SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended September 30, 1999
Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ________________ to ________________
Commission file number 1-4125
NORTHERN INDIANA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Indiana 35-0552990
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5265 Hohman Avenue, Hammond, Indiana 46320-1775
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (219) 853-5200
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports) and (2)
has been subject to such filing requirements for the past 90 days.
Yes X No
-------- --------
As of October 31, 1999, 73,282,258 common shares were outstanding.
<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 sheets of Northern
Indiana Public Service Company (an Indiana corporation and a wholly owned
subsidiary of NiSource Inc.) and subsidiaries as of September 30, 1999,
and December 31, 1998, and the related consolidated statements of
income, retained earnings and cash flows for the three, nine and twelve month
periods ended September 30, 1999 and 1998. These consolidated financial
statements are the responsibility of the company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Northern
Indiana Public Service Company and subsidiaries as of September 30, 1999, and
December 31, 1998, and the results of their operations and their cash flows
for the three, nine and twelve month periods ended September 30, 1999 and
1998, in conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Chicago, Illinois
November 9, 1999
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
ASSETS 1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
UTILITY PLANT, AT ORIGINAL COST (INCLUDING
CONSTRUCTION WORK IN PROGRESS OF
$192,761 AND $149,426 RESPECTIVELY)
(NOTE 2):
Electric $ 4,217,811 $ 4,154,060
Gas 1,311,413 1,272,483
Common 365,101 364,822
------------ ------------
5,894,325 5,791,365
Less - Accumulated depreciation
and amortization 2,943,983 2,804,720
------------ ------------
Total Utility Plant 2,950,342 2,986,645
------------ ------------
OTHER PROPERTY AND INVESTMENTS 2,636 519
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 7,813 19,541
Accounts receivable, less reserve of
$8,442 and $4,458, respectively (Note 2) 133,032 104,445
Fuel cost adjustment clause (Note 2) 5,715 0
Gas cost adjustment clause (Note 2) 12,666 44,044
Materials and supplies, at average cost 52,219 51,554
Electric production fuel, at average cost 23,091 32,402
Natural gas in storage, at last-in,
first-out cost (Note 2) 49,384 50,859
Prepayments and other 25,029 31,056
------------ ------------
Total Current Assets 308,949 333,901
------------ ------------
OTHER ASSETS:
Regulatory assets (Note 2) 200,958 203,722
Prepayments and other (Note 5) 149,491 127,162
------------ ------------
Total Other Assets 350,449 330,884
------------ ------------
$ 3,612,376 $ 3,651,949
============ ============
<FN>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
CAPITALIZATION AND LIABILITIES 1999 1998
============ ============
(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 12,524
Retained earnings (see accompanying
statement) (Note 10) 146,289 146,138
------------ ------------
Common shareholder's equity 1,018,302 1,018,150
Cumulative preferred stocks,
(excluding amounts due within one
year) (Note 7)
Series without mandatory redemption
provisions (Note 8) 81,114 81,116
Series with mandatory redemption
provisions (Note 9) 54,585 56,435
Long-term debt excluding amounts due
within one year (Note 13) 922,800 1,077,959
------------ ------------
Total Capitalization 2,076,801 2,233,660
------------ ------------
CURRENT LIABILITIES -
Current portion of long-term
debt (Note 14) 157,000 2,000
Short-term borrowings (Note 15) 89,110 126,100
Accounts payable 143,750 142,414
Dividends declared on common and
preferred stocks 59,028 63,101
Customer deposits 22,887 20,178
Taxes accrued 73,368 88,401
Interest accrued 15,023 9,118
Fuel adjustment clause 0 6,279
Accrued employment costs 40,975 44,223
Other accruals 47,823 28,546
------------ ------------
Total Current Liabilities 648,964 530,360
------------ ------------
OTHER:
Deferred income taxes (Note 4) 600,670 608,935
Deferred investment tax credits, being
amortized over life of related property
(Note 4) 87,348 92,693
Deferred credits 50,044 48,084
Accrued liability for postretirement
benefits (Note 6) 137,051 127,115
Other noncurrent liabilities 11,498 11,102
------------ ------------
Total Other Liabilities 886,611 887,929
------------ ------------
COMMITMENTS AND CONTINGENCIES
(Notes 3, 16 and 17)
$ 3,612,376 $ 3,651,949
============ ============
<FN>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
Three Months Nine Months
Ended September 30, Ended September 30,
---------------------- ----------------------
1999 1998 1999 1998
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 84,156 $ 71,773 $ 435,237 $ 389,362
Electric 324,940 311,512 862,203 823,309
---------- ---------- ---------- ----------
