SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 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.)
801 E. 86th Avenue, Merrillville, Indiana 46410-6272
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (219) 853-5200
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports) and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No
-------- --------
As of October 31, 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 September 30, 2000, and
December 31, 1999, and the related consolidated statements of income,
retained earnings and cash flows for the three, nine and twelve month periods
ended September 30, 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
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Northern
Indiana Public Service Company and subsidiaries as of September 30, 2000, and
December 31, 1999, and the results of their operations and their cash flows
for the three, nine and twelve month periods ended September 30, 2000 and
1999, in conformity with accounting principles generally accepted in the
United States.
/s/ Arthur Andersen LLP
Chicago, Illinois
October 30, 2000
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
September 30, December 31,
ASSETS 2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
UTILITY PLANT, AT ORIGINAL COST (INCLUDING
CONSTRUCTION WORK IN PROGRESS OF
$232,127 AND $200,011 RESPECTIVELY)
(NOTE 2):
Electric $ 4,307,752 $ 4,237,427
Gas 1,357,316 1,323,528
Common 385,520 381,486
------------ ------------
6,050,588 5,942,441
Less - Accumulated depreciation
and amortization 3,148,994 2,993,412
------------ ------------
Total Utility Plant 2,901,594 2,949,029
------------ ------------
OTHER PROPERTY AND INVESTMENTS 2,670 2,668
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 10,151 6,145
Accounts receivable, less reserve of
$8,759 and $7,804, respectively (Note 2) 114,497 141,537
Fuel cost adjustment clause (Note 2) 0 4,201
Gas cost adjustment clause (Note 2) 46,157 36,787
Materials and supplies, at average cost 53,193 52,735
Electric production fuel, at average cost 26,521 31,968
Natural gas in storage, at last-in,
first-out cost (Note 2) 88,371 22,966
Price risk management assets 12,368 31,677
Prepayments and other 32,895 28,608
------------ ------------
Total Current Assets 384,153 356,624
------------ ------------
OTHER ASSETS:
Regulatory assets (Note 2) 178,542 186,080
Prepayments and other (Note 6) 204,086 161,053
------------ ------------
Total Other Assets 382,628 347,133
------------ ------------
$ 3,671,045 $ 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
September 30, 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) 134,029 136,118
------------ ------------
Common shareholder's equity 1,006,042 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) 52,180 54,030
Long-term debt excluding amounts due
within one year (Note 13) 905,199 920,413
------------ ------------
Total Capitalization 2,044,535 2,063,688
------------ ------------
CURRENT LIABILITIES -
Current portion of long-term
debt (Note 14) 18,000 158,000
Short-term borrowings (Note 15) 291,200 96,290
Accounts payable 162,022 129,532
Dividends declared on common and
preferred stocks 53,971 59,017
Customer deposits 26,541 24,264
Taxes accrued 86,714 115,761
Interest accrued 14,370 7,392
Fuel adjustment clause 1,421 0
Accrued employment costs 52,188 51,393
Price risk management liabilities 23,979 54,001
Other accruals 21,242 22,162
------------ ------------
Total Current Liabilities 751,648 717,812
------------ ------------
OTHER:
Deferred income taxes (Note 4) 566,917 592,022
Deferred investment tax credits, being
amortized over life of related property
(Note 4) 80,251 85,566
Deferred credits 48,843 47,105
Accrued liability for postretirement
benefits (Note 6) 146,076 137,211
Other noncurrent liabilities 32,775 12,050
------------ ------------
Total Other Liabilities 874,862 873,954
------------ ------------
COMMITMENTS AND CONTINGENCIES
(Notes 3, 16 and 17)
$ 3,671,045 $ 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 Nine Months
Ended September 30, Ended September 30,
---------- ---------- ---------- ----------
2000 1999 2000 1999
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 119,424 $ 84,156 $ 513,273 $ 435,237
Electric 292,216 324,940 800,690 853,294
---------- ---------- ---------- -----------
411,640 409,096 1,313,963 1,288,531
---------- ---------- ---------- -----------
Cost of Energy: (Note 2)
Gas costs 82,543 52,761 328,541 250,998
Fuel for electric
generation 64,824 72,092 178,794 188,020
Power purchased 6,958 28,181 22,221 62,965
---------- ---------- ---------- ----------
154,325 153,034 529,556 501,983
---------- ---------- ---------- ----------
Operating Margin 257,315 256,062 784,407 786,548
---------- ---------- ---------- ----------
Operating Expenses and
Taxes (except income):
Operation 59,960 53,215 181,406 185,955
Maintenance (Note 2) 12,632 14,515 51,135 50,226
Depreciation and
amortization (Note 2) 59,883 58,422 178,696 174,620
Taxes (except income) 16,776 17,751 49,028 55,807
---------- ---------- ---------- ----------
149,251 143,903 460,265 466,608
---------- ---------- ---------- ----------
Operating Income Before
Utility Income Taxes 108,064 112,159 324,142 319,940
---------- ---------- ---------- ----------
Utility Income Taxes
(Note 4) 31,872 33,029 96,071 94,084
---------- ---------- ---------- ----------
Operating Income 76,192 79,130 228,071 225,856
---------- ---------- ---------- ----------
Other Income (Deductions)
(Note 2) 270 1,681 2,086 1,701
---------- ---------- ---------- ----------
Interest:
Interest on long-term debt 14,883 16,951 48,461 50,544
Other interest 3,859 708 6,128 1,642
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 1,616 1,037 3,697 3,108
---------- ---------- ---------- ----------
20,358 18,696 58,286 55,294
---------- ---------- ---------- ----------
Net Income 56,104 62,115 171,871 172,263
Dividend requirements on
preferred shares 1,975 2,021 5,960 6,112
---------- ---------- ---------- ----------
Balance available
for common shares $ 54,129 $ 60,094 $ 165,911 $ 166,151
========== ========== ========== ==========
Dividends declared $ 53,000 $ 58,000 $ 168,000 $ 166,000
========== ========== ========== ==========
<CAPTION>
Twelve Months
Ended September 30,
---------- ----------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 722,723 $ 618,360
Electric 1,054,928 1,106,103
---------- ----------
1,777,651 1,724,463
---------- ----------
Cost of Energy: (Note 2)
Gas costs 457,152 354,353
Fuel for electric
generation 239,938 245,406
Power purchased 26,220 71,907
---------- ----------
723,310 671,666
---------- ----------
Operating Margin 1,054,341 1,052,797
---------- ----------
Operating Expenses and
Taxes (except income):
Operation 251,925 243,747
Maintenance (Note 2) 66,371 65,027
Depreciation and
amortization (Note 2) 237,631 232,520
Taxes (except income) 67,384 73,534
---------- ----------
623,311 614,828
---------- ----------
Operating Income Before
Utility Income Taxes 431,030 437,969
---------- ----------
Utility Income Taxes
(Note 4) 129,254 128,442
---------- ----------
Operating Income 301,776 309,527
---------- ----------
Other Income (Deductions)
(Note 2) (1,863) 1,049
---------- ----------
Interest:
Interest on long-term debt 65,612 67,502
Other interest 7,838 3,287
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 4,744 4,149
---------- ----------
78,194 74,938
---------- ----------
Net Income 221,719 235,638
Dividend requirements on
preferred shares 7,979 8,182
