-----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, J7+pJTN8Ouuck9rj8qCtorOZm5d36pZtGhAS/OzZcWQq1qYzuj1rX75uOcl+2WM/ 0N5sIeSyickq/Z5nYO2jww== 0000072843-98-000004.txt : 19980813 0000072843-98-000004.hdr.sgml : 19980813 ACCESSION NUMBER: 0000072843-98-000004 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980812 SROS: NYSE 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: 98684053 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 June 30, 1998 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 July 31, 1998, 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 sheet of Northern Indiana Public Service Company (an Indiana corporation and a wholly owned subsidiary of NIPSCO Industries, Inc.) and subsidiaries as of June 30, 1998, and December 31, 1997, and the related consolidated statements of income, retained earnings and cash flows for the three, six and twelve month periods ended June 30, 1998 and 1997. 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 June 30, 1998 and December 31, 1997, and the results of their operations and their cash flows for the three, six and twelve month periods ended June 30, 1998 and 1997, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP Chicago, Illinois July 29, 1998
CONSOLIDATED BALANCE SHEET June 30, December 31, ASSETS 1998 1997 ============ ============ (Dollars in thousands) UTILITY PLANT, AT ORIGINAL COST (INCLUDING CONSTRUCTION WORK IN PROGRESS OF $142,554 AND $140,534 RESPECTIVELY) (NOTE 2): Electric $ 4,106,198 $ 4,066,568 Gas 1,244,595 1,223,693 Common 352,333 351,350 ------------ ------------ 5,703,126 5,641,611 Less - Accumulated provision for depreciation and amortization 2,702,436 2,613,352 ------------ ------------ Total Utility Plant 3,000,690 3,028,259 ------------ ------------ OTHER PROPERTY AND INVESTMENTS 701 1,215 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents 14,831 9,800 Accounts receivable, less reserve of $4,533 and $4,524, respectively (Note 2) 88,727 101,188 Fuel adjustment clause (Note 2) 0 2,679 Gas cost adjustment clause (Note 2) 24,991 86,520 Materials and supplies, at average cost 52,546 53,666 Electric production fuel, at average cost 16,499 18,837 Natural gas in storage, at last-in, first-out cost (Note 2) 29,582 45,880 Prepayments and other 25,705 23,128 ------------ ------------ Total Current Assets 252,881 341,698 ------------ ------------ OTHER ASSETS: Regulatory assets (Note 2) 199,152 205,965 Prepayments and other (Note 6) 113,668 97,777 ------------ ------------ Total Other Assets 312,820 303,742 ------------ ------------ $ 3,567,092 $ 3,674,914 ============ ============ The accompanying notes to consolidated financial statements are an integral part of this statement.
CONSOLIDATED BALANCE SHEET June 30, December 31, CAPITALIZATION AND LIABILITIES 1998 1997 ============ ============ (Dollars in thousands) CAPITALIZATION: Common stock - without par value - authorized 75,000,000 shares, issued and outstanding 73,282,258 shares (Note 12) $ 859,488 $ 859,488 Additional paid-in capital 12,524 12,522 Retained earnings (see accompanying statement) (Note 11) 152,676 146,293 ------------ ------------ Common shareholder's equity 1,024,688 1,018,303 Cumulative preferred stocks (Note 8) Series without mandatory redemption provisions (Note 9) 81,117 81,123 Series with mandatory redemption provisions (Note 10) 57,591 58,841 Long-term debt excluding amounts due within one year (Note 14) 1,079,734 1,079,496 ------------ ------------ Total Capitalization 2,243,130 2,237,763 ------------ ------------ CURRENT LIABILITIES - Current portion of long-term debt (Note 15) 16,009 51,009 Short-term borrowings (Note 16) 112,300 119,000 Accounts payable 95,806 127,742 Dividends declared on common and preferred stocks 50,138 56,198 Customer deposits 21,067 20,236 Taxes accrued 87,130 88,852 Interest accrued 8,093 7,646 Fuel adjustment clause 625 0 Accrued employment costs 35,483 51,095 Other accruals 24,740 34,051 ------------ ------------ Total Current Liabilities 451,391 555,829 ------------ ------------ OTHER: Deferred income taxes (Note 5) 593,134 602,936 Deferred investment tax credits, being amortized over life of related property (Note 5) 96,289 99,853 Deferred credits 51,148 53,323 Accrued liability for postretirement benefits (Note 7) 121,494 115,177 Other noncurrent liabilities 10,506 10,033 ------------ ------------ Total Other 872,571 881,322 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Notes 3, 4, 17 and 18) $ 3,567,092 $ 3,674,914 ============ ============ The accompanying notes to consolidated financial statements are an integral part of this statement.
CONSOLIDATED STATEMENT OF INCOME Three Months Six Months Ended June 30, Ended June 30, ---------------------- ---------------------- 1998 1997 1998 1997 ========== ========== ========== ========== (Dollars in thousands) Operating Revenues: (Notes 2, 3 and 20) Gas $ 98,859 $ 108,541 $ 317,589 $ 414,215 Electric 271,611 244,054 511,797 489,878 ---------- ---------- ---------- ---------- 370,470 352,595 829,386 904,093 ---------- ---------- ---------- ---------- Cost of Energy: (Note 2) Gas costs 55,204 55,645 178,374 252,380 Fuel for electric generation 65,423 54,609 121,017 113,017 Power purchased 12,400 10,518 16,047 19,478 ---------- ---------- ---------- ---------- 133,027 120,772 315,438 384,875 ---------- ---------- ---------- ---------- Operating Margin 237,443 231,823 513,948 519,218 ---------- ---------- ---------- ---------- Operating Expenses and Taxes (except income): Operation 61,814 70,084 123,917 139,873 Maintenance (Note 2) 18,627 17,534 35,321 34,872 Depreciation and amortization (Note 2) 56,800 56,237 113,320 111,489 Taxes (except income) 17,462 17,500 36,599 37,657 ---------- ---------- ---------- ---------- 154,703 161,355 309,157 323,891 ---------- ---------- ---------- ---------- Operating Income Before Utility Income Taxes 82,740 70,468 204,791 195,327 ---------- ---------- ---------- ---------- Utility Income Taxes (Note 5) 22,434 17,899 58,351 54,906 ---------- ---------- ---------- ---------- Operating Income 60,306 52,569 146,440 140,421 ---------- ---------- ---------- ---------- Other Income (Deductions) (Note 2) (1,268) (1,036) (1,876) (1,445) ---------- ---------- ---------- ---------- Interest: Interest on long-term debt 17,461 16,962 35,311 33,179 Other interest 728 1,797 1,577 4,648 Amortization of premium, reacquisition premium, discount and expense on debt, net 1,047 1,046 2,100 2,089 ---------- ---------- ---------- ---------- 19,236 19,805 38,988 39,916 ---------- ---------- ---------- ---------- Net Income 39,802 31,728 105,576 99,060 Dividend requirements on preferred shares 2,077 2,128 4,193 4,295 ---------- ---------- ---------- ---------- Balance available for common shares $ 37,725 $ 29,600 $ 101,383 $ 94,765 ========== ========== ========== ========== Dividends declared $ 49,000 $ 44,000 $ 95,000 $ 88,000 ========== ========== ========== ========== Twelve Months Ended June 30, ---------------------- 1998 1997 ========== ========== (Dollars in thousands) Operating Revenues: (Notes 2, 3 and 20) Gas $ 638,673 $ 735,707 Electric 1,039,002 1,019,453 ---------- ---------- 1,677,675 1,755,160 ---------- ---------- Cost of Energy: (Note 2) Gas costs 378,430 452,302 Fuel for electric generation 246,548 235,846 Power purchased 33,843 46,946 ---------- ---------- 658,821 735,094 ---------- ---------- Operating Margin 1,018,854 1,020,066 ---------- ---------- Operating Expenses and Taxes (except income): Operation 253,319 276,312 Maintenance (Note 2) 69,302 66,727 Depreciation and amortization (Note 2) 224,856 217,070 Taxes (except income) 70,694 72,813 ---------- ---------- 618,171 632,922 ---------- ---------- Operating Income Before Utility Income Taxes 400,683 387,144 ---------- ---------- Utility Income Taxes (Note 5) 113,544 107,893 ---------- ---------- Operating Income 287,139 279,251 ---------- ---------- Other Income (Deductions) (Note 2) (4,090) 742 ---------- ---------- Interest: Interest on long-term debt 71,559 66,422 Other interest 4,149 11,369 Amortization of premium, reacquisition premium, discount and expense on debt, net 4,205 4,184 ---------- ---------- 79,913 81,975 ---------- ---------- Net Income 203,136 198,018 Dividend requirements on preferred shares 8,437 8,630 ---------- ---------- Balance available for common shares $ 194,699 $ 189,388 ========== ========== Dividends declared $ 194,775 $ 186,200 ========== ========== The accompanying notes to consolidated financial statements are an integral part of this statement.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS Three Months Six Months Twelve Months Ended June 30, Ended June 30, Ended June 30, ------------------- ------------------- ------------------- 1998 1997 1998 1997 1998 1997 ========= ========= ========= ========= ========= ========= (Dollars in thousands) BALANCE AT BEGINNING OF PERIOD $ 163,951 $ 167,152 $ 146,293 $ 145,987 $ 152,752 $ 149,564 ADD: Net income 39,802 31,728 105,576 99,060 203,136 198,018 --------- --------- --------- --------- --------- --------- 203,753 198,880 251,869 245,047 355,888 347,582 --------- --------- --------- --------- --------- --------- LESS: Dividends Cumulative Preferred stocks - 4-1/4% series 223 223 445 445 889 889 4-1/2% series 89 89 180 180 360 360 4.22% series 111 111 224 224 448 448 4.88% series 122 122 244 244 488 488 7.44% series 79 79 156 156 312 312 7.50% series 65 65 131 131 261 261 8.85% series 129 156 295 350 627 737 7-3/4% series 80 92 161 183 340 374 8.35% series 125 137 250 275 497 546 6.50% series 699 699 1,397 1,397 2,795 2,795 Adjustable Rate, Series A 355 355 710 710 1,420 1,420 Common shares 49,000 44,000 95,000 88,000 194,775 186,200 --------- --------- --------- --------- --------- --------- 51,077 46,128 99,193 92,295 203,212 194,830 --------- --------- --------- --------- --------- --------- BALANCE AT END OF PERIOD $ 152,676 $ 152,752 $ 152,676 $ 152,752 $ 152,676 $ 152,752 ========= ========= ========= ========= ========= ========= The accompanying notes to consolidated financial statements are an integral part of this statement.