409,096 383,285 1,297,440 1,212,671
---------- ---------- ---------- ----------
Cost of Energy: (Note 2)
Gas costs 52,761 39,304 250,998 217,678
Fuel for electric
generation 72,092 72,246 188,020 193,263
Power purchased 28,181 17,001 71,899 33,048
---------- ---------- ---------- ----------
153,034 128,551 510,917 443,989
---------- ---------- ---------- ----------
Operating Margin 256,062 254,734 786,523 768,682
---------- ---------- ---------- ----------
Operating Expenses and
Taxes (except income):
Operation 53,215 64,211 185,955 188,128
Maintenance (Note 2) 14,515 15,180 50,226 50,501
Depreciation and
amortization (Note 2) 58,422 57,327 174,620 170,647
Taxes (except income) 17,751 17,901 55,807 54,500
---------- ---------- ---------- ----------
143,903 154,619 466,608 463,776
---------- ---------- ---------- ----------
Operating Income Before
Utility Income Taxes 112,159 100,115 319,915 304,906
---------- ---------- ---------- ----------
Utility Income Taxes
(Note 4) 33,029 28,077 94,084 86,428
---------- ---------- ---------- ----------
Operating Income 79,130 72,038 225,831 218,478
---------- ---------- ---------- ----------
Other Income (Deductions)
(Note 2) 1,681 (1,061) 1,726 (2,937)
---------- ---------- ---------- ----------
Interest:
Interest on long-term debt 16,951 17,403 50,544 52,714
Other interest 708 1,302 1,642 2,879
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 1,037 1,043 3,108 3,143
---------- ---------- ---------- ----------
18,696 19,748 55,294 58,736
---------- ---------- ---------- ----------
Net Income 62,115 51,229 172,263 156,805
Dividend requirements on
preferred shares 2,021 2,072 6,112 6,265
---------- ---------- ---------- ----------
Balance available
for common shares $ 60,094 $ 49,157 $ 166,151 $ 150,540
========== ========== ========== ==========
Dividends declared $ 58,000 $ 55,000 $ 166,000 $ 150,000
========== ========== ========== ==========
<CAPTION>
Twelve Months
Ended September 30,
----------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
Operating Revenues:
(Notes 2, 3 and 20)
Gas $ 618,360 $ 628,940
Electric 1,115,012 1,071,293
---------- ----------
1,733,372 1,700,233
---------- ----------
Cost of Energy: (Note 2)
Gas costs 354,353 367,794
Fuel for electric
generation 245,406 253,786
Power purchased 80,841 37,701
---------- ----------
680,600 659,281
---------- ----------
Operating Margin 1,052,772 1,040,952
---------- ----------
Operating Expenses and
Taxes (except income):
Operation 243,747 248,379
Maintenance (Note 2) 65,027 68,715
Depreciation and
amortization (Note 2) 232,520 225,622
Taxes (except income) 73,534 72,223
---------- ----------
614,828 614,939
---------- ----------
Operating Income Before
Utility Income Taxes 437,944 426,013
---------- ----------
Utility Income Taxes
(Note 4) 128,442 122,339
---------- ----------
Operating Income 309,502 303,674
---------- ----------
Other Income (Deductions)
(Note 2) 1,074 (4,110)
---------- ----------
Interest:
Interest on long-term debt 67,502 70,741
Other interest 3,287 4,262
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 4,149 4,195
---------- ----------
74,938 79,198
---------- ----------
Net Income 235,638 220,366
Dividend requirements on
preferred shares 8,182 8,386
---------- ----------
Balance available
for common shares $ 227,456 $ 211,980
========== ==========
Dividends declared $ 228,000 $ 205,000
========== ==========
<FN>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------- ------------------- -------------------
1999 1998 1999 1998 1999 1998
========= ========= ========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT
BEGINNING OF
PERIOD $ 144,195 $ 152,676 $ 146,138 $ 146,293 $ 146,833 $ 139,853
ADD:
Net income 62,115 51,229 172,263 156,805 235,638 220,366
--------- --------- --------- --------- --------- ---------
206,310 203,905 318,401 303,098 382,471 360,219
--------- --------- --------- --------- --------- ---------
LESS:
Dividends
Cumulative
Preferred
stocks -
4-1/4% series 223 222 667 667 889 889
4-1/2% series 90 90 270 270 360 360
4.22% series 113 113 337 337 448 448
4.88% series 122 122 366 366 488 488
7.44% series 77 77 233 233 312 312
7.50% series 65 65 196 196 261 261
8.85% series 111 138 351 433 489 599
7-3/4% series 70 82 210 243 286 330
8.35% series 96 109 321 359 434 484
6.50% series 699 699 2,096 2,096 2,795 2,795
Adjustable
Rate,
Series A 355 355 1,065 1,065 1,420 1,420
Common shares 58,000 55,000 166,000 150,000 228,000 205,000
--------- --------- --------- --------- --------- ---------
60,021 57,072 172,112 156,265 236,182 213,386
--------- --------- --------- --------- --------- ---------
BALANCE AT END
OF PERIOD $ 146,289 $ 146,833 $ 146,289 $ 146,833 $ 146,289 $ 146,833
========= ========= ========= ========= ========= =========
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months
Ended September 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 62,115 $ 51,229
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 58,422 57,327
Deferred federal and state income