---------- ----------
Balance available
for common shares $ 213,740 $ 227,456
========== ==========
Dividends declared $ 226,000 $ 228,000
========== ==========
<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 Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------- ------------------- --------- ---------
2000 1999 2000 1999 2000 1999
========= ========= ========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT
BEGINNING OF
PERIOD $ 132,900 $ 144,195 $ 136,118 $ 146,138 $ 146,289 $ 146,833
ADD:
Net income 56,104 62,115 171,871 172,263 $ 221,719 $ 235,638
--------- --------- --------- --------- --------- ---------
189,004 206,310 307,989 318,401 $ 368,008 $ 382,471
--------- --------- --------- --------- --------- ---------
LESS:
Dividends
Cumulative
Preferred
stocks -
4-1/4% series 222 223 666 667 887 889
4-1/2% series 91 90 271 270 361 360
4.22% series 113 113 337 337 448 448
4.88% series 122 122 366 366 488 488
7.44% series 78 77 234 233 313 312
7.50% series 65 65 196 196 261 261
8.85% series 83 111 267 351 377 489
7-3/4% series 59 70 178 210 244 286
8.35% series 88 96 284 321 385 434
6.50% series 699 699 2,096 2,096 2,795 2,795
Adjustable
Rate,
Series A 355 355 1,065 1,065 1,420 1,420
Common shares 53,000 58,000 168,000 166,000 226,000 228,000
--------- --------- --------- --------- --------- ---------
54,975 60,021 173,960 172,112 233,979 236,182
--------- --------- --------- --------- --------- ---------
BALANCE AT END
OF PERIOD $ 134,029 $ 146,289 $ 134,029 $ 146,289 $ 134,029 $ 146,289
========= ========= ========= ========= ========= =========
<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 September 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 56,104 $ 62,115
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 59,883 58,422
Net changes for price risk management
assets and liabilities (11,729) 4,341
Deferred federal and state income
taxes, net (251) 3,287
Deferred investment tax credits, net (1,772) (1,782)
Other, net (8,343) (12,555)
Change in certain assets and liabilities -
Accounts receivable, net 22,373 10,452
Electric production fuel 9,968 3,871
Materials and supplies (20) (625)
Natural gas in storage (56,447) (23,825)
Accounts payable 9,999 16,678
Taxes accrued (20,762) (16,977)
Fuel adjustment clause (2,815) (8,452)
Gas cost adjustment clause (35,761) (19,731)
Accrued employment costs 3,122 3,585
Other accruals 9,928 1,015
Other, net 20,693 4,645
---------- ----------
Net cash provided by operating activities 54,170 84,464
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (48,673) (46,447)
Other, net (3,064) (3,881)
---------- ----------
Net cash used in investing activities (51,737) (50,328)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 56,800 20,910
Retirement of long-term debt (500) (500)
Retirement of preferred shares (300) (601)
Cash dividends paid on common shares (57,000) (53,000)
Cash dividends paid on preferred shares (1,972) (2,023)
Other, net 73 114
---------- ----------
Net cash used in financing activities (2,899) (35,100)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS (466) (964)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 10,617 8,777
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,151 $ 7,813
========== ==========
<CAPTION>
Nine Months
Ended September 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 171,871 $ 172,263
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 178,696 174,620
Net changes for price risk management
assets and liabilities (10,713) 8,361
Deferred federal and state operating
income taxes, net (32,429) (31,170)
Deferred investment tax credits, net (5,315) (5,345)
Other, net (6,205) (11,605)
Change in certain assets and liabilities -
Accounts receivable, net 22,830 4,522
Electric production fuel 5,447 9,311
Materials and supplies (458) (665)
Natural gas in storage (65,405) 1,475
Accounts payable 37,662 8,323
Taxes accrued (25,685) (988)
Fuel adjustment clause 5,622 (11,994)
Gas cost adjustment clause (9,370) 31,378
Accrued employment costs 795 (3,248)
Other accruals (1,220) (9,163)
Other, net 16,959 9,708
---------- ----------
Net cash provided by operating activities 283,082 345,783
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (129,714) (133,156)
Other, net (8,238) (9,203)
---------- ----------
Net cash used in investing activities (137,952) (142,359)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 194,910 (36,990)
Retirement of long-term debt (155,500) (500)
Retirement of preferred shares (1,850) (1,852)
Cash dividends paid on common shares (173,000) (170,000)
Cash dividends paid on preferred shares (5,970) (6,151)
Other, net 286 341
---------- ----------
Net cash used in financing activities (141,124) (215,152)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS 4,006 (11,728)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 6,145 19,541
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,151 $ 7,813
========== ==========
<CAPTION>
Twelve Months
Ended September 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 221,719 $ 235,638
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 237,631 232,520
Net changes for price risk management
assets and liabilities 3,250 8,361
Deferred federal and state operating
income taxes, net (20,755) (17,214)
Deferred investment tax credits, net (7,096) (7,158)
Other, net 495 (11,130)
Change in certain assets and liabilities -
Accounts receivable, net 7,222 (38,331)
Electric production fuel (3,430) (5,551)
Materials and supplies (974) (1,281)
Natural gas in storage (38,987) 5,923
Accounts payable 19,099 44,800
Taxes accrued 11,843 (14,229)
Fuel adjustment clause 7,136 (8,768)
Gas cost adjustment clause (33,491) 17,346
Accrued employment costs 11,213 1,314
Other accruals 1,859 (5,093)
Other, net (22,899) (679)
---------- ----------
Net cash provided by operating activities 393,835 436,468
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (189,396) (188,600)
Other, net (5,190) 4,781
---------- ----------
Net cash used in investing activities (194,586) (183,819)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Issuance of long-term debt 0 500
Net change in short-term debt 202,090 (4,290)
Retirement of long-term debt (158,000) (16,509)
Retirement of preferred shares (2,405) (2,409)
Cash dividends paid on common shares (231,000) (225,000)
Cash dividends paid on preferred shares (7,995) (8,226)
Other, net 399 454
---------- ----------
Net cash used in financing activities (196,911) (255,480)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS 2,338 (2,831)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 7,813 10,644
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,151 $ 7,813
========== ==========
<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 its name to NiSource Inc.
on April 14, 1999 to reflect its new direction as a multi-state supplier
of energy 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 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 approximate weighted average remaining lives
for major components of electric and gas plant are as follows:
Electric:
--------
Electric generation plant 24 years
Transmission plant 26 years
Distribution plant 25 years
Other electric plant 24 years
Gas:
----
Gas storage plant 18 years
Transmission plant 34 years
Distribution plant 27 years
Other gas plant 24 years
The depreciation provision for electric utility plant, as a percentage
of the original cost, was 3.7% for the three month, nine month and twelve
month periods ended September 30, 2000 and September 30, 1999.
