March 31, 1999, and is qualified in its entirety by reference to such financial statements. 1,000 3-MOS DEC-31-1998 JAN-01-1999 MAR-31-1999 PER-BOOK 4,742,835 306,146 661,920 213,036 302,467 6,226,404 411,362 170,111 790,142 1,371,615 56,435 85,613 484,600 135,773 1,482,800 114,200 39,122 1,828 0 0 2,454,418 6,226,404 891,492 44,922 735,583 735,583 155,909 7,084 162,993 (42,512) 76,559 0 76,559 30,114 0 287,353 0.62 0.62
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