taxes, net 3,287 (6,557)
Deferred investment tax credits, net (1,782) (1,783)
Other, net (12,555) 475
Change in certain assets and liabilities -
Accounts receivable, net 1,260 18,675
Electric production fuel 3,871 (1,041)
Materials and supplies (625) 1,608
Natural gas in storage (23,825) (25,725)
Accounts payable 16,678 3,667
Taxes accrued (16,977) 10,801
Fuel adjustment clause (8,452) 2,428
Gas cost adjustment clause (19,731) (5,021)
Accrued employment costs 3,585 4,178
Other accruals 14,548 (264)
Other, net 4,645 (729)
---------- ----------
Net cash provided by operating activities 84,464 109,268
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (46,447) (43,453)
Other, net (3,881) 973
---------- ----------
Net cash used in investing activities (50,328) (42,480)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 20,910 (18,900)
Retirement of long-term debt (500) (500)
Retirement of preferred shares (601) (600)
Cash dividends paid on common shares (53,000) (49,000)
Cash dividends paid on preferred shares (2,023) (2,087)
Other, net 114 112
---------- ----------
Net cash provided by (used in)
financing activities (35,100) (70,975)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS (964) (4,187)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 8,777 14,831
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 7,813 $ 10,644
========== ==========
<CAPTION>
Nine Months
Ended September 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 172,263 $ 156,805
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 174,620 170,647
Deferred federal and state operating
income taxes, net (31,170) (46,530)
Deferred investment tax credits, net (5,345) (5,347)
Other, net (11,605) 1,425
Change in certain assets and liabilities -
Accounts receivable, net (15,557) 38,659
Electric production fuel 9,311 1,297
Materials and supplies (665) 2,728
Natural gas in storage 1,475 (9,427)
Accounts payable 8,323 (20,231)
Taxes accrued (988) 37,360
Fuel adjustment clause (11,994) 5,732
Gas cost adjustment clause 31,378 56,508
Accrued employment costs (3,248) (11,434)
Other accruals 19,277 (9,575)
Other, net 9,708 (993)
---------- ----------
Net cash provided by operating activities 345,783 367,624
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (133,156) (131,178)
Other, net (9,203) (16,679)
---------- ----------
Net cash used in investing activities (142,359) (147,857)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt (36,990) (25,600)
Retirement of long-term debt (500) (35,500)
Retirement of preferred shares (1,852) (1,856)
Cash dividends paid on common shares (170,000) (150,000)
Cash dividends paid on preferred shares (6,151) (6,317)
Other, net 341 350
---------- ----------
Net cash used in financing activities (215,152) (218,923)
---------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (11,728) 844
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 19,541 9,800
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 7,813 $ 10,644
========== ==========
<CAPTION>
Twelve Months
Ended September 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 235,638 $ 220,366
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 232,520 225,622
Deferred federal and state operating
income taxes, net (17,214) (24,800)
Deferred investment tax credits, net (7,158) (7,172)
Other, net (11,130) 1,900
Change in certain assets and liabilities -
Accounts receivable, net (58,410) (22,076)
Electric production fuel (5,551) (392)
Materials and supplies (1,281) 4,884
Natural gas in storage 5,923 2,584
Accounts payable 44,800 (4,927)
Taxes accrued (14,229) 31,895
Fuel adjustment clause (8,768) 6,859
Gas cost adjustment clause 17,346 27,007
Accrued employment costs 1,314 (2,068)
Other accruals 23,347 (8,429)
Other, net (679) (29,088)
---------- ----------
Net cash provided by operating activities 436,468 422,165
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (188,600) (164,193)
Other, net 4,781 (19,936)
---------- ----------
Net cash used in investing activities (183,819) (184,129)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Issuance of long-term debt 500 0
Net change in short-term debt (4,290) 2,275
Retirement of long-term debt (16,509) (36,500)
Retirement of preferred shares (2,409) (2,411)
Cash dividends paid on common shares (225,000) (194,775)
Cash dividends paid on preferred shares (8,226) (8,444)
Other, net 454 470
---------- ----------
Net cash used in financing activities (255,480) (239,385)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS (2,831) (1,349)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 10,644 11,993
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 7,813 $ 10,644
========== ==========
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) HOLDING COMPANY STRUCTURE: NiSource Inc.(NiSource), formerly NIPSCO
Industries, Inc., was incorporated in Indiana on September 22, 1987 and became
the parent of Northern Indiana Public Service Company (Northern Indiana) on
March 3, 1988. NIPSCO Industries, Inc. changed it name to NiSource Inc.