CONSOLIDATED STATEMENT OF CASH FLOWS Three Months Ended June 30, ------------------------ 1998 1997 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 39,802 $ 31,728 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 56,800 56,237 Deferred federal and state operating income taxes, net (13,307) (21,170) Deferred investment tax credits, net (1,782) (1,793) Advance contract payment 475 475 Change in certain assets and liabilities - Accounts receivable, net 16,183 37,234 Electric production fuel 4,742 (4,500) Materials and supplies 2,434 392 Natural gas in storage (11,265) (11,439) Accounts payable (7,367) (17,447) Taxes accrued (52,099) (28,207) Fuel adjustment clause 1,736 4,673 Gas cost adjustment clause 11,465 40,215 Accrued employment costs (1,788) 2,403 Other accruals (6,148) (14,323) Other, net (12,699) 8,773 ---------- ---------- Net cash provided by operating activities 27,182 83,251 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (46,892) (55,956) Other, net (779) 256 ---------- ---------- Net cash used in investing activities (47,671) (55,700) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Issuance of long-term debt 0 99,000 Issuance of short-term debt 196,200 151,080 Net change in commercial paper 52,600 (57,100) Retirement of long-term debt (35,000) 0 Retirement of short-term debt (155,000) (183,530) Retirement of preferred shares (1,256) (1,252) Cash dividends paid on common shares (46,000) (44,000) Cash dividends paid on preferred shares (2,116) (2,139) Other, net 117 (583) ---------- ---------- Net cash provided by (used in) financing activities 9,545 (38,524) ---------- ---------- NET INCREASE IN CASH AND CASH EQUIVALENTS (10,944) (10,973) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 25,775 22,693 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 14,831 $ 11,720 ========== ========== Six Months Ended June 30, ------------------------ 1998 1997 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 105,576 $ 99,060 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 113,320 111,489 Deferred federal and state operating income taxes, net (39,973) (29,185) Deferred investment tax credits, net (3,564) (3,587) Advance contract payment 950 950 Change in certain assets and liabilities - Accounts receivable, net 12,461 32,112 Electric production fuel 2,338 (2,149) Materials and supplies 1,120 448 Natural gas in storage 16,298 24,146 Accounts payable (23,898) (55,065) Taxes accrued 26,559 35,097 Fuel adjustment clause 3,304 892 Gas cost adjustment clause 61,529 53,538 Accrued employment costs (15,612) (1,950) Other accruals (9,311) 9,846 Other, net (7,787) 25,864 ---------- ---------- Net cash provided by operating activities 243,310 301,506 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (80,202) (101,377) Other, net (10,129) (208) ---------- ---------- Net cash used in investing activities (90,331) (101,585) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Issuance of long-term debt 0 99,000 Issuance of short-term debt 314,360 331,480 Net change in commercial paper (400) (148,505) Retirement of long-term debt (35,000) 0 Retirement of short-term debt (320,660) (375,430) Retirement of preferred shares (1,256) (1,253) Cash dividends paid on common shares (101,000) (97,000) Cash dividends paid on preferred shares (4,230) (4,304) Other, net 238 (468) ---------- ---------- Net cash used in financing activities (147,948) (196,480) ---------- ---------- NET INCREASE IN CASH AND CASH EQUIVALENTS 5,031 3,441 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,800 8,279 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 14,831 $ 11,720 ========== ========== Twelve Months Ended June 30, ------------------------ 1998 1997 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 203,136 $ 198,018 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 224,856 217,070 Deferred federal and state operating income taxes, net (19,202) (15,802) Deferred investment tax credits, net (7,182) (7,593) Advance contract payment 1,900 1,900 Change in certain assets and liabilities - Accounts receivable, net (8,973) (13,429) Electric production fuel 12,133 2,265 Materials and supplies 3,802 3,252 Natural gas in storage (3,319) (3,519) Accounts payable (20,106) (17,094) Taxes accrued 12,950 43,274 Fuel adjustment clause 8,882 3,366 Gas cost adjustment clause 19,638 4,477 Accrued employment costs (3,482) 1,364 Other accruals (13,040) 4,914 Other, net (11,852) 31,536 ---------- ---------- Net cash provided by operating activities 400,141 453,999 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (153,056) (200,221) Other, net (13,112) 1,215 ---------- ---------- Net cash used in investing activities (166,168) (199,006) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Issuance of long-term debt 40,000 99,000 Issuance of short-term debt 517,310 1,045,630 Net change in commercial paper 25,700 (43,000) Retirement of long-term debt (102,247) (80,000) Retirement of short-term debt (511,160) (1,074,780) Retirement of preferred shares (2,411) (2,411) Cash dividends paid on common shares (189,775) (187,200) Cash dividends paid on preferred shares (8,482) (8,658) Other, net 203 (233) ---------- ---------- Net cash used in financing activities (230,862) (251,652) ---------- ---------- NET INCREASE IN CASH AND CASH EQUIVALENTS 3,111 3,341 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 11,720 8,379 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 14,831 $ 11,720 ========== ========== The accompanying notes to consolidated financial statements are an integral part of this statement.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) HOLDING COMPANY STRUCTURE: NIPSCO Industries, Inc. (Industries) was incorporated in Indiana on September 22, 1987 and became the parent of Northern Indiana Public Service Company (Northern Indiana) on March 3, 1988. Northern Indiana is a public utility operating company supplying electricity and gas to the public in the northern third of Indiana. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: BASIS OF PRESENTATION. The consolidated financial statements include the accounts of Northern Indiana and its two subsidiaries, Shore Line Shops, Inc. and NIPSCO Exploration Company, Inc. All significant intercompany items have been eliminated in consolidation. 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 each 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 The depreciation provision for electric utility plant, as a percentage of the original cost, was 3.7% for the three-month, 3.6% for the six-month and twelve-month periods ended June 30, 1998, and was 3.6% for three-month, six- month and twelve-month periods ended June 30, 1997. Gas: ---- Gas storage plant 18 years Transmission plant 34 years Distribution plant 27 years Other gas plant 24 years The depreciation provision for gas utility plant, as a percentage of the original cost, was 5.4% for the three-month, six-month and twelve-month periods ended June 30, 1998, and 5.3% for the three-month, six-month and twelve-month periods ended June 30, 1997. Northern Indiana follows the practice of charging maintenance and repairs, including the cost of renewals of minor items of property, to maintenance expense accounts, except for repairs of transportation and service equipment which are charged to clearing accounts and redistributed to operating expense and other accounts. When property which 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. Northern Indiana has capitalized software relating to various technology functions. At the date of installation, Northern Indiana estimates that the specific software will have a useful life between five and ten years. The Federal Energy Regulatory Commission (FERC) prescribes certain amortization periods, and Northern Indiana's management has determined that, on average, these are reasonable useful life estimates for the portfolio of capitalized software. Northern Indiana includes these amortization estimates, based on useful life, in its quarterly filings with the Indiana Utility Regulatory Commission (Commission). COAL RESERVES. Northern Indiana has a long-term mining contract to mine its coal reserves through the year 2001. The costs of these reserves are being recovered through the rate-making process as such coal reserves are used to produce electricity. POWER PURCHASED. Power purchases and net interchange power with other electric utilities under interconnection agreements are included in Cost of Energy under the caption "Power purchased." ACCOUNTS RECEIVABLE. At June 30, 1998, Northern Indiana had sold $100 million of its accounts receivable under a sales agreement which expires May 31, 2002. The June 30, 1998 and December 31, 1997 accounts receivable balances include approximately $3.7 million and $5.4 million, respectively, due from associated companies. COMPREHENSIVE INCOME. Northern Indiana adopted 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 SFAS No. 130 did not impact Northern Indiana's financial statements for the periods presented. STATEMENT OF CASH FLOWS. For the purposes of the Consolidated Statement of Cash Flows, Northern Indiana considers temporary cash investments with an original maturity of three months or less to be cash equivalents. Cash paid during the periods reported for income taxes and interest was as follows:
Three Months Six Months Twelve Months Ended June 30, Ended June 30, Ended June 30, ------------------ ------------------ ------------------ 1998 1997 1998 1997 1998 1997 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Income taxes $ 73,320 $ 50,000 $ 73,340 $ 50,000 $ 128,149 $ 69,463 Interest, net of amounts capitalized $ 26,736 $ 28,992 $ 34,270 $ 35,800 $ 73,555 $ 77,217
