-----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, Hgjo5DBqGOLhrsRB/y2gwqVtfL6AjttMK8SnsnHSuhQZ8MUnIGuBbLyXMF4TLpiP b82B8DC4nSf+hbAZsdEX/A== 0000072843-00-000008.txt : 20000516 0000072843-00-000008.hdr.sgml : 20000516 ACCESSION NUMBER: 0000072843-00-000008 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20000331 FILED AS OF DATE: 20000515 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: 633460 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 March 31, 2000 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 April 30, 2000, 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 NiSource Inc.) and subsidiaries as of March 31, 2000, and December 31, 1999, and the related consolidated statements of income, retained earnings and cash flows for the three and twelve month periods ended March 31, 2000 and 1999. 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 auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial 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 March 31, 2000, and December 31, 1999, and the results of their operations and their cash flows for the three and twelve month periods ended March 31, 2000 and 1999, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP Chicago, Illinois May 2, 2000
CONSOLIDATED BALANCE SHEET March 31, December 31, ASSETS 2000 1999 ============ ============ (Dollars in thousands) UTILITY PLANT, AT ORIGINAL COST (INCLUDING CONSTRUCTION WORK IN PROGRESS OF $204,423 AND $200,011 RESPECTIVELY) (NOTE 2): Electric $ 4,252,466 $ 4,237,427 Gas 1,332,453 1,323,528 Common 384,946 381,486 ------------ ------------ 5,969,865 5,942,441 Less - Accumulated depreciation and amortization 3,044,267 2,993,412 ------------ ------------ Total Utility Plant 2,925,598 2,949,029 ------------ ------------ OTHER PROPERTY AND INVESTMENTS 2,665 2,668 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents 43,469 6,145 Accounts receivable, less reserve of $8,142 and $7,804, respectively (Note 2) 143,793 141,537 Fuel cost adjustment clause (Note 2) 0 4,201 Gas cost adjustment clause (Note 2) 4,944 36,787 Materials and supplies, at average cost 52,943 52,735 Electric production fuel, at average cost 35,390 31,968 Natural gas in storage, at last-in, first-out cost (Note 2) 21,095 22,966 Prepayments and other 70,695 60,285 ------------ ------------ Total Current Assets 372,329 356,624 ------------ ------------ OTHER ASSETS: Regulatory assets (Note 2) 183,651 186,080 Prepayments and other (Note 6) 175,328 161,053 ------------ ------------ Total Other Assets 358,979 347,133 ------------ ------------ $ 3,659,571 $ 3,655,454 ============ ============ The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED BALANCE SHEET March 31, December 31, CAPITALIZATION AND LIABILITIES 2000 1999 ============ ============ (Dollars in thousands) CAPITALIZATION: Common stock - without par value - authorized 75,000,000 shares, issued and outstanding 73,282,258 shares (Note 11) $ 859,488 $ 859,488 Additional paid-in capital 12,525 12,525 Retained earnings (see accompanying statement) (Note 10) 148,943 136,118 ------------ ------------ Common shareholder's equity 1,020,956 1,008,131 Cumulative preferred stocks, (excluding amounts due within one year) (Note 7) Series without mandatory redemption provisions (Note 8) 81,114 81,114 Series with mandatory redemption provisions (Note 9) 52,780 54,030 Long-term debt excluding amounts due within one year (Note 13) 920,527 920,413 ------------ ------------ Total Capitalization 2,075,377 2,063,688 ------------ ------------ CURRENT LIABILITIES - Current portion of long-term debt (Note 14) 152,000 158,000 Short-term borrowings (Note 15) 27,350 96,290 Accounts payable 119,156 129,532 Dividends declared on common and preferred stocks 58,986 59,017 Customer deposits 25,176 24,264 Taxes accrued 184,005 115,761 Interest accrued 14,671 7,392 Fuel adjustment clause 2,655 0 Accrued employment costs 45,621 51,393 Other accruals 89,898 76,163 ------------ ------------ Total Current Liabilities 719,518 717,812 ------------ ------------ OTHER: Deferred income taxes (Note 4) 583,672 592,022 Deferred investment tax credits, being amortized over life of related property (Note 4) 83,795 85,566 Deferred credits 45,159 47,105 Accrued liability for postretirement benefits (Note 6) 140,283 137,211 Other noncurrent liabilities 11,767 12,050 ------------ ------------ Total Other Liabilities 864,676 873,954 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Notes 3, 16 and 17) $ 3,659,571 $ 3,655,454 ============ ============ The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF INCOME Three Months Twelve Months Ended March 31, Ended March 31, ---------- ---------- ---------- ---------- 2000 1999 2000 1999 ========== ========== ========== ========== (Dollars in thousands) Operating Revenues: (Notes 2 and 20) Gas $ 263,533 $ 246,703 $ 661,517 $ 600,458 Electric 253,506 259,883 1,101,155 1,095,815 ---------- ---------- ---------- ----------- 517,039 506,586 1,762,672 1,696,273 ---------- ---------- ---------- ----------- Cost of Energy: (Note 2) Gas costs 161,301 137,966 402,944 335,829 Fuel for electric generation 57,499 58,298 248,365 253,353 Power purchased 8,234 16,782 58,416 55,125 ---------- ---------- ---------- ---------- 227,034 213,046 709,725 644,307 ---------- ---------- ---------- ---------- Operating Margin 290,005 293,540 1,052,947 1,051,966 ---------- ---------- ---------- ---------- Operating Expenses and Taxes (except income): Operation 61,143 67,655 249,962 251,472 Maintenance (Note 2) 17,805 18,253 65,014 66,861 Depreciation and amortization (Note 2) 59,262 58,138 234,679 230,165 Taxes (except income) 19,790 20,719 73,234 73,809 ---------- ---------- ---------- ---------- 158,000 164,765 622,889 622,307 ---------- ---------- ---------- ---------- Operating Income Before Utility Income Taxes 132,005 128,775 430,058 429,659 ---------- ---------- ---------- ---------- Utility Income Taxes (Note 4) 40,626 39,700 128,193 124,569 ---------- ---------- ---------- ----------Operating Income 91,379 89,075 301,865 305,090 ---------- ---------- ---------- ---------- Other Income (Deductions) (Note 2) 560 (1,071) (617) (4,052) ---------- ---------- ---------- ---------- Interest: Interest on long-term debt 17,203 16,720 68,178 68,542 Other interest 1,102 857 3,984 4,532 Amortization of premium, reacquisition premium, discount and expense on debt, net 804 1,035 3,537 4,166 ---------- ---------- ---------- ---------- 19,109 18,612 75,699 77,240 ---------- ---------- ---------- ---------- Net Income 72,830 69,392 225,549 223,798 Dividend requirements on preferred shares 2,005 2,065 8,071 8,284 ---------- ---------- ---------- ---------- Balance available for common shares $ 70,825 $ 67,327 $ 217,478 $ 215,514 ========== ========== ========== ========== Dividends declared $ 58,000 $ 55,000 $ 227,000 $ 221,000 ========== ========== ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Three Months Twelve Months Ended March 31, Ended March 31, ------------------- ------------------- 2000 1999 2000 1999 ========= ========= ========= ========= (Dollars in thousands) BALANCE AT BEGINNING OF PERIOD $ 136,118 $ 146,138 $ 158,465 $ 163,951 ADD: Net income 72,830 69,392 225,549 223,798 --------- --------- --------- --------- 208,948 215,530 384,014 387,749 --------- --------- --------- --------- LESS: Dividends Cumulative Preferred stocks - 4-1/4% series 222 222 888 889 4-1/2% series 91 91 360 360 4.22% series 113 113 448 448 4.88% series 122 122 488 488 7.44% series 77 77 312 312 7.50% series 66 66 261 261 8.85% series 101 138 424 543 7-3/4% series 60 70 266 308 8.35% series 100 113 409 460 6.50% series 698 698 2,795 2,795 Adjustable Rate, Series A 355 355 1,420 1,420 Common shares 58,000 55,000 227,000 221,000 --------- --------- --------- --------- 60,005 57,065 235,071 229,284 --------- --------- --------- --------- BALANCE AT END OF PERIOD $ 148,943 $ 158,465 $ 148,943 $ 158,465 ========= ========= ========= ========= The accompanying notes to consolidated financial statements are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS Three Months Ended March 31 ------------------------ 2000 1999 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 72,830 $ 69,392 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 59,262 58,138 Deferred federal and state income taxes, net (22,892) (26,784) Deferred investment tax credits, net (1,772) (1,781) Other, net 2,714 475 Change in certain assets and liabilities - Accounts receivable, net (3,831) (26,675) Electric production fuel (3,422) 7,223 Materials and supplies (208) (2,300) Natural gas in storage 1,871 31,220 Accounts payable (2,775) (29,839) Taxes accrued 81,579 84,387 Fuel adjustment clause 6,856 (2,256) Gas cost adjustment clause 31,843 49,240 Accrued employment costs (5,772) (9,181) Other accruals 1,433 5,063 Other, net (221) 11,917 ---------- ---------- Net cash provided by operating activities 217,495 218,239 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (36,661) (33,473) Other, net (7,422) (8,927) ---------- ---------- Net cash used in investing activities (44,083) (42,400) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Net change in short-term debt (68,940) (108,100) Retirement of long-term debt (6,000) 0 Retirement of preferred shares (1,250) 0 Cash dividends paid on common shares (58,000) (62,000) Cash dividends paid on preferred shares (2,012) (2,063) Other, net 114 113 ---------- ---------- Net cash used in investing activities (136,088) (172,050) ---------- ---------- NET DECREASE IN CASH AND CASH EQUIVALENTS 37,324 3,789 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,145 19,541 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 43,469 $ 23,330 ========== ========== Twelve Months Ended March 31, ------------------------ 2000 1999 ========== ========== (Dollars in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 225,549 $ 223,798 ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH: Depreciation and amortization 234,679 230,165 Deferred federal and state operating income taxes, net (15,604) (32,692) Deferred investment tax credits, net (7,117) (7,159) Other, net (2,666) 1,900 Change in certain assets and liabilities - Accounts receivable, net (8,321) (32,647) Electric production fuel (10,211) (3,938) Materials and supplies 911 1,126 Natural gas in storage (1,456) (1,322) Accounts payable 16,824 2,939 Taxes accrued 33,732 29,848 Fuel adjustment clause (1,368) 5,134 Gas cost adjustment clause (10,140) 41,652 Accrued employment costs 10,579 (2,229) Other accruals 15,963 2,721 Other, net (25,562) (9,875) ---------- ---------- Net cash provided by operating activities 455,792 449,421 ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES: Construction expenditures (196,026) (176,786) Other, net (4,650) (1,272) ---------- ---------- Net cash used in investing activities (200,676) (178,058) ---------- ---------- CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES: Issuance of long-term debt 0 500 Net change in short-term debt 9,350 (500) Retirement of long-term debt (9,000) (51,509) Retirement of preferred shares (3,657) (2,413) Cash dividends paid on common shares (224,000) (212,000) Cash dividends paid on preferred shares (8,125) (8,341) Other, net 455 455 ---------- ---------- Net cash used in financing activities (234,977) (273,808) ---------- ---------- NET DECREASE IN CASH AND CASH EQUIVALENTS 20,139 (2,445) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 23,330 25,775 ---------- ---------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 43,469 $ 23,330 ========== ========== The accompanying notes to consolidated financial statements are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) HOLDING COMPANY STRUCTURE: NiSource Inc.(NiSource), formerly NIPSCO Industries, Inc., was incorporated in Indiana on September 22, 1987 and became the parent of Northern Indiana Public Service Company (Northern Indiana) on March 3, 1988. NIPSCO Industries, Inc. changed it name to NiSource Inc. on April 14, 1999 to reflect its new direction as a multi-state supplier of energy and water resources and related services. Northern Indiana is a public utility operating company supplying electricity and gas to the public in the northern third of Indiana. Northern Indiana is subject to regulation with respect to rates, accounting and certain other matters which are governed by the Indiana Utility Regulatory Commission (IURC) and the Federal Energy Regulatory Commission (FERC), collectively called the "Commissions." (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: BASIS OF PRESENTATION. The Consolidated Financial Statements include the accounts of Northern Indiana and subsidiaries, after the elimination of all significant intercompany items. Certain reclassifications were made to conform the prior years' financial statements to the current presentation. USE OF ESTIMATES. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. OPERATING REVENUES. Revenues are recorded based on estimated service rendered, but are billed to customers monthly on a cycle basis. DEPRECIATION AND MAINTENANCE. Northern Indiana provides depreciation on a straight-line method over the remaining service lives of the electric, gas and common properties. The approximated weighted average remaining lives for major components of electric and gas plant are as follows: Electric: -------- Electric generation plant 24 years Transmission plant 26 years Distribution plant 25 years Other electric plant 24 years Gas: ---- Gas storage plant 18 years Transmission plant 34 years Distribution plant 27 years Other gas plant 24 years The depreciation provision for electric utility plant, as a percentage of the original cost, was 3.6% for the three-month and 3.7% for the twelve- month periods ended March 31, 2000 and was 3.7% for three-month and twelve- month periods ended March 31, 1999. The depreciation provision for gas utility plant, as a percentage of the original cost, was 5.4% for the three-month and twelve-month periods ended March 31, 2000 and March 31, 1999. Northern Indiana follows the practice of charging maintenance and repairs, including the cost of removal of minor items of property, to expense as incurred. When property that represents a retired unit is replaced or removed, the cost of such property is credited to utility plant, and such cost, together with the cost of removal less salvage, is charged to the accumulated provision for depreciation. AMORTIZATION OF SOFTWARE COSTS. External and incremental internal costs associated with computer software developed for internal use are capitalized. Capitalization of such costs commences upon the completion of the preliminary stage of the project. Once the installed software is ready for its intended use, such capitalized costs are amortized on a straight-line basis over a period of five to ten years which the FERC prescribes as reasonable useful life estimates for capitalized software. COAL RESERVES. The costs of reserves under a long-term mining contract to mine coal reserves through the year 2001 are being recovered through the rate-making process as such coal reserves are used to produce electricity. ACCOUNTS RECEIVABLE. At March 31, 2000, $100 million of accounts receivable had been sold under a sales agreement, which expires on May 31, 2002. The March 31, 2000 and December 31, 1999 accounts receivable balances include approximately $14.1 million and $14.0 million, respectively, due from associated companies. COMPREHENSIVE INCOME. Northern Indiana adopted Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income" effective January 1, 1998. This statement established standards for reporting and display of comprehensive income and its components in a financial statement that is displayed with the same prominence as other financial statements. The adoption of this statement did not impact Northern Indiana's consolidated financial statements for the periods presented. STATEMENTS OF CASH FLOWS. Temporary cash investments with an original maturity of three months or less are considered to be cash equivalents. Cash paid during the periods reported for income taxes and interest was as follows:
Three Months Twelve Months Ended March 31, Ended March 31, ------------------ ------------------ 2000 1999 2000 1999 ======== ======== ======== ======== (Dollars in thousands) Income taxes $ 15 $ 46 $125,549 $135,171 Interest, net of amounts capitalized $ 8,457 $ 9,320 $ 70,872 $ 73,431
FUEL ADJUSTMENT CLAUSE. All metered electric rates contain a provision for adjustment in charges for electric energy to reflect increases and decreases in the cost of fuel and the cost of purchased power through operation of a fuel adjustment clause. As prescribed by order of the IURC applicable to metered retail rates, the adjustment factor has been calculated based on the estimated cost of fuel and the fuel cost of purchased power in a future three-month period. If two statutory requirements relating to expense and return levels are satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given three-month period will be included in a future filing. 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 IURC and remains in effect for a three-month period. On August 18, 1999, the IURC issued a generic order which established new guidelines for the recovery of purchased power costs through fuel adjustment clauses. The IURC ruled that each utility had to establish a "benchmark" which is the utility's highest on-system fuel cost per kilowatt- hour (kwh) during the most recent annual period. The IURC stated that if the weekly average of a utility's purchased power costs were less than the "benchmark," these costs per kwh should be considered net energy costs which are presumed "fuel costs included in purchased power." If the weekly average of a utility's purchased power costs exceeded the "benchmark," the utility would need to submit additional evidence demonstrating the reasonableness of these costs. The Office of Utility Consumer Counselor (OUCC) has appealed the August 18, 1999 order to the Indiana Court of Appeals. GAS COST ADJUSTMENT CLAUSE. All metered gas sales rates contain an adjustment factor, which reflects the increases and decreases in the cost of purchased gas, contracted gas storage and storage transportation charges. The gas cost adjustment factor is subject to a quarterly hearing by the IURC and remains in effect for a three-month period. On August 11, 1999, the IURC approved a flexible gas cost adjustment mechanism for Northern Indiana. Under the new procedure, the demand component of the adjustment factor will be determined, after hearing and IURC approval, and made effective on November 1 of each year. The demand component will remain in effect for one year until a new demand component is approved by the IURC. The commodity component of the adjustment factor will be determined by monthly filings, which will become effective on the first day of each calendar month, subject to refund. The monthly filings do not require IURC approval but will be reviewed by the IURC during the annual hearing that will take place regarding the demand component filing. If the statutory requirement relating to the level of return is satisfied, any under-recovery or over-recovery caused by variances between estimated and actual cost in a given monthly period will be allocated over a twelve-month period beginning with the next monthly filing. Any under- recovery or over-recovery is recorded as a current asset or current liability until such time it is billed or refunded to its customers. Northern Indiana's gas cost adjustment factor includes a gas cost incentive mechanism (GCIM) which allows or the sharing of any cost savings or cost increases with customers based upon a comparison of actual gas supply portfolio cost to a market-based benchmark price. NATURAL GAS IN STORAGE. Natural gas in storage is valued using the last-in, first-out (LIFO) inventory methodology. Based on the average cost of gas purchased in March 2000 and December 1999, the estimated replacement cost of gas in storage (current and non-current) at March 31, 2000 and December 31, 1999 exceeded the stated LIFO cost by $42.9 million and $48.9 million, respectively. AFFILIATED COMPANY TRANSACTIONS. Northern Indiana receives executive, financial, gas supply, sales and marketing, and administrative and general services from an affiliate, NiSource Management Services Company (NMSC), a wholly-owned subsidiary of NiSource. The costs of these services are charged to Northern Indiana based on payroll costs and expenses incurred by NMSC employees for the benefit of Northern Indiana. These costs, which totaled $6.1 million and $19.1 million for the three-month and twelve-month periods ended March 31, 2000, respectively, and totaled $4.8 million and $19.2 million for the three-month, and twelve-month periods ended March 31, 1999, respectively, consist primarily of employee compensation and benefits. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $4.1 million and $16.8 million representing 3.2% and 4.5% of Northern Indiana's total gas costs for the three-month and twelve-month periods ended March 31, 2000, respectively. Northern Indiana purchased natural gas and transportation services from affiliated companies in the amounts of $3.6 million and $22.5 million representing 3.6% and 7.2% of Northern Indiana's total gas costs for the three-month and twelve-month periods ended March 31, 1999, respectively. Northern Indiana subleases a portion of its office facilities to affiliated companies for a monthly fee, which includes operating expenses, based on space utilization. ACCOUNTING FOR PRICE RISK MANAGEMENT. Northern Indiana is exposed to commodity price risk in its natural gas and electric operations. A variety of commodity-based derivative financial instruments are utilized to reduce this price risk. When these derivatives are used to reduce price risk in non-trading operations such as activities in gas supply for regulated gas utilities and certain customer choice programs, gains and losses on these derivative financial instruments are deferred as assets or liabilities and are recognized in earnings concurrent with the disposition of the underlying physical commodity. In certain circumstances, a derivative financial instrument will serve to hedge the acquisition cost of natural gas injected into storage. In this situation, the gain or loss on the derivative financial instrument is deferred as part of the cost basis of gas in storage and recognized upon the ultimate disposition of the gas. If a derivative financial instrument contract is terminated early because it is probable that a transaction or forecasted transaction will not occur, any gain or loss as of such date is immediately recognized in earnings. If a derivative financial instrument is terminated for other economic reasons, any gain or losses as of the termination date is deferred and recorded when the associated transaction or forecasted transaction affects earnings. Northern Indiana also uses derivative financial instruments in connection with trading activities at its power trading operations. These derivatives, along with the related physical contracts, are recorded at fair value pursuant to Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities." Because the majority of our trading activities started in 1999, the impact of adopting EITF Issue No. 98-10 on January 1, 1999, was insignificant. Transactions related to utility system load management do not qualify as a trading activity under EITF Issue No. 98-10 and are accounted for on an accrual basis. Northern refers to this activity as Power Marketing. IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards Board (FASB) has issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," in June 1998 and SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities-Deferral of the Effective Date of FASB Statement No. 133" in June 1999." Statement No. 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts, by requiring that a company recognize those items as assets or liabilities in the balance sheet and measure them at fair value. Special accounting within this Statement generally provides for matching of the timing of gain or loss recognition of derivative instruments qualifying as a hedge with the recognition of changes in the fair value of the hedged asset or liability through earnings, and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The Statement also provide that the effective portion of hedging instrument's gain or loss on a forecasted transaction be initially reported in other comprehensive income and subsequently reclassified into earnings when the hedged forecasted transaction affects earnings. Unless those specific hedge accounting criteria are met, SFAS No. 133 requires that changes in derivatives' fair value be recognized currently in earnings. SFAS No. 133, as amended by SFAS No. 137, is not effective for Northern Indiana until January 1, 2001. SFAS No. 133 must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts. With respect to hybrid instruments, a company may elect to apply SFAS No. No. 133, as amended, to (1) all hybrid instruments, (2) only those hybrid instruments that were issued, acquired or substantively modified after December 31, 1997, or (3) only those hybrid instruments that were issued, acquired or substantively modified after December 31, 1998. Northern Indiana anticipates adopting SFAS No. 133 on January 1, 2001, but has not determined the impact or method of adoption. The fair value of derivatives used in price risk management are described in "Risk Management Activities." The fair value of these derivatives would be recognized as assets or liabilities on the balance sheet consistent with the current accounting treatment for certain freestanding derivatives. Northern Indiana has not yet quantified the other effects of adopting SFAS No. 133 on its financial statements. However, the Statement could increase volatility in earnings and other comprehensive income. REGULATORY ASSETS. Northern Indiana's operations are subject to the regulation of the Commissions. Accordingly, Northern Indiana's accounting policies are subject to the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." Northern Indiana monitors changes in market and regulatory conditions and the resulting impact of such changes in order to continue to apply the provisions of SFAS No. 71 to some or all of its operations. As of March 31, 2000, and December 31, 1999, the regulatory assets identified below represent probable future revenues to Northern Indiana as these costs are recovered through the rate-making process. If a portion of Northern Indiana's operations becomes no longer subject to the provisions of SFAS No. 71, a write-off of certain regulatory assets might be required, unless some form of transition cost recovery is established by the appropriate regulatory body which would meet the requirements under generally accepted accounting principles for continued accounting as regulatory assets during such recovery period. Regulatory assets were comprised of the following items:
March 31, December 31, 2000 1999 ============= ============= (Dollars in thousands) Unamortized reacquisition premium on debt (Note 13) $ 38,633 $ 39,499 Unamortized R. M. Schahfer Unit 17 and Unit 18 carrying charges and deferred depreciation (See below) 57,057 58,111 Bailly scrubber carrying charges and deferred depreciation (See below) 7,776 8,010 Deferral of SFAS No. 106 expense not recovered (Note 6) 71,370 72,769 FERC Order No. 636 transition costs 11,150 13,728 Regulatory income tax asset, net (Note 4) 19,332 18,208 ------------- ------------- 205,318 210,325 Less: Current portion of regulatory assets 21,667 24,245 ------------- ------------- $ 183,651 $ 186,080 ============= =============
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 IURC until the cost of each unit was allowed in rates. Such carrying charges and deferred depreciation are being amortized over the remaining life of each unit. Northern Indiana has capitalized carrying charges and deferred depreciation and certain operating expenses relating to its scrubber service agreement for its Bailly Generating Station in accordance with an order of the IURC. The accumulated balance of the deferred costs and related carrying charges is being amortized over the remaining life of the scrubber service agreement. INCOME TAXES. The liability method of accounting is used for income taxes under which deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between book and tax bases of assets and liabilities. Deferred investment tax credits are being amortized over the life of the related property. (3) ENVIRONMENTAL MATTERS: GENERAL. The operations of Northern Indiana are subject to extensive and evolving federal, state and local environmental laws and regulations intended to protect public health and the environment. Such environmental laws and regulations affect Northern Indiana's operations as they relate to impacts on air, water and land. SUPERFUND. Because Northern Indiana is a "potentially responsible party" (PRP), under Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), at several waste disposal sites, as well as at former manufactured-gas plant sites which it, or its corporate predecessors, own or owned or operated, it may be required to share in the costs of clean up of such sites. A program was instituted to investigate former manufactured-gas plant sites where it is the current or former owner, which investigation has identified twenty-four of such sites. Initial sampling has been conducted at nineteen sites. Investigation activities have been completed at fourteen sites and remedial measures have been selected or implemented at nine sites. Northern Indiana intends to continue to evaluate its facilities and properties with respect to environmental laws and regulations and take any required corrective action. In an effort to recover a portion of the costs related to the former manufactured gas plants, various companies that provided insurance coverage which Northern Indiana believed covered costs related to former manufactured-gas plant sites were approached. Northern Indiana filed claims in Indiana state court against various insurance companies, seeking coverage for costs associated with several manufactured-gas plant sites and damages for alleged misconduct by some of the insurance companies. Settlements have been reached with all insurance companies. Additionally, agreements have been reached with other Indiana utilities relating to cost sharing and management of the investigation and remediation of several former manufactured-gas plant sites at which Northern Indiana and such utilities or their predecessors were operators or owners. As of March 31, 2000, a reserve of approximately $17.2 million has been recorded to cover probable corrective actions. The ultimate liability in connection with these sites will depend upon many factors, including the volume of material contributed to the site, the number of other PRP's and their financial viability, the extent of corrective actions required and rate recovery. Based upon investigations and management's understanding of current environmental laws and regulations, Northern Indiana believes that any corrective actions required, after consideration of insurance coverages and contributions from other PRP's and rate recovery will not have a material effect on its financial position or results of operations. CLEAN AIR ACT. The Clean Air Act Amendments of 1990 (CAAA) impose limits to control acid rain on the emission of sulfur dioxide and nitrogen oxides (NOx) which become fully effective in 2000. All of Northern Indiana's facilities are already in compliance with sulfur dioxide limits. Northern Indiana has already taken most of the steps necessary to meet the NOx limits. The CAAA also contain other provisions that could lead to limitations on emissions of hazardous air pollutants and other air pollutants (including NOx as discussed below), which may require significant capital expenditures for control of these emissions. Until specific rules have been issued that affect Northern Indiana's facilities, what these requirements will be or the costs of complying with these potential requirements cannot be predicted. NITROGEN OXIDES. During 1998, the Environmental Protection Agency (EPA) issued a final rule, the NOx State Implementation Plan (SIP) call, requiring certain states, including Indiana, to reduce NOx levels from several sources, including industrial and utility boilers. The EPA stated that the intent of the rule is to lower regional transport of ozone impacting other states' ability to attain the federal ozone standard. According to the rule, the State of Indiana must issue regulations implementing the control program. The State of Indiana, as well as some other states, filed a legal challenge in December 1998 to the EPA NOx SIP call rule. Lawsuits have also been filed against the rule by various groups, including utilities. On May 25, 1999, the United Sates Circuit Court of Appeals for the D.C. Circuit Court issued an order staying the NOx SIP call rule's September 30, 1999 deadline for the state submittals until further order of the court. In a March 3, 2000 decision, the United States Court of Appeals for the D.C. Circuit ruled largely in favor of EPA's regional NOx plan. An appeal of this decision is expected. The State of Indiana in February 2000 proposed a moderate NOx control plan designed to address Indiana's ozone nonattainment areas and regional ozone transport. Any NOx emission limitations resulting from these actions could be more restrictive than those imposed on electric utilities under the CAAA's acid rain NOx reduction program described above. Northern Indiana is evaluating the EPA's final rule and any potential requirements that could result from the final rule as implemented by the State of Indiana. Northern Indiana believes that the costs relating to compliance with the new standards may be substantial, but such costs are dependent upon the outcome of the current litigation and the ultimate control program agreed to by the targeted states and the EPA. Northern Indiana is continuing its programs to reduce NOx emissions and Northern Indiana will continue to closely monitor developments in this area. In a related matter to EPA's NOx SIP call, several Northeastern states have filed petitions with the EPA under Section 126 of the Clean Air Act. The petitions allege harm and request relief from sources of emissions in the Midwest that allegedly cause or contribute to ozone nonattainment in their states. Northern Indiana is monitoring EPA's decisions on these petitions and existing litigation to determine the impact of these developments on Northern Indiana's programs to reduce NOx emissions. The EPA issued final rules revising the National Ambient Air Quality Standards for ozone and particulate matter in July 1997. On May 14, 1999, the United States Court of Appeals for the D.C. Circuit remanded the new rules for both ozone and particulate matter standards to the EPA. Once rectified, the revised standards could require additional reductions in sulfur dioxide, particulate matter and NOx emissions from coal-fired boilers (including Northern Indiana's generating stations) beyond measures discussed above. Final implementation methods will be set by the EPA as well as state regulatory authorities. Northern Indiana believes that the costs relating to compliance with any new limits may be substantial but are dependent upon the ultimate control program agreed to by the targeted states and the EPA. Northern Indiana will continue to closely monitor developments in this area and anticipates the exact nature of the impact of the new limits on its operations will not be known for some time. In a letter dated September 15, 1999, the Attorney General of the State of New York alleged that Northern Indiana violated the Clean Air Act by constructing a major modification of one of its electric generating stations without obtaining pre-construction permits required by the Prevention of Significant Deterioration (PSD) program. The major modification allegedly took place at the R. M. Schahfer Station when, "in approximately 1995-1997, Northern Indiana upgraded the coal handling system at Unit 14 at the plant." While Northern Indiana is investigating these allegation, Northern Indiana does not believe that the modifications required pre-construction review under the PSD program and believes that all appropriate permits were acquired. CARBON DIOXIDE. Initiatives are being discussed both in the United States and worldwide to reduce so-called "greenhouse gases" such as carbon dioxide, and other by-products of burning fossil fuels. Reduction of such emissions could result in significant capital outlays or operating expenses to Northern Indiana. CLEAN WATER ACT AND RELATED MATTERS. Northern Indiana's wastewater and water operations are subject to pollution control and water quality control regulations, including those issued by the EPA and the State of Indiana. Under the Federal Clean Water Act and Indiana's regulations, Northern Indiana must obtain National Pollutant Discharge Elimination System permits for water discharges from various water discharges from various facilities, including electric generating and water treatment stations. These facilities either have permits for their water discharge or they have applied for a permit renewal of any expiring permits. These permits continue in effect pending review of the current applications. (4) INCOME TAXES: Deferred income taxes are recognized as costs in the rate-making process by the Commissions having jurisdiction over rates charged by Northern Indiana. Deferred income taxes are provided as a result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the consolidated financial statements. These taxes are reversed by a debit or credit to deferred income tax expense as the temporary differences reverse. Investment tax credits have been deferred and are being amortized to income over the life of the related property. To the extent certain deferred income taxes are recoverable or payable through future rates, regulatory assets and liabilities have been established. Regulatory assets are primarily attributable to undepreciated allowance for funds used during construction-equity (AFUDC) and the cumulative net amount of other income tax timing differences for which deferred taxes had not been provided in the past, when regulators did not recognize such taxes as costs in the rate-making process. Regulatory liabilities are primarily attributable to Northern Indiana's obligation to credit to ratepayers deferred income taxes provided at rates higher than the current federal tax rate currently being credited to ratepayers using the average rate assumption method and unamortized deferred investment tax credits. Northern Indiana joins in the filing of consolidated tax returns with NiSource and currently pays to NiSource its separate return tax liability as defined in the Tax Sharing Agreement between NiSource and its subsidiaries. The components of the net deferred income tax liability at March 31, 2000 and December 31, 1999 were as follows:
March 31, December 31, 2000 1999 ============= ============= (Dollars in thousands) Deferred tax liabilities - Accelerated depreciation and other property differences $ 709,308 $ 714,246 AFUDC-equity 30,302 30,748 Adjustment clauses 868 15,545 Other regulatory assets 27,067 27,598 Prepaid pension and other benefits 56,227 56,227 Reacquisition premium on debt 14,652 14,980 Deferred tax assets - Deferred investment tax credits (31,779) (32,451) Removal costs (174,803) (171,645) Other postretirement/postemployment benefits (53,202) (53,061) Other, net (26,066) (27,928) ------------- ------------- 552,574 574,259 Less: Deferred income taxes related to current assets and liabilities (31,098) (17,763) ------------- ------------- Deferred income taxes - noncurrent $ 583,672 $ 592,022 ============= =============
Federal and state income taxes as set forth in the Consolidated Statements of Income are comprised of the following:
