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.
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
March 31, December 31,
ASSETS 2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
March 31, December 31,
CAPITALIZATION AND LIABILITIES 2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
Three Months Twelve Months
Ended March 31, Ended March 31,
---------- ---------- ---------- ----------
2000 1999 2000 1999
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
========== ========== ========== ==========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Three Months Twelve Months
Ended March 31, Ended March 31,
------------------- -------------------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
========= ========= ========= =========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months
Ended March 31
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
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
========== ==========
<CAPTION>
Twelve Months
Ended March 31,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
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
========== ==========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended March 31, Ended March 31,
------------------ ------------------
2000 1999 2000 1999
======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Income taxes $ 15 $ 46 $125,549 $135,171
Interest, net of
amounts
capitalized $ 8,457 $ 9,320 $ 70,872 $ 73,431
</TABLE>
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:
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
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
============= =============
</TABLE>
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:
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
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
============= =============
</TABLE>
Federal and state income taxes as set forth in the Consolidated Statements
of Income are comprised of the following:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended March 31, Ended March 31,
-------------------------------------------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
========= ========= ========= =========
</TABLE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended March 31, Ended March 31,
--------- --------- --------- ---------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
========= ========= ========= =========
</TABLE>
(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:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
The change in the fair value of the plan's assets for years 1999 and 1998
is as follows:
<TABLE>
<CAPTION>
1999 1998
=========== ===========
(Dollars in thousands)
<S> <C> <C>
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
=========== ===========
</TABLE>
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:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended Ended
March 31, March 31,
-------- -------- -------- --------
2000 1999 2000 1999
======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
Assumptions used in the valuation and determination of 2000 and 1999
pension expense were as follows:
<TABLE>
<CAPTION>
2000 1999
===== =====
<S> <C> <C>
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%
</TABLE>
(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:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
The change in the fair value of the plan's assets for the years 1999 and
1998 is as follows:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
Following is the funded status for postretirement benefits as of December
31, 1999 and 1998:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
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)
========= =========
</TABLE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended Ended
March 31, March 31,
------- ------- ------- -------
2000 1999 2000 1999
======= ======= ======= =======
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
======= ======= ======= =======
</TABLE>
Assumptions used in the determination of 2000 and 1999 net periodic
postretirement benefit costs were as follows:
<TABLE>
<CAPTION>
2000 1999
===== =====
<S> <C> <C>
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%
</TABLE>
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):
<TABLE>
<CAPTION>
Redemption
Price at
March 31, December 31, March 31,
2000 1999 2000
============ ============ ============
(Dollars in thousands)
<S> <C> <C> <C>
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
============ ============
</TABLE>
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:
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
</TABLE>
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:
<TABLE>
<CAPTION>
Sinking Fund Or
Mandatory Redemption
Series Redemption Price Per Share Provisions
====== ========================== =============================
<S> <C> <C>
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.
</TABLE>
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:
<TABLE>
<CAPTION>
Twelve Months Ended March 31,
==================================
(Dollars in thousands)
<S> <C>
2002 $ 1,828
2003 $ 44,828
2004 $ 578
2005 $ 878
</TABLE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended Ended
March 31, March 31,
------------------ ------------------
2000 1999 2000 1999
======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Net Income:
As reported $ 72,830 $ 69,392 $225,549 $223,798
Pro forma $ 72,293 $ 68,985 $223,766 $222,483
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
========== ========== ==========
<S> <C> <C> <C>
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%
</TABLE>
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:
<TABLE>
<CAPTION>
AMOUNT OUTSTANDING
---------------------------
March 31, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
</TABLE>
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:
<TABLE>
<CAPTION>
Twelve Months Ended March 31,
=================================
(Dollars in thousands)
<S> <C>
2002 $ 19,000
2003 $ 79,000
2004 $ 110,000
2005 $ 32,000
</TABLE>
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:
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
</TABLE>
(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:
<TABLE>
<CAPTION>
March 31, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
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
============ ============
</TABLE>
(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:
<TABLE>
<CAPTION>
Twelve Months Ended March 31,
================================
(Dollars in thousands)
<S> <C>
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
========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
March 31, March 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Three months ended $ 2,710 $ 2,666
Twelve months ended $11,182 $ 9,909
</TABLE>
(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:
<TABLE>
<CAPTION>
March 31, 2000 December 31, 1999
---------------------- ----------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
</TABLE>
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."
<TABLE>
<CAPTION>
For the Three Months Adjust-
Ended March 31, 2000 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
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
<CAPTION>
For the Three Months Adjust-
Ended March 31, 1999 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
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
<CAPTION>
For the Twelve Months Adjust-
Ended March 31, 2000 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
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
<CAPTION>
For the Twelve Months Adjust-
Ended March 31, 1999 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended March 31, Ended March 31,
------------------ ------------------
2000 1999 2000 1999
======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C>
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
======== ======== ======== ========
</TABLE>
<PAGE>
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:
<TABLE>
<CAPTION>
March 31, 2000
Compared to
March 31, 1999
---------------------------------
Three Twelve
Months Months
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
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:
<TABLE>
<CAPTION>
March 31, 2000
Compared to
March 31, 1999
-------------------------------
Three Twelve
Months Months
========= =========
(Dollars in thousands)
<S> <C> <C>
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
========= =========
</TABLE>
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."
<PAGE>
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
<PAGE>
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
<PAGE>
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
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
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.
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<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
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<PERIOD-START> JAN-01-2000
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<TOTAL-DEFERRED-CHARGES> 175,328
<OTHER-ASSETS> 183,651
<TOTAL-ASSETS> 3,659,571
<COMMON> 859,488
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<EARNINGS-AVAILABLE-FOR-COMM> 70,825
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