FUEL ADJUSTMENT CLAUSE. All metered electric rates contain a provision for adjustment in charges for electric energy to reflect increases and decreases in the cost of fuel and the fuel cost of purchased power through operation of a fuel adjustment clause. As prescribed by order of the Commission applicable to metered retail rates, the adjustment factor has been calculated based on the estimated cost of fuel and the fuel cost of purchased power in a future three-month period. If two statutory requirements relating to expense and return levels are satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given three-month period will be included in a future filing. Northern Indiana records any under-recovery or over-recovery as a current 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 Commission and remains in effect for a three-month period. GAS COST ADJUSTMENT CLAUSE. All metered gas rates contain an adjustment factor which reflects the cost of purchased gas, contracted gas storage and storage transportation charges. Northern Indiana records any under-recovery or over-recovery as a current asset or current liability until such time it is billed or refunded to its customers. The gas cost adjustment factor is subject to a quarterly hearing by the Commission and remains in effect for a three-month period. 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 three-month period will be included in a future filing. The gas cost adjustment clause includes a gas cost incentive mechanism (GCIM) that allows Northern Indiana to share any cost savings or cost increases with customers based on a comparison of Northern Indiana's actual gas supply portfolio costs to a market based benchmark price. See Note 3, FERC Order No. 636 for a discussion of gas transition cost charges. 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 June 1998 and December 1997 the estimated replacement cost of gas in storage (current and non-current) at June 30, 1998 and December 31, 1997 exceeded the stated LIFO cost by approximately $41 million and $42 million, respectively. AFFILIATED COMPANY TRANSACTIONS. Pursuant to agreement, effective July 1, 1996, Northern Indiana receives executive, financial, gas supply, sales and marketing, and administrative and general services from an affiliate, NIPSCO Industries Management Services Company (NIMSC), a wholly-owned subsidiary of Industries. The costs of these services are charged to Northern Indiana based on payroll and expenses incurred by NIMSC's employees for the benefit of Northern Indiana. These costs, which totaled $4.6 million, $11.6 million and $23.2 million for the three-month, six-month and twelve-month periods ended June 30, 1998 and totaled $8.6 million, $17.2 million and $34.4 million for the three-month, six-month and twelve-month periods ended June 30, 1997, consist primarily of employee compensation and benefits. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $6.7 million, $8.6 million and $14.8 million representing 8.8%, 5.1% and 4.2% of Northern Indiana's total gas costs for the three-month, six-month and twelve-month periods ended June 30, 1998, respectively. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $1.0 million, $4.0 million and $11.4 million representing 1.2%, 1.8% and 2.5% of Northern Indiana's total gas costs for the three-month, six-month and twelve-month periods ended June 30, 1997, respectively. Northern Indiana subleases a portion of office facilities to affiliated companies for a monthly fee, which includes operating expenses, based on space utilization. HEDGING ACTIVITIES. Northern Indiana uses commodity futures and option contracts to hedge the impact of natural gas price fluctuations related to its business activities. Gains and losses on these commodity-based derivative financial instruments are deferred and recognized in income concurrent with the related purchases and sales of natural gas. As of June 30, 1998, Northern Indiana had open futures and option contracts representing hedges of natural gas sales of 4.5 billion cubic feet (Bcf) and natural gas purchases of 8.0 Bcf. The net deferred gain on these commodity-based derivative financial instruments as of June 30, 1998 was not material. REGULATORY ASSETS. Northern Indiana's operations are subject to the regulation of the Commission and FERC. Accordingly, Northern Indiana's accounting policies are subject to the provisions of Statement of Financial Accounting Standards (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 June 30, 1998 and December 31, 1997, the regulatory assets identified below represent probable future revenue to Northern Indiana associated with certain incurred costs 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:
June 30, December 31, 1998 1997 ============= ============= (Dollars in thousands) Unamortized reacquisition premium on debt (Note 14) $ 44,694 $ 46,426 Unamortized R.M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation (See below) 64,437 66,546 Bailly scrubber carrying charges and deferred depreciation (See below) 9,413 9,880 Deferral of SFAS No. 106 expense not recovered (Note 7) 81,166 83,965 FERC Order No. 636 transition costs (Note 3) 23,985 28,744 Regulatory income tax asset, net (Note 5) 9,958 9,664 ------------- ------------- 233,653 245,225 Less: Current portion of regulatory assets 34,501 39,260 ------------- ------------- $ 199,152 $ 205,965 ============= =============
CARRYING CHARGES AND DEFERRED DEPRECIATION. Upon completion of R. M. Schahfer Units 17 and 18, Northern Indiana capitalized the carrying charges and deferred depreciation in accordance with orders of the Commission 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 Commission. 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. At January 1, 1996 a pre-tax rate of 5.5% for all construction was being used; effective January 1, 1997 the rate remained at 5.5% and effective January 1, 1998, the rate increased to 6.0%. INCOME TAXES. Deferred income taxes are recognized as costs in the rate-making process by the commissions having jurisdiction over the 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 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. (3) FERC ORDER NO. 636. Since December 1993, Northern Indiana has paid approximately $138 million of interstate pipeline transition costs to pipeline suppliers to reflect the impact of FERC Order No. 636. Northern Indiana expects that additional transition costs will not be significant. The Commission has approved the recovery of these FERC-allowed transition costs on a volumetric basis from sales and transportation customers. Regulatory assets, in amounts corresponding to the costs recorded but not yet collected, have been recorded to reflect the ultimate recovery of these costs. (4) ENVIRONMENTAL MATTERS: Northern Indiana has an ongoing program to remain aware of laws and regulations involved with hazardous waste and other environmental matters. It is Northern Indiana's intent to continue to evaluate its facilities and properties with respect to these rules and identify any sites that would require corrective action. Northern Indiana has recorded a reserve of approximately $17 million to cover probable corrective actions as of June 30, 1998; however, environmental regulations and remediation techniques are subject to future change. The ultimate cost could be significant, depending on the extent of corrective actions required. Based upon investigations and management's understanding of current laws and regulations, Northern Indiana believes that any corrective actions required, after consideration of insurance coverages and contributions from other potentially responsible parties, will not have a significant impact on the results of operations or financial position of Northern Indiana. Because of major investments made in modern environmental control facilities and the use of low-sulfur coal, all of Northern Indiana's electric production facilities now comply with the sulfur dioxide limitations contained in the acid deposition provisions of the Clean Air Act Amendments of 1990 (CAAA). Reflecting this compliance, on December 31, 1997, the Indiana Department of Environmental Management (IDEM) issued the Phase II Acid Rain permits for all four of Northern Indiana's electric generating stations. As discussed below, however, other provisions of the CAAA impose additional requirements on Northern Indiana. On December 19, 1996, the Environmental Protection Agency (EPA) promulgated rules for Phase II of the Acid Rain nitrogen oxides (N0x)reduction program. For Phase I, during the summer of 1997, the EPA formally approved the Acid Rain Early Election permits for the pulverized coal units at D. H. Mitchell and R. M. Schahfer stations. The permits establish the Phase I limits for the NOx emissions on these units until 2007. On December 23, 1997, Northern Indiana submitted an Acid Rain Phase II NOx Compliance Plan to IDEM which included additional controls for two cyclone fired boilers and a plan for emission averaging to achieve the NOx limits for the system by 2000. Northern Indiana plans a project to demonstrate a cost effective combustion control technique on the Unit 12 cyclone fired boiler at Michigan City during 1998. The CAAA also contain other provisions that could lead to limitations on emissions of hazardous air pollutants which may require significant capital expenditures for control of these emissions. Northern Indiana cannot predict what these requirements will be or the costs of complying with these potential requirements. On October 10, 1997, and supplemented on May 11, 1998, the EPA proposed a rule under the nonattainment provisions of the CAAA to reduce emissions transported across state boundaries that allegedly are contributing to nonattainment of the one hour ozone standard in downwind states. Because N0x, along with other factors, contributes to ozone formation, the EPA proposed significant NOx reductions for 22 states, including Indiana, to address the ozone transport issue. These proposals, and any resulting NOx emission limitations arise under different provisions of the CAAA than the Acid Rain NOx program and can result in additional, more restrictive emissions limitations than are imposed under the Acid Rain Program. The EPA has encouraged states to achieve the reductions by requiring controls on electric utilities and large boilers. Northern Indiana is evaluating the EPA's proposal and evaluating potential requirements that could result from any final rule. The EPA issued final rules on July 18, 1997 revising the National Ambient Air Quality Standards for ozone and particulate matter. The revised standards begin a regulatory process that may lead to reductions in particulate, NOx emissions and possibly sulfur dioxide emissions from many sources (including Northern Indiana's coal-fired boilers at its generating stations) beyond current CAAA requirements. Northern Indiana cannot predict the costs of complying with future control requirements to meet these new standards. Northern Indiana will continue to closely monitor developments in this area and anticipates the exact nature of the impact of the new standards on its operations will not be known for some time. The EPA has notified Northern Indiana that it is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and may be required to share in the cost of cleanup of several waste disposal sites identified by the EPA. The sites are in various stages of investigation, analysis and remediation. At each of the sites, Northern Indiana is one of several PRPs, and it is expected that remedial costs, as provided under CERCLA, will be shared among them. At some sites Northern Indiana and/or the other named PRPs are presently working with the EPA to clean up the sites and avoid the imposition of fines or added costs. In