Three Months Twelve Months Ended March 31, Ended March 31, ------------------------------------------- 2000 1999 2000 1999 ========= ========= ========= ========= (Dollars in thousands) Current income taxes - Federal $ 57,456 $ 59,582 $ 133,661 $ 143,817 State 7,834 8,683 17,253 20,603 --------- --------- --------- --------- 65,290 68,265 150,914 164,420 --------- --------- --------- --------- Deferred income taxes, net - Federal (21,126) (24,746) (14,571) (30,388) State (1,766) (2,038) (1,033) (2,304) --------- --------- --------- --------- (22,892) (26,784) (15,604) (32,692) --------- --------- --------- --------- Deferred investment tax credits, net (1,772) (1,781) (7,117) (7,159) --------- --------- --------- --------- Total utility operating income taxes 40,626 39,700 128,193 124,569 Income tax applicable to non- operating activities and income of subsidiaries 328 (644) (613) (2,176) --------- --------- --------- --------- Total income taxes $ 40,954 $ 39,056 $ 127,580 $ 122,393 ========= ========= ========= =========
A reconciliation of total income tax expense to an amount computed by applying the statutory federal income tax rate to pre-tax income is as follows:
Three Months Twelve Months Ended March 31, Ended March 31, --------- --------- --------- --------- 2000 1999 2000 1999 ========= ========= ========= ========= (Dollars in thousands) Net income $ 72,830 $ 69,392 $ 225,549 $ 223,798 Add-Income taxes 40,954 39,056 127,580 122,393 --------- --------- --------- --------- Net income before income taxes $ 113,784 $ 108,448 $ 353,129 $ 346,191 ========= ========= ========= ========= Amount derived by multiplying pre-tax income by the statutory rate $ 39,824 $ 37,957 $ 123,595 $ 121,167 Reconciling items multiplied by the statutory rate: Book depreciation over related tax depreciation 918 969 3,883 3,963 Amortization of deferred investment tax credits (1,772) (1,781) (7,117) (7,159) State income taxes, net of federal income tax benefit 3,326 3,606 10,181 11,088 Reversal of deferred taxes provided at rates in excess of the current federal income tax rate (919) (721) (5,655) (5,922) Other, net (423) (974) 2,693 (744) --------- --------- --------- --------- Total income taxes $ 40,954 $ 39,056 $ 127,580 $ 122,393 ========= ========= ========= =========
(5) PENSION PLANS: NiSource has a noncontributory, defined benefit retirement plan covering substantially all employees of Northern Indiana. Benefits under the plan reflect the employees' compensation, years of service and age at retirement. The change in the benefit obligation for 1999 and 1998 is as follows:
1999 1998 ========= ========= (Dollars in thousands) Benefit obligation at beginning $ 914,273 $ 843,049 of year (January 1,) Service cost 15,858 15,347 Interest cost 61,613 58,337 Plan amendments 0 14,655 Actuarial (gain) loss (50,217) 37,247 Benefits paid (54,823) (54,362) --------- --------- Benefit obligation at end of the year (December 31,) $ 886,704 $ 914,273 ========= =========
The change in the fair value of the plan's assets for years 1999 and 1998 is as follows:
1999 1998 =========== =========== (Dollars in thousands) Fair value of plan assets at $ 958,435 $ 896,950 beginning of year January 1,) Actual return on plan's assets 158,775 82,547 Employer contributions 35,000 33,300 Benefits paid (54,823) (54,362) ----------- ----------- Plan assets at fair value at end of the year (December 31,) $ 1,097,387 $ 958,435 =========== ===========
The plan's assets are invested primarily in common stocks, bonds and notes. The plan's funded status as of 1999 and 1998 is as follows:
1999 1998 ========= ========= (Dollars in thousands) Plan assets in excess of $ 210,683 $ 44,162 benefit obligation Unrecognized net actuarial (gain) (140,665) (16,162) Unrecognized prior service cost 50,165 55,761 Unrecognized transition amount being recognized over seventeen years 21,953 27,442 --------- --------- Prepaid pension costs $ 142,136 $ 111,203 ========= =========
The benefit obligation is the present value of future pension benefit payments and is based on a plan benefit formula which considers expected future salary increases. A discount rates of 7.75% and 7.00% and rate of increase in compensation levels of 4.5% and 4.5% were used to determine the benefit obligation at December 31, 1999 and December 31, 1998, respectively. The long-term portion of prepaid pension costs were $156.4 million and $141.5 million at March 31, 2000 and December 31, 1999, respectively, and are reported under the caption "Prepayments and Other" in the Consolidated Balance Sheet. The following items are the components of provisions for pensions for the three-month and twelve-month periods ended March 31, 2000 and March 31, 1999:
Three Months Twelve Months Ended Ended March 31, March 31, -------- -------- -------- -------- 2000 1999 2000 1999 ======== ======== ======== ======== (Dollars in thousands) Service costs $ 4,265 $ 4,583 $ 15,540 $ 13,934 Interest costs 16,899 15,644 62,868 52,908 Expected return on plan assets (23,113) (21,109) (86,492) (73,468) Amortization of transition obligation 1,372 1,372 5,488 4,958 Amortization of prior service cost 1,399 1,385 5,610 4,257 Amortization of gain (687) 0 (687) 0 -------- -------- -------- -------- $ 135 $ 1,875 $ 2,327 $ 2,589 ======== ======== ======== ========
Assumptions used in the valuation and determination of 2000 and 1999 pension expense were as follows:
2000 1999 ===== ===== Discount rate 7.75% 7.00% Rate of increase in compensation levels 4.50% 4.50% Expected long-term rate of return on assets 9.00% 9.00%
(6) POSTRETIREMENT BENEFITS: Northern Indiana provides certain health care and life insurance benefits for retired employees are provided. Substantially all 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. Current rates include postretirement benefit costs on an accrual basis, including amortization of the regulatory assets that arose prior to inclusion of these costs in rates. The following table sets forth the change in the plan's accumulated postretirement benefit obligation (APBO) as of December 31, 1999 and 1998:
1999 1998 ========= ========= (Dollars in thousands) Accumulated postretirement $ 207,079 $ 195,003 benefit obligation at beginning of year (January 1,) Service cost 3,010 3,314 Interest cost 14,217 13,685 Plan amendments 1,191 0 Actuarial (gain) loss (15,959) 6,260 Benefits paid (13,883) (11,183) --------- --------- Accumulated postretirement benefit obligation at end of the year (December 31,) $ 195,655 $ 207,079 ========= =========
The change in the fair value of the plan's assets for the years 1999 and 1998 is as follows:
1999 1998 ========= ========= (Dollars in thousands) Fair value of plan assets at $ 2,903 $ 2,400 beginning of year (January 1,) Actual return on plan assets 704 1,103 Employer contributions 12,477 9,301 Participant contributions 1,191 1,282 Benefits paid (13,883) (11,183) --------- --------- Plan assets at fair value at end of the year (December 31,) $ 3,392 $ 2,903 ========= =========
Following is the funded status for postretirement benefits as of December 31, 1999 and 1998:
1999 1998 ========= ========= (Dollars in thousands) Funded status $(192,262) $(204,176) Unrecognized actuarial (gain) (103,623) (90,700) Unrecognized prior service cost 3,178 3,458 Unrecognized transition amount being recognized over twenty years 139,719 150,466 --------- --------- Accrued liability for postretirement benefits $(152,988) $(140,952) ========= =========
In order to determine the APBO at December 31, 1999 a discount rate of 7.75% and a pre-Medicare medical trend rate of 6% declining to a long-term rate of 5% was used, and at December 31, 1998, a discount rate of 7% and a pre-Medicare medical trend rate of 7% declining to a long-term rate of 5% was used. The accrued liability for postretirement benefits was $149.3 million at March 31, 2000. Net periodic postretirement benefits costs, before consideration of the rate-making discussed previously, for the three-month and twelve-month periods ended March 31, 2000 and March 31, 1999 include the following components:
Three Months Twelve Months Ended Ended March 31, March 31, ------- ------- ------- ------- 2000 1999 2000 1999 ======= ======= ======= ======= (Dollars in thousands) Service costs $ 801 $ 477 $ 3,638 $ 3,054 Interest costs 3,900 3,850 13,735 13,885 Expected return on plan assets (50) (50) (216) (216) Amortization of transition obligation over twenty years 2,700 2,675 10,773 10,748 Amortization of prior service cost 75 75 279 279 Amortization of actuarial (gain) (1,375) (1,150) (6,011) (5,561) ------- ------- ------- ------- $ 6,051 $ 5,877 $22,198 $22,189 ======= ======= ======= =======
Assumptions used in the determination of 2000 and 1999 net periodic postretirement benefit costs were as follows:
2000 1999 ===== ===== Discount rate 7.75% 7.00% Rate of increase in compensation levels 4.50% 4.50% Assumed annual rate of increase in health care benefits 7.00% 7.00% Assumed ultimate trend rate 5.00% 5.00%
The effect of a 1% increase in the assumed health care cost trend rates for each future year would increase the APBO at January 1, 2000 by approximately $21.9 million, and increase the aggregate of the service and interest cost components of plan costs by approximately $0.6 million for the three-month period ended March 31, 2000. The effect of a 1% decrease in the assumed health care cost trend rates for each future year would decrease the APBO at January 1, 2000 by approximately $18.1 million, and decrease the aggregate of the service and interest cost components of plan costs by approximately $0.5 million for the three-month period ended March 31,2000. Amounts disclosed above could be changed significantly in the future by changes in health care costs, work force demographics, interest rates, or plan changes. (7) AUTHORIZED CLASSES OF CUMULATIVE PREFERRED AND PREFERENCE STOCKS OF NORTHERN INDIANA: 2,400,000 shares - Cumulative Preferred - $100 par value 3,000,000 shares - Cumulative Preferred - no par value 2,000,000 shares - Cumulative Preference - $50 par value (none outstanding) 3,000,000 shares - Cumulative Preference - no par value (none issued) Note 8 sets forth the preferred stocks which are redeemable solely at the option of Northern Indiana and Note 9 sets forth the preferred stocks which are subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana. The preferred shareholders of Northern Indiana have no voting rights, except in the event of a default on the payment of four consecutive quarterly dividends, or as required by Indiana law to authorize additional preferred shares, or by the Articles of Incorporation in the event of certain merger transactions. (8) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF NORTHERN INDIANA, OUTSTANDING AT MARCH 31, 2000 AND DECEMBER 31, 1999 (SEE NOTE 7):
Redemption Price at March 31, December 31, March 31, 2000 1999 2000 ============ ============ ============ (Dollars in thousands) Cumulative preferred stock - $100 par value - 4-1/4% series - 209,035 shares outstanding $ 20,903 $ 20,903 $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 March 31, 2000), Series A (stated value $50 per share) 473,285 shares outstanding 23,664 23,664 $50.00 ------------ ------------ $ 81,114 $ 81,114 ============ ============
During the period April 1, 1998 to March 31, 2000 there were no additional issuances of the above preferred stocks. The foregoing preferred stocks are redeemable in whole or in part, at any time upon thirty days' notice at the option of Northern Indiana at the redemption prices shown. (9) REDEEMABLE PREFERRED STOCKS OUTSTANDING AT MARCH 31, 2000 AND DECEMBER 31, 1999 (SEE NOTE 7): Preferred stocks subject to mandatory redemption requirements or whose redemption is outside the control of Northern Indiana, excluding sinking fund payments due within one year were as follows:
March 31, December 31, 2000 1999 ============ ============ (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 - 25,000 and 37,500 shares outstanding, respectively, excluding sinking fund payments due within one year $ 2,500 $ 3,750 7-3/4% series - 27,798 shares outstanding, excluding sinking fund payments due within one year 2,780 2,780 8.35% series - 45,000 shares outstanding excluding sinking fund payments due within one year 4,500 4,500 Cumulative preferred stock - no par value - 6.50% series - 430,000 shares outstanding 43,000 43,000 ------------ ------------ $ 52,780 $ 54,030 ============ ============
The redemption prices at March 31, 2000, as well as sinking fund provisions for the cumulative preferred stocks subject to mandatory redemption requirements, or whose redemption is outside the control of Northern Indiana, were as follows:
Sinking Fund Or Mandatory Redemption Series Redemption Price Per Share Provisions ====== ========================== ============================= Cumulative preferred stock - $100 par value - 8.85% $100.37, reduced periodically 12,500 shares on or before April 1. 7-3/4% $103.88, reduced periodically 2,777 shares on or before December 1; noncumulative option to double amount each year. 8.35% $103.20, reduced periodically 3,000 shares on or before July 1; increasing to 6,000 shares beginning in 2004; noncumulative option to double amount each year. Cumulative preferred stock - no par value - 6.50% $100.00 on October 14, 2002 430,000 shares on October 14, 2002.
