-----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, PRBsU3vO112Qk8924eEIsk3gS+BfcwvCUmeUeL2r5AWXasxrtLCMdBiQtMseLnad t0BnE4aipEv0ePfSqYhn8g== 0000072843-99-000004.txt : 19991115 0000072843-99-000004.hdr.sgml : 19991115 ACCESSION NUMBER: 0000072843-99-000004 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991112 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN INDIANA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000072843 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 350552990 STATE OF INCORPORATION: IN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-04125 FILM NUMBER: 99748605 BUSINESS ADDRESS: STREET 1: 5265 HOHMAN AVE CITY: HAMMOND STATE: IN ZIP: 46320-1775 BUSINESS PHONE: 2198535200 MAIL ADDRESS: STREET 1: 5265 HOHMAN AVENUE CITY: HAMMOND STATE: IN ZIP: 46320-1775 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 September 30, 1999 Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ________________ to ________________ Commission file number 1-4125 NORTHERN INDIANA PUBLIC SERVICE COMPANY (Exact name of registrant as specified in its charter) Indiana 35-0552990 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5265 Hohman Avenue, Hammond, Indiana 46320-1775 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (219) 853-5200 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 October 31, 1999, 73,282,258 common shares were outstanding. NORTHERN INDIANA PUBLIC SERVICE COMPANY PART 1. FINANCIAL INFORMATION Item I. FINANCIAL STATEMENTS REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To The Board of Directors of NORTHERN INDIANA PUBLIC SERVICE COMPANY: We have audited the accompanying consolidated balance sheets of Northern Indiana Public Service Company (an Indiana corporation and a wholly owned subsidiary of NiSource Inc.) and subsidiaries as of September 30, 1999, and December 31, 1998, and the related consolidated statements of income, retained earnings and cash flows for the three, nine and twelve month periods ended September 30, 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 Northern Indiana Public Service Company and subsidiaries as of September 30, 1999, and December 31, 1998, and the results of their operations and their cash flows for the three, nine and twelve month periods ended September 30, 1999 and 1998, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP Chicago, Illinois November 9, 1999
CONSOLIDATED BALANCE SHEETS September 30, December 31, ASSETS 1999 1998 ============ ============ (Dollars in thousands) UTILITY PLANT, AT ORIGINAL COST (INCLUDING CONSTRUCTION WORK IN PROGRESS OF $192,761 AND $149,426 RESPECTIVELY) (NOTE 2): Electric $ 4,217,811 $ 4,154,060 Gas 1,311,413 1,272,483 Common 365,101 364,822 ------------ ------------ 5,894,325 5,791,365 Less - Accumulated depreciation and amortization 2,943,983 2,804,720 ------------ ------------ Total Utility Plant 2,950,342 2,986,645 ------------ ------------ OTHER PROPERTY AND INVESTMENTS 2,636 519 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents 7,813 19,541 Accounts receivable, less reserve of $8,442 and $4,458, respectively (Note 2) 133,032 104,445 Fuel cost adjustment clause (Note 2) 5,715 0 Gas cost adjustment clause (Note 2) 12,666 44,044 Materials and supplies, at average cost 52,219 51,554 Electric production fuel, at average cost 23,091 32,402 Natural gas in storage, at last-in, first-out cost (Note 2) 49,384 50,859 Prepayments and other 25,029 31,056 ------------ ------------ Total Current Assets 308,949 333,901 ------------ ------------ OTHER ASSETS: Regulatory assets (Note 2) 200,958 203,722 Prepayments and other (Note 5) 149,491 127,162 ------------ ------------ Total Other Assets 350,449 330,884 ------------ ------------ $ 3,612,376 $ 3,651,949 ============ ============ The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEETS September 30, December 31, CAPITALIZATION AND LIABILITIES 1999 1998 ============ ============ (Dollars in thousands) CAPITALIZATION: Common stock - without par value - authorized 75,000,000 shares, issued and outstanding 73,282,258 shares (Note 11) $ 859,488 $ 859,488 Additional paid-in capital 12,525 12,524 Retained earnings (see accompanying statement) (Note 10) 146,289 146,138 ------------ ------------ Common shareholder's equity 1,018,302 1,018,150 Cumulative preferred stocks, (excluding amounts due within one year) (Note 7) Series without mandatory redemption provisions (Note 8) 81,114 81,116 Series with mandatory redemption provisions (Note 9) 54,585 56,435 Long-term debt excluding amounts due within one year (Note 13) 922,800 1,077,959 ------------ ------------ Total Capitalization 2,076,801 2,233,660 ------------ ------------ CURRENT LIABILITIES - Current portion of long-term debt (Note 14) 157,000 2,000 Short-term borrowings (Note 15) 89,110 126,100 Accounts payable 143,750 142,414 Dividends declared on common and preferred stocks 59,028 63,101 Customer deposits 22,887 20,178 Taxes accrued 73,368 88,401 Interest accrued 15,023 9,118 Fuel adjustment clause 0 6,279 Accrued employment costs 40,975 44,223 Other accruals 47,823 28,546 ------------ ------------ Total Current Liabilities 648,964 530,360 ------------ ------------ OTHER: Deferred income taxes (Note 4) 600,670 608,935 Deferred investment tax credits, being amortized over life of related property (Note 4) 87,348 92,693 Deferred credits 50,044 48,084 Accrued liability for postretirement benefits (Note 6) 137,051 127,115 Other noncurrent liabilities 11,498 11,102 ------------ ------------ Total Other Liabilities 886,611 887,929 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Notes 3, 16 and 17) $ 3,612,376 $ 3,651,949 ============ ============ The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF INCOME Three Months Nine Months Ended September 30, Ended September 30, ---------------------- ---------------------- 1999 1998 1999 1998 ========== ========== ========== ========== (Dollars in thousands) Operating Revenues: (Notes 2 and 20) Gas $ 84,156 $ 71,773 $ 435,237 $ 389,362 Electric 324,940 311,512 862,203 823,309 ---------- ---------- ---------- ---------- 409,096 383,285 1,297,440 1,212,671 ---------- ---------- ---------- ---------- Cost of Energy: (Note 2) Gas costs 52,761 39,304 250,998 217,678 Fuel for electric generation 72,092 72,246 188,020 193,263 Power purchased 28,181 17,001 71,899 33,048 ---------- ---------- ---------- ---------- 153,034 128,551 510,917 443,989 ---------- ---------- ---------- ---------- Operating Margin 256,062 254,734 786,523 768,682 ---------- ---------- ---------- ---------- Operating Expenses and Taxes (except income): Operation 53,215 64,211 185,955 188,128 Maintenance (Note 2) 14,515 15,180 50,226 50,501 Depreciation and amortization (Note 2) 58,422 57,327 174,620 170,647 Taxes (except income) 17,751 17,901 55,807 54,500 ---------- ---------- ---------- ---------- 143,903 154,619 466,608 463,776 ---------- ---------- ---------- ---------- Operating Income Before Utility Income Taxes 112,159 100,115 319,915 304,906 ---------- ---------- ---------- ---------- Utility Income Taxes (Note 4) 33,029 28,077 94,084 86,428 ---------- ---------- ---------- ---------- Operating Income 79,130 72,038 225,831 218,478 ---------- ---------- ---------- ---------- Other Income (Deductions) (Note 2) 1,681 (1,061) 1,726 (2,937) ---------- ---------- ---------- ---------- Interest: Interest on long-term debt 16,951 17,403 50,544 52,714 Other interest 708 1,302 1,642 2,879 Amortization of premium, reacquisition premium, discount and expense on debt, net 1,037 1,043 3,108 3,143 ---------- ---------- ---------- ---------- 18,696 19,748 55,294 58,736 ---------- ---------- ---------- ---------- Net Income 62,115 51,229 172,263 156,805 Dividend requirements on preferred shares 2,021 2,072 6,112 6,265 ---------- ---------- ---------- ---------- Balance available for common shares $ 60,094 $ 49,157 $ 166,151 $ 150,540 ========== ========== ========== ========== Dividends declared $ 58,000 $ 55,000 $ 166,000 $ 150,000 ========== ========== ========== ========== Twelve Months Ended September 30, ---------------------- 1999 1998 ========== ========== (Dollars in thousands) Operating Revenues: (Notes 2, 3 and 20) Gas $ 618,360 $ 628,940 Electric 1,115,012 1,071,293 ---------- ---------- 1,733,372 1,700,233 ---------- ---------- Cost of Energy: (Note 2) Gas costs 354,353 367,794 Fuel for electric generation 245,406 253,786 Power purchased 80,841 37,701 ---------- ---------- 680,600 659,281 ---------- ---------- Operating Margin 1,052,772 1,040,952 ---------- ---------- Operating Expenses and Taxes (except income): Operation 243,747 248,379 Maintenance (Note 2) 65,027 68,715 Depreciation and amortization (Note 2) 232,520 225,622 Taxes (except income) 73,534 72,223 ---------- ---------- 614,828 614,939 ---------- ---------- Operating Income Before Utility Income Taxes 437,944 426,013 ---------- ---------- Utility Income Taxes (Note 4) 128,442 122,339 ---------- ---------- Operating Income 309,502 303,674 ---------- ---------- Other Income (Deductions) (Note 2) 1,074 (4,110) ---------- ---------- Interest: Interest on long-term debt 67,502 70,741 Other interest 3,287 4,262 Amortization of premium, reacquisition premium, discount and expense on debt, net 4,149 4,195 ---------- ---------- 74,938 79,198 ---------- ---------- Net Income 235,638 220,366 Dividend requirements on preferred shares 8,182 8,386 ---------- ---------- Balance available for common shares $ 227,456 $ 211,980 ========== ========== Dividends declared $ 228,000 $ 205,000 ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Three Months Nine Months Twelve Months Ended September 30, Ended September 30, Ended September 30, ------------------- ------------------- ------------------- 1999 1998 1999 1998 1999 1998 ========= ========= ========= ========= ========= ========= (Dollars in thousands) BALANCE AT BEGINNING OF PERIOD $ 144,195 $ 152,676 $ 146,138 $ 146,293 $ 146,833 $ 139,853 ADD: Net income 62,115 51,229 172,263 156,805 235,638 220,366 --------- --------- --------- --------- --------- --------- 206,310 203,905 318,401 303,098 382,471 360,219 --------- --------- --------- --------- --------- --------- LESS: Dividends Cumulative Preferred stocks - 4-1/4% series 223 222 667 667 889 889 4-1/2% series 90 90 270 270 360 360 4.22% series 113 113 337 337 448 448 4.88% series 122 122 366 366 488 488 7.44% series 77 77 233 233 312 312 7.50% series 65 65 196 196 261 261 8.85% series 111 138 351 433 489 599 7-3/4% series 70 82 210 243 286 330 8.35% series 96 109 321 359 434 484 6.50% series 699 699 2,096 2,096 2,795 2,795 Adjustable Rate, Series A 355 355 1,065 1,065 1,420 1,420 Common shares 58,000 55,000 166,000 150,000 228,000 205,000 --------- --------- --------- --------- --------- --------- 60,021 57,072 172,112 156,265 