The depreciation provision for gas utility plant, as a percentage of the
original cost, was 5.5% for the three month, nine month and twelve month
periods ended September 30, 2000 and 5.4% for the three month and nine month
periods and 5.5% for the twelve month period ended September 30, 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 September 30, 2000, $100 million of accounts
receivable had been sold under a sales agreement, which expires on May 31,
2002. The September 30, 2000 and December 31, 1999 accounts receivable
balances include approximately $12.8 million and $14.0 million, respectively,
due from associated companies.
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 Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------ ------------------ ------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 42,900 $ 39,250 $141,343 $125,336 $141,587 $169,641
Interest, net of
amounts
capitalized $ 7,927 $ 9,509 $ 42,258 $ 43,492 $ 70,501 $ 70,343
</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 (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 Generic Order to the Indiana Court of Appeals. All
briefs have been filed and the case is pending Court decision. Northern
Indiana applied the Generic Order's guidelines to purchased power transactions
sought to be recovered for February, March and April 2000.
By an order issued February 23, 2000, the IURC approved the recovery of
Northern Indiana's purchased power transactions during the months of July,
August and September 1999. Northern Indiana and the OUCC filed petitions for
reconsideration of the February 23, 2000 Order.
On June 30, 2000, Northern Indiana and the OUCC filed a joint motion to
withdraw petitions for reconsideration and requested IURC approval of a
Stipulation and Agreement (Agreement). The Agreement establishes a recovery
mechanism for certain purchase power transactions for the months of July,
August and September 2000 that will be utilized in lieu of the IURC's Generic
Order guidelines. The Agreement also calls for Northern Indiana to return,
by an adjustment to fuel adjustment clause factors, $1.8 million to retail
ratepayers during the period from November 2000 through April 2001. Northern
Indiana has established a reserve for this amount. By its order issued
August 9, 2000, the IURC approved the Agreement. On September 5, 2000, the
Court of Appeals issued an order approving a joint stipulation for dismissal
with prejudice, of the OUCC's appeal of the Generic Order.
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 hearings 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. Northern Indiana made its annual filing on September 1, 2000 and the
matter is scheduled for hearing on December 14, 2000.
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 also includes a gas cost
incentive mechanism (GCIM) which allows or the sharing of any cost savings or
cost increases with customers based upon a comparison of actual gas supply
portfolio cost to a market-based benchmark price.
NATURAL GAS IN STORAGE. Natural gas in storage is valued using the
last-in, first-out (LIFO) inventory methodology. Based on the average cost
of gas purchased in September 2000 and December 1999, the estimated
replacement cost of gas in storage (current and non-current) at September 30,
2000 and December 31, 1999 exceeded the stated LIFO cost by $138.2 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 Corporate Services Company (NCSC), a
wholly-owned subsidiary of NiSource.
The costs of these services are charged to Northern Indiana based on
payroll costs and expenses incurred by NCSC employees for the benefit of
Northern Indiana. These costs, which totaled $6.7 million, $19.3 million and
$22.9 million for the three month, nine month and twelve month periods ended
September 30, 2000, respectively, and totaled $4.7 million, $14.2 million and
$19.1 million for the three month, nine month and twelve month periods ended
September 30, 1999, respectively, consist primarily of employee compensation
and benefits.
Northern Indiana purchased natural gas and transportation services
from affiliated companies in the amounts of $24.2 million, $41.8 million and
$45.8 million representing 19.8%, 12.2% and 9.9% of Northern Indiana's total
gas costs for the three month, nine month and twelve month periods ended
September 30, 2000, respectively. Northern Indiana purchased natural gas and
transportation services from affiliated companies in the amounts of $6.4
million, $12.3 million and $14.7 million representing 15.1%, 5.6% and 4.7% of
Northern Indiana's total gas costs for the three month, nine month and twelve
month periods ended September 30, 1999, respectively.
Northern Indiana 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 ACTIVITIES. 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 electric 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 and SFAS No. 138, "Accounting for
Certain Derivatives Instruments and Certain Hedging Activities - an amendment
of FASB No. 133" in June 2000. Statement No. 133 as amended standardizes the
accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, by requiring that a company recognize
those items as assets or liabilities in the balance sheet and measure them at
fair value. The standard also suggests in certain circumstances commodity based
contracts may qualify as derivatives. 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
provides 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, 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 will adopt
SFAS No. 133 on January 1, 2001, but has not completed its determination of
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 is in the process of
projecting the impact of SFAS No. 133 but has not yet quantified the other
effects of adopting SFAS No. 133 on its financial statements. However,
adoption of SFAS No. 133 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 September 30, 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>
September 30, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
Unamortized reacquisition premium on
debt (Note 13) $ 36,901 $ 39,499
Unamortized R. M. Schahfer Unit 17 and
Unit 18 carrying charges
and deferred depreciation (See below) 54,948 58,111
Bailly scrubber carrying charges and
deferred depreciation (See below) 7,308 8,010
Deferral of SFAS No. 106 expense not
recovered (Note 6) 68,571 72,769
FERC Order No. 636 transition costs 9,097 13,728
Regulatory income tax asset, net (Note 4) 21,330 18,208
------------- -------------
198,155 210,325
Less: Current portion of regulatory assets 19,613 24,245
------------- -------------
$ 178,542 $ 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 the Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA) at several waste disposal sites, as well as at
former manufactured-gas plant sites which it, or its corporate predecessors,
own or owned or operated, it may be required to share in the 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 sites. Initial sampling has been conducted at
twenty sites. Investigation activities have been completed at fifteen
sites and remedial measures have been selected or implemented at thirteen
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 solvent 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 September 30, 2000, a reserve of approximately $16.7 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,
existing reserves, 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 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 States 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. The state-led group requested a
hearing of the issue from the full court. On June 22, 2000, the court denied
the rehearing and lifted the stay for the state plan submittals. The states
now have until the end of October 2000 to submit their plans implementing the
EPA NOx SIP Call. Further legal challenges are expected, including an appeal
to the United States Supreme Court. 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 court decision and any
potential requirements that could result from the rules 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. The Supreme Court
has agreed to here appeals from the Court of Appeals Decision. 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 September 30,
2000 and December 31, 1999 were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
Deferred tax liabilities -
Accelerated depreciation
and other property differences $ 699,432 $ 714,246
AFUDC-equity 29,410 30,748
Adjustment clauses 16,966 15,545
Other regulatory assets 26,006 27,598
Prepaid pension and other benefits 55,440 56,227
Reacquisition premium on debt 13,995 14,980
Deferred tax assets -
Deferred investment tax credits (30,435) (32,451)
Removal costs (181,118) (171,645)
Other postretirement/postemployment
benefits (55,399) (53,061)
Other, net (28,505) (27,928)
------------- -------------
545,792 574,259
Less: Deferred income taxes related to
current assets and liabilities (21,125) (17,763)
------------- -------------
Deferred income taxes - noncurrent $ 566,917 $ 592,022
============= =============
</TABLE>
Deferred income taxes on price risk management assets and liabilities
are reflected net as a component of Other, net above.