Sinking fund requirements with respect to redeemable preferred stocks outstanding at March 31, 2000 for each of the twelve-month periods subsequent to March 31, 2001 were as follows:
Twelve Months Ended March 31, ================================== (Dollars in thousands) 2002 $ 1,828 2003 $ 44,828 2004 $ 578 2005 $ 878
Sinking fund payments due within one year are reported under the caption "Other" in the Consolidated Balance Sheets. (10) COMMON SHARE DIVIDEND: Northern Indiana's Indenture dated August 1, 1939, as amended and supplemented (Indenture), provides that it will not declare or pay any dividends on any class of capital stock (other than preferred or preference stock) except out of the earned surplus or net profits of Northern Indiana. At March 31, 2000, Northern Indiana had approximately $148.9 million of retained earnings (earned surplus) available for the payment of dividends. Future dividends will depend upon adequate retained earnings, adequate future earnings and the absence of adverse developments. (11) COMMON SHARES: Effective with the exchange of common shares on March 3, 1988, all of Northern Indiana's common shares are owned by NiSource. (12) LONG-TERM INCENTIVE PLAN: NiSource has two long-term incentive plans for key management employees, including management of Northern Indiana, that were approved by shareholders on April 13, 1988 (1988 Plan) and April 13, 1994 (1994 Plan), each of which provides for the issuance of up to 5.0 million of NiSource common shares to key employees through April 1998 and April 2004, respectively. The 1988 Plan, as amended and restated, and the 1994 Plan, as amended and restated, were re-approved by shareholders at NiSource's 1999 Annual Meeting of Shareholders, held April 14, 1999. At March 31, 2000, there were 805,836 shares reserved for future awards under the 1994 Plan. The Plans permit the following types of grants, separately or in combination: nonqualified stock options, incentive stock options, restricted stock awards, stock appreciation rights and performance units. No incentive stock options or performance units were outstanding at March 31, 2000. Under the Plans, the exercise price of each option equals the market price of NiSource's common stock on the date of grant. Each option has a maximum term of ten years and vests one year from the date of grant. Stock appreciation rights (SARs) may be granted only in tandem with stock options on a one-for-one basis and are payable in cash, NiSource's common shares, or a combination thereof. There were no SARs outstanding at March 31, 2000. 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 lapsed on January 27, 2000 and vested 116% of the number awarded, due to attaining specific earnings per share and stock appreciation goals. Restrictions on shares awarded in 1998 lapsed two years from date of grant and vested at 100% of the number awarded. Restrictions on shares awarded in 2000 lapse three years from date of grant and vesting may vary from 0% to 200% if 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 683,500 and 513,500 restricted shares outstanding at March 31, 2000 and December 31, 1999, respectively. On January 29, 2000, the board of directors of NiSource approved certain additional amendments to the 1994 Plan. The amended and restated 1994 Plan would provide for the number of common shares subject to the plan to increase from 5.0 million to 11.0 million, and would permit contingent stock awards and dividend equivalents payable on grants of options, SARs, performance units and contingent stock awards. The amended and restated 1994 Plan is subject to shareholder approval at the 2000 Annual Meeting of Shareholders of NiSource. Northern Indiana accounts for its allocable portion of these plans under Accounting Principles Board Opinion No. 25, under which no compensation cost has been recognized for nonqualified stock options. The compensation cost that has been charged against income for restricted stock awards was 0.1 million and $0.2 million for the three month and $1.0 million and $0.8 million for the twelve-month periods ending March 31, 2000 and March 31, 1999, respectively. Had compensation cost for non-qualified stock options been determined consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," net income would have been reduced to the following pro forma amounts:
Three Months Twelve Months Ended Ended March 31, March 31, ------------------ ------------------ 2000 1999 2000 1999 ======== ======== ======== ======== (Dollars in thousands) Net Income: As reported $ 72,830 $ 69,392 $225,549 $223,798 Pro forma $ 72,293 $ 68,985 $223,766 $222,483
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions used for grants in 2000, 1999 and 1998:
2000 1999 1998 ========== ========== ========== Interest Rate 6.60% 5.87% 5.29% Expected Dividend Yield $1.08 $1.02 $0.96 Expected Life 5.4 years 5.25 years 5.4 years Volatility 28.98% 15.72% 13.09%
The weighted average fair value of options granted to all plan participants was $3.69 and $4.28 for the twelve-month periods ended March 31, 2000 and March 31, 1999, respectively. There were 1,027,750 and 607,000 non- qualified stock options granted to all plan participants for the twelve-month periods ended March 31, 2000 and March 31, 1999, respectively. (13) LONG-TERM DEBT: At March 31, 2000 and December 31, 1999, the long-term debt of Northern Indiana, excluding amounts due within one year, issued and not retired or canceled was as follows:
AMOUNT OUTSTANDING --------------------------- March 31, December 31, 2000 1999 ============ ============ (Dollars in thousands) First mortgage bonds - Series T, 7-1/2%, due April 1, 2002 $ 38,500 $ 38,500 Series NN, 7.10%, due July 1, 2017 55,000 55,000 ------------ ------------ Total 93,500 93,500 ------------ ------------ Pollution control notes and bonds - Series A Note - City of Michigan City, 5.70% due October 1, 2003 14,000 14,000 Series 1988 Bonds - Jasper County - Series A, B and C - 4.17% weighted average at March 31, 2000, due November 1, 2016 130,000 130,000 Series 1988 Bonds - Jasper County - Series D - 4.12% weighted average at March 31, 2000, due November 1, 2007 24,000 24,000 Series 1994 Bonds - Jasper County - Series A - 4.00% at March 31, 2000, due August 1, 2010 10,000 10,000 Series 1994 Bonds - Jasper County - Series B - 4.00% at March 31, 2000, due June 1, 2013 18,000 18,000 Series 1994 Bonds - Jasper County - Series C - 4.00% at March 31, 2000, due April 1, 2019 41,000 41,000 ------------ ------------ Total 237,000 237,000 ------------ ------------ Medium-term notes - Interest rates between 6.50% and 7.69% with a weighted average interest rate of 7.05% and various maturities between August 15, 2001 and August 4, 2027 593,025 593,025 ------------ ------------ Unamortized premium and discount on long-term debt, net (2,998) (3,112) ------------ ------------ Total long-term debt excluding amounts due in one year $ 920,527 $ 920,413 ============ ============
The sinking fund requirements and maturities of long-term debt outstanding at March 31, 2000 for each of the twelve-month periods subsequent to March 31, 2001 were as follows:
Twelve Months Ended March 31, ================================= (Dollars in thousands) 2002 $ 19,000 2003 $ 79,000 2004 $ 110,000 2005 $ 32,000
Unamortized debt expense, premium and discount on long-term debt applicable to outstanding bonds are being amortized over the lives of such bonds. Reacquisition premiums are being deferred and amortized. These premiums are not earning a return during the recovery period. Northern Indiana's Indenture, pursuant to which first mortgage bonds have been issued, constitutes a direct first mortgage lien upon substantially all of Northern Indiana's property and franchises, other than expressly excepted property. Northern Indiana is authorized to issue and sell up to $217,692,000 Medium-Term Notes, Series E, with various maturities, for purposes of refinancing certain first mortgage bonds and medium-term notes. As of March 31, 2000, $139.0 million of the medium-term notes had been issued with various interest rates and maturities. (14) CURRENT PORTION OF LONG-TERM DEBT: At March 31, 2000 and December 31, 1999, Northern Indiana's current portion of long-term debt due within one year was as follows:
March 31, December 31, 2000 1999 ============ ============ (Dollars in thousands) Medium-term notes - Interest rate 6.10% and 6.90% with a weighted average interest rate of 6.82% and maturities between April 5, 2000 and June 1, 2000 $ 149,000 $ 155,000 Sinking funds due within one year 3,000 3,000 ------------ ------------ Total current portion of long-term debt $ 152,000 $ 158,000 ============ ============
(15) SHORT-TERM BORROWINGS: Northern Indiana entered into a five-year $100 million credit agreement and a 364-day $100 million revolving credit agreement with several banks. These agreements terminate on September 23, 2003 and September 23, 2000, respectively. The 364-day agreement may be extended at expiration for additional periods of 364-days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for a short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. As of March 31, 2000, there were no borrowings outstanding under these agreements. In addition, Northern Indiana has $11.4 million in lines of credit which run until May 31, 2000. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. As of March 31, 2000, there were no borrowings under these lines of credit. The credit agreements and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $220 million of money market lines of credit. As of March 31, 2000, there were no borrowings outstanding under these lines of credit. As of December 31, 1999, $33.7 million of borrowings was outstanding under these lines of credit. At March 31, 2000 and December 31, 1999, Northern Indiana's short-term borrowings were as follows:
March 31, December 31, 2000 1999 ============ ============ (Dollars in thousands) Commercial paper - Interest rate of 5.90% at March 31, 2000 $ 27,350 $ 62,565 Notes payable - Issued at interest rates between 6.50% and 7.45% with a weighted average interest rate of 7.06% and maturities of January 18, 2000 and January 28, 2000 0 33,725 ------------ ------------ Total short-term borrowings $ 27,350 $ 96,290 ============ ============
(16) OPERATING LEASES: On April 1, 1990, Northern Indiana entered into a twenty-year agreement for the rental of office facilities from NiSource Development Company, Inc., a subsidiary of NiSource, at a current annual rental payment of approximately $3.5 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 March 31, 2000:
Twelve Months Ended March 31, ================================ (Dollars in thousands) 2001 $ 7,107 2002 7,107 2003 7,107 2004 6,945 2005 4,385 Later years 31,002 -------- Total minimum payments required $ 63,653 ========
The consolidated financial statements include rental expense for all operating leases as follows:
March 31, March 31, 2000 1999 ============ ============ (Dollars in thousands) Three months ended $ 2,710 $ 2,666 Twelve months ended $11,182 $ 9,909