236,182 213,386 --------- --------- --------- --------- --------- --------- BALANCE AT END OF PERIOD $ 146,289 $ 146,833 $ 146,289 $ 146,833 $ 146,289 $ 146,833 ========= ========= ========= ========= ========= ========= The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS Three Months Ended September 30, ------------------------ 1999 1998 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 62,115 $ 51,229 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 58,422 57,327 Deferred federal and state income taxes, net 3,287 (6,557) Deferred investment tax credits, net (1,782) (1,783) Other, net (12,555) 475 Change in certain assets and liabilities - Accounts receivable, net 1,260 18,675 Electric production fuel 3,871 (1,041) Materials and supplies (625) 1,608 Natural gas in storage (23,825) (25,725) Accounts payable 16,678 3,667 Taxes accrued (16,977) 10,801 Fuel adjustment clause (8,452) 2,428 Gas cost adjustment clause (19,731) (5,021) Accrued employment costs 3,585 4,178 Other accruals 14,548 (264) Other, net 4,645 (729) ---------- ---------- Net cash provided by operating activities 84,464 109,268 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (46,447) (43,453) Other, net (3,881) 973 ---------- ---------- Net cash used in investing activities (50,328) (42,480) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Net change in short-term debt 20,910 (18,900) Retirement of long-term debt (500) (500) Retirement of preferred shares (601) (600) Cash dividends paid on common shares (53,000) (49,000) Cash dividends paid on preferred shares (2,023) (2,087) Other, net 114 112 ---------- ---------- Net cash provided by (used in) financing activities (35,100) (70,975) ---------- ---------- NET DECREASE IN CASH AND CASH EQUIVALENTS (964) (4,187) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 8,777 14,831 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 7,813 $ 10,644 ========== ========== Nine Months Ended September 30, ------------------------ 1999 1998 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 172,263 $ 156,805 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 174,620 170,647 Deferred federal and state operating income taxes, net (31,170) (46,530) Deferred investment tax credits, net (5,345) (5,347) Other, net (11,605) 1,425 Change in certain assets and liabilities - Accounts receivable, net (15,557) 38,659 Electric production fuel 9,311 1,297 Materials and supplies (665) 2,728 Natural gas in storage 1,475 (9,427) Accounts payable 8,323 (20,231) Taxes accrued (988) 37,360 Fuel adjustment clause (11,994) 5,732 Gas cost adjustment clause 31,378 56,508 Accrued employment costs (3,248) (11,434) Other accruals 19,277 (9,575) Other, net 9,708 (993) ---------- ---------- Net cash provided by operating activities 345,783 367,624 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (133,156) (131,178) Other, net (9,203) (16,679) ---------- ---------- Net cash used in investing activities (142,359) (147,857) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Net change in short-term debt (36,990) (25,600) Retirement of long-term debt (500) (35,500) Retirement of preferred shares (1,852) (1,856) Cash dividends paid on common shares (170,000) (150,000) Cash dividends paid on preferred shares (6,151) (6,317) Other, net 341 350 ---------- ---------- Net cash used in financing activities (215,152) (218,923) ---------- ---------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (11,728) 844 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 19,541 9,800 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 7,813 $ 10,644 ========== ========== Twelve Months Ended September 30, ------------------------ 1999 1998 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 235,638 $ 220,366 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 232,520 225,622 Deferred federal and state operating income taxes, net (17,214) (24,800) Deferred investment tax credits, net (7,158) (7,172) Other, net (11,130) 1,900 Change in certain assets and liabilities - Accounts receivable, net (58,410) (22,076) Electric production fuel (5,551) (392) Materials and supplies (1,281) 4,884 Natural gas in storage 5,923 2,584 Accounts payable 44,800 (4,927) Taxes accrued (14,229) 31,895 Fuel adjustment clause (8,768) 6,859 Gas cost adjustment clause 17,346 27,007 Accrued employment costs 1,314 (2,068) Other accruals 23,347 (8,429) Other, net (679) (29,088) ---------- ---------- Net cash provided by operating activities 436,468 422,165 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (188,600) (164,193) Other, net 4,781 (19,936) ---------- ---------- Net cash used in investing activities (183,819) (184,129) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Issuance of long-term debt 500 0 Net change in short-term debt (4,290) 2,275 Retirement of long-term debt (16,509) (36,500) Retirement of preferred shares (2,409) (2,411) Cash dividends paid on common shares (225,000) (194,775) Cash dividends paid on preferred shares (8,226) (8,444) Other, net 454 470 ---------- ---------- Net cash used in financing activities (255,480) (239,385) ---------- ---------- NET DECREASE IN CASH AND CASH EQUIVALENTS (2,831) (1,349) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,644 11,993 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 7,813 $ 10,644 ========== ========== 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.(NiSource), formerly NIPSCO Industries, Inc., was incorporated in Indiana on September 22, 1987 and became the parent of Northern Indiana Public Service Company (Northern Indiana) on March 3, 1988. NIPSCO Industries, Inc. changed it name to NiSource Inc. on April 14, 1999 to reflect its new direction as a multi-state supplier of energy and water resources and related services. Northern Indiana is a public utility operating company supplying electricity and gas to the public in the northern third of Indiana. Northern Indiana is subject to regulation with respect to rates, accounting and certain other matters which are governed by the Indiana Utility Regulatory Commission (IURC) and the Federal Energy Regulatory Commission (FERC), collectively called the "Commissions." (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: BASIS OF PRESENTATION. The Consolidated Financial Statements include the accounts of Northern Indiana and subsidiaries, after the elimination of all significant intercompany items. Certain reclassifications were made to conform the prior years' financial statements to the current presentation. USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. OPERATING REVENUES. Revenues are recorded based on estimated service rendered, but are billed to customers monthly on a cycle basis. DEPRECIATION AND MAINTENANCE. Northern Indiana provides depreciation on a straight-line method over the remaining service lives of the electric, gas and common properties. The approximated weighted average remaining lives for major components of electric and gas plant are as follows: Electric: -------- Electric generation plant 24 years Transmission plant 26 years Distribution plant 25 years Other electric plant 24 years Gas: ---- Gas storage plant 18 years Transmission plant 34 years Distribution plant 27 years Other gas plant 24 years The depreciation provision for electric utility plant, as a percentage of the original cost, was 3.7% for the three-month, nine-month and twelve-month periods ended September 30, 1999 and was 3.8% for three-month, 3.7% for the nine-month and 3.6% for the twelve-month periods ended September 30, 1998. The depreciation provision for gas utility plant, as a percentage of the original cost, was 5.4% for the three-month and the nine-month periods and 5.5% for the twelve-month periods ended September 30, 1999 and 5.4% for the three-month, nine-month and twelve-month periods ended September 30, 1998. Northern Indiana follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a 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. 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 September 30, 1999, $100 million of accounts receivable had been sold under a sales agreement, which expires on May 31, 2002. The September 30, 1999 and December 31, 1998 accounts receivable balances include approximately $8.8 million and $11.6 million, respectively, due from associated companies. COMPREHENSIVE INCOME. Northern Indiana adopted Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income" effective January 1, 1998. This statement established standards for reporting and display of comprehensive income and its components in a financial statement that is displayed with the same prominence as other financial statements. The adoption of this statement did not impact Northern Indiana's consolidated financial statements for the periods presented. 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 Nine Months Twelve Months Ended September 30, Ended September 30, Ended September 30, ------------------ ------------------ ------------------ 1999 1998 1999 1998 1999 1998 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Income taxes $ 39,250 $ 17,500 $125,336 $ 90,840 $169,641 $124,949 Interest, net of amounts capitalized $ 9,509 $ 10,524 $ 43,492 $ 44,794 $ 70,343 $ 75,133