Federal and state income taxes as set forth in the Consolidated
Statements of Income were comprised of the following:
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
-------------------- --------------------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Current income taxes -
Federal $ 29,842 $ 27,636 $ 117,844 $ 114,289
State 4,053 3,888 15,971 16,310
--------- --------- --------- ---------
33,895 31,524 133,815 130,599
--------- --------- --------- ---------
Deferred income taxes, net -
Federal (231) 3,006 (29,926) (28,849)
State (20) 281 (2,503) (2,321)
--------- --------- --------- ---------
(251) 3,287 (32,429) (31,170)
--------- --------- --------- ---------
Deferred investment tax credits,
net (1,772) (1,782) (5,315) (5,345)
--------- --------- --------- ---------
Total utility operating income
taxes 31,872 33,029 96,071 94,084
Income tax applicable to non-
operating activities and income
of subsidiaries (275) 1,049 697 1,043
--------- --------- --------- ---------
Total income taxes $ 31,597 $ 34,078 $ 96,768 $ 95,127
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended September 30,
--------------------
2000 1999
========= =========
(Dollars in thousands)
<S> <C> <C>
Current income taxes -
Federal $ 139,342 $ 134,355
State 17,763 18,459
--------- ---------
157,105 152,814
--------- ---------
Deferred income taxes, net -
Federal (19,268) (16,082)
State (1,487) (1,132)
--------- ---------
(20,755) (17,214)
--------- ---------
Deferred investment tax credits,
net (7,096) (7,158)
--------- ---------
Total utility operating income
taxes 129,254 128,442
Income tax applicable to non-
operating activities and income
of subsidiaries (1,931) 958
--------- ---------
Total income taxes $ 127,323 $ 129,400
========= =========
</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 Nine Months
Ended September 30, Ended September 30,
--------- --------- --------- ---------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Net income $ 56,104 $ 62,115 $ 171,871 $ 172,263
Add-Income taxes 31,597 34,078 96,768 95,127
--------- --------- --------- ---------
Net income before income taxes $ 87,701 $ 96,193 $ 268,639 $ 267,390
========= ========= ========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 30,696 $ 33,668 $ 94,024 $ 93,587
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 918 969 2,753 2,906
Amortization of deferred
investment tax credits (1,772) (1,782) (5,315) (5,345)
State income taxes, net of
federal income tax benefit 2,614 2,809 7,878 8,281
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (920) (721) (2,758) (2,163)
Other, net 61 (865) 186 (2,139)
--------- --------- --------- ---------
Total income taxes $ 31,597 $ 34,078 $ 96,768 $ 95,127
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended September 30,
--------- ---------
2000 1999
========= =========
(Dollars in thousands)
<S> <C> <C>
Net income $ 221,719 $ 235,638
Add-Income taxes 127,323 129,400
--------- ---------
Net income before income taxes $ 349,042 $ 365,038
========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 122,165 $ 127,763
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 3,781 3,904
Amortization of deferred
investment tax credits (7,096) (7,158)
State income taxes, net of
federal income tax benefit 10,058 10,866
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (6,052) (4,822)
Other, net 4,467 (1,153)
--------- ---------
Total income taxes $ 127,323 $ 129,400
========= =========
</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 December 31,1999 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 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. Discount rates of 7.75% and 7.00% and rates 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 $190.5 million and
$141.5 million at September 30, 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, nine month and twelve month periods ended September 30, 2000
and September 30, 1999:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------- -------- -------- -------- -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 4,265 $ 4,123 $ 12,796 $ 12,371 $ 16,283 $ 15,725
Interest costs 16,899 15,403 50,696 46,209 66,100 62,400
Expected return
on plan assets (24,367) (21,121) (73,101) (63,365) (94,224) (87,753)
Amortization of
transition
obligation 1,373 1,373 4,117 4,117 5,488 5,801
Amortization of
prior service
costs 1,398 1,398 4,196 4,196 5,596 5,543
Amortization of
(gain) (686) 0 (2,060) 0 (2,060) 0
-------- -------- -------- -------- -------- --------
$ (1,118) $ 1,176 $ (3,356) $ 3,528 $ (2,817) $ 1,716
======== ======== ======== ======== ======== ========
</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. 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 net actuarial (gain) (103,623) (90,700)
Unrecognized prior service cost 3,178 3,458
Unrecognized transition amount 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 $155.1 million at
September 30, 2000.
Net periodic postretirement benefits costs, before consideration of the
rate-making discussed previously, for the three month, nine month and twelve
month periods ended September 30, 2000 and September 30, 1999 include the
following components:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------- ------- ------- ------- ------- -------
2000 1999 2000 1999 2000 1999
======= ======= ======= ======= ======= =======
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 761 $ 781 $ 2,184 $ 2,608 $ 2,890 $ 3,032
Interest costs 3,900 3,850 11,700 11,550 13,835 14,285
Expected return
on plan assets (50) (50) (150) (150) (216) (216)
Amortization of
transition
obligation
over twenty years 2,700 2,675 8,100 8,025 10,823 10,748
Amortization of
prior service cost 75 75 225 225 279 279
Amortization of
actuarial (gain) (1,375) (1,150) (4,125) (3,450) (6,461) (5,111)
------- ------- ------- ------- ------- -------
$ 6,011 $ 6,181 $17,934 $18,808 $21,150 $23,017
======= ======= ======= ======= ======= =======
</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 and $1.8
million for the three month and nine month periods ended September 30, 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 $0.4 million and $1.4 million for
the three month and nine month periods ended September 30,2000. 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 default on the payment of four consecutive quarterly
dividends, or as required by Indiana law to authorize additional preferred
shares, or by the Articles of Incorporation in the event of certain merger
transactions.
(8) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF NORTHERN INDIANA,
OUTSTANDING AT SEPTEMBER 30, 2000 AND DECEMBER 31, 1999 (SEE NOTE 7):
<TABLE>
<CAPTION>
Redemption
Price at
September 30, December 31, September 30,
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
September 30, 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 October 1, 1998 to September 30, 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 SEPTEMBER 30, 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>
September 30, 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 - 39,000 and 45,000 shares
outstanding, respectively, excluding sinking
fund payments due within one year 3,900 4,500
Cumulative preferred stock - no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
------------ ------------
$ 52,180 $ 54,030
============ ============
</TABLE>
The redemption prices at September 30, 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% $102.95, 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 September 30, 2000 for each of the twelve month periods
subsequent to September 30, 2001, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
==================================
(Dollars in thousands)
<S> <C>
2002 $ 1,828
2003 $ 44,828
2004 $ 878
2005 $ 878
</TABLE>
Sinking fund payments due within one year are reported under the caption
"Other" included in Current Liabilities in the Consolidated Balance Sheet.
(10) COMMON SHARE DIVIDEND: Northern Indiana's Indenture dated August 1,
1939, as amended and supplemented (Indenture), provides that it will not
declare or pay any dividends on any class of capital stock (other than
preferred or preference stock) except out of the earned surplus or net profits
of Northern Indiana. At September 30, 2000, Northern Indiana had
approximately $134.0 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). The 1988 Plan, as amended and restated, and the
1994 Plan, as amended and restated, were re-approved by shareholders on
April 14, 1999. 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. Under
the Plans, the exercise price of each option equals the market price of common
stock on the date of grant. Each option has a maximum term of ten years and
vests one year from the date of grant.