December 1997, at the Summit on Climate Change in Kyoto, Japan, 159 nations formally agreed to targets reducing worldwide levels of greenhouse gases. If the U.S. Senate ratifies the agreement, the Kyoto Protocol would impose an obligation on the United States to reduce its emissions of greenhouse gas to a level seven percent below 1990 levels during the period 2008 to 2012. The impact of this agreement on Northern Indiana is uncertain. Northern Indiana, as a charter member of the Department of Energy's Climate Challenge Program, the electric industries' voluntary reduction effort, has already implemented over 21 projects to voluntarily reduce greenhouse gas emissions. Northern Indiana continues to investigate methods to address reduction in carbon dioxide emissions and will monitor the development of U.S. climate change policy. Northern Indiana has instituted a program to investigate former manufactured-gas plants where it is the current or former owner. Northern Indiana has identified twenty-four of these sites and made visual inspections of these sites. Initial samplings have been conducted at fifteen sites. Follow-up investigations have been conducted at eight sites and remedial measures have been selected at five sites. Northern Indiana will continue its program to assess and cleanup sites. During the course of various investigations, Northern Indiana has identified impacts to soil, groundwater, sediment and surface water from former manufactured-gas plants. At three sites where residues were noted seeping into rivers, Northern Indiana notified the IDEM and the EPA and immediately took steps to contain the material. Northern Indiana has worked with IDEM or the EPA on investigation or remedial activities at several sites. Three of the sites have been enrolled in the IDEM Voluntary Remediation Program (VRP). The goal of placing these sites in the VRP is to obtain IDEM approval of the selection and implementation of whatever remedial measures, if any, may be required. Northern Indiana anticipates placing additional sites in the VRP after remedial measures have been selected. Northern Indiana and Indiana Gas Company, Inc. (Indiana Gas) have entered into an agreement covering cost sharing and management of investigation and remediation programs at five former manufactured-gas plant sites at which both companies or their predecessors were former operators or owners. One of these sites is the Lafayette site which Indiana Gas had previously notified Northern Indiana is being investigated and remediated pursuant to an administrative order with IDEM. Northern Indiana also notified Cinergy Services, Inc. (Cinergy) (formerly PSI Energy, Inc.) that it was a former owner or operator of seven former manufactured-gas plants at which Northern Indiana had conducted or was planning investigation or remediation activities. In December 1996, Northern Indiana sent a written demand to Cinergy related to one of these sites, Goshen. Northern Indiana demanded that Cinergy pay Northern Indiana for costs Northern Indiana has already incurred and to be incurred to implement the needed remedy at the Goshen site. In August 1997, Northern Indiana filed suit in federal court against Cinergy seeking recovery of those costs. In 1994, Northern Indiana approached various companies that provided insurance coverage which Northern Indiana believes covers costs related to actions taken at former manufactured-gas plants. There has been litigation between Northern Indiana and various insurance companies over covered costs. Northern Indiana has filed claims in state court against various insurance companies, seeking coverage for costs associated with several former manufactured-gas plants and damages for alleged misconduct by some of the insurance companies. The state court action is now proceeding. Northern Indiana has received cash settlements from several of the insurance companies. The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects has been the subject of public, governmental and media attention. Recently, researchers from the National Cancer Institute and the Childhood Cancer Group reported they found no evidence that magnetic fields in homes increase the risk of childhood leukemia. This study follows an EMF report released in 1997 by the U.S. National Research Council of the National Academy of Sciences, which concluded, after examining more than 500 EMF studies spanning seventeen years, that, among other things, there was insufficient evidence to consider EMF a threat to human health. A new report in June 1998 from a National Institute of Health panel accepted the position that EMF should be regarded as a "possible human carcinogen." Further panel comments also stated that the risk "is possibly quite small compared to many other public health risks." (5) INCOME TAXES: Northern Indiana uses the liability method of accounting for income taxes under which deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial statement and tax bases of assets and liabilities. 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 Industries and currently pays to Industries its separate return tax liability as defined in the Tax Sharing Agreement between Industries and its subsidiaries. The components of the net deferred income tax liability at June 30, 1998 and December 31, 1997 are as follows:
June 30, December 31, 1998 1997 ============= ============= (Dollars in thousands) Deferred tax liabilities - Accelerated depreciation and other property differences $ 734,131 $ 729,153 AFUDC-equity 34,067 35,282 Adjustment clauses 9,241 33,829 Other regulatory assets 30,782 31,844 Reacquisition premium on debt 16,950 17,607 Deferred tax assets - Deferred investment tax credits (36,503) (37,869) Removal costs (150,307) (144,111) Other postretirement/postemployment benefits (46,077) (43,680) Other, net (13,444) (5,132) ------------- ------------- 578,840 616,923 Less: Deferred income taxes related to current assets and liabilities (14,294) 13,987 ------------- ------------- Deferred income taxes - noncurrent $ 593,134 $ 602,936 ============= =============
Federal and state income taxes as set forth in the Consolidated Statement of Income are comprised of the following:
Three Months Six Months Ended June 30, Ended June 30, -------------------- -------------------- 1998 1997 1998 1997 ========= ========= ========= ========= (Dollars in thousands) Current income taxes - Federal $ 32,618 $ 35,675 $ 88,747 $ 76,420 State 4,905 5,187 13,141 11,258 --------- --------- --------- --------- 37,523 40,862 101,888 87,678 --------- --------- --------- --------- Deferred income taxes, net - Federal (12,319) (19,591) (36,967) (27,042) State (988) (1,579) (3,006) (2,143) --------- --------- --------- --------- (13,307) (21,170) (39,973) (29,185) --------- --------- --------- --------- Deferred investment tax credits, net (1,782) (1,793) (3,564) (3,587) --------- --------- --------- --------- Total utility operating income taxes 22,434 17,899 58,351 54,906 Income tax applicable to non- operating activities and income of subsidiaries (827) (618) (1,232) (871) --------- --------- --------- --------- Total income taxes $ 21,607 $ 17,281 $ 57,119 $ 54,035 ========= ========= ========= ========= Twelve Months Ended June 30, -------------------- 1998 1997 ========= ========= (Dollars in thousands) Current income taxes - Federal $ 121,229 $ 114,067 State 18,699 17,221 --------- --------- 139,928 131,288 --------- --------- Deferred income taxes, net - Federal (17,923) (14,828) State (1,279) (974) --------- --------- (19,202) (15,802) --------- --------- Deferred investment tax credits, net (7,182) (7,593) --------- --------- Total utility operating income taxes 113,544 107,893 Income tax applicable to non- operating activities and income of subsidiaries (3,645) (1,086) --------- --------- Total income taxes $ 109,899 $ 106,807 ========= =========
A reconciliation of total tax expense to an amount computed by applying the statutory federal income tax rate to pre-tax income is as follows:
Three Months Six Months Ended June 30, Ended June 30, -------------------- -------------------- 1998 1997 1998 1997 ========= ========= ========= ========= (Dollars in thousands) Net income $ 39,802 $ 31,728 $ 105,576 $ 99,060 Add-Income taxes 21,607 17,281 57,119 54,035 --------- --------- --------- --------- Net income before income taxes $ 61,409 $ 49,009 $ 162,695 $ 153,095 ========= ========= ========= ========= Amount derived by multiplying pre-tax income by the statutory rate $ 21,493 $ 17,153 $ 56,943 $ 53,583 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 998 1,044 1,996 2,088 Amortization of deferred investment tax credits (1,782) (1,793) (3,564) (3,587) State income taxes, net of federal income tax benefit 2,133 1,747 5,443 5,111 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (1,271) (1,518) (2,542) (3,036) Other, net 36 648 (1,157) (124) --------- --------- --------- --------- Total income taxes $ 21,607 $ 17,281 $ 57,119 $ 54,035 ========= ========= ========= ========= Twelve Months, Ended June 30, -------------------- 1998 1997 ========= ========= (Dollars in thousands) Net income $ 203,136 $ 198,018 Add-Income taxes 109,899 106,807 --------- --------- Net income before income taxes $ 313,035 $ 304,825 ========= ========= Amount derived by multiplying pre-tax income by the statutory rate $ 109,562 $ 106,689 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 3,980 4,696 Amortization of deferred investment tax credits (7,182) (7,593) State income taxes, net of federal income tax benefit 10,579 10,186 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (3,569) (6,861) Other, net (3,471) (310) --------- --------- Total income taxes $ 109,899 $ 106,807 ========= =========
(6) PENSION PLANS: Industries 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 1997 and 1996 is as follows:
1997 1996 ========= ========= (Dollars in thousands) Benefit obligation at beginning $ 732,870 $ 749,869 of year (January 1,) Service cost 13,325 15,877 Interest cost 55,920 52,787 Plan amendments 25,096 0 Actuarial (gain)loss 67,975 (39,435) Benefits paid (52,137) (46,228) --------- --------- Benefit obligation at end of the year (December 31,) $ 843,049 $ 732,870 ========= =========
The change in the fair value of the plan's assets for years 1997 and 1996 is as follows:
1997 1996 ========= ========= (Dollars in thousands) Fair value of plan assets at $ 782,162 $ 697,919 beginning of year January 1,) Actual return on plan's assets 122,537 86,622 Employer contributions 44,388 43,850 Benefits paid (52,137) (46,229) --------- --------- Plan assets at fair value at end of the year (December 31,) $ 896,950 $ 782,162 ========= =========
The plan's funded status as of January 1, 1998 and January 1, 1997 is as follows:
January 1, January 1, 1998 1997 ========= ========= (Dollars in thousands) Plan assets in excess of $ 53,901 $ 49,292 benefit obligation Unrecognized net actuarial loss (51,191) (67,111) Unrecognized prior service cost 45,502 23,736 Unrecognized transition amount being recognized over seventeen years 32,930 38,418 --------- --------- Prepaid pension costs $ 81,142 $ 44,335 ========= =========
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. Discount rates of 7.00% and 7.75% and rates of increase in compensation levels of 4.50% and 5.5% were used to determine the benefit obligation at January 1, 1998 and 1997, respectively. The increase in benefit obligation at January 1, 1998 was impacted by the decrease in the discount rate from 7.75% to 7.00%. Prepaid pension costs were $98.3 million as of June 30, 1998. The following items are the components of provisions for pensions for the three-month, six-month and twelve-month periods ended June 30, 1998 and June 30, 1997:
Three Months Six Months Twelve Months Ended Ended Ended June 30, June 30, June 30, ------------------ ------------------ ------------------ 1998 1997 1998 1997 1998 1997 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Service costs $ 5,997 $ 4,466 $ 11,993 $ 8,932 $ 16,386 $ 14,466 Interest costs 21,073 16,325 42,146 32,651 65,416 53,690 Expected return on plan assets (27,971) (20,308) (55,941) (40,616) (85,807) (89,480) Amortization of transition obligation 1,902 1,604 3,804 3,208 6,084 5,400 Amortization of prior service cost 1,525 913 3,050 1,825 4,554 26,583 -------- -------- -------- -------- -------- -------- $ 2,526 $ 3,000 $ 5,052 $ 6,000 $ 6,633 $ 10,659 ======== ======== ======== ======== ======== ========
Assumptions used in the valuation and determination of 1998 and 1997 pension expense were as follows:
1998 1997 ===== ===== Discount rate 7.00% 7.75% Rate of increase in compensation levels 4.50% 5.50% Expected long-term rate of return on assets 9.00% 9.00%
Plan assets are invested primarily in common stocks, bonds and notes. On July 9, 1998, a substantial portion of the plan's domestic equity investments were hedged against movements in the S&P 500 Index. The hedge will expire on December 31, 1998. (7) POSTRETIREMENT BENEFITS: Northern Indiana provides certain health care and life insurance benefits for retired employees. Substantially all of Northern Indiana's 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. Northern Indiana's rate-making has historically included the cost of providing these benefits based on the related insurance premiums. On December 30, 1992, the Commission authorized the accrual method of accounting for postretirement benefits for rate-making purposes consistent with SFAS No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions," and authorized the deferral of the differences between the net periodic postretirement benefit costs and the insurance premiums paid for such benefits as a regulatory asset. On June 11, 1997, the Commission issued an order approving the inclusion of accrual-based postretirement benefit costs in the rate-making process to be effective February 1, 1997 for electric rates and March 1, 1997 for gas rates. These costs include an amortization of the existing regulatory asset consistent with the remaining amortization period for the transition obligation. Northern Indiana discontinued its cost deferral and began amortizing its regulatory asset concurrent with these dates. The following table sets forth the plan's change in accumulated postretirement benefit obligation (APBO) for the years 1997 and 1996:
1997 1996 ========= ========= (Dollars in thousands) Accumulated postretirement $ 194,937 $ 253,157 benefit obligation at beginning of year (January 1,) Service cost 3,068 5,853 Interest cost 14,523 17,973 Plan amendments 4,015 (9,607) Actuarial (gain) (12,534) (66,112) Benefits paid (9,006) (6,327) --------- --------- Accumulated postretirement benefit obligation at end of the year (December 31,) $ 195,003 $ 194,937 ========= =========
The change in the fair value of the plan's assets for the years 1997 and 1996 is as follows:
1997 1996 ========= ========= (Dollars in thousands) Fair value of plan assets at $ 0 $ 0 beginning of year (January 1,) Employer contributions 11,406 6,327 Benefits paid (9,006) (6,327) --------- --------- Plan assets at fair value at end of the year (December 31,) $ 2,400 $ 0 ========= =========
Following is the funded status for postretirement benefits as of January 1, 1998 and January 1, 1997:
January 1, January 1, 1998 1997 ========= ========= (Dollars in thousands) Funded status $(192,603) $(194,937) Unrecognized actuarial gain (99,262) (88,784) Unrecognized prior service cost 3,737 0 Unrecognized transition amount being recognized over twenty years 161,214 171,962 --------- --------- Accrued liability for postretirement benefits $(126,914) $(111,759) ========= =========
A discount rate of 7.00%, a pre-Medicare medical trend rate of 8% declining to a long-term rate of 5%, a discount rate of 7.75% and a pre-Medicare medical trend rate of 9% declining to a long-term rate of 6%, were used to determine the APBO at January 1, 1998 and 1997, respectively. The change in the APBO reflects the decrease in the discount rate from 7.75% to 7.00%, substantially offset by favorable claim experience and reduction in the medical trend rate assumption. The accrued liability for postretirement benefits was $130.5 million at June 30, 1998. Net periodic postretirement benefits costs, before consideration of the rate-making discussed previously, for the three-month, six-month and twelve-month periods ended June 30, 1998 and June 30, 1997 include the following components:
Three Months Six Months Twelve Months Ended Ended Ended June 30, June 30, June 30, ---------------- ---------------- ---------------- 1998 1997 1998 1997 1998 1997 ======= ======= ======= ======= ======= ======= (Dollars in thousands) Service costs $ 1,069 $ 941 $ 1,806 $ 1,858 $ 3,016 $ 5,007 Interest costs 3,650 4,376 7,300 8,752 13,071 16,778 Expected return on plan assets (50) 0 (100) 0 (100) 0 Amortization of transition obligation over twenty years 2,675 2,702 5,350 5,404 10,693 10,686 Amortization of prior service cost 75 0 150 0 429 0 Amortization of actuarial (gain) (1,375) (993) (2,750) (1,986) (6,542) (1,326) ------- ------- ------- ------- ------- ------- $ 6,044 $ 7,026 $11,756 $14,028 $20,567 $31,145 ======= ======= ======= ======= ======= =======
Assumptions used in the valuation and determination of 1998 and 1997 net periodic postretirement benefit costs were as follows:
1998 1997 ===== ===== Discount rate 7.00% 7.75% Rate of increase in compensation levels 4.50% 5.50%
The pre-Medicare medical trend rates used for 1998 and 1997 were 8% declining to a long-term rate of 5% and 9% declining to a long-term rate of 6%, respectively. The effect of a 1% increase in the assumed health care cost trend rates for each future year would increase the accumulated postretirement benefit obligation at January 1, 1998 by approximately $23.2 million, and increase the aggregate of the service and interest cost components of plan costs by approximately $0.7 million and $1.3 million for the three-month and six-month periods ended June 30, 1998. The effect of a 1% decrease in the assumed health care cost trend rates for each future year would decrease the accumulated postretirement benefit obligation at January 1, 1998 by approximately $19.2 million, and decrease the aggregate of the service and interest cost components of plan costs by approximately $0.5 million and $1.0 million for the three-month and six-month periods ended June 30, 1998. Amounts disclosed above could be changed significantly in the future by changes in health care costs, work force demographics, interest rates, or plan changes. (8) 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 9 sets forth the preferred stocks which are redeemable solely at the option of Northern Indiana and Note 10 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 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. (9) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF NORTHERN INDIANA, OUTSTANDING AT JUNE 30, 1998 AND DECEMBER 31, 1997 (SEE NOTE 8):
Redemption Price at June 30, December 31, June 30, 1998 1997 1998 ============ ============ ============ (Dollars in thousands) Cumulative preferred stock - $100 par value - 4-1/4% series - 209,057 and 209,118 shares outstanding, respectively $ 20,906 $ 20,912 $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 June 30, 1998), Series A (stated value $50 per share) 473,285 shares outstanding 23,664 23,664 $50.00 ------------ ------------ $ 81,117 $ 81,123 ============ ============
During the period July 1, 1996 to June 30, 1998 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. (10) REDEEMABLE PREFERRED STOCKS OUTSTANDING AT JUNE 30, 1998 AND DECEMBER 31, 1997 (SEE NOTE 8): Preferred stocks subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana are as follows:
June 30, December 31, 1998 1997 ============ ============ (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 - 50,000 and 62,500 shares outstanding, respectively, excluding sinking fund payments due within one year $ 5,000 $ 6,250 7-3/4% series - 38,906 shares outstanding, excluding sinking fund payments due within one year 3,891 3,891 8.35% series - 57,000 shares outstanding, excluding sinking fund payments due within one year 5,700 5,700 Cumulative preferred stock - no par value - 6.50% series - 430,000 shares outstanding 43,000 43,000 ------------ ------------ $ 57,591 $ 58,841 ============ ============
The redemption prices at June 30, 1998, 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, are as follows:
Sinking Fund Or Mandatory Redemption Series Redemption Price Per Share Provisions ====== ========================== ============================= Cumulative preferred stock - $100 par value - 8.85% $101.11, reduced periodically 12,500 shares on or before April 1. 8.35% $103.69, reduced periodically 3,000 shares on or before July 1; increasing to 6,000 shares beginning in 2004; noncumulative option to double amount each year. 7-3/4% $104.23, reduced periodically 2,777 shares on or before December 1; noncumulative option to double amount each year. Cumulative preferred stock - no par value - 6.50% $100.00 on October 14, 2002 430,000 shares on October 14, 2002.
Sinking fund requirements with respect to redeemable preferred stocks outstanding at June 30, 1998 for each of the twelve-month periods subsequent to June 30, 1999 are as follows:
Twelve Months Ended June 30,* ================================== 2000 $1,827,700 2001 $1,827,700 2002 $1,827,700 2003 $1,827,700 * Table does not reflect redemptions made after June 30, 1998.