FUEL ADJUSTMENT CLAUSE. All metered electric rates contain a provision for adjustment in charges for electric energy to reflect increases and decreases in the cost of fuel and the cost of purchased power through operation of a fuel adjustment clause. As prescribed by order of the IURC applicable to metered retail rates, the adjustment factor has been calculated based on the estimated cost of fuel and the fuel cost of purchased power in a future three-month period. If two statutory requirements relating to expense and return levels are satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given three-month period will be included in a future filing. 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. On August 18, 1999, the IURC issued a generic order which established new guidelines for the recovery of purchased power costs through fuel adjustment clauses. The IURC ruled that each utility had to establish a "benchmark" which is the utility's highest on-system fuel cost per kilowatt- hour (kwh) during the most recent annual period. The IURC stated that if the weekly average of a utility's purchased power costs were less than the "benchmark," these costs per kwh should be considered net energy costs which are presumed "fuel costs included in purchased power." If the weekly average of a utility's purchased power costs exceeded the "benchmark," the utility would need to submit additional evidence demonstrating the reasonableness of these costs. The Office of Utility Consumer Counselor has appealed the August 18 order to the Indiana Court of Appeals. GAS COST ADJUSTMENT CLAUSE. All metered gas sales rates contain an adjustment factor, which reflects the increases and decreases in the cost of purchased gas, contracted gas storage and storage transportation charges. The gas cost adjustment factor is subject to a quarterly hearing by the IURC and remains in effect for a three-month period. On August 11, 1999, the IURC approved a flexible gas cost adjustment mechanism for Northern Indiana. Under the new procedure, the demand component of the adjustment factor will be determined, after hearing and IURC approval, and made effective on November 1 of each year. The demand component will remain in effect for one year until a new demand component is approved by the IURC. The commodity component of the adjustment factor will be determined by monthly filings, which will become effective on the first day of each calendar month, subject to refund. The monthly filings do not require IURC approval but will be reviewed by the IURC during the annual hearing that will take place regarding the demand component filing. If the statutory requirement relating to the level of return is satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given monthly period will be allocated over a twelve-month period beginning with the next monthly filing. Any under-recovery or over-recovery is recorded as a current asset or current liability until such time it is billed or refunded to its customers. Northern Indiana's gas cost adjustment factor includes a gas cost incentive mechanism (GCIM) which allows or the sharing of any cost savings or cost increases with customers based upon a comparison of actual gas supply portfolio cost to a market-based benchmark price. NATURAL GAS IN STORAGE. Natural gas in storage is valued using the last-in, first-out (LIFO) inventory methodology. Based on the average cost of gas purchased in September 1999 and December 1998, the estimated replacement cost of gas in storage (current and non-current) at September 30, 1999 and December 31, 1998 exceeded the stated LIFO cost by $67.6 million and $33.7 million, respectively. AFFILIATED COMPANY TRANSACTIONS. Northern Indiana receives executive, financial, gas supply, sales and marketing, and administrative and general services from an affiliate, NiSource Management Services Company (NMSC), a wholly-owned subsidiary of NiSource. The costs of these services are charged to Northern Indiana based on payroll costs and expenses incurred by NMSC employees for the benefit of Northern Indiana. These costs, which totaled $4.7 million, $14.2 million and $19.1 million for the three-month, nine-month and twelve-month periods ended September 30, 1999, respectively, and totaled $4.3 million, $15.9 million and $20.5 million for the three-month, nine-month and twelve-month periods ended September 30, 1998, respectively, consist primarily of employee compensation and benefits. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $6.4 million, $12.3 million and $14.7 million representing 15.1%, 5.6% and 4.7% of Northern Indiana's total gas costs for the three-month, nine-month and twelve-month periods ended September 30, 1999, respectively. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $9.8 million, $18.4 million and $21.4 million representing 18.2%, 8.7% and 5.9% of Northern Indiana's total gas costs for the three-month, nine-month and twelve-month periods ended September 30, 1998, respectively. Northern Indiana subleases a portion of its office facilities to affiliated companies for a monthly fee, which includes operating expenses, based on space utilization. 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 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." This change in accounting effective January 1, 1999 was insignificant. Such contracts are recorded at their fair value with changes in their value included in earnings (other income and deductions). IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards Board (FASB) has issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," and SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133." Statement No. 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, by requiring that a company recognize those items as assets or liabilities in the balance sheet and measure them at fair value. 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. Statement No. 137, which was issued June 1999, deferred implementation of Statement No. 133 until January 1, 2001. The impact of adopting the accounting prescribed in Statement No. 133 is currently being assessed. REGULATORY ASSETS. Northern Indiana's operations are subject to the regulation of the Commissions. Accordingly, Northern Indiana's accounting policies are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Northern Indiana monitors changes in market and regulatory conditions and the resulting impact of such changes in order to continue to apply the provisions of SFAS No. 71 to some or all of its operations. As of September 30, 1999, and December 31, 1998, the regulatory assets identified below represent probable future revenues to Northern Indiana as these costs are recovered through the rate-making process. If a portion of Northern Indiana's operations becomes no longer subject to the provisions of SFAS No. 71, a write-off of certain regulatory assets might be required, unless some form of transition cost recovery is established by the appropriate regulatory body which would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets during such recovery period. Regulatory assets were comprised of the following items:
September 30, December 31, 1999 1998 ============= ============= (Dollars in thousands) Unamortized reacquisition premium on debt (Note 13) $ 40,365 $ 42,962 Unamortized R. M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation (See below) 59,166 62,329 Bailly scrubber carrying charges and deferred depreciation (See below) 8,243 8,945 Deferral of SFAS No. 106 expense not recovered (Note 6) 74,169 78,367 FERC Order No. 636 transition costs 15,504 22,093 Regulatory income tax asset, net (Note 4) 29,532 21,635 ------------- ------------- 226,979 236,331 Less: Current portion of regulatory assets 26,021 32,609 ------------- ------------- $ 200,958 $ 203,722 ============= =============
CARRYING CHARGES AND DEFERRED DEPRECIATION. Upon completion of R. M. Schahfer Units 17 and 18, Northern Indiana 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. Northern Indiana has capitalized carrying charges and deferred depreciation and certain operating expenses relating to its scrubber service agreement for its Bailly Generating Station in accordance with an order of the IURC. The accumulated balance of the deferred costs and related carrying charges is being amortized over the remaining life of the scrubber service agreement. 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, Northern Indiana is 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 pre-tax rate of 6.0% in 1999, 5.75% in 1998 and 5.5% in 1997. INCOME TAXES. The liability method of accounting is used for income taxes under which deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between book and tax bases of assets and liabilities. Deferred investment tax credits are being amortized over the life of the related property. (3) ENVIRONMENTAL MATTERS: GENERAL. The operations of Northern Indiana are subject to extensive and evolving federal, state and local environmental laws and regulations intended to protect public health and the environment. Such environmental laws and regulations affect Northern Indiana's operations as they relate to impacts on air, water and land. SUPERFUND. Because Northern Indiana is a "potentially responsible party" (PRP), under Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), at several waste disposal sites, as well as at former manufactured-gas plant sites which it, or its corporate predecessors, own or owned or operated, it may be required to share in the costs of clean up of such sites. A program was instituted to investigate former manufactured-gas plant sites where it is the current or former owner, which investigation has identified wenty-four of such sites. Initial sampling has been conducted at seventeen sites. Investigation activities have been completed at twelve sites and remedial measures have been selected or implemented at seven sites. Northern Indiana intends to continue to evaluate its facilities and properties with respect to environmental laws and regulations and take any required corrective action. In an effort to recover a portion of the costs related to the former manufactured gas plants, various companies that provided insurance coverage which Northern Indiana believed covered costs related to former manufactured-gas plant sites were approached. Northern Indiana filed claims in Indiana state court against various insurance companies, seeking coverage for costs associated with several manufactured-gas plant sites and damages for alleged misconduct by some of the insurance companies. Settlements have been reached with several insurance companies including $13.0 million in the third quarter 1999. Additionally, agreements have been reached with other Indiana utilities relating to cost sharing and management of the investigation and remediation of several former manufactured-gas plant sites at which Northern Indiana and such utilities or their predecessors were operators or owners. As of September 30, 1999, a reserve of approximately $18 million has been recorded to cover probable corrective actions. The ultimate liability in connection with these sites will depend upon many factors, including the volume of material contributed to the site, the number of other PRP's and their financial viability, the extent of corrective actions required and rate recovery. Based upon investigations and management's understanding of current environmental laws and regulations, Northern Indiana believes that any corrective actions required, after consideration of insurance coverages and contributions from other PRP's and rate recovery will not have a material effect on its financial position or results of operations. CLEAN AIR ACT. The Clean Air Act Amendments of 1990 (CAAA) impose limits to control acid rain on the emission of sulfur dioxide and nitrogen oxides (NOx) which become fully effective in 2000. All of Northern Indiana's facilities are already in compliance with sulfur dioxide limits. Northern Indiana has already taken most of the steps necessary to meet the NOx limits. The CAAA also contain other provisions that could lead to limitations on emissions of hazardous air pollutants and other air pollutants (including NOx as discussed below), which may require significant capital expenditures for control of these emissions. Until specific rules have