The 1988 Plan provided for the issuance of up to 5.0 million common
shares to key employees through April 1998. On January 29, 2000, the Board of
Directors of NiSource approved certain additional amendments to the 1994 Plan
and on June 1, 2000, the 1994 Plan, as amended and restated, was approved by
shareholders at the 2000 Annual Meeting of Shareholders of NiSource. The
amended and restated 1994 Plan provides for the issuance of up to 11 million
shares through April 2004, and permits contingent stock awards and dividend
equivalents payable on grants of options, stock appreciation rights (SARs),
performance units and contingent stock awards. At September 30, 2000, there
were 6,006,336 shares reserved for future awards under the amended and
restated 1994 Plan.
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. 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 679,500 and 513,500 restricted shares
outstanding at September 30, 2000 and December 31, 1999, respectively.
Northern Indiana accounts for its allocable portion of these plans
under Accounting Principles Board Opinion No. 25, under which no compensation
cost has been recognized for nonqualified stock options. The compensation
cost that has been charged against net income for restricted stock awards was
0.2 million and $0.3 million for the three month, $0.5 million and $0.7
million for the nine month and $0.9 million and $0.9 million for the twelve
month periods ending September 30, 2000 and September 30, 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 Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------------------ ------------------ -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Net Income:
As reported $ 56,104 $ 62,115 $171,871 $172,263 $221,719 $235,638
Pro forma $ 55,368 $ 61,724 $169,910 $171,065 $219,347 $234,036
</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>
August January August August
2000 2000 1999 1998
========== ========== ========== ==========
<S> <C> <C> <C> <C>
Interest Rate 6.6% 6.60% 5.87% 5.29%
Expected Dividend Yield $1.08 $1.08 $1.02 $0.96
Expected Life 5.8 years 5.4 years 5.25 years 5.4 years
Volatility 26.16% 28.98% 15.72% 13.09%
</TABLE>
The weighted average fair value of options granted to all plan
participants was $4.33 and $3.66 for the twelve month periods ended
September 30, 2000 and September 30, 1999, respectively. There were
1,235,000 and 744,750 non-qualified stock options granted to all plan
participants for the twelve month periods ended September 30, 2000 and
September 30, 1999, respectively.
(13) LONG-TERM DEBT: At September 30, 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
---------------------------
September 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
First mortgage bonds -
Series T, 7-1/2%, due April 1, 2002 $ 38,000 $ 38,500
Series NN, 7.10%, due July 1, 2017 55,000 55,000
------------ ------------
Total 93,000 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 - 4.50% weighted
average at September 30, 2000, due
November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County -
Series D - 4.47% weighted average at
September 30, 2000, due November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County -
Series A - 5.55% at September 30, 2000,
due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County -
Series B - 5.55% at September 30, 2000,
due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County -
Series C - 5.55% at September 30, 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 7.06%
and various maturities between
June 3, 2002 and August 4, 2027 578,025 593,025
------------ ------------
Unamortized premium and discount
on long-term debt, net (2,826) (3,112)
------------ ------------
Total long-term debt excluding
amounts due in one year $ 905,199 $ 920,413
============ ============
</TABLE>
The sinking fund requirements and maturities of long-term debt
outstanding at September 30, 2000 for each of the twelve month periods
subsequent to September 30, 2001, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
=================================
(Dollars in thousands)
<S> <C>
2002 $ 58,000
2003 $ 128,500
2004 $ 38,000
2005 $ 71,275
</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
September 30, 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 September 30, 2000 and
December 31, 1999, Northern Indiana's current portion of long-term debt due
within one year was as follows:
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Medium-term notes -
Interest rate 6.60%, due August 15, 2001 $ 15,000 $ 155,000
Sinking funds due within one year 3,000 3,000
------------ ------------
Total current portion of long-term debt $ 18,000 $ 158,000
============ ============
</TABLE>
(15) SHORT-TERM BORROWINGS: Northern Indiana entered into a 364-day $200
million revolving credit agreement that terminates on September 23, 2001.
Under this agreement, funds are borrowed at a floating rate of interest or,
under certain circumstances, at a fixed rate of interest for a short-term
period. This agreement provides financing flexibility and may be used to
support the issuance of commercial paper. As of September 30, 2000, there
were no borrowings outstanding under this agreement.
In addition, Northern Indiana has $11.4 million in lines of credit with
lenders at either the lender's commercial prime or market lending rates. As
of September 30, 2000, there were no borrowings under these lines of credit.
Northern Indiana also has $171.5 million of money market lines of
credit. As of September 30, 2000 and December 31, 1999, $107.7 million and
$33.7 million, respectively, were outstanding under these lines of credit.
At September 30, 2000 and December 31, 1999, Northern Indiana's short-
term borrowings were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Commercial paper -
Weighted average interest rate of 6.59% $ 183,500 $ 62,565
at September 30, 2000
Notes payable -
Issued at interest rates between 6.65%
and 7.60% with a weighted average
interest rate of 6.82% and maturities
of October 2, 2000 and October 17, 2000 107,700 33,725
------------ ------------
Total short-term borrowings $ 291,200 $ 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 September 30, 2000:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
================================
(Dollars in thousands)
<S> <C>
2001 $ 7,030
2002 7,030
2003 7,031
2004 5,643
2005 4,060
Later years 28,415
--------
Total minimum
payments required $ 59,209
========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
September 30, September 30,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Three months ended $ 2,699 $ 2,919
Nine months ended $ 8,105 $ 8,210
Twelve months ended $11,033 $10,637
</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
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-
based derivative 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 and certain customer choice programs. At
September 30, 2000, Northern Indiana had no futures contracts outstanding.
Northern Indiana's trading operations include 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 $0.9 million,
$1.8 million and $0.5 million, $0.7 million, $2.1 million and $0.004 million and
$0.7 million, $2.1 million and $0.004 million for the three month, nine month
and twelve month periods ended September 30, 2000, respectively.
Unrealized gains and losses on Northern Indiana's trading 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 Consolidated Balance Sheet reflects price risk management
assets of $14.2 million and $31.7 million at September 30, 2000 and December 31,
1999, respectively, of which $12.4 million and $31.7 million were included in
"Price risk management assets" and $1.8 million and $0.0 million were
included under the caption "Prepayments and other" included in the Other
Assets at September 30, 2000 and December 31, 1999, respectively. The
accompanying Consolidated Balance Sheet also reflects price risk management
liabilities (including net option premiums) of $44.5 million and $54.0 million
of which $24.0 million and $54.0 million were included in "Price risk
management liabilities" and $20.5 million and $0.0 million were included in
"Other noncurrent liabilities" at September 30, 2000 and December 31, 1999,
respectively. Power trading results are reflected on a net basis in the
accompanying Consolidated Statements of Income, consistent with the guidance in
EITF Issue No. 98-10 with respect to the use of written options and its
settlement methodology with respect to physical forward sales and purchase
contracts.