(11) 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 earned surplus or net profits of Northern Indiana. At June 30, 1998, Northern Indiana had approximately $152.7 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. (12) COMMON SHARES: Effective with the exchange of common shares on March 3, 1988, all of Northern Indiana's common shares are owned by Industries. On December 16, 1997, the Industries Board of Directors authorized a two-for-one stock split of Industries' common stock. The stock split was paid February 20, 1998, to shareholders of record at the close of business on January 30, 1998. All references to number of common shares reported for the period including per share amounts and stock option data of Industries' common stock reflect the two-for-one stock split as if it had occurred at the beginning of the earliest period. (13) LONG-TERM INCENTIVE PLAN: Industries 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 of Industries' common shares to key employees through 1998 and 2004, respectively. At June 30, 1998, there were 3,847,500 shares reserved for future awards under the 1994 Plan. The 1994 Plan permits 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 June 30, 1998. Under this Plan, the exercise price of each option equals the market price of Industries' stock on the date of grant. Each option has a maximum term of ten years and vests one year from the date of grant. The stock appreciation rights (SARs) may be exercised only in tandem with stock options on a one-for-one basis and are payable in cash, Industries' common shares, or a combination thereof. 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 is variable from 0% to 200% of the number awarded, subject to specific earnings per share and stock appreciation goals. Restrictions on shares awarded in 1997 and 1998 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 534,666 and 542,666 restricted shares outstanding at June 30, 1998 and December 31, 1997, 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 non-qualified stock options. The compensation cost that has been charged against income for restricted stock awards was $0.2, $0.4 and $0.7 million for the three-month, six-month and twelve-month periods ending June 30, 1998, respectively. Had compensation cost for non- ualified stock options been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," Northern Indiana's net income would have been reduced to the following pro forma amounts:
Three Months Six Months Twelve Months Ended Ended Ended June 30, June 30, June 30, ------------------ ------------------ ------------------- 1998 1997 1998 1997 1998 1997 ======== ======== ======== ======== ======== ======== (Dollars in thousands) Net Income: As reported $ 39,802 $ 31,728 $105,576 $ 99,060 $203,136 $198,018 Pro forma $ 39,588 $ 31,521 $105,148 $ 98,646 $202,282 $197,228
The fair value of each option granted 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 three-month, six-month and twelve-month periods ended June 30, 1998 and June 30, 1997: risk-free interest rate of 6.29% and 6.39%, respectively; expected dividend yield per share of $0.87 and $0.84, respectively; expected option term of five and one-quarter years and five years, respectively; and expected volatilities of 12.7% and 13.2%, respectively. The weighted average fair value of options granted to all plan participants was $2.66 and $2.50 for the twelve-month period ended June 30, 1998 and June 30, 1997, respectively. There were 533,600 and 556,600 non-qualified stock options granted to all plan participants for the twelve-month periods ended June 30, 1998 and June 30, 1997, respectively. (14) LONG-TERM DEBT: At June 30, 1998 and December 31, 1997, the long-term debt of Northern Indiana, excluding amounts due within one year, issued and not retired or canceled was as follows:
AMOUNT OUTSTANDING --------------------------- June 30, December 31, 1998 1997 ============ ============ (Dollars in thousands) First mortgage bonds - Series T, 7-1/2%, due April 1, 2002 $ 39,500 $ 39,500 Series NN, 7.10%, due July 1, 2017 55,000 55,000 ------------ ------------ Total 94,500 94,500 ------------ ------------ Pollution control notes and bonds - Series A Note - City of Michigan City, 5.70% due October 1, 2003 18,000 18,000 Series 1988 Bonds - Jasper County - Series A, B and C - 3.67% weighted average at June 30, 1998, due November 1, 2016 130,000 130,000 Series 1988 Bonds - Jasper County - Series D - 3.60% weighted average at June 30, 1998, due November 1, 2007 24,000 24,000 Series 1994 Bonds - Jasper County - Series A - 3.80% at June 30, 1998, due August 1, 2010 10,000 10,000 Series 1994 Bonds - Jasper County - Series B - 3.80% at June 30, 1998, due June 1, 2013 18,000 18,000 Series 1994 Bonds - Jasper County - Series C - 3.80% at June 30, 1998, due April 1, 2019 41,000 41,000 ------------ ------------ Total 241,000 241,000 ------------ ------------ Medium-term notes - Interest rates between 6.10% and 7.69% with a weighted average interest rate of 7.00% and various maturities between March 20, 2000 and August 4, 2027 748,025 748,025 ------------ ------------ Unamortized premium and discount on long-term debt, net (3,791) (4,029) ------------ ------------ Total long-term debt excluding amounts due in one year $ 1,079,734 $ 1,079,496 ============ ============
The sinking fund requirements of long-term debt outstanding at June 30, 1998 (including the maturity of first mortgage bonds: Series T, 7-1/2%, due April 1, 2002; and medium-term notes due from March 20, 2000 to April 21, 2003) for each of the twelve-month periods subsequent to June 30, 1999 are as follows:
Twelve Months Ended June 30, ================================= 2000 $157,000,000 2001 $ 3,000,000 2002 $ 73,500,000 2003 $ 58,500,000
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, securing the first mortgage bonds issued by Northern Indiana, constitutes a direct first mortgage lien upon substantially all property and franchises, other than expressly excepted property, owned by Northern Indiana. On May 28, 1997, Northern Indiana was authorized to issue and sell up to $217,692,000 of its Medium-Term Notes, Series E, with various maturities, for purposes of refinancing certain first mortgage bonds and medium-term notes. As of June 30, 1998, $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. (15) CURRENT PORTION OF LONG-TERM DEBT: At June 30, 1998 and December 31, 1997, Northern Indiana's current portion of long-term debt due within one year was as follows:
June 30, December 31, 1998 1997 ============ ============ (Dollars in thousands) First mortgage bonds - Series P, 6-7/8% - due October 1, 1998 $ 14,509 $ 14,509 Medium-term notes - Interest rate of 5.83% and 5.95% with a weighted average interest rate of 5.86% and various maturities between April 6, 1998 and April 13, 1998 0 35,000 Sinking funds due within one year 1,500 1,500 ------------ ------------ Total current portion of long-term debt $ 16,009 $ 51,009 ============ ============
(16) SHORT-TERM BORROWINGS: Northern Indiana uses commercial paper to fund short-term working capital requirements. Northern Indiana has a $250 million revolving Credit Agreement with several banks which terminates August 19, 1999. As of June 30, 1998, there were no borrowings outstanding under this agreement. In addition, Northern Indiana has $14.2 million in lines of credit which run to May 31, 1999. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. Northern Indiana has agreed to compensate the participating banks with arrangements that vary from no commitment fees to a combination of fees which are mutually satisfactory to both parties. As of June 30, 1998, there were no borrowings under these lines of credit. The Credit Agreement and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $273.5 million of money market lines of credit. As of June 30, 1998 and December 31, 1997, $41.2 million and $47.5 million, respectively, were outstanding under these lines of credit. Northern Indiana has a $50 million uncommitted finance facility. At June 30, 1998, there were no borrowings outstanding under this facility. At June 30, 1998 and December 31, 1997, Northern Indiana's short- term borrowings were as follows:
June 30, December 31, 1998 1997 ============ ============ (Dollars in thousands) Commercial paper - Weighted average interest rate of 5.66% at June 30, 1998 $ 71,100 $ 71,500 Notes payable - Issued at interest rates between 5.65% and 6.50 % with a weighted average interest rate of 5.83% and various maturities between July 2, 1998 and August 13, 1998 41,200 47,500 ------------ ------------ Total short-term borrowings $ 112,300 $ 119,000 ============ ============
(17) OPERATING LEASES: On April 1, 1990, Northern Indiana entered into a twenty-year agreement for the rental of office facilities from NIPSCO Development Company, Inc., a subsidiary of Industries, 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 June 30, 1998:
Twelve Months Ended June 30, ============================= (Dollars in thousands) 1999 $ 4,389 2000 3,055 2001 3,055 2002 3,055 2003 3,054 Later years 31,616 -------- Total minimum payments required $ 48,224 ========
The consolidated financial statements include rental expense for all operating leases as follows:
June 30, June 30, 1998 1997 ============ ============ (Dollars in thousands) Three months ended $ 2,331 $ 1,937 Six months ended $ 4,479 $ 4,027 Twelve months ended $ 8,127 $ 8,384
(18) COMMITMENTS: Northern Indiana estimates that approximately $762 million will be expended for construction purposes for the period from January 1, 1998 to December 31, 2002. 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 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. During the fourth quarter of 1995, Northern Indiana entered into a ten year agreement with IBM to perform all data center, application development and maintenance, and desktop management. Annual fees under this agreement are estimated at $20.6 million. (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 that value: Cash and cash equivalents: The carrying amount approximates fair value because of the short maturity of those instruments. Investments: Investments are carried at cost, which approximates market value. Long-term debt/Preferred stock: The fair value of long-term debt and preferred stock is estimated based on the quoted market prices for the same or similar issues or on the rates offered to Northern Indiana 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 Northern Indiana's financial instruments (excluding derivatives) are as follows:
June 30, 1998 December 31, 1997 ---------------------- ---------------------- Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value ========== ========== ========== ========== (Dollars in thousands) Cash and cash equivalents $ 14,831 $ 14,831 $ 9,800 $ 9,800 Investments $ 256 $ 256 $ 256 $ 256 Long-term debt (including current portion) $1,095,743 $1,122,922 $1,130,505 $1,128,851 Preferred stock $ 140,536 $ 133,136 $ 141,792 $ 135,317
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 19% of electric revenue for the twelve months ended June 30, 1998 as compared to 5% and 22%, respectively, for the twelve months ended June 30, 1997. (21) BUSINESS SEGMENTS: Northern Indiana adopted SFAS No. 131 "Disclosures about Segments of an Enterprise and Related Information" during the first quarter of 1998. SFAS No. 131 established standards for reporting information about operating segments in financial statements and disclosures about products and services, and geographic areas. Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. 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, non-utility revenues and expenses, and other corporate assets. Northern Indiana's reportable segments are operations that are managed separately and meet the quantitative thresholds required by SFAS No. 131. Revenues for each of Northern Indiana's segments are attributable to customers in the United States. The following tables provide information about Northern Indiana's business segments. Northern Indiana uses income before interest and income taxes as its primary measurement for each of the reported segments. Adjustments have been made to the segment information to arrive at information included in the results of operations and financial position of Northern Indiana. 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 June 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $ 98,859 $ 271,611 $ 0 $ 0 $ 370,470 Other income (deductions)$ 171 $ 85 $ (1,502) $ (22) $ (1,268) Depreciation and amortization $ 17,845 $ 38,955 $ 0 $ 0 $ 56,800 Income before interest and utility income taxes $ (3,968) $ 86,964 $ (1,475) $ (49) $ 81,472 Assets $740,292 $2,481,851 $344,949 $ 0 $3,567,092 For the Three Months Adjust- Ended June 30, 1997 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $108,541 $ 244,054 $ 0 $ 0 $ 352,595 Other income (deductions)$ 108 $ 44 $ (1,147) $ (41) $ (1,036) Depreciation and amortization $ 17,414 $ 38,823 $ 0 $ 0 $ 56,237 Income before interest and utility income taxes $ 1,766 $ 68,854 $ (1,155) $ (33) $ 69,432 Assets $763,785 $2,549,642 $317,399 $ 0 $3,630,826 For the Six Months Adjust- Ended June 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $317,589 $ 511,797 $ 0 $ 0 $ 829,386 Other income (deductions)$ 753 $ 170 $ (2,746) $ (53) $ (1,876) Depreciation and amortization $ 35,598 $ 77,722 $ 0 $ 0 $ 113,320 Income before interest and utility income taxes $ 41,341 $ 164,373 $ (2,783) $ (16) $ 202,915 Assets $740,292 $2,481,851 $344,949 $ 0 $3,567,092 For the Six Months Adjust- Ended June 30, 1997 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $414,215 $ 489,878 $ 0 $ 0 $ 904,093 Other income (deductions)$ 574 $ 241 $ (1,926) $ (334) $ (1,445) Depreciation and amortization $ 34,384 $ 77,105 $ 0 $ 0 $ 111,489 Income before interest and utility income taxes $ 56,856 $ 139,286 $ (1,961) $ (299) $ 193,882 Assets $763,785 $2,549,642 $317,399 $ 0 $3,630,826 For the Twelve Months Adjust- Ended June 30, 1998 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $638,673 $1,039,002 $ 0 $ 0 $1,677,675 Other income (deductions)$ 1,002 $ 547 $ (5,515) $ (124) $ (4,090) Depreciation and amortization $ 70,395 $ 154,461 $ 0 $ 0 $ 224,856 Income before interest and utility income taxes $ 64,740 $ 337,492 $ (5,603) $ (36) $ 396,593 Assets $740,292 $2,481,851 $344,949 $ 0 $3,567,092 For the Twelve Months Adjust- Ended June 30, 1997 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $735,707 $1,019,453 $ 0 $ 0 $1,755,160 Other income (deductions)$ 1,037 $ 1,029 $ (553) $ (771) $ 742 Depreciation and amortization $ 67,022 $ 150,048 $ 0 $ 0 $ 217,070 Income before interest and utility income taxes $ 81,599 $ 307,611 $ (523) $ (801) $ 387,886 Assets $763,785 $2,549,642 $317,399 $ 0 $3,630,826