(17) COMMITMENTS: Northern Indiana estimates that approximately $1.1 billion will be expended for construction purposes for the period from January 1, 2000 to December 31, 2004. Substantial commitments have been made by Northern Indiana in connection with this program. Northern Indiana has entered into a service agreement with Pure Air, a general partnership between Air Products and Chemicals, Inc. and Mitsubishi Heavy Industries America, Inc., under which Pure Air provides scrubber services to reduce sulfur dioxide emissions for Units 7 and 8 at its Bailly Generating Station. Services under this contract commenced on June 15, 1992 with annual charges approximating $20 million. The agreement provides that, assuming various performance standards are met by Pure Air, a termination payment would be due if Northern Indiana terminates the agreement prior to the end of the twenty-year contract period. A ten-year agreement to outsource all data center, application development and maintenance, and desktop management expires in 2005. Annual fees under this agreement are approximately $20 million. (18) RISK MANAGEMENT ACTIVITIES: Northern Indiana uses certain commodity- base derivatives financial instruments to manage certain risks inherent in its business. Northern Indiana's senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. The open positions resulting from risk management activities are managed in accordance with strict policies which limit exposure to market risk and require daily reporting to management of potential financial exposure. Northern Indiana uses futures contracts, options and swaps to hedge a portion of its price risk associated with its non-trading activities in gas supply for its regulated gas utility, certain customer choice programs. At March 31, 2000, Northern Indiana had futures contracts representing the hedge of natural gas sales in the notional amount of 0.3 billion cubic feet (BCF) and the resulting deferred gain was not material. Northern Indiana trading operation includes the activities of its power trading business. Northern Indiana employs a value-at-risk (VaR) model to assess the market risk of its energy trading portfolios. Northern Indiana estimates the one - day VaR for its trading group which utilizes derivatives using either a Monte Carlo simulation or variance/covariance at 95 percent confidence level. Based on the results of the VaR analysis, the daily market exposure for power trading on an average, high and low basis was $0.4, $1.3 and $0.2 million and $0.4, $1.3 and $0.01 million for three-month and twelve-month periods ended March 31, 2000, respectively. Unrealized gains and losses on Northern Indiana's portfolio are recorded as price risk management assets and liabilities. The market prices used to value price risk management activities reflect the best estimate of market prices considering various factors, including closing exchange and over-the- counter quotations and price volatility factors underlying the commitments. The accompanying financial statements reflect price risk management assets of $44.5 million and $31.7 million at March 31, 2000 and December 31, 1999, respectively, were included in prepayments and other current assets. The accompanying financial statements also reflect price risk management liabilities (including net option premiums) of $67.5 million and $54.0 million at March 31, 2000.and December 31, 1999, respectively, were included in other current liabilities. Power trading results are reflected on a net basis in the accompanying statement of income, consistent with the guidance in EITF Issue No.98-10 with respect to the use of written options. Northern Indiana has recorded a net profit of $2.8 and $13.6 million as a component of Other Income (deductions) for the three and twelve months ended March 31, 2000, respectively. (19) FAIR VALUE OF FINANCIAL INSTRUMENTS: The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate fair value: CASH AND CASH EQUIVALENTS. The carrying amount approximates fair value due to the short maturity of those instruments. INVESTMENTS. Investments are carried at cost, which approximates market value. LONG-TERM DEBT AND PREFERRED STOCK. The fair value of these securities are estimated based on quoted market prices for the same or similar issues or on the rates offered for securities of the same remaining maturities. Certain premium costs associated with the early settlement of long-term debt are not taken into consideration in determining fair value. The carrying values and estimated fair values of financial instruments were as follows:
March 31, 2000 December 31, 1999 ---------------------- ---------------------- Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value ========== ========== ========== ========== (Dollars in thousands) Cash and cash equivalents $ 43,469 $ 43,469 $ 6,145 $ 6,145 Investments $ 251 $ 251 $ 251 $ 251 Long-term debt (including current portion) $1,072,527 $ 988,804 $1,078,413 $ 997,196 Preferred stock (including current portion) $ 135,722 $ 111,230 $ 136,972 $ 116,464
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 revenues for the twelve months ended March 31, 2000 as compared to 3% and 17%, respectively, for the twelve months ended March 31,1999. (21) SEGMENTS OF BUSINESS: Operating segments are defined as components of an enterprise for which separate financial information is available and is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Northern Indiana makes all decisions on finance, dividends and taxes at the corporate level. 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. In addition, the electric segment includes Northern Indiana's wholesale power marketing operation which markets wholesale power to other utilities and electric power marketers. The other category includes gas exploration, real estate transactions, and non- utility revenues and expenses. Reportable segments are operations that are managed separately and meet the quantitative thresholds. Revenues for each segments are attributable to customers in the United States. The following tables provide information about business segments. In addition, adjustments have been made to the segment information to arrive at information included in the results of operations and financial position. These adjustments include unallocated corporate assets, revenues and expenses. The accounting policies of the operating segments are the same as those described in "Summary of Significant Accounting Policies."
For the Three Months Adjust- Ended March 31, 2000 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $263,533 $ 253,506 $ 0 $ 0 $ 517,039 Other income (deductions)$ 499 $ (21) $ 82 $ 0 $ 560 Depreciation and amortization $ 19,270 $ 39,992 $ 0 $ 0 $ 59,262 Income before interest and utility income taxes $ 52,060 $ 80,423 $ 82 $ 0 $ 132,565 Assets $911,692 $2,747,879 $ 0 $ 0 $3,659,571 Capital expenditures $ 11,715 $ 24,946 $ 0 $ 0 $ 36,661 For the Three Months Adjust- Ended March 31, 1999 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $246,703 $ 259,883 $ 0 $ 0 $ 506,586 Other income (deductions)$ 613 $ 128 $ (1,812) $ 0 $ (1,071) Depreciation and amortization $ 18,563 $ 39,575 $ 0 $ 0 $ 58,138 Income before interest and utility income taxes $ 55,690 $ 73,826 $ (1,812) $ 0 $ 127,704 Assets $893,747 $2,688,028 $ 0 $ 0 $3,581,775 Capital expenditures $ 9,195 $ 24,278 $ 0 $ 0 $ 33,473 For the Twelve Months Adjust- Ended March 31, 2000 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $661,517 $1,101,155 $ 0 $ 0 $1,762,672 Other income (deductions)$ 1,757 $ 583 $ (2,910) $ (47) $ (617) Depreciation and amortization $ 75,723 $ 158,956 $ 0 $ 0 $ 234,679 Income before interest and utility income taxes $ 70,471 $ 361,927 $ (2,941) $ (16) $ 429,441 Assets $911,692 $2,747,879 $ 0 $ 0 $3,659,571 Capital expenditures $ 63,863 $ 132,163 $ 0 $ 0 $ 196,026 For the Twelve Months Adjust- Ended March 31, 1999 Gas Electric Other ments Total - ------------------------ -------- ---------- -------- -------- ---------- (Dollars in thousands) Operating revenues $600,458 $1,095,815 $ 0 $ 0 $1,696,273 Other income (deductions)$ 1,428 $ 592 $ (5,952) $ (120) $ (4,052) Depreciation and amortization $ 72,517 $ 157,648 $ 0 $ 0 $ 230,165 Income before interest and utility income taxes $ 69,746 $ 361,933 $ (5,993) $ (79) $ 425,607 Assets $893,747 $2,688,028 $ 0 $ 0 $3,581,775 Capital expenditures $ 56,528 $ 120,258 $ 0 $ 0 $ 176,786
The following table reconciles total reportable segment income before interest and utility income taxes to net income for three-month, nine-month and twelve-month periods ended March 31, 2000 and 1999:
Three Months Twelve Months Ended March 31, Ended March 31, ------------------ ------------------ 2000 1999 2000 1999 ======== ======== ======== ======== (Dollars in thousands) Income before interest and utility income taxes $132,565 $127,704 $429,441 $425,607 Interest 19,109 18,612 75,699 77,240 Utility income taxes 40,626 39,700 128,193 124,569 -------- -------- -------- -------- Net income $ 72,830 $ 69,392 $225,549 $223,798 ======== ======== ======== ========
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RESULTS OF OPERATIONS OPERATING REVENUES - GAS REVENUES. Gas revenues were $661.5 million for the twelve months ended March 31, 2000, an increase of $61.1 million from the comparable period ended twelve months ended March 31, 1999. This increase was mainly due to increased gas costs, increased gas transportation services and increased wholesale gas sales, partially offset by decreased sales to residential and commercial customers as a result of warmer weather during the period and decreased gas transition costs. During the period, gas deliveries in dekatherms (dth) increased mainly as a result of increased gas transportation services, partially offset by decreased deliveries to residential and commercial customers reflecting heating degree days being 10% lower than 1999. Gas revenues were $263.5 million for the three months ended March 31, 2000, an increase of $16.8 million from the comparable period ended March 31, 1999. This increase was mainly due to increased gas costs, increased wholesale gas sales and increased gas transportation services, partially offset by decreased sales to residential and commercial customers due to a significant warmer weather during the period. During the period, gas deliveries in dth increased mainly as a result of increased gas transportation services, partially offset by decreased gas deliveries to residential and commercial customers reflecting heating degree days 11% lower than 1999. Large commercial and industrial customers continue to utilize transportation services provided by Northern Indiana. Gas transportation customers purchase much of their gas directly from producers and marketers and then pay a transportation fee to have their gas delivered over Northern Indiana's system. Northern Indiana transported 186.5 and 53.3 million dth for others during the twelve and three months ended March 31, 2000, respectively. The basic steel industry accounted for 39% of natural gas delivered (including volumes transported) during the twelve months ended March 31, 2000. The components of the changes in gas operating revenues are shown in the following table:
March 31, 2000 Compared to March 31, 1999 --------------------------------- Three Twelve Months Months ========= ========= (Dollars in thousands) Gas Revenue Changes - Pass through of net changes in purchased gas costs, gas storage, and storage transportation costs $ 46,573 $ 88,539 Gas transition costs (322) (3,662) Changes in sales levels (35,239) (49,671) Gas transported 1,878 4,519 Wholesale gas 3,940 21,334 --------- --------- Total Gas Revenue Change $ 16,830 $ 61,059 ========= =========
GAS COSTS OF ENERGY. Gas costs increased $67.1 million (20%) to $402.9 million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999, due to increased purchased gas costs per dth. The average cost for purchased gas for the period, after adjustment for gas transition costs billed to transport customers, was $2.86 per dth as compared to $2.34 for the comparable period ended March 31, 1999. Gas costs increased $23.3 million (17%) to $161.3 million for the three months ended March 31, 2000, from the comparable period ended March 31, 1999, mainly due to increased gas costs per dth, partially offset by decreased gas transition costs. The average cost for purchased gas for the period, after adjustment for gas transition costs billed to transport customers, was $2.81 per dth as compared to $2.06 for the comparable period ended March 31, 1999. GAS OPERATING MARGINS. The gas operating margin for the twelve months ended March 31, 2000 decreased $6.0 million from the comparable period ended March 31, 1999. This decrease is due to decreased deliveries to residential and commercial customers reflecting warmer heating season during the period, partially offset by increased wholesale gas sales. Gas operating margin decreased $6.5 million to $102.2 million during the three months ended March 31, 2000 from the comparable period ended March 31, 1999. This decrease is due to decreased deliveries to residential and commercial customers reflecting the warmer heating season during the first quarter of 2000, partially offset by increased transportation services. ELECTRIC REVENUES. Electric revenues were $1.1 billion for the twelve months ended March 31, 2000, an increase of $5.3 million from the comparable period ended March 31, 1999. The increase in electric revenues was mainly due to increased sales to commercial customers due to warmer weather during the third quarter of 1999, increased industrial sales and partially offset by decreased wholesale transactions. Electric revenues were $253.5 million for the three months ended March 31, 2000, a decrease of $6.3 million from the comparable period ended March 31, 1999. Sales of electricity in kilowatt-hours (kwh) decreased 7% from the comparable period ended March 31, 1999. The decrease in electric revenues was mainly due to decreased sales to residential customers and decreased wholesale transactions, partially offset by increased sales to commercial and industrial customers. The basic steel industry accounted for 31% of electric sales during the twelve months ended March 31, 2000. The components of the changes in electric operating revenues are shown in the following table:
March 31, 2000 Compared to March 31, 1999 ------------------------------- Three Twelve Months Months ========= ========= (Dollars in thousands) Electric Revenue Changes- Pass through of net changes in fuel costs $ (2,816) $ 1,813 Changes in sales levels 10,136 40,876 Wholesale electric (13,697) (37,349) --------- --------- Total Electric Revenue Change $ (6,377) $ 5,340 ========= =========
ELECTRIC COST OF ENERGY. Cost of fuel for electric generation decreased $5.0 million to $248.4 million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999. The decrease is primarily due to decreased fuel costs per kwh generated. The average cost per kwh generated decreased 5% from the comparable period ended March 31, 1999, to 1.44 cents per kwh, for the twelve months ended March 31, 2000. Cost of fuel for electric generation decreased $0.8 million to $57.5 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999. The decrease is primarily due to decreased fuel costs per kwh generated. The average cost per kwh generated decreased 7% from the comparable period ended March 31, 1999, to 1.37 cents per kwh. POWER PURCHASED. Power purchased increased $3.3 million to $58.4 million for the twelve months ended March 31, 2000 from the comparable period ended in March 31, 1999. The decrease is a result of increased cost per kwh, partially offset by decreased bulk power purchases. Power purchased decreased $8.5 million to $8.2 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999. The decrease is as a result of decreased bulk power purchases, partially offset by increased cost per kwh. ELECTRIC OPERATING MARGINS. Operating margin from electric sales increased $7.0 million to $794.3 million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999. This increase occurred mainly due to increased sales to commercial and industrial sales, partially offset by decreased wholesale transactions. Operating margin from electric sales increased $3.0 million to $187.8 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999. This increase is due to increased sales to commercial and industrial customers, partially offset by decreased sales to residential customers and decreased wholesale transactions. OPERATING EXPENSES AND TAXES (EXCEPT INCOME). Operating expenses and taxes (except income) decreased $6.8 million to $158.0 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999. Operating expenses and taxes (except income) for the twelve months ended March 31, 2000 remained relatively unchanged from the comparable period ended March 31, 1999. Operation expenses decreased $1.5 million to $250.0 million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999. The decrease is due to $13 million insurance settlement related to manufactured gas plants site cleanup costs, decreased operating costs for electric production facilities of $2.3 million, partially offset by increased employee related costs of $9.2 million and increased expenses for distributed generation and fuel cell research and development of $4.0 million. Operation expenses decreased $6.5 million to $61.1 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999. The decrease is mainly due to lower employee related costs of $4.2 million and other decreased operating costs. Maintenance expenses decreased $1.8 million to $65.0 million for the twelve months ended March 31, 2000 from comparable period ended March 31, 1999 due to decreased maintenance activity for electric production facilities and electric and gas distribution facilities. Maintenance expenses for the three months ended March 31, 2000 were relatively unchanged from the comparable period ended March 31, 1999. Depreciation and amortization expenses increased $4.5 million to $234.7 million and $1.1 million to $59.3 million for the twelve and three months ended March 31, 2000, respectively, from the comparable periods ended March 31, 1999, resulting from plant additions. Utility income taxes increased $3.6 million to $128.2 million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999 mainly as a result of increased pre-tax income and higher effective income tax rate. Utility income taxes increased $1.0 million to $40.6 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999 mainly as a result of increased pre-tax income. Other Income (Deductions) increased $3.4 million to $(0.6) million for the twelve months ended March 31, 2000 from the comparable period ended March 31, 1999, as a result of increased power trading activities, partially offset by Northern Indiana deciding to abandon certain business facilities that were not consistent with its strategic direction. Other Income (Deductions) increased $1.6 million to $0.6 million for the three months ended March 31, 2000 from the comparable period ended March 31, 1999, as a result of increased power trading activities. Interest charges decreased $1.5 million for the twelve months ended March 31, 2000 to $75.7 million from the comparable period ended March 31, 1999, due to decreased short-term borrowing and long-term debt during the period. Interest charges for the three months ended March 31, 2000 were relatively unchanged from the comparable period ended March 31, 1999. LIQUIDITY AND CAPITAL RESOURCES. Generally, cash flow from operations has provided sufficient liquidity to meet current operating requirements. Because the utility and utility construction business is seasonal in nature, commercial paper is issued for short-term financing. As of March 31, 2000 and December 31, 1999, $27.3 million and $62.6 million of commercial paper was outstanding, respectively. The interest rate of commercial paper outstanding as of March 31, 2000 was 5.90%. Northern Indiana entered into a five-year $100 million credit agreement and a 364-day $100 million revolving credit agreement with several banks. These agreements terminate on September 23, 2003 and September 23, 2000, respectively. The 364-day agreement may be extended at expiration for additional periods of 364-days. Under these agreements, funds are borrowed at a floating rate of interest or, under certain circumstances, at a fixed rate of interest for a short-term periods. These agreements provide financing flexibility and may be used to support the issuance of commercial paper. As of March 31, 2000, there were no borrowings outstanding under these agreements. In addition, Northern Indiana has $11.4 million in lines of credit which run until May 31, 2000. The credit pricing of each of the lines varies from either the lending banks' commercial prime or market rates. As of March 31, 2000, there were no borrowings under these lines of credit. The credit agreements and lines of credit are also available to support the issuance of commercial paper. Northern Indiana also has $220 million of money market lines of credit. As of March 31, 2000, there were no borrowings outstanding under these lines of credit. As of December 31, 1999, $33.7 million of borrowings was outstanding under these lines of credit. On January 27, 2000, the Citizens Action Coalition (CAC), a private consumer organization, filed a petition before the Indiana Utility Regulatory Commission (IURC). The petition does not seek a specified amount of rate reduction, but rather alleges that the existing electric rates are "unreasonable and unsafe," and seeks to have the IURC force Northern Indiana to produce detailed financial calculations that would justify its electric rates. Northern Indiana is opposing the petition on both legal and factual grounds, and believes that its current rates are just and reasonable as required by statue. CONSTRUCTION PROGRAM. Future commitments with respect to its construction program are expected to be met through internally generated funds. MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS - RISK MANAGEMENT Risk is an inherent part of Northern Indiana's energy businesses and activities. The extent to which Northern Indiana properly and effectively identifies, assesses, monitors and manages each of the various types of risk involved in its businesses is critical to its profitability. Northern Indiana seeks to identify, assess, monitor and manage, in accordance with defined policies and procedures, the following principal risks involved in Northern Indiana's energy businesses: commodity market risk, interest rate risk and credit risk. Risk management at Northern Indiana is a multi-faceted process with independent oversight that requires constant communication, judgment and knowledge of specialized products and markets. Northern Indiana's senior management takes an active role in the risk management process and has developed policies and procedures that require specific administrative and business functions to assist in the identification, assessment and control of various risks. In recognition of the increasingly varied and complex nature of the energy business, Northern Indiana's risk management policies and procedures are evolving and subject to ongoing review and modification. Northern Indiana is exposed to risk through various daily business activities, including specific trading risks and non-trading risks. The non- trading risks to which Northern Indiana is exposed include interest rate risk and commodity price risk. The market risk resulting from trading activities consists primarily of commodity price risk. Northern Indiana's risk management policy permits the use of certain financial instruments to manage its market risk, including futures, forwards, options and swaps. Risk management at Northern Indiana is defined as the process by which the organization ensures that the risks to which it is exposed are the risks to which it desires to be exposed to achieve its primary business objectives. Northern Indiana employs various analytic techniques to measure and monitor its market risks, including value-at-risk (VaR) and instrument sensitivity to market factors. VaR represents the potential loss for an instrument or portfolio from adverse changes in market factors, for a specified time period and at a specified confidence level. TRADING RISKS COMMODITY MARKET RISK. Market risk refers to the risk that a change in the level of one or more market prices, rates, indices, volatilities, correlations or other market factors, such as liquidity, will result in losses for a specified position or portfolio. Northern Indiana employs a VaR model to assess the market risk of all open derivative financial instruments. Northern Indiana estimates the one-day VaR across all trading groups which utilize derivatives using either Monte Carlo simulation or variance/covariance at a 95 percent confidence level. Based on the results of the VaR analysis, the daily market risk exposure for power trading on an average, high, and low basis was $0.4, $1.3 and $0.2 million and $0.4, $1.3 and $0.01 million for three-month and twelve-month periods ended March 31, 2000, respectively. Northern Indiana implemented a VaR methodology in 1999 to introduce additional market sophistication and to recognize the developing complexity of its businesses. NON-TRADING RISKS COMMODITY MARKET RISK. Currently, commodity price risk resulting from non-trading activities is relatively limited, since current regulations allow Northern Indiana to recoup any prudently incurred fuel and gas costs through rate-making. As the utility industry undergoes deregulation, however, Northern Indiana will be providing services without the benefit of the traditional rate-making and, therefore, will be more exposed to commodity