Northern Indiana has recorded as a component of electric revenues a
realized net profit of $3.1 million, $10.7 million and $13.1 million for the
three month, nine month and twelve month periods ended September 30, 2000,
respectively, and $5.0 million, $8.6 million and $8.6 million for the
three month, nine month and twelve months ended September 30, 1999,
respectively. These net amounts reflect realized revenues and cost of sales
related to option contracts and physical forward sales and purchase contracts
as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
-------- -------- -------- -------- -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Power trading
revenues $203,085 $121,461 $378,003 $178,339 $437,420 $178,339
Power trading
cost of sales $203,154 $115,264 $370,339 $171,294 $429,466 $171,294
</TABLE>
(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>
September 30, 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 $ 10,151 $ 10,151 $ 6,145 $ 6,145
Investments $ 251 $ 251 $ 251 $ 251
Long-term debt (including
current portion) $ 923,199 $ 841,535 $1,078,413 $ 997,196
Preferred stock (including
current portion) $ 135,122 $ 110,064 $ 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 2% of gas revenues (including
transportation services) and 20% of electric revenues for the twelve months
ended September 30, 2000 as compared to 3% and 17%, respectively, for the
twelve months ended September 30,1999.
(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
certain quantitative thresholds.
Revenues for each segment are attributable to customers in the United
States.
The following tables provide information about business segments.
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 September 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $119,424 $ 292,216 $ 0 $ 0 $ 411,640
Other income (deductions)$ (106) $ (29) $ 405 $ 0 $ 270
Depreciation and
amortization $ 19,481 $ 40,402 $ 0 $ 0 $ 59,883
Income before interest
and utility income
taxes $ (9,413) $ 117,342 $ 405 $ 0 $ 108,334
Assets $949,661 $2,721,384 $ 0 $ 0 $3,671,045
Capital expenditures $ 15,275 $ 33,398 $ 0 $ 0 $ 48,673
<CAPTION>
For the Three Months Adjust-
Ended September 30, 1999 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 84,156 $ 324,940 $ 0 $ 0 $ 409,096
Other income (deductions)$ 126 $ 332 $ 1,224 $ (1) $ 1,681
Depreciation and
amortization $ 18,685 $ 39,737 $ 0 $ 0 $ 58,422
Income before interest
and utility income
taxes $ (4,334) $ 116,951 $ 1,223 $ 0 $ 113,840
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 21,801 $ 24,646 $ 0 $ 0 $ 46,447
<CAPTION>
For the Nine Months Adjust-
Ended September 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $513,273 $ 800,690 $ 0 $ 0 $1,313,963
Other income (deductions)$ 361 $ 48 $ 1,709 $ (32) $ 2,086
Depreciation and
amortization $ 58,136 $ 120,560 $ 0 $ 0 $ 178,696
Income before interest
and utility income
taxes $ 39,768 $ 284,783 $ 1,712 $ (35) $ 326,228
Assets $949,661 $2,721,384 $ 0 $ 0 $3,671,045
Capital expenditures $ 38,582 $ 91,132 $ 0 $ 0 $ 129,714
<CAPTION>
For the Nine Months Adjust-
Ended September 30, 1999 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $435,237 $ 853,294 $ 0 $ 0 $1,288,531
Other income (deductions)$ 908 $ 671 $ 161 $ (39) $ 1,701
Depreciation and
amortization $ 55,835 $ 118,785 $ 0 $ 0 $ 174,620
Income before interest
and utility income
taxes $ 45,610 $ 275,909 $ 110 $ 12 $ 321,641
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 42,995 $ 90,161 $ 0 $ 0 $ 133,156
<CAPTION>
For the Twelve Months Adjust-
Ended September 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $722,723 $1,054,928 $ 0 $ 0 $1,777,651
Other income (deductions)$ 1,324 $ 85 $ (3,257) $ (15) $ (1,863)
Depreciation and
amortization $ 77,317 $ 160,314 $ 0 $ 0 $ 237,631
Income before interest
and utility income
taxes $ 68,259 $ 364,180 $ (3,256) $ (16) $ 429 167
Assets $949,661 $2,721,384 $ 0 $ 0 $3,671,045
Capital expenditures $ 56,928 $ 132,468 $ 0 $ 0 $ 189,396
<CAPTION>
For the Twelve Months Adjust-
Ended September 30, 1999 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $618,360 $1,106,103 $ 0 $ 0 $1,724,463
Other income (deductions)$ 1,495 $ 869 $ (1,209) $ (106) $ 1,049
Depreciation and
amortization $ 74,054 $ 158,466 $ 0 $ 0 $ 232,520
Income before interest
and utility income
taxes $ 78,982 $ 361,351 $ (1,303) $ (12) $ 439,018
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 60,638 $ 127,962 $ 0 $ 0 $ 188,600
</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 September 30, 2000 and 1999:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------ ------------------ ------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income before
interest and
utility income
taxes $108,334 $113,840 $326,228 $321,641 $429,167 $439,018
Interest 20,358 18,696 58,286 55,294 $ 78,194 $ 74,938
Utility income
taxes 31,872 33,029 96,071 94,084 $129,254 $128,442
-------- -------- -------- -------- -------- --------
Net income $ 56,104 $ 62,115 $171,871 $172,263 $221,719 $235,638
======== ======== ======== ======== ======== ========
</TABLE>
(22) EVENT (UNAUDITED) SUBSEQUENT TO DATE OF AUDITORS' REPORT: On
November 1, 2000, NiSource, the Parent Company of Northern Indiana, completed
its acquisition of Columbia Energy Group (CEG) for approximately $6 billion,
plus the assumption of approximately $2 billion of CEG debt.
<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 $722.7 million for the twelve months
ended September 30, 2000, an increase of $104.4 million from the comparable
period ended twelve months ended September 30, 1999. This increase was mainly
due to the pass-through of increased gas costs, increased gas transportation
services and increased revenue per dekatherm from wholesale customers,
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) decreased mainly
as a result of decreased deliveries to residential and commercial customers
reflecting heating degree-days being 3% lower than 1999 and decreased
wholesale gas sales, partially offset by increased deliveries to industrial
customers and increased gas transportation services.
Gas revenues were $513.3 million for the nine months ended
September 30, 2000, an increase of $78.0 million from the comparable period
ended September 30, 1999. This increase was mainly due to the pass-through of
increased gas costs and increased industrial sales, partially offset by
decreased sales to residential and commercial customers due to a significantly
warmer weather during the period. During the period, gas deliveries in dth
decreased mainly as a result of decreased gas deliveries to residential and
commercial customers reflecting heating degree-days 6% lower than 1999 and
decreased gas transportation services, partially offset by increased
industrial sales.
Gas revenues were $119.4 million for the three months ended
September 30, 2000, an increase of $35.2 million from the comparable period
ended September 30, 1999. This increase was mainly due to the pass-through of
increased gas costs, increased industrial sales and increased sales to
residential and commercial customers due to cooler weather during the period,
partially offset by decreased wholesale gas sales and decreased transportation
services. During the 2000 period, gas deliveries in dth decreased mainly as
a result of decreased wholesale gas sales and decreased gas transportation
services, partially offset by increased industrial sales and increased gas
deliveries to residential and commercial customers reflecting heating degree
days 51% higher 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 38.1 million, 133.8 million
and 183.7 million dth for others during the three month, nine month and twelve
month periods ended September 30, 2000, respectively.