been issued that affect Northern Indiana's facilities, what these requirements will be or the costs of complying with these potential requirements cannot be predicted. NITROGEN OXIDES. During 1998, the Environmental Protection Agency (EPA) issued a final rule, the NOx State Implementation Plan (SIP) call, requiring certain states, including Indiana, to reduce NOx levels from several sources, including industrial and utility boilers. The EPA stated that the intent of the rule is to lower regional transport of ozone impacting other states' ability to attain the federal ozone standard. According to the rule, the State of Indiana must issue regulations implementing the control program. The State of Indiana, as well as some other states, filed a legal challenge in December 1998 to the EPA NOx SIP call rule. Lawsuits have also been filed against the rule by various groups. On May 25, 1999, the D.C. Circuit Court of Appeals issued an order staying the NOx SIP call rule's September 30, 1999 deadline for the state submittals until further order of the court. Any resulting NOx emissions limitations could be more restrictive than those imposed on electric utilities under the CAAA's acid rain NOx reduction program described above. Northern Indiana is evaluating the EPA's final rule and any potential requirements that could result from the final rule as implemented by the State of Indiana. Northern Indiana believes that the costs relating to compliance with the new standards may be substantial, but such costs depend upon the outcome of the current litigation and the ultimate control program agreed to by the targeted states and the EPA. Northern Indiana is continuing its programs to reduce NOx emissions and will continue to closely monitor developments in this area. The EPA issued final rules revising the National Ambient Air Quality Standards for ozone and particulate matter in July 1997. On May 14, 1999, the United States Court of Appeals for the D.C. Circuit remanded the new rules for both ozone and particulate matter standards to the EPA. Once rectified, the revised standards could require additional reductions in sulfur dioxide, particulate matter and NOx emissions from coal-fired boilers (including Northern Indiana's generating stations) beyond measures discussed above. Final implementation methods will be set by the EPA as well as state regulatory authorities. Northern Indiana believes that the costs relating to compliance with any new limits may be substantial but are dependent upon the ultimate control program agreed to by the targeted states and the EPA. Northern Indiana will continue to closely monitor developments in this area and anticipates the exact nature of the impact of the new limits on its operations will not be known for some time. In a letter dated September 15, 1999, the Attorney General of the State of New York alleged that Northern Indiana violated the Clean Air Act by constructing a major modification of one of its electric generating stations without obtaining pre-construction permits required by the Prevention of Significant Deterioration (PSD) program. The major modification allegedly took place at the R. M. Schahfer Station when, "in approximately 1995-1997, Northern Indiana upgraded the coal handling system at Unit 14 at the plant." While Northern Indiana is investigating these allegation, Northern Indiana does not believe that the modifications required pre-construction review under the PSD program and believes that all appropriate permits were acquired. CARBON DIOXIDE. Initiatives are being discussed both in the United States and worldwide to reduce so-called "greenhouse gases" such as carbon dioxide, and other by-products of burning fossil fuels. Reduction of such emissions could result in significant capital outlays or operating expenses to Northern Indiana. CLEAN WATER ACT AND RELATED MATTERS. Northern Indiana's wastewater and water operations are subject to pollution control and water quality control regulations, including those issued by the EPA and the State of Indiana. Under the Federal Clean Water Act and Indiana's regulations, Northern Indiana must obtain National Pollutant Discharge Elimination System (NPDES) permits for water discharges from various water discharges from various facilities, including electric generating and water treatment stations. These facilities either have permits for their water discharge or they have applied for a permit renewal of any expiring permits. These permits continue in effect pending review of the current applications. (4) INCOME TAXES: Deferred income taxes are recognized as costs in the rate-making process by the Commissions having jurisdiction over rates charged by Northern Indiana. Deferred income taxes are provided as a result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the consolidated financial statements. These taxes are reversed by a debit or credit to deferred income tax expense as the temporary differences reverse. Investment tax credits have been deferred and are being amortized to income over the life of the related property. To the extent certain deferred income taxes are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets are primarily attributable to undepreciated 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 Northern Indiana's obligation to credit to ratepayers deferred income taxes provided at rates higher than the current federal tax rate currently being credited to ratepayers using the average rate assumption method and unamortized deferred investment tax credits. Northern Indiana joins in the filing of consolidated tax returns with NiSource and currently pays to NiSource its separate return tax liability as defined in the Tax Sharing Agreement between NiSource and its subsidiaries. The components of the net deferred income tax liability at September 30, 1999 and December 31, 1998 were as follows:
September 30, December 31, 1999 1998 ============= ============= (Dollars in thousands) Deferred tax liabilities - Accelerated depreciation and other property differences $ 731,657 $ 735,589 AFUDC-equity 31,367 33,029 Adjustment clauses 6,971 14,322 Other regulatory assets 28,129 29,721 Prepaid pension and other benefits 33,179 34,170 Reacquisition premium on debt 15,308 16,293 Deferred tax assets - Deferred investment tax credits (33,127) (35,154) Removal costs (168,745) (157,728) Other postretirement/postemployment benefits (51,977) (48,208) Other, net (16,720) (23,682) ------------- ------------- 576,042 598,352 Less: Deferred income taxes related to current assets and liabilities (24,628) (10,583) ------------- ------------- Deferred income taxes - noncurrent $ 600,670 $ 608,935 ============= =============
Federal and state income taxes as set forth in the Consolidated Statements of Income were comprised of the following:
Three Months Nine Months Ended September 30, Ended September 30, -------------------- -------------------- 1999 1998 1999 1998 ========= ========= ========= ========= (Dollars in thousands) Current income taxes - Federal $ 27,636 $ 31,551 $ 114,289 $ 120,298 State 3,888 4,866 16,310 18,007 --------- --------- --------- --------- 31,524 36,417 130,599 138,305 --------- --------- --------- --------- Deferred income taxes, net - Federal 3,006 (6,090) (28,849) (43,057) State 281 (467) (2,321) (3,473) --------- --------- --------- --------- 3,287 (6,557) (31,170) (46,530) --------- --------- --------- --------- Deferred investment tax credits, net (1,782) (1,783) (5,345) (5,347) --------- --------- --------- --------- Total utility operating income taxes 33,029 28,077 94,084 86,428 Income tax applicable to non- operating activities and income of subsidiaries 1,049 (620) 1,043 (1,852) --------- --------- --------- --------- Total income taxes $ 34,078 $ 27,457 $ 95,127 $ 84,576 ========= ========= ========= ========= Twelve Months Ended September 30, -------------------- 1999 1998 ========= ========= (Dollars in thousands) Current income taxes - Federal $ 134,355 $ 133,777 State 18,459 20,534 --------- --------- 152,814 154,311 --------- --------- Deferred income taxes, net - Federal (16,082) (23,071) State (1,132) (1,729) --------- --------- (17,214) (24,800) --------- --------- Deferred investment tax credits, net (7,158) (7,172) --------- --------- Total utility operating income taxes 128,442 122,339 Income tax applicable to non- operating activities and income of subsidiaries 958 (3,646) --------- --------- Total income taxes $ 129,400 $ 118,693 ========= =========
A reconciliation of total income tax expense to an amount computed by applying the statutory federal income tax rate to pre-tax income is as follows:
Three Months Nine Months Ended September 30, Ended September 30, -------------------- -------------------- 1999 1998 1999 1998 ========= ========= ========= ========= (Dollars in thousands) Net income $ 62,115 $ 51,229 $ 172,263 $ 156,805 Add-Income taxes 34,078 27,457 95,127 84,576 --------- --------- --------- --------- Net income before income taxes $ 96,193 $ 78,686 $ 267,390 $ 241,381 ========= ========= ========= ========= Amount derived by multiplying pre-tax income by the statutory rate $ 33,668 $ 27,540 $ 93,587 $ 84,483 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 969 998 2,906 2,994 Amortization of deferred investment tax credits (1,782) (1,783) (5,345) (5,347) State income taxes, net of federal income tax benefit 2,809 2,696 8,281 8,232 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (721) (1,271) (2,163) (3,813) Other, net (865) (723) (2,139) (1,973) --------- --------- --------- --------- Total income taxes $ 34,078 $ 27,457 $ 95,127 $ 84,576 ========= ========= ========= ========= Twelve Months, Ended September 30, -------------------- 1999 1998 ========= ========= (Dollars in thousands) Net income $ 235,638 $ 220,366 Add-Income taxes 129,400 118,693 --------- --------- Net income before income taxes $ 365,038 $ 339,059 ========= ========= Amount derived by multiplying pre-tax income by the statutory rate $ 127,763 $ 118,671 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 3,904 3,957 Amortization of deferred investment tax credits (7,158) (7,172) State income taxes, net of federal income tax benefit 10,866 11,618 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (2,734) (3,807) Other, net (3,241) (4,574) --------- --------- Total income taxes $ 129,400 $ 118,693 ========= =========
(5) PENSION PLANS: NiSource has a noncontributory, defined benefit retirement plan covering substantially all employees of Northern Indiana. Benefits under the plan reflect the employees' compensation, years of service and age at retirement. The change in the benefit obligation for 1998 and 1997 was as follows:
1998 1997 ========= ========= (Dollars in thousands) Benefit obligation at beginning $ 843,049 $ 732,870 of year (January 1,) Service cost 15,347 13,325 Interest cost 58,336 55,920 Plan amendments 14,655 25,096 Actuarial loss 37,248 67,975 Benefits paid (54,362) (52,137) --------- --------- Benefit obligation at end of the year (December 31,) $ 914,273 $ 843,049 ========= =========
The change in the fair value of the plan's assets for years 1998 and 1997 was as follows:
1998 1997 ========= ========= (Dollars in thousands) Fair value of plan assets at $ 896,950 $ 782,162 beginning of year January 1,) Actual return on plan's assets 82,547 122,537 Employer contributions 33,300 44,388 Benefits paid (54,362) (52,137) --------- --------- Plan assets at fair value at end of the year (December 31,) $ 958,435 $ 896,950 ========= =========
Plan assets are invested primarily in common stocks, bonds and notes. The plan's funded status as of 1998 and 1997 is as follows:
1998 1997 ========= ========= (Dollars in thousands) Plan assets in excess of $ 44,162 $ 53,901 benefit obligation Unrecognized net actuarial loss (16,162) (51,191) Unrecognized prior service cost 55,761 45,502 Unrecognized transition amount being recognized over seventeen years 27,442 32,930 --------- --------- Prepaid pension costs $ 111,203 $ 81,142 ========= =========
The benefit obligation is the present value of future pension benefit payments and is 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 obligation at December 31, 1998 and December 31, 1997. Northern Indiana's prepaid pension costs were $132.6 million at September 30, 1999 and are reported under the caption "Prepayments and Other" in the Consolidated Balance Sheets. The following items are the components of provisions for pensions for the three-month, nine-month and twelve-month periods ended September 30, 1999 and September 30, 1998:
Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, ------------------ ------------------ ------------------ 1999 1998 1999 1998 1999 1998 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Service costs $ 4,123 $ 4,234 $ 12,371 $ 16,227 $ 15,725 $ 14,349 Interest costs 15,403 14,883 46,209 57,029 62,400 49,143 Expected return on plan assets (21,121) (19,754) (63,365) (75,695) (87,753) (65,755) Amortization of transition obligation 1,373 1,344 4,117 5,148 5,801 4,373 Amortization of prior service cost 1,398 1,077 4,196 4,127 5,543 3,657 -------- -------- -------- -------- -------- -------- $ 1,176 $ 1,784 $ 3,528 $ 6,836 $ 1,716 $ 5,767 ======== ======== ======== ======== ======== ========
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%
(6) POSTRETIREMENT BENEFITS: Certain health care and life insurance benefits for retired employees are provided. Substantially all Northern Indiana employees may become eligible for those benefits if they reach retirement age while working for Northern Indiana. The expected cost of such benefits is accrued during the employees' 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. The following table sets forth the change in the plan's accumulated postretirement benefit obligation (APBO) as of December 31, 1998 and 1997:
1998 1997 ========= ========= (Dollars in thousands) Accumulated postretirement $ 195,003 $ 194,937 benefit obligation at beginning of year (January 1,) Service cost 3,314 3,068 Interest cost 13,685 14,523 Plan amendments 0 4,015 Actuarial (gain) loss 6,260 (12,534) Benefits paid (11,183) (9,006) --------- --------- Accumulated postretirement benefit obligation at end of the year (December 31,) $ 207,079 $ 195,003 ========= =========
The change in the fair value of the plan's assets for the years 1998 and 1997 was as follows:
1998 1997 ========= ========= (Dollars in thousands) Fair value of plan assets at $ 2,400 $ 0 beginning of year (January 1,) Actual return on plan assets 1,103 0 Employer contributions 9,301 11,406 Participant contributions 1,282 0 Benefits paid (11,183) (9,006) --------- --------- 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 December 31, 1997:
1998 1997 ========= ========= (Dollars in thousands) Funded status $(204,176) $(192,603) Unrecognized actuarial gain (90,700) (99,262) Unrecognized prior service cost 3,458 3,737 Unrecognized transition amount being recognized over twenty years 150,466 161,214 --------- --------- Accrued liability for postretirement benefits $(140,952) $(126,914) ========= =========
In order to determine the APBO at December 31, 1998, a discount rate of 7% and a pre-Medicare medical trend rate of 7% declining to a long-term rate of 5% was used, and at December 31, 1997, a discount rate of 7% and a pre-Medicare medical trend rate of 8% declining to a long-term rate of 5% was used. The accrued liability for postretirement benefits was $146.1 million at September 30, 1999. Net periodic postretirement benefits costs, before consideration of the rate-making discussed previously, for the three-month, nine-month and twelve-month periods ended September 30, 1999 and September 30, 1998 include the following components:
Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, ---------------- ---------------- ---------------- 1999 1998 1999 1998 1999 1998 ======= ======= ======= ======= ======= ======= (Dollars in thousands) Service costs $ 781 $ 1,084 $ 2,608 $ 2,890 $ 3,032 $ 3,169 Interest costs 3,850 3,650 11,550 10,950 14,285 12,345 Expected return on plan assets (50) (50) (150) (150) (216) (150) Amortization of transition obligation over twenty years 2,675 2,675 8,025 8,025 10,748 10,666 Amortization of prior service cost 75 75 225 225 279 504 Amortization of actuarial (gain) (1,150) (1,375) (3,450) (4,125) (5,111) (6,924) ------- ------- ------- ------- ------- ------- $ 6,181 $ 6,059 $18,808 $17,815 $23,017 $19,610 ======= ======= ======= ======= ======= =======
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 $25.8 million, and increase the aggregate of the service and interest cost components of plan costs by approximately $0.6 million and $1.8 million for the three-month and nine-month periods ended September 30, 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 $20.0 million, and decrease the aggregate of the service and interest cost components of plan costs by approximately $0.5 million and $1.4 million for the three-month and nine-month periods ended September 30, 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. (7) AUTHORIZED CLASSES OF CUMULATIVE PREFERRED AND PREFERENCE STOCKS OF 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) Note 8 sets forth the preferred stocks which are redeemable solely at the option of Northern Indiana and Note 9 sets forth the preferred stocks which are subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana. The preferred shareholders of Northern Indiana have no voting rights, except in the event of a 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. (8) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF NORTHERN INDIANA, OUTSTANDING AT SEPTEMBER 30, 1999 AND DECEMBER 31, 1998 (SEE NOTE 7):
Redemption Price at September 30, December 31, September 30, 1999 1998 1999 ============ ============ ============ (Dollars in thousands) Cumulative preferred stock - $100 par value - 4-1/4% series - 209,035 and 209,051 shares outstanding, respectively $ 20,903 $ 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 Cumulative preferred stock - no par value - Adjustable rate (6.00% at September 30, 1999), Series A (stated value $50 per share) 473,285 shares outstanding 23,664 23,664 $50.00 ------------ ------------ $ 81,114 $ 81,116 ============ ============
During the period October 1, 1997 to September 30, 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 Northern Indiana at the redemption prices shown. (9) REDEEMABLE PREFERRED STOCKS OUTSTANDING AT SEPTEMBER 30, 1999 AND DECEMBER 31, 1998 (SEE NOTE 7): Preferred stocks subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana, excluding sinking fund payments due within one year were as follows:
September 30, December 31, 1999 1998 ============ ============ (Dollars in thousands) Preferred stocks subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana: Cumulative preferred stock - $100 par value - 8.85% series - 37,500 and 50,000 shares outstanding, respectively, excluding sinking fund payments due within one year $ 3,750 $ 5,000 7-3/4% series - 33,352 shares outstanding, excluding sinking fund payments due within one year 3,335 3,335 8.35% series - 45,000 and 51,000 shares outstanding, respectively, excluding sinking fund payments due within one year 4,500 5,100 Cumulative preferred stock - no par value - 6.50% series - 430,000 shares outstanding 43,000 43,000 ------------ ------------ $ 54,585 $ 56,435 ============ ============
The redemption prices at September 30, 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 Northern Indiana, were as follows:
Sinking Fund Or Mandatory Redemption Series Redemption Price Per Share Provisions ====== ========================== ============================= Cumulative preferred stock - $100 par value - 8.85% $100.74, reduced periodically 12,500 shares on or before April 1. 7-3/4% $104.06, reduced periodically 2,777 shares on or before December 1; noncumulative option to double amount each year. 8.35% $103.20, 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. 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, not reflecting redemptions made after September 30, 1999, were as follows:
Twelve Months Ended September 30, ================================== (Dollars in thousands) 2000 $ 1,828 2001 $ 1,828 2002 $ 1,828 2003 $44,828 2004 $ 878
Sinking fund payments due within one year are reported under the caption "Other accruals" in the Consolidated Balance Sheets. (10) COMMON SHARE DIVIDEND: 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 the earned surplus or net profits of Northern Indiana. At September 30, 1999, Northern Indiana had approximately $146.3 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. (11) COMMON SHARES: Effective with the exchange of common shares on March 3, 1988, all of Northern Indiana's common shares are owned by NiSource. (12) LONG-TERM INCENTIVE PLAN: NiSource has two long-term incentive plans for key management employees, including management of Northern Indiana, 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 NiSource 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 NiSource's 1999 Annual Meeting of Shareholders, held April 14, 1999. At September 30, 1999, there were 1.8 million 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 September 30, 1999. Under the Plans, the exercise price of each option equals the market price of NiSource's 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. Stock appreciation rights (SARs) may be granted only in tandem with stock options on a one-for-one basis and are payable in cash, NiSource's common shares, or a combination thereof. There were no SARs outstanding at September 30, 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 is variable 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 513,500 and 534,666 restricted shares outstanding at September 30, 1999 and December 31, 1998, respectively. Northern Indiana accounts for its allocable portion of these plans under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized for nonqualified stock options. The compensation cost that has been charged against income for restricted stock awards was 0.3 million and $0.2 million for the three-month, $0.7 and $0.6 million for the nine-month and $0.9 million and $0.7 million for the twelve-month periods ending September 30, 1999 and September 30, 1998, respectively. Had compensation cost for non-qualified stock options been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," net income would have been reduced to the following pro forma amounts:
Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, ------------------ ------------------ ------------------- 1999 1998 1999 1998 1999 1998 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Net Income: As reported $ 62,115 $ 51,229 $172,263 $156,805 $235,638 $220,366 Pro forma $ 61,724 $ 50,941 $171,065 $156,091 $234,036 $219,439
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 September 30, 1999 and September 30, 1998: risk-free interest rate of 5.87% and 5.29%, respectively; expected dividend yield per share of $1.02 and $0.96, respectively; expected option term of 5.22 and 5.4 years, respectively; and expected volatilities of 15.72% and 13.09%, respectively. The weighted average fair value of options granted to all plan participants was $3.66 and $4.28 for the twelve-month periods ended September 30, 1999 and September 30, 1998, respectively. There were 744,750 and 607,000 non-qualified stock options granted to all plan participants for the twelve-month periods ended September 30, 1999 and September 30, 1998, respectively. (13) LONG-TERM DEBT: At September 30, 1999 and December 31, 1998, the long-term debt of Northern Indiana, excluding amounts due within one year, issued and not retired or canceled was as follows:
AMOUNT OUTSTANDING --------------------------- September 30, December 31, 1999 1998 ============ ============ (Dollars in thousands) First mortgage bonds - Series T, 7-1/2%, due April 1, 2002 $ 38,500 $ 39,000 Series NN, 7.10%, due July 1, 2017 55,000 55,000 ------------ ------------ Total 93,500 94,000 ------------ ------------ Pollution control notes and bonds - Series A Note - City of Michigan City, 5.70% due October 1, 2003 16,500 16,500 Series 1988 Bonds - Jasper County - Series A, B and C - 3.81% weighted average at September 30, 1999, due November 1, 2016 130,000 130,000 Series 1988 Bonds - Jasper County - Series D - 3.53% weighted average at September 30, 1999, due November 1, 2007 24,000 24,000 Series 1994 Bonds - Jasper County - Series A - 3.80% at September 30, 1999, due August 1, 2010 10,000 10,000 Series 1994 Bonds - Jasper County - Series B - 3.80% at September 30, 1999, due June 1, 2013 18,000 18,000 Series 1994 Bonds - Jasper County - Series C - 3.80% at September 30, 1999, due April 1, 2019 41,000 41,000 ------------ ------------ Total 239,500 239,500 ------------ ------------ Medium-term notes - Interest rates between 6.50% and 7.69% with a weighted average interest rate of 7.05% and various maturities between August 15, 2001 and August 4, 2027 593,025 748,025 ------------ ------------ Unamortized premium and discount on long-term debt, net (3,225) (3,566) ------------ ------------ Total long-term debt excluding amounts due in one year $ 922,800 $ 1,077,959 ============ ============
The sinking fund requirements and maturities of long-term debt for the next five years were as follows as of September 30, 1999:
Twelve Months Ended September 30, ================================= (Dollars in thousands) 2000 $157,000 2001 $ 18,000 2002 $ 58,000 2003 $128,500 2004 $ 38,000
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. Northern Indiana's Indenture, pursuant to which first mortgage bonds have been issued, constitutes a direct first mortgage lien upon substantially all of Northern Indiana's property and franchises, other than expressly excepted property. Northern Indiana 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 September 30, 1999, $139.0 million of the 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. (14) CURRENT PORTION OF LONG-TERM DEBT: At September 30, 1999 and December 31, 1998, Northern Indiana's current portion of long-term debt due within one year was as follows:
September 30, December 31, 1999 1998 ============ ============ (Dollars in thousands) Medium-term notes - Interest rate 6.10% and 6.90% with a weighted average interest rate of 6.80% and maturities between October 20, 2000 and June 1, 2000 $ 155,000 $ 0 Sinking funds due within one year 2,000 2,000 ------------ ------------ Total current portion of long-term debt $ 157,000 $ 2,000 ============ ============
(15) SHORT-TERM BORROWINGS: Northern Indiana entered into a five-year $100 million credit agreement and a 364-day $100 million revolving credit agreement with several banks. These agreements terminate on September 23, 2003 and September 23, 2000, respectively. The 364-day agreement may be extended at expiration for additional periods of 364-days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for a short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. As of September 30, 1999, there were no borrowings outstanding under these agreements. In addition, Northern Indiana has $13.2 million in lines of credit which run until May 31, 2000. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. As of September 30, 1999, there were no borrowings under these lines of credit. The credit agreements and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $220 million of money market lines of credit. As of September 30, 1999 and December 31, 1998, $45.9 million and $40.5 million of borrowings were outstanding, respectively, under these lines of credit. At September 30, 1999 and December 31, 1998, Northern Indiana's short- term borrowings were as follows:
September 30, December 31, 1999 1998 ============ ============ (Dollars in thousands) Commercial paper - Weighted average interest rate of 5.36% at September 30, 1999 $ 43,250 $ 85,600 Notes payable - Issued at interest rates between 5.38% and 5.73% with a weighted average interest rate of 5.46% and maturities of October 1, 1999 and October 18, 1999 45,860 40,500 ------------ ------------ Total short-term borrowings $ 89,110 $ 126,100 ============ ============
(16) OPERATING LEASES: On April 1, 1990, Northern Indiana entered into a twenty-year agreement for the rental of office facilities from NiSource Development Company, Inc., a subsidiary of NiSource, at a current annual rental payment of approximately $3.4 million. The following is a schedule, by years, 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 September 30, 1999:
Twelve Months Ended September 30, ================================ (Dollars in thousands) 2000 $ 7,357 2001 7,107 2002 7,107 2003 7,107 2004 5,714 Later years 33,065 -------- Total minimum payments required $ 67,457 ========
The consolidated financial statements include rental expense for all operating leases as follows:
September 30, September 30, 1999 1998 ============ ============ (Dollars in thousands) Three months ended $ 2,919 $ 2,485 Nine months ended $ 8,210 $ 6,964 Twelve months ended $10,637 $ 8,802
(17) COMMITMENTS: Northern Indiana estimates that approximately $802 million will be expended for construction purposes for the period from January 1, 1999 to December 31, 2003. Substantial commitments have been made by Northern Indiana in connection with this 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 million. The agreement provides that, assuming various performance standards are met by Pure Air, a termination payment would be due if Northern Indiana terminates the agreement prior to the end of the twenty-year contract period. A ten-year agreement to outsource all data center, application development and maintenance, and desktop management expires in 2005. Annual fees under this agreement are estimated at $20 million. (18) 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 September 30, 1999, open derivative financial instruments represented hedges of natural gas sales of 0.4 billion cubic feet (Bcf). The net deferred gains 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 September 30, 1999. (19) 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. Investments are carried at cost, which approximates market value. LONG-TERM DEBT AND PREFERRED STOCK. The fair value of these securities are estimated based on quoted market prices for the same or similar issues or on the rates offered 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:
September 30, 1999 December 31, 1998 ---------------------- ---------------------- Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value ========== ========== ========== ========== (Dollars in thousands) Cash and cash equivalents $ 7,813 $ 7,813 $ 19,541 $ 19,541 Investments $ 251 $ 251 $ 251 $ 251 Long-term debt (including current portion) $1,079,800 $1,026,098 $1,079,959 $1,137,657 Preferred stock (including current portion) $ 137,527 $ 122,100 $ 139,379 $ 136,316
Northern Indiana is 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. (20) CUSTOMER CONCENTRATIONS: Northern Indiana is a public utility operating company supplying natural gas and electrical energy in the northern third of Indiana. Although Northern Indiana has a diversified base of residential and commercial customers, a substantial portion of its electric and gas industrial deliveries are dependent upon the basic steel industry. The basic steel industry accounted for 3% of gas revenues (including transportation services) and 17% of electric revenues for the twelve months ended September 30, 1999 and September 30, 1998. (21) SEGMENTS OF BUSINESS: 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. Northern Indiana's reportable operating segments include regulated gas and electric services. Northern Indiana supplies gas and electric services to residential, commercial and industrial customers. The other category includes gas exploration, real estate transactions, and non-utility revenues and expenses. Reportable segments are operations that are managed separately and meet the quantitative thresholds. Revenues for each segments are attributable to customers in the United States. 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. The accounting policies of the operating segments are the same as those described in Note 2, "Summary of Significant Accounting Policies."