price risk. Additionally, Northern Indiana enters into certain sales contracts with customers based upon a fixed sales price and varying volumes which are ultimately dependent upon the customer's supply requirements. Northern Indiana utilizes derivative financial instruments to reduce the commodity price risk based on modeling techniques to anticipate these future supply requirements. INTEREST RATE RISK. Northern Indiana is exposed to interest rate risk as a result from changes in interest rates on borrowings under the revolving credit agreements and lines of credit. These instruments have interest rates that are indexed to short-term market interest rates. At March 31, 2000 and December 31, 1999, the combined borrowings outstanding under these facilities totaled $27.4 million and $96.3 million, respectively. Based upon average borrowings under these agreements during 2000 and 1999, an increase in short- term interest rates of 100 basis points (1%) would have increased interest expense by $0.6 million and $0.7 million for the three months ending March 31, 2000 and 1999 and $2.8 million and $3.5 million for the twelve months ending March 31, 2000 and 1999, respectively. Long-term debt is utilized as a primary source of capital. A significant portion of this long-term debt consists of medium-term notes. In addition, longer term fixed-price debt instruments have been used that in the past have been refinanced when interest rates decreased. To the extent that such refinancing is economical, refinancing these fixed-price instruments will continue. CREDIT RISK. Credit risk arises in many of Northern Indiana's business activities. In sales and trading activities, credit risk arises because of the possibility that a counterparty will not be able or willing to fulfill its obligations on a transaction on or before settlement date. In derivative activities, credit risk arises when counterparties to derivative contracts, such as interest rate swaps, are obligated to pay Northern Indiana the positive fair value or receivable resulting from the execution of contract terms. Exposure to credit risk is measured in terms of both current and potential exposure. Current credit exposure is generally measured by the notional or principal value of financial instruments and direct credit substitutes, such as commitments and standby letters of credit and guarantees. Current credit exposure includes the positive fair value of derivative instruments. Because many of Northern Indiana's exposures vary with changes in market prices, Northern Indiana also estimates the potential credit exposure over the remaining term of transactions through statistical analyses of market prices. In determining exposure, Northern Indiana considers collateral and master netting agreements, which are used to reduce individual counterparty risk, primarily in connection with derivative products. Refer to Consolidated Statement of Long-Term Debt for detailed information related to Northern Indiana's long-term debt outstanding and "Fair Value of Financial Instruments" in Notes to Consolidated Financial Statements for current market valuation of long-term debt. Refer to "Summary of Significant Accounting Policies-Accounting for Price Risk Management Activities" for further discussion of Northern Indiana's risk management. Refer to "Financial Instruments and Risk Management," in Notes to Consolidated Financial Statements for a discussion of the types of commodity- based derivative financial instruments and risk management. COMPETITION AND REGULATORY CHANGES - The regulatory frameworks applicable to Northern Indiana, at both state and federal levels, are undergoing fundamental changes. These changes have impacted and will continue to have an impact on Northern Indiana's operations, structure and profitability. At the same time, competition within the electric and gas industries will create opportunities to compete for new customers and revenues. Management has taken steps to become more competitive and profitable in this changing environment, including converting some of its generating units to allow use of lower cost, low sulfur coal and providing its gas customers with increased customer choice for new products and services throughout the service territory. THE ELECTRIC INDUSTRY. At the Federal level, the FERC issued Order No. 888-A in 1996 which required all public utilities owning, controlling, or operating transmission lines to file non-discriminatory open-access tariffs and offer wholesale electricity suppliers and marketers the same transmission service they provide themselves. In 1997, FERC approved Northern Indiana's open-access transmission tariff. On December 20, 1999, FERC issued a final rule addressing the formation and operation of Regional Transmission Organizations (RTOs). The rule is intended to eliminate pricing inequities in the provision of wholesale transmission service. Northern Indiana does not believe that compliance with the new rules will be material to future earnings. Although wholesale customers currently represent a small portion of Northern Indiana's electricity sales, it intends to continue its efforts to retain and add wholesale customers by offering competitive rates and also intends to expand the customer base for which it provides transmission services. At the state level, Northern Indiana announced in 1997 and 1998 that if a consensus could be reached regarding electric utility restructuring legislation, Northern Indiana would support a restructuring bill before the Indiana General Assembly. During 1999, discussions were held with other investor-owned utilities in Indiana regarding the technical and economic aspects of possible legislation leading to greater customer choice. A consensus was not reached. Therefore, Northern Indiana did not support legislation regarding electric restructuring during the 2000 session of the Indiana General Assembly. During 2000, discussions will continue with all segments of the Indiana electric industry in an attempt to reach a consensus on electric restructuring legislation for introduction during the 2001 session of the Indiana General Assembly. THE GAS INDUSTRY. At the Federal level, gas industry deregulation began in the mid-1980's when FERC required interstate pipelines to provide nondiscriminatory transportation services pursuant to unbundled rates. This regulatory change permitted large industrial and commercial customers to purchase their gas supplies either from Northern Indiana or directly from competing producers and marketers, which would then use Northern Indiana's facilities to transport the gas. More recently, the focus of deregulation in the gas industry has shifted to the states. At the state level, the IURC approved in 1997 Northern Indiana's Alternative Regulatory Plan (ARP), which implemented new rates and services that included, among other things, unbundling of services for additional customer classes (primarily residential and commercial users), negotiated services and prices, a gas cost incentive mechanism, and a price protection program. The gas cost incentive mechanism allows Northern Indiana to share any cost savings or cost increases with its customers based upon a comparison of Northern Indiana's actual gas supply portfolio cost to a market-based benchmark price. Phase I of Northern Indiana's Customer Choice Pilot Program ended on March 31, 1999. This pilot program offered 82,000 residential customers within St. Joseph County and 10,000 commercial customers throughout the Northern Indiana service area the right to choose alternative gas suppliers. Phase II of Northern Indiana's Customer Choice Pilot Program commenced on April 1, 1999 and will continue for a one-year period. During this phase, Northern Indiana is offering customer choice to all 660,000 residential and 50,000 commercial customers throughout its gas service territory. A limit of 150,000 residential and 20,000 commercial customers are eligible to enroll in Phase II of the program. The IURC order allows a specific NiSource natural gas marketing subsidiary to participate as a supplier of choice to Northern Indiana customers. In addition, as Northern Indiana has allowed residential and commercial customers to designate alternative gas suppliers, it has also offered new services to all classes of customers including, price protection, negotiated sales and services, gas lending and parking, and new storage services. To date, Northern Indiana has not been materially affected by competition, and management does not foresee substantial adverse effects in the near future unless the current regulatory structure is substantially altered. Northern Indiana believes the steps that it has taken to deal with increased competition have had and will continue to have significant positive effects in the next few years. IMPACT OF ACCOUNTING STANDARDS. Refer to "Summary of Significant Accounting Policies-Impact of Accounting Standards" in the Notes to the Consolidated Financial Statements for information regarding impact of accounting standards not yet adopted. FORWARD LOOKING STATEMENTS. This report contains forward looking statements within the meaning of the securities laws. Forward looking statements include terms such as "may," "will," "expect," "believe," "plan" and other similar terms. Northern Indiana cautions that, while it believes such statements to be based on reasonable assumptions and makes such statements in good faith, you cannot be assured that the actual results will not differ materially from such assumptions or that the expectations set forth in the forward looking statements derived from such assumptions will be realized. You should be aware of important factors that could have a material impact on future results. These factors include, weather, the federal and state regulatory environment, the economic climate, regional, commercial, industrial and residential growth in the service territories served by Northern Indiana, customers' usage patterns and preferences, the speed and degree to which competition enters the utility industry, the timing and extent of changes in commodity prices, changing conditions in the capital and equity markets and other uncertainties, all of which are difficult to predict, and many of which are beyond Northern Indian's control. ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. For a discussion of primary market risks and risk management policy, see "Management's Discussion and Analysis of Financial Condition and Results of Operations-Market Risk Sensitive Instruments and Positions." PART II. OTHER INFORMATION Item 1. LEGAL PROCEEDINGS. Northern Indiana is a party to various pending proceedings, including suits and claims against it for personal injury, death and property damage. Such proceedings and suits, and the amounts involved, are routine for the kind of business conducted by Northern Indiana, except as described under Note 4 "Environmental Matters," in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Report on Form 10-Q, which note is incorporated by reference. No other material legal proceedings against Northern Indiana or its subsidiaries are pending or, to the knowledge of Northern Indiana, contemplated by governmental authorities and other parties. Item 2. CHANGES IN SECURITIES. None Item 3. DEFAULTS UPON SENIOR SECURITIES. None Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. None Item 5. OTHER INFORMATION. None Item 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits. Exhibit 23 - Consent of Arthur Andersen LLP Exhibit 27 - Financial Data Schedule (b) Reports on Form 8-K. None SIGNATURE 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, Vice President, Finance and Chief Accounting Officer Date May 15, 2000 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 May 15, 2000 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 March 31, 2000 and is qualified in its entirety by reference to such financial statements. 1,000 3-MOS DEC-31-2000 JAN-01-2000 MAR-31-2000 PER-BOOK 2,925,598 2,665 372,329 175,328 183,651 3,659,571 859,488 12,525 148,943 1,020,956 52,780 81,114 313,502 00,000 607,025 27,350 152,000 1,828 0 0 1,4030168 3,659,571 517,039 40,626 385,034 425,660 91,379 560 91,939 19,109 72,830 2,005 70,825 58,000 0 217,495 0 0
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