The basic steel industry accounted for 39% of natural gas delivered
(including volumes transported) during the twelve months ended
September 30, 2000.
The components of the changes in gas operating revenues are shown in the
following table:
<TABLE>
<CAPTION>
September 30, 2000
Compared to
September 30, 1999
---------------------------------
Three Nine Twelve
Months Months Months
========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C>
Gas Revenue Changes -
Pass through of net changes in
purchased gas costs, gas storage,
and storage transportation costs $ 27,005 $ 90,546 $ 111,102
Gas transition costs (3) (451) (1,159)
Changes in sales levels 10,313 (14,701) (18,106)
Gas transported (772) 531 1,383
Wholesale gas (1,275) 2,111 11,143
--------- --------- ---------
Total Gas Revenue Change $ 35,268 $ 78,036 $ 104,363
========= ========= =========
</TABLE>
GAS COSTS OF ENERGY. Gas costs increased $102.8 million (29%) to $457.2
million for the twelve months ended September 30, 2000 from the comparable
period ended September 30, 1999, due to increased purchased 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 $3.49 per dth as compared to $2.37 for the
comparable period ended September 30, 1999.
Gas costs increased $77.5 million (31%) to $328.5 million for the nine
months ended September 30, 2000, from the comparable period ended
September 30, 1999, mainly due to increased gas costs per dth. The average
cost for purchased gas for the period, after adjustment for gas transition
costs billed to transport customers, was $3.61 per dth as compared to $2.39
for the comparable period ended September 30, 1999.
Gas costs increased $29.8 million (56%) to $82.5 million for the three
months ended September 30, 2000, from the comparable period ended
September 30, 1999, mainly due to increased gas costs per dth. The average
cost for purchased gas for the period, after adjustment for gas transition
costs billed to transport customers, was $5.08 per dth as compared to $2.97
for the comparable period ended September 30, 1999.
GAS OPERATING MARGIN. The gas operating margin for the twelve months
ended September 30, 2000 increased $1.5 million to $265.6 million from the
comparable period ended September 30, 1999. This increase is due to increased
deliveries to industrial customers and increased transportation services,
partially offset by decreased deliveries to residential and commercial customers
reflecting warmer heating season during the period and decreased wholesale gas
sales.
Gas operating margin of $184.7 million for the nine months ended
September 30, 2000 was relatively unchanged from the comparable period ended
September 30, 1999.
Gas operating margin increased $5.5 million to $36.9 million during the
three months ended September 30, 2000 from the comparable period ended
September 30, 1999. This increase is due to increased industrial sales and
increased sales to residential and commercial customers reflecting increased
heating days during the period, partially offset by decreased wholesale sales
and decreased transportation services.
ELECTRIC REVENUES. Electric revenues were $1.1 billion for the twelve
months ended September 30, 2000, a decrease of $51.2 million from the comparable
period ended September 30, 1999. The decrease in electric revenues was mainly
due to decreased sales to residential customers, decreased wholesale
transactions and decreased fuel costs, partially offset by increased sales to
commercial and industrial customers. Sales of electricity in kilowatt-hours
(kwh) decreased 5% from the comparable period ended September 30, 1999.
Electric revenues were $800.7 million for the nine months ended
September 30, 2000, a decrease of $52.6 million from the comparable period
ended September 30, 1999. The decrease in electric revenues was mainly due to
decreased sales to residential customers, decreased wholesale transactions and
decreased fuel costs, partially offset by increased sales to commercial and
industrial customers. Sales of electricity in kwh decreased 7% from the
comparable period ended September 30, 1999.
Electric revenues were $292.2 million for the three months ended
September 30, 2000, a decrease of $32.7 million from the comparable period
ended September 30, 1999. The decrease in electric revenues was mainly due to
decreased sales to residential and industrial customers, decreased wholesale
transactions and decreased fuel costs, partially offset by increased sales to
commercial customers. Sales of electricity in kwh decreased 8% from the
comparable period ended September 30, 1999.
The basic steel industry accounted for 33% of electric sales during the
twelve months ended September 30, 2000.
The components of the changes in electric operating revenues are shown in
the following table:
<TABLE>
<CAPTION>
September 30, 2000
Compared to
September 30, 1999
---------------------------------
Three Nine Twelve
Months Months Months
========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C>
Electric Revenue Changes-
Pass through of net changes in
fuel costs $ (12,234) $ (17,774) $ (20,182)
Changes in sales levels (6,958) 1,251 12,907
Wholesale sales (13,532) (36,081) (43,900)
--------- --------- ---------
Total Electric Revenue Change $ (32,724) $ (52,604) $ (51,175)
========= ========= =========
</TABLE>
ELECTRIC COST OF ENERGY. Cost of fuel for electric generation decreased
$5.5 million to $239.9 million for the twelve months ended September 30, 2000
from the comparable period ended September 30, 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 September 30, 1999, to
1.41 cents per kwh, for the twelve months ended September 30, 2000.
Cost of fuel for electric generation decreased $9.2 million to $178.8
million for the nine months ended September 30, 2000 from the comparable period
ended September 30, 1999. The decrease is primarily due to decreased fuel costs
per kwh generated. The average cost per kwh generated decreased 6% from the
comparable period ended September 30, 1999, to 1.40 cents per kwh.
Cost of fuel for electric generation decreased $7.3 million to $64.8
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999. The decrease is primarily due to decreased fuel costs
per kwh generated. The average cost per kwh generated decreased 3% from the
comparable period ended September 30, 1999, to 1.45 cents per kwh.
POWER PURCHASED. Power purchased decreased $45.7 million to $26.2 million
for the twelve months ended September 30, 2000 from the comparable period ended
in September 30, 1999. The decrease is a result of decreased bulk power
purchases and decreased cost per kwh.
Power purchased decreased $40.7 million to $22.2 million for the nine
months ended September 30, 2000 from the comparable period ended September 30,
1999. The decrease is as a result of decreased bulk power purchases and
decreased cost per kwh.
Power purchased decreased $21.2 million to $7.0 million for the three
months ended September 30, 2000 from the comparable period ended September 30,
1999. The decrease is as a result of decreased bulk power purchases and
decreased cost per kwh.
ELECTRIC OPERATING MARGIN. Operating margin from electric sales
for the twelve months ended September 30, 2000 were relatively unchanged from
the comparable period ended September 30, 1999.
Operating margin from electric sales decreased $2.6 million to $599.7
million for the nine months ended September 30, 2000 from the comparable
period ended September 30, 1999. This period results included a $1.8
million charge to earnings due to a change in the regulatory mechanism for
recovery of purchased power costs. This decrease is due to decreased sales
to residential customers and decreased wholesale transaction, partially offset
by increased sales to commercial and industrial customers.
Operating margin from electric sales decreased $4.2 million to $220.4
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999. This decrease is due to decreased sales to
residential and industrial customers and decreased wholesale transactions,
partially offset by increased sales to commercial customers.