on April 14, 1999 to reflect its new direction as a multi-state supplier
of energy and water resources and related services. Northern Indiana is a
public utility operating company supplying electricity and gas to the public
in the northern third of Indiana.
Northern Indiana is subject to regulation with respect to rates,
accounting and certain other matters which are governed by the Indiana
Utility Regulatory Commission (IURC) and the Federal Energy Regulatory
Commission (FERC), collectively called the "Commissions."
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION. The Consolidated Financial Statements include
the accounts of Northern Indiana and subsidiaries, after the elimination of
all significant intercompany items. Certain reclassifications were made to
conform the prior years' financial statements to the current presentation.
USE OF ESTIMATES. The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. Actual results could
differ from those estimates.
OPERATING REVENUES. Revenues are recorded based on estimated service
rendered, but are billed to customers monthly on a cycle basis.
DEPRECIATION AND MAINTENANCE. Northern Indiana provides depreciation
on a straight-line method over the remaining service lives of the electric,
gas and common properties. The approximated weighted average remaining lives
for major components of electric and gas plant are as follows:
Electric:
--------
Electric generation plant 24 years
Transmission plant 26 years
Distribution plant 25 years
Other electric plant 24 years
Gas:
----
Gas storage plant 18 years
Transmission plant 34 years
Distribution plant 27 years
Other gas plant 24 years
The depreciation provision for electric utility plant, as a percentage
of the original cost, was 3.7% for the three-month, nine-month and
twelve-month periods ended September 30, 1999 and was 3.8% for three-month,
3.7% for the nine-month and 3.6% for the twelve-month periods ended
September 30, 1998.
The depreciation provision for gas utility plant, as a percentage of the
original cost, was 5.4% for the three-month and the nine-month periods and
5.5% for the twelve-month periods ended September 30, 1999 and 5.4% for the
three-month, nine-month and twelve-month periods ended September 30, 1998.
Northern Indiana follows the practice of charging maintenance and
repairs, including the cost of removal of minor items of property, to expense
as incurred. When property that represents a retired unit is replaced or
removed, the cost of such property is credited to utility plant, and such
cost, together with the cost of removal less salvage, is charged to the
accumulated provision for depreciation.
AMORTIZATION OF SOFTWARE COSTS. External and incremental internal costs
associated with computer software developed for internal use are capitalized.
Capitalization of such costs commences upon the completion of the preliminary
stage of the project. Once the installed software is ready for its intended
use, such capitalized costs are amortized on a straight-line basis over a
period of five to ten years which the FERC prescribes as reasonable useful
life estimates for capitalized software.
COAL RESERVES. The costs of reserves under a long-term mining contract
to mine coal reserves through the year 2001 are being recovered through the
rate-making process as such coal reserves are used to produce electricity.
ACCOUNTS RECEIVABLE. At September 30, 1999, $100 million of accounts
receivable had been sold under a sales agreement, which expires on May 31,
2002. The September 30, 1999 and December 31, 1998 accounts receivable
balances include approximately $8.8 million and $11.6 million, respectively,
due from associated companies.
COMPREHENSIVE INCOME. Northern Indiana adopted Statement of Financial
Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income"
effective January 1, 1998. This statement established standards for reporting
and display of comprehensive income and its components in a financial
statement that is displayed with the same prominence as other financial
statements. The adoption of this statement did not impact Northern
Indiana's consolidated financial statements for the periods presented.
STATEMENTS OF CASH FLOWS. Temporary cash investments with an original
maturity of three months or less are considered to be cash equivalents.
Cash paid during the periods reported for income taxes and interest
was as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 39,250 $ 17,500 $125,336 $ 90,840 $169,641 $124,949
Interest, net of
amounts
capitalized $ 9,509 $ 10,524 $ 43,492 $ 44,794 $ 70,343 $ 75,133
</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