For the Three Months Adjust- Ended September 30, 1999 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $ 84,156 $ 324,940 $ 0 $ 0 $ 409,096 Other income (deductions)$ 126 $ 332 $ 1,224 $ (1) $ 1,681 Depreciation and amortization $ 18,685 $ 39,737 $ 0 $ 0 $ 58,422 Income before interest and utility income taxes $ (4,334) $ 116,951 $ 223 $ 0 $ 112,840 Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376 Capital expenditures $ 21,801 $ 24,646 $ 0 $ 0 $ 46,447 For the Three Months Adjust- Ended September 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $ 71,773 $ 311,512 $ 0 $ 0 $ 383,285 Other income (deductions)$ 56 $ 180 $ (1,267) $ (30) $ (1,061) Depreciation and amortization $ 17,890 $ 39,437 $ 0 $ 0 $ 57,327 Income before interest and utility income taxes $(15,350) $ 115,701 $ (1,341) $ 44 $ 99,054 Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710 Capital expenditures $ 15,450 $ 35,878 $ 0 $ 0 $ 51,328 For the Nine Months Adjust- Ended September 30, 1999 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $435,237 $ 862,203 $ 0 $ 0 $1,297,440 Other income (deductions)$ 908 $ 696 $ 161 (39) $ 1,726 Depreciation and amortization $ 55,835 $ 118,785 $ 0 $ 0 $ 174,620 Income before interest and utility income taxes $ 45,610 $ 275,909 $ 110 $ 12 $ 321,641 Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376 Capital expenditures $ 42,995 $ 90,161 $ 0 $ 0 $ 133,156 For the Nine Months Adjust- Ended September 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $389,362 $ 823,309 $ 0 $ 0 $1,212,671 Other income (deductions)$ 809 $ 350 $ (4,013) $ (83) $ (2,937) Depreciation and amortization $ 53,488 $ 117,159 $ 0 $ 0 $ 170,647 Income before interest and utility income taxes $ 25,991 $ 280,074 $ (4,124) $ 28 $ 301,969 Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710 Capital expenditures $ 38,900 $ 92,630 $ 0 $ 0 $ 131,530 For the Twelve Months Adjust- Ended September 30, 1999 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $618,360 $1,115,012 $ 0 $ 0 $1,733,372 Other income (deductions)$ 1,495 $ 894 $ (1,209) $ (106) $ 1,074 Depreciation and amortization $ 74,054 $ 158,466 $ 0 $ 0 $ 232,520 Income before interest and utility income taxes $ 78,982 $ 361,351 $ (1,303) $ (12) $ 439,018 Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376 Capital expenditures $ 60,638 $ 127,962 $ 0 $ 0 $ 188,600 For the Twelve Months Adjust- Ended September 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $628,940 $1,071,293 $ 0 $ 0 $1,700,233 Other income (deductions)$ 1,144 $ 627 $ (5,747) $ (134) $ (4,110) Depreciation and amortization $ 70,807 $ 154,815 $ 0 $ 0 $ 225,622 Income before interest and utility income taxes $ 67,532 $ 360,252 $ (5,929) $ 48 $ 421,903 Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710 Capital expenditures $ 57,139 $ 107,054 $ 0 $ 0 $ 164,193
The following table reconciles total reportable segment income before interest and utility income taxes to net income for three-month, nine-month and twelve-month periods ended September 30, 1999 and 1998:
Three Months Six Months Twelve Months Ended September 30, Ended September 30, Ended September 30, ------------------ ------------------ ------------------ 1999 1998 1999 1998 1999 1998 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Income before interest and utility income taxes $113,840 $ 99,054 $321,641 $301,969 $439,018 $421,903 Interest 18,696 19,748 55,294 58,736 74,938 79,198 Utility income taxes 33,029 28,077 94,084 86,428 128,442 122,339 -------- -------- -------- -------- -------- -------- Net income $ 62,115 $ 51,229 $172,263 $156,805 $235,638 $220,366 ======== ======== ======== ======== ======== ========
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS OPERATING REVENUES - TWELVE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for the twelve months ended September 30, 1999 were $33.1 million higher than for the twelve months ended September 30, 1998, representing a 1.9% increase. Gas revenues were $618.4 million, which represented a $10.6 million decrease from the comparable period for 1998. This decrease occurred mainly due to decreased sales to residential and commercial customers as a result of unusually warm weather during the fourth quarter of 1998, decreased industrial sales, decreased gas cost per dekatherm (dth) and decreased gas transition costs, partially offset by increased wholesale sales and increased deliveries of gas transported for others. Electric revenues were $1.1 billion, which represented a $43.7 million increase from the comparable period for 1998. This increase occurred mainly due to increased sales to residential and commercial customers as a result of warmer weather during the third quarter of 1999, increased wholesale transactions and increased fuel costs. NINE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for the nine months ended September 30, 1999 were $84.8 million higher than for the nine months ended September 30, 1999, representing a 7.0% increase. Gas revenues were $435.2 million, which represented a 11.8% increase from the comparable period for 1998. This increase occurred primarily due to increased sales to residential customers as a result of colder weather during the period, increased deliveries of gas transported for others and increased wholesale sales partially offset by decreased gas cost per dth and decreased gas transition costs. Electric revenues were $862.2 million, which represented a $38.9 million increase from the comparable period for 1998. This increase was mainly attributable to increased sales to residential, commercial and industrial customers, increased wholesale transactions and increased fuel costs. THREE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for the three months ended September 30, 1999 were $25.8 million higher than for the three months ended September 30, 1999, representing a 6.7% increase. Gas revenues were $84.2 million, which represented a 17.3% increase from the comparable period for 1998. This increase occurred primarily due to increased wholesale sales and increased gas cost per dth, partially offset by decreased industrial sales, decreased deliveries of gas transported for others and decreased gas transition costs. Electric revenues were $324.9 million, which represented a $13.4 million increase from the comparable period for 1998. This increase was mainly attributable to increased sales to residential and commercial customers, increased sales to industrial customers, increased fuel costs, partially offset by decreased wholesale transactions The basic steel industry accounted for 39% of natural gas delivered (including volumes transported) and 27% of electric sales during the twelve months ended September 30, 1999. The components of the variations in gas and electric revenues are shown in the following table:
Variations from Prior Periods --------------------------------- September 30, 1999 Compared to September 30, 1998 Three Nine Twelve Months Months Months ========= ========= ========= (Dollars in thousands) Gas Revenue Changes - Pass through of net changes in purchased gas costs, gas storage, and storage transportation costs $ 9,298 $ (14,737) $ (44,620) Gas transition costs (1,156) (3,382) (6,815) Changes in sales levels 563 40,399 8,161 Gas transported (62) 460 6,069 Wholesale gas 3,740 23,135 26,625 --------- --------- --------- Total Gas Revenue Change $ 12,383 $ 45,875 $ (10,580) --------- --------- --------- Electric Revenue Changes- Pass through of net changes in fuel costs $ 12,128 $ 9,312 $ 9,078 Changes in sales levels 14,149 25,333 24,600 Wholesale electric (12,849) 4,249 10,041 --------- --------- --------- Total Electric Revenue Change $ 13,428 $ 38,894 $ 43,719 --------- --------- --------- Total Revenue Change $ 25,811 $ 84,769 $ 33,139 ========= ========= =========
You can find information about the gas adjustment factor that Northern Indiana applies to its sales rates in Note 2, "Summary of Accounting Policies - - Gas Cost Adjustment Clause" to the Consolidated Financial Statements. COST OF SALES - Cost of sales consists of gas costs, costs of fuel for electric production and costs of power purchased. GAS COSTS. Gas costs for the twelve months ended September 30, 1999 decreased by $13.4 million, or by 3.7%, from the twelve months ended September 30, 1998. This decrease resulted due to decreased gas cost per dth and decreased gas transition costs, partially offset by increased gas purchased. Gas costs for the nine months ended September 30, 1999 increased by $33.3 million, or by 15.3%, from the nine months ended September 30, 1998. This increase occurred as a result of increased gas purchases during the period, partially offset by decreased gas cost per dth and decreased gas transition costs. Gas costs for the three months ended September 30, 1999 increased by $13.5 million, or by 34.2%, from the three months ended September 30, 1998. This increase occurred as a result of increased gas cost per dth and increased gas purchases during the period, partially offset by decreased gas transition costs. FUEL AND PURCHASED POWER. The cost of fuel used for electric generation during the twelve months ended September 30, 1999 was $8.4 million lower than the cost of fuel used during the twelve months ended September 30, 1998, mainly due to decreased fuel costs per kilowatt-hour (kwh). The average cost per kwh generated decreased by 3.4% from 1.54 cents per kwh during the twelve months ended September 30, 1998, to 1.48 cents per kwh for the comparable period for 1999. The cost of fuel used for electric generation during the nine months ended September 30, 1999 was $5.2 million lower than the cost of fuel used during the nine months ended September 30, 1998, mainly due to decreased fuel costs of 2.7%, partially offset by increased electric generation of 0.7%. The average cost per kwh generated during the nine months ended September 30, 1999 decreased by 3.4% from 1.53 cents per kwh to 1.48 cents per kwh from the comparable period for 1998. The cost of fuel used for electric generation during the three months ended September 30, 1999 was relatively unchanged from the three months ended September 30, 1998. The average cost per kwh generated during the three months ended September 30, 1999 decreased by 4.3% from 1.57 cents per kwh to 1.50 cents per kwh from the comparable period for 1998. Northern Indiana spent $43.1 million more during the twelve months ended September 30, 1999 than during the comparable period in 1998 to purchase power, primarily due to increased purchases of 153.6%, partially offset by an 15.4% decrease in the cost per kwh. Power purchased increased by $38.9 million for the nine-month period ended September 30, 1998, reflecting increased bulk power purchases of 162.8%, partially offset by an 17.1% decrease in the cost per kwh. Power purchased increased by $11.2 million for the three-month period ended September 30, 1998, reflecting 169.9% increase in the cost per kwh, partially offset by decreased bulk power purchases of 38.6% OPERATING MARGINS - TWELVE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the twelve months ended September 30, 1999 were $11.8 million higher than for the twelve months ended September 30, 1998, representing a 1.1% increase. Gas operating margin was $2.9 million higher than in the comparable period for 1998. This increase occurred mainly as a result of increased wholesale sales and increased deliveries of gas transported for others, partially offset by decreased sales to residential customers, reflecting unusually warm weather during the fourth quarter of 1998 and decreased sales to industrial customers. Electric operating margin was $788.8 million, which represented a $8.9 million increase from the comparable for 1998. This increase occurred mainly due to increased sales to residential and commercial customers, partially offset by decreased margins on wholesale transactions. NINE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the nine months ended September 30, 1999 were $17.8 million higher than the nine months ended September 30, 1998, representing a 2.3% increase. Gas operating margin was $12.5 million higher than in the comparable period for 1998. This increase occurred mainly as a result of increased sales to residential customers reflecting colder weather during the first quarter of 1999, increased wholesale sales and increased deliveries of gas transported for others. Electric operating margin was $602.3 million, which represented a $5.3 million increase from the comparable period for 1998. This increase occurred mainly due to increased sales to residential, commercial and industrial customers, partially offset by decreased margins on wholesale transactions. THREE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the three months ended September 30, 1999 were $1.3 million higher than the three months ended September 30, 1998. Gas operating margin was $1.1 million lower than in the comparable period in 1998. This decrease occurred mainly as a result of decreased sales to industrial customers and lower margins on wholesale transactions. Electric operating margin was $224.7 million, which represented a $2.4 million increase from the