OPERATING EXPENSES AND TAXES (EXCEPT INCOME). Operating expenses and
taxes (except income) increased $8.5 million to $623.3 million for the twelve
months ended September 30, 2000 from the comparable period ended September 30,
1999. Operating expenses and taxes (except income) decreased $6.3 million to
$460.3 million for the nine months ended September 30, 2000 from the comparable
period ended September 30, 1999. Operating expenses and taxes (except income)
increased $5.3 million to $149.3 million for the three months ended
September 30, 2000 from the comparable period ended September 30, 1999.
Operation expenses increased $8.2 million to $251.9 million for the
twelve months ended September 30, 2000 from the comparable period ended
September 30, 1999. The increase is mainly due to the favorable $13.0 million
insurance settlement related to manufactured gas plants site cleanup costs
received in September 1999, increased employee related costs of $2.2 million,
partially offset by decreased customer related costs of $2.8 million, decreased
expenses of electric production facilities of $1.6 million and other decreased
operating costs.
Operation expenses decreased $4.5 million to $181.4 million for the nine
months ended September 30, 2000 from the comparable period ended September 30,
1999. The decrease is mainly due to lower employee related costs of $7.4
million, decreased sales and marketing costs of $1.3 million, decreased customer
related costs of $1.4 million and various other decreased operating costs.
Operation expenses increased $6.7 million to $60.0 million for the three
months ended September 30, 2000 from the comparable period ended September 30,
1999. The increase is mainly due to the $13.0 million insurance settlement
related to manufacturing gas plants site cleanup costs received in September
1999, partially offset by decreased employee related costs of $1.8 million and
other decreased operating costs.
Maintenance expenses increased $1.3 million to $66.4 million for the
twelve months ended September 30, 2000 from comparable period ended
September 30, 1999 due to increased maintenance activity for electric
production facilities and electric distribution facilities.
Maintenance expenses increased $0.9 million to $51.1 million for the
nine months ended September 30, 2000 from comparable period ended
September 30, 1999 due to increased maintenance activity for electric
distribution facilities, partially offset by decreased maintenance activity
for electric production facilities.
Maintenance expenses decreased $1.9 million to $12.6 million for the
three months ended September 30, 2000 from comparable period ended
September 30, 1999 due to decreased maintenance activity for electric
production facilities and electric and gas distribution facilities.
Depreciation and amortization expenses increased $5.1 million to $237.6
million, $4.1 million to $178.7 million and $1.5 million to $59.9 million for
the twelve month, nine month and three month periods ended September 30, 2000,
respectively, from the comparable periods ended September 30, 1999, resulting
from plant additions.
Taxes (except income) decreased $6.2 million to $67.4 million, $6.8
million to $49.0 million and $1.0 million to $16.8 million for the twelve
month, nine month and three month periods ended September 30, 2000,
respectively, from the comparable periods ended September 30, 1999 mainly as a
result of decreased property tax expense.
Utility income taxes for the twelve months ended September 30, 2000
remained relatively unchanged from the comparable periods ended September 30,
1999. Utility income taxes for the nine months ended September 30, 2000
increased $2.0 million to $96.1 million from the comparable periods ended
September 30, 1999 as a result of increased pre-tax income. Utility income
taxes for the three months ended September 30, 2000 decreased $1.2 million to
$31.9 from the comparable period ended September 30, 1999 as a result of
decreased pre-tax income.
Other Income (Deductions) decreased $2.9 million to $(1.9) million for
the twelve months ended September 30, 2000 from the comparable period ended
September 30, 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) for the nine months ended September 30, 2000 were
relatively unchanged. Other Income (Deductions) decreased $1.4 million to
$0.3 million for the three months ended September 30, 2000 from the comparable
period ended September 30, 1999, mainly due to decreased power trading
activities.
Interest charges for the twelve months ended increased $3.3 million to
$78.2 million, $3.0 million to $58.3 million and $1.7 million to $20.4 million
for the twelve month, nine month and three month periods ended September 30,
2000, respectively, from the comparable periods ended September 30, 1999, due
to increased short-term borrowing.
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 September 30, 2000
and December 31, 1999, $183.5 million and $62.6 million of commercial paper
was outstanding, respectively. The weighted average interest rate of
commercial paper outstanding as of September 30, 2000 was 6.59%.
Northern Indiana entered into a 364-day $200 million revolving credit
agreement that terminates on September 23, 2001. Under this agreement, funds
are borrowed at a floating rate of interest or, under certain circumstances,
at a fixed rate of interest for a short-term periods. This agreement provides
financing flexibility and may be used to support the issuance of commercial
paper. As of September 30, 2000, there were no borrowings outstanding under
this agreement.
In addition, Northern Indiana has $11.4 million in lines of credit with
lenders at either the lender's commercial prime or market lending rates. As
of September 30, 2000, there were no borrowings under these lines of credit.
Northern Indiana also has $171.5 million of money market lines of
credit. As of September 30, 2000 and December 31, 1999, $107.7 million and
$33.7 million, respectively, were outstanding under these lines of credit.
Northern Indiana has arranged to put in place bond insurance to make the
variable rate Jasper County Pollution Control Bonds more marketable. The bond
insurance is scheduled to be in place for the 1988 series bonds on
November 15, 2000 and on December 1, 2000 for the 1994 series bonds.
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 Northern Indiana 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 intends to oppose the petition on both legal
and factual grounds, and believes that its current rates are just and
reasonable as required by statute. On May 17, 2000 the IURC issued an order
finding, among other things, that the type of investigation requested by CAC
could only be conducted by the IURC itself. Northern Indiana has been meeting
with the interested parties in this proceedings. As of October 30, 2000, no
further orders have been issued in this proceeding.
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 its energy trading portfolios. 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
exposure for power trading on an average, high and low basis was $0.9
million, $1.8 million and $0.5 million, $0.7 million, $2.1 million and $0.004
million and $0.7 million, $2.1 million and $0.004 million for the three month,
nine month and twelve month periods ended September 30, 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 purchased power, 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 September 30, 2000 and
December 31, 1999, the combined borrowings outstanding under these facilities
totaled $291.2 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 $2.7 million and $0.7 million for the three months, $4.6 million
and $1.9 million for the nine months and $5.5 million and $3.0 million for the
twelve months ending September 30, 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
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" in Notes to the
Consolidated Financial Statements for further discussion of Northern Indiana's
risk management.
Refer to "Risk Management Activities," in Notes to the 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
previously had, 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 choice for new products and services.
THE ELECTRIC INDUSTRY. At the Federal level, the Federal Energy
Regulatory Commission (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. On
June 30, 2000, the D.C. Circuit Court of Appeals upheld FERC's open access
orders in all major respects. 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). On October 16, 2000, Northern Indiana filed with the FERC indicating
that it is committed to joining a RTO and that it would likely join the
Alliance RTO. 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 and with other segments of the Indiana electric industry
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. The gas
cost incentive mechanism will be reviewed by parties to the ARP proceeding for
possible revision. 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 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 Indiana's control.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For a discussion of primary market risks and risk management policy,
see "Management's Discussion and Analysis of Financial Condition and Results
of Operations-Market Risk Sensitive Instruments and Positions."
<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 or 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 November 13, 2000