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS REVENUES - Total operating revenues for the twelve months ended June 30,1998 decreased $77.5 million as compared to the twelve months ended June 30, 1997. Gas revenues decreased $97.0 million and electric revenues increased $19.5 million as compared to the same period in 1997. The decrease in gas revenues was mainly due to decreased sales to residential and commercial customers reflecting unusually warm weather during the first quarter of 1998, decreased industrial sales, decreased gas transition costs and decreased gas cost per dekatherm (dth), partially offset by increased wholesale sales and increased deliveries of gas transported for others. The increase in electric revenues was mainly due to increased sales to residential and commercial customers due to warmer weather during the second quarter of 1998 and increased fuel costs per kilowatt-hour (kwh), partially offset by decreased sales to industrial customers. Total operating revenues for the six months ended June 30, 1998 decreased $74.7 million as compared to the six months ended June 30, 1997. Gas revenues decreased $96.6 million and electric revenues increased $21.9 million. The decrease in gas revenues resulted from decreased sales to residential and commercial customers due to warmer weather during the period, decreased sales to industrial customers, decreased gas cost per dth and decreased transition costs, partially offset by increased wholesale sales and increased deliveries of gas transported for others. Electric revenues increased $21.9 million due to increased sales to residential and commercial customers as a result of warmer weather during the second quarter of 1998 and increased wholesale transactions, partially offset by decreased industrial sales and decreased fuel cost per kwh. Total operating revenues for the three months ended June 30, 1998 increased $17.9 million as compared to the three months ended June 30, 1997. Gas revenues decreased $9.7 million and electric revenues increased $27.6 million. The decrease in gas revenues was mainly attributable to decreased sales to residential and commercial customers as a result of warmer weather during the second quarter of 1998, decreased sales to industrial customers and decreased gas transition costs, partially offset by increased sales to wholesale customers and increased gas costs per dth. The increase in electric revenues was mainly attributable to increased sales to residential and commercial customers due to warmer weather, increased sales to industrial customers and increased wholesale transactions, partially offset by increased fuel cost per kwh. The basic steel industry accounted for 39% of natural gas delivered (including volumes transported) and 31% of electric sales during the twelve months ended June 30, 1998. The components of the variations in gas and electric revenues are shown in the following table:
Variations from Prior Periods --------------------------------- June 30, 1998 Compared to June 30, 1997 Three Six Twelve Months Months Months ========= ========= ========= (Dollars in thousands) Gas Revenue - Pass through of net changes in purchased gas costs, gas storage, and storage transportation costs $ 17,498 $ (27,565) $ (25,924) Gas transition costs (5,860) (12,962) (18,362) Changes in sales levels (21,598) (57,220) (54,455) Gas transported 278 1,121 1,707 --------- --------- --------- Gas Revenue Change $ (9,682) $ (96,626) $ (97,034) --------- --------- --------- Electric Revenue - Pass through of net changes in fuel costs $ 3,899 $ (1,061) $ 2,540 Changes in sales levels 23,658 22,980 17,009 --------- --------- --------- Electric Revenue Change $ 27,557 $ 21,919 $ 19,549 --------- --------- --------- Total Revenue Change $ 17,875 $ (74,707) $ (77,485) ========= ========= =========
See "Summary of Significant Accounting Policies - Gas Cost Adjustment Clause" in the Notes to Consolidated Financial Statements for a discussion of the gas cost incentive mechanism. Also, see Note 3 to Notes to Consolidated Financial Statements regarding FERC Order No. 636 transition costs. GAS COSTS - Gas costs decreased $0.4, $74.0 and $73.9 million for the three-month, six-month and twelve-month periods ended June 30, 1998, respectively. Gas costs decreased for the six-month and twelve-month periods due to decreased gas purchases, decreased gas costs per dth and decreased gas transition costs. The average cost of purchased gas for the three-month, six-month and twelve-month periods ended June 30, 1998, after adjustment for gas transition costs billed to transport customers, was $2.78, $2.59 and $2.87 per dth, respectively, as compared to $2.53, $3.03 and $3.08 per dth for the same periods in 1997. FUEL AND PURCHASED POWER - The cost of fuel for electric generation increased $10.8, $8.0 and $10.7 million for the three-month, six-month and twelve-month periods ended June 30, 1998, compared to 1997 periods, mainly as a result of increased production of electricity. Power purchased decreased $3.4 and $13.1 million for the six-month and twelve-month periods ended June 30, 1998, respectively, as a result of decreased bulk power purchases, partially offset by increased cost per megawatt-hour (mwh). Purchased power increased during the three-month period ended June 30, 1998 due to increased costs per mwh, partially offset by decreased power purchases. OPERATING MARGINS - Operating margins for the twelve months ended June 30,1998 decreased $1.2 million from the same period a year ago. The operating margin from gas deliveries decreased $23.2 million due to decreased sales to residential and commercial customers reflecting unusually warm weather during the first quarter of 1998 and decreased industrial sales, partially offset by increased sales to wholesale customers and increased deliveries of gas transported for others. Electric operating margin increased $22.0 million due to increased sales to residential and commercial customers and increased wholesale transactions, partially offset by decreased sales to industrial customers. Operating margins for the six months ended June 30, 1998 decreased $5.3 million from the same period a year ago. Gas operating margin decreased $22.6 million reflecting decreased residential and commercial sales due to warmer weather during the first half of 1998 and decreased industrial sales, partially offset by increased wholesale sales and increased deliveries of gas transported for others. Electric operating margin increased $17.3 million as a result of increased sales to residential and commercial customers due to warmer weather during the second quarter of 1998 and increased wholesale transactions, partially offset by decreased sales to industrial customers. Operating margins for the three months ended June 30, 1998 increased $5.6 million from the same period a year ago. Gas operating margin decreased $9.2 million due to decreased sales to residential and commercial customers reflecting unusually mild weather during the period and decreased industrial sales, partially offset by increased sales to wholesale customers and increased deliveries of gas transported for others. Electric operating margin increased $14.8 million as a result of increased sales to residential and commercial customers due to warmer weather, increased industrial sales and increased wholesale transactions. OPERATING EXPENSES AND TAXES - Operation expenses decreased $23.0 million for the twelve-month period ended June 30, 1998 mainly as a result of decreased marketing activity of $10.0 million, decreased environmental costs of $3.1 million and decreased insurance costs of $1.7 million. Operation expenses decreased $16.0 million for the six-month period mainly reflecting decreased employee costs of $7.7 million and decreased marketing activity of $5.6 million. Operation expenses decreased $8.3 million for the three-month period reflecting decreased employee related costs of $4.7 million and decreased marketing activity of $3.9 million. Maintenance expenses increased for the twelve-month period ended June 30, 1998 reflecting increased maintenance activity on the electric production facilities and the electric and gas distribution facilities. Maintenance expenses increased for the three and six-month periods ended June 30, 1998 mainly reflecting increased electric production maintenance activity. Depreciation and amortization expense increased $0.6, $1.8 and $7.8 million for the three-month, six-month and twelve-month periods ended June 30, 1998, respectively, resulting from plant additions, partially offset by a gain on disposition of utility plant in December 1996. OTHER INCOME (DEDUCTIONS) - Other Income (Deductions) decreased $4.8 million for the twelve-month period ended June 30, 1998 mainly due to a loss on disposition of property during the current twelve-month period compared to a gain of $3.6 million on the sale of Crescent Dunes Lakeshore property during the same period a year ago. INTEREST CHARGES - Interest charges decreased for the twelve-month period ended June 30, 1998 reflecting decreased short-term borrowings, partially offset by increased long-term debt outstanding during the period. See Notes to Consolidated Financial Statements for a discussion of accounting policies and transactions impacting this analysis. NET INCOME - Net income for the twelve months ended June 30, 1998 was $203.1 million compared to $198.0 million for the twelve months ended June 30, 1997. Net income for the six months ended June 30, 1998 was $105.6 million compared to $99.1 million for the six months ended June 30, 1997. Net income for the three months ended June 30, 1998 was $39.8 million compared to $31.7 million for the three months ended June 30, 1997. ENVIRONMENTAL MATTERS - Northern Indiana has an ongoing program to remain aware of laws and regulations involved with hazardous waste and other environmental matters. It is Northern Indiana's intent to continue to evaluate its facilities and properties with respect to these rules and identify any sites that would require corrective action. Northern Indiana has recorded a reserve of approximately $17 million to cover probable corrective actions as of June 30, 1998; however, environmental regulations and remediation techniques are subject to future change. The ultimate cost could be significant, depending on the extent of corrective actions required. Based upon investigations and management's understanding of current laws and regulations, Northern Indiana believes that any corrective actions required, after consideration of insurance coverages and contributions from other potentially responsible parties, will not have a significant impact on the results of operations or financial position of Northern Indiana. The Environmental Protection Agency (EPA) has notified Northern Indiana that it is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and may be required to share in the cost of cleanup of several waste disposal sites identified by the EPA. The sites are in various stages of investigation, analysis and remediation. At each of the sites, Northern Indiana is one of several PRPs, and it is expected that remedial costs, as provided under CERCLA, will be shared among them. At some sites, Northern Indiana and/or the other named PRPs are presently working with the EPA to clean up the sites and avoid the imposition of fines or added costs. Refer to Note 4 "Environmental Matters" for a more detailed discussion of the status of certain environmental issues. LIQUIDITY AND CAPITAL RESOURCES - Cash flow from operations has provided sufficient liquidity to meet current operating requirements. Because of the seasonal nature of the utility business and the construction program, Northern Indiana makes use of commercial paper intermittently as short-term financing. As of June 30, 1998 and December 31,1997, Northern Indiana had $71.1 million and $71.5 million in commercial paper outstanding, respectively. As of June 30, 1998, the weighted average interest rate of commercial paper was 5.66%. Northern Indiana has a $250 million revolving Credit Agreement with several banks which terminates August 19, 1999. As of June 30, 1998, there were no borrowings outstanding under this agreement. In addition, Northern Indiana has $14.2 million in lines of credit which run to May 31, 1999. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. Northern Indiana has agreed to compensate the participating banks with arrangements that vary from no commitment fees to a combination of fees which are mutually satisfactory to both parties. As of June 30, 1998, there were no borrowings under these lines of credit. The Credit Agreement and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $273.5 million of money market lines of credit. As of June 30, 1998, $41.2 million were outstanding under these lines of credit. Northern Indiana has a $50 million uncommitted finance facility. At June 30, 1998, there were no borrowings outstanding under this facility. During recent years, Northern Indiana has been able to finance its construction program with internally generated funds and expects to be able to meet future commitments through such funds. Northern Indiana does not expect the effects of inflation at current levels to have a significant impact on their results of operations, ability to contain cost increases, or need to seek timely and adequate rate relief. Northern Indiana does not anticipate the need to file for gas and electric base rate increases in the near future. YEAR 2000 COSTS - Northern Indiana has several major projects underway to modify portions of its systems for proper functioning in the year 2000. These include a project to evaluate Northern Indiana's proprietary software and to work with each of Northern Indiana's software vendors to assure that appropriate steps are being taken to mitigate the problem in each vendor's software or, in some cases, to replace software with year 2000 compliant software; a project to identify and mitigate problems wherever they exist in Northern Indiana's systems ranging from equipment used in Northern Indiana's generating stations to Northern Indiana's phone system that have date information embedded within them; and an initiative to assure that each entity that electronically receives information from Northern Indiana or sends information to Northern Indiana is aware of the steps that Northern Indiana is taking and is taking appropriate steps of its own to address the problem. Consistent with its plan, Northern Indiana expects to be year 2000 compliant with some systems as early as third quarter 1998 and other systems no later than the third quarter of 1999. Northern Indiana is currently in the process of structuring its contingency plans with respect to the potential nonperformance of certain of its information systems and embedded systems as a result of year 2000 problems, and estimates that those plans will be complete by the third quarter of 1999. Northern Indiana is currently working with utility industry groups to evaluate the potential impact of the year 2000 computer problems on the interconnected national electric grid and pipeline network. Northern Indiana estimates that costs to become year 2000 compliant will be approximately $13-$19 million, including acquisition costs of new systems which will be capitalized consistent with Northern Indiana's accounting policies. Costs related to maintenance or modification of Northern Indiana's systems have been and will be expensed as incurred. Northern Indiana does not anticipate the related costs will have a material impact on its results of operations, nor does Northern Indiana currently anticipate any disruption of its ability to deliver service as a result of the year 2000 issue. COMPETITION - The Energy Policy Act of 1992 (Energy Act) allowed FERC to order electric utilities to grant access to transmission systems by third-party power producers. The Energy Act specifically prohibits federally mandated wheeling of power for retail customers. On April 24, 1996, the FERC issued its Order No. 888-A which opens wholesale power sales to competition and requires public utilities owning, controlling, or operating transmission lines to file non-discriminatory open access tariffs that offer others the same transmission service they provide themselves. Northern Indiana filed its tariff as did virtually all other transmission owners subject to FERC jurisdiction. Order No. 888-A also provides for the recovery of stranded costs - that is, costs that were prudently incurred to serve wholesale power customers and that could go unrecovered if these customers use open access to move to another supplier. FERC expects this rule will accelerate competition and bring lower prices and more choices to wholesale energy customers. On November 25, 1997, FERC issued Order No. 888-B on rehearing, affirming in all important respects its earlier Order No. 888-A. Although wholesale customers represent a relatively small portion of Northern Indiana's sales, Northern Indiana will continue its efforts to retain and add customers by offering competitive rates. In January 1997 and January 1998 legislation was introduced in the Indiana General Assembly addressing electric utility competition and deregulation. Neither bill was passed. Northern Indiana has begun discussions with other utilities and its largest customers on the technical and economic aspects of possible legislation to allow customer choice. If Northern Indiana believes that consensus legislation is possible, Northern Indiana would support a deregulation bill in the January 1999 Indiana General Assembly. Operating in a competitive environment will place added pressures on utility profit margins and credit quality. Increasing competition in the electric utility industry has already led the credit rating agencies to apply more stringent guidelines in making credit rating determinations. Competition within the electric utility industry will create opportunities to compete for new customers and revenues, as well as increase the risk of the loss of customers. Northern Indiana's management has taken steps to make the company more competitive and profitable in the changing utility environment, including conversions of some of its generating units to allow use of lower cost, low sulfur coal. FERC Order No. 636 shifted primary responsibility for gas acquisition, transportation, and peak days' supply from pipelines to local gas distribution companies, such as Northern Indiana. Although pipelines continue to transport gas, they no longer provide sales service. Northern Indiana believes it has taken appropriate steps to ensure the continued acquisition of adequate gas supplies at reasonable prices. The mix of gas revenues from retail sales, interruptible retail sales, firm transportation service, and interruptible transportation services has changed significantly over the past several years. The deregulation of the gas industry, since the mid-1980's, allows large industrial and commercial customers to purchase their gas supplies directly from producers and use Northern Indiana's facilities to transport the gas. Transportation customers pay Northern Indiana only for transporting their gas from the pipeline to the customers' premises. The Commission has approved Northern Indiana's Alternative Regulatory Plan (ARP) which implements new rates and services that include, among other things, further unbundling of services for additional customer classes, increased customer choice for sources of natural gas supply, negotiated services and prices, an incentive gas cost 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 on a comparison of Northern Indiana's actual gas supply portfolio costs to a market based benchmark price. The first pilot program was launched in January 1998 and the first gas volumes flowed under this program in April 1998. The Commission order allows the natural gas marketing affiliate of Northern Indiana to participate as a supplier of choice to customers on the Northern Indiana system. Northern Indiana offers customers a price protection service (PPS), which allows residential customers to purchase gas at a fixed price or capped price for a specific period of time. To date, Northern Indiana's system has not been materially adversely 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 will have significant, positive effects in the next few years. 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, there can be no assurance 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. Investors should be aware of important factors that could have a material impact on future results. These factors include, but are not limited to, weather, the federal and state regulatory environment, 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 the control of Northern Indiana. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The primary market risks to which Northern Indiana is exposed and in connection with which Northern Indiana uses market risk sensitive instruments are commodity price risk and interest rate risk. Although Northern Indiana is subject to commodity price risk as part of its traditional operations, the current regulatory framework within which Northern Indiana operates allows for collection of fuel and gas costs in rate-making. Consequently, there is limited commodity price risk after consideration of the related rate-making. However, as the utility industry deregulates, Northern Indiana will be providing services without the benefit of the traditional rate-making allowances and will therefore be more exposed to commodity price risk. Northern Indiana utilizes commodity futures and option contracts to minimize the impact of price changes to a small portion of its supply portfolio. The Commission issued an order approving the inclusion of any gains or losses associated with the use of derivative financial and commodity instruments into Northern Indiana's gas cost adjustment clause. Because the commodities covered by Northern Indiana's derivative financial and commodity instruments are substantially the same commodities that Northern Indiana buys and sells in the physical market, no special correlation studies other than monitoring the degree of convergence between the derivative and cash market are deemed necessary. Due to the provisions of the gas cost adjustment clause and the fuel adjustment clause, movements in the natural gas and electric market prices would not significantly impact net income. Northern Indiana utilizes long-term debt as a primary source of capital in its business. A significant portion of Northern Indiana's long-term debt consists of fixed price debt instruments which have been and will be refinanced at lower interest rates if Northern Indiana deems it to be economical. Refer to Notes to Consolidated Financial Statements for detailed information related to Northern Indiana's long-term debt outstanding and Fair Value of Financial Instruments. PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS. Northern Indiana is 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 litigation and proceedings 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. To the knowledge of Northern Indiana no other material legal proceedings against Northern Indiana or its subsidiaries are 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 August 12, 1998 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 August 12, 1998 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 June 30, 1998 and is qualified in its entirety by reference to such financial statements. 1,000 3-MOS DEC-31-1998 APR-01-1998 JUN-30-1998 PER-BOOK 3,000,690 701 252,881 113,668 199,152 3,567,092 859,488 12,524 152,676 1,024,688 57,591 81,117 313,709 41,200 766,025 71,100 16,009 1,828 0 0 1,193,825 3,567,092 370,470 22,434 287,730 310,164 60,306 (1,268) 59,038 19,236 39,802 2,077 37,725 49,000 0 27,182 0 0
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