comparable period for 1998. This increase occurred mainly due to increased sales to residential customers, partially offset by decreased wholesale transactions. OPERATING EXPENSES AND TAXES - Operating expenses and taxes (except income) consists of operations expenses, maintenance expenses, depreciation and amortization expenses and taxes (except income). OPERATIONS EXPENSE. Operation expenses for the twelve months ended September 30, 1999 were $4.6 million lower than in the twelve months ended September 30, 1998. Operation expenses were lower primarily as a result of $13.0 million insurance settlement related to manufactured gas plant site cleanup costs partially offset by increased employee related costs of $2.2 million, increased property and liability claims of $1.9 million, increased write-offs for uncollectible accounts of $1.2 million and increased consulting services. Operation expenses for the nine months ended September 30, 1999 were $2.2 million lower than for the nine months ended September 30, 1998. Operation expenses were lower in the nine-month period primarily as a result of a $13.0 million insurance settlement related to manufactured gas plant site cleanup costs, partially offset increased employee related costs of $6.2 million, increased property and liability claims of $1.9 million and increased consulting services of $2.0 million. Operation expenses for the three months ended September 30, 1999 were $11.0 million lower than for the three months ended September 30, 1998. Operation expenses were lower in the three-month period primarily as a result of a $13.0 million insurance settlement related to manufactured gas plant site cleanup costs, partially offset by increased consulting services of $1.8 million. MAINTENANCE EXPENSE. Maintenance expenses for the twelve months ended September 30, 1999 were $3.7 million lower than in the twelve months ended September 30, 1998. Maintenance expenses were lower primarily as a result of decreased electric production facility maintenance costs of $1.9 million and decreased electric and gas distribution facilities maintenance of $2.0 million. Maintenance expenses for the three and nine months ended September 30, 1999 were relatively unchanged from the three and nine months ended September 30, 1998. DEPRECIATION AND AMORTIZATION EXPENSE. Depreciation and amortization expenses for the three-month, nine-month and twelve-months periods ended September 30, 1999 were $1.1, $4.0 and $6.9 million, respectively, higher than in the comparable period for 1998. These higher expenses primarily related to increased depreciation expense as a result of increased depreciable plant. OTHER INCOME (DEDUCTIONS) Other Income (Deductions) for the three-month, nine-month and twelve- month periods ended September 30, 1999 increased by $2.7, $4.7 and $5.2 million, respectively, from the comparable periods for 1998 primarily as a result of power trading activities which began in early 1999. INTEREST CHARGES - Interest charges for the three-month, nine-month and twelve-month periods ended September 30, 1999 were $1.1, $3.4 and $4.3 million lower, respectively, than in the comparable periods for 1998. These decreases resulted primarily due to decreased short-term and long term debt outstanding during the three-month, nine-month and twelve-month periods ended September 30, 1999. LIQUIDITY AND CAPITAL RESOURCES - 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 is issued for short-term financing. As of September 30, 1999 and December 31, 1998, $43.3 million and $85.6 million of commercial paper was outstanding, respectively. The weighted average interest rate of commercial paper outstanding as of September 30, 1999 was 5.36%. Northern Indiana entered into a five-year $100 million credit agreement and a 364-day $100 million revolving credit agreement with several banks. These agreements terminate on September 23, 2003 and September 23, 2000, respectively. The 364-day agreement may be extended at expiration for additional periods of 364-days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for a short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. As of September 30, 1999, there were no borrowings outstanding under these agreements. In addition, Northern Indiana has $13.2 million in lines of credit which run until May 31, 2000. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. As of September 30, 1999, there were no borrowings under these lines of credit. The credit agreements and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $220 million of money market lines of credit. As of September 30, 1999 and December 31, 1998, $45.9 million and $40.5 million of borrowings were outstanding, respectively, under these lines of credit. CONSTRUCTION PROGRAM. Future commitments with respect to its construction program are expected to be met through internally generated funds. MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS - See Note 18, "Financial Instruments and Risk Management," to the consolidated financial statements for a discussion of the types of commodity- based derivative financial instruments and risk management. There are two primary market risks, commodity price risk and interest rate risk, to which Northern Indiana is exposed. 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, not all basis exposure is 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, Northern Indiana 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 Northern Indiana business is relatively limited, since current regulations allow Northern Indiana to recoup any prudently incurred fuel and gas costs through rate-making. As the utility industry undergoes deregulation, however, Northern Indiana will be providing services without the benefit of the traditional rate-making and, therefore, will be more exposed to commodity price risk. Because derivative financial and commodity instruments are substantially the same commodities that are bought and sold in the physical market, Northern Indiana 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. 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 13 to the consolidated financial statements, "Long-term Debt." Information about the current market valuation of long-term debt is in Note 19 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-Derivaties." 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 Northern Indiana anticipates 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 Northern Indiana. Similarly, gas operations depend on natural gas pipelines that are not owned or controlled by Northern Indiana, and any non-compliance by a company owning or controlling those pipelines may affect Northern Indiana'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 and testing remediated systems to confirm compliance). Northern Indiana has completed the remediation and validation phases for all of its mission-critical systems. Northern Indiana 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. Substantial completion of mission-critical year 2000 efforts was completed in June 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 $19 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. Northern Indiana 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 alternative 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 were completed during the second quarter 1999; however, the contingency plans will be under review during the fourth quarter of 1999. ALL STATEMENTS REGARDING YEAR 2000 MATTERS CONTAINED IN THIS REPORT ARE "YEAR 2000 READINESS DISCLOSURES" WITHIN THE MEANING OF THE YEAR 2000 INFORMATION AND READINESS DISCLOSURE ACT. COMPETITION AND REGULATORY CHANGES - The regulatory frameworks applicable to Northern Indiana, at both state and federal levels, are undergoing fundamental change. These changes have had and will continue to have an impact on operations, structure and profitability. At the same time, competition within the electric and gas industries will create opportunities to compete for new customers and revenues. Management has taken steps to become more competitive and profitable in this changing environment, including converting some of its generating units to allow use of lower cost, low sulfur coal, providing its gas customers with increased customer choice for new products and services throughout the service territory. THE ELECTRIC INDUSTRY. At the Federal level, 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 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-1980's when FERC required interstate pipelines to provide nondiscriminatory transportation services pursuant to unbundled rates. This regulatory change permitted large industrial and commercial customers to purchase their gas supplies either from Northern Indiana or directly from competing producers and marketers, which would then use Northern Indiana's facilities to transport the gas. More recently, the focus of deregulation in the gas industry has shifted to the states. At the state level, the 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 82,000 residential customers within St. Joseph County and 10,000 commercial customers throughout the Northern Indiana service area the right to choose alternative gas suppliers. Phase II of Northern Indiana's Customer Choice Pilot Program will commence on April 1, 1999 and continue for a one-year period. During this phase, Northern Indiana is offering customer choice to all 660,000 residential and 50,000 commercial customers throughout its gas service territory. A limit of 150,000 residential and 20,000 commercial customers are eligible to enroll in Phase II of the program. The IURC order allows 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, price protection, negotiated sales and services, gas lending and parking, and new storage services. To date, Northern Indiana's system has not been materially affected by competition, and management does not foresee substantial adverse effects in the near future unless the current regulatory structure is substantially altered. Northern Indiana believes the steps it is taking 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. Northern Indiana cautions that, while it believes such statements to be based on reasonable assumptions and makes such statements in good faith, you cannot be assured that the actual results will not differ materially from such assumptions or that the expectations set forth in the forward looking statements derived from such assumptions will be realized. You should be aware of important factors that could have a material impact on future results. These factors include, weather, the federal and state regulatory environment, year 2000 issues, the economic climate, regional, commercial, industrial and residential growth in the service territories served by Northern Indiana, customers' usage patterns and preferences, the speed and degree to which competition enters the utility industry, the timing and extent of changes in commodity prices, changing conditions in the capital and equity markets and other uncertainties, all of which are difficult to predict, and many of which are beyond Northern Indiana'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. Northern Indiana is a party to various pending proceedings, including suits and claims against it for personal injury, death and property damage. Such proceedings and suits, and the amounts involved, are routine for the kind of business conducted by Northern Indiana, except as described under Note 4 "Environmental Matters," in the notes to consolidated financial statements under Part I, Item 1 of this Report on Form 10-Q, which note is incorporated by reference. No other material legal proceedings against Northern Indiana or its subsidiaries are pending or, to the knowledge of Northern Indiana, contemplated by governmental authorities and other parties. Item 2. CHANGES IN SECURITIES. None Item 3. DEFAULTS UPON SENIOR SECURITIES. None Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None 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 (b) Reports on Form 8-K. None 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. Northern Indiana Public Service Company (Registrant) /s/ David J. Vajda --------------------------------------- David J. Vajda, Controller and Chief Accounting Officer Date November 12, 1999 EX-23 2 Exhibit 23 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 Northern Indiana Public Service Company's previously filed Form S-3 Registration Statement No. 333-26847. /s/ Arthur Andersen LLP Chicago, Illinois November 12, 1999 EX-27 3
UT This schedule contains summary financial information extracted from the financial statements of Northern Indiana Public Service Company for three months ended September 30, 1999 and is qualified in its entirety by reference to such financial statements. 1,000 3-MOS DEC-31-1999 JUL-01-1999 SEP-30-1999 PER-BOOK 2,950,342 2,636 308,949 149,491 200,958 3,612,376 859,488 12,525 146,289 1,018,302 54,585 81,114 316,500 45,860 611,025 43,250 157,000 1,828 0 0 1,282,912 3,612,376 409,096 33,029 296,937 329,966 79,130 1,681 80,811 18,696 62,115 2,021 60,094 58,000 0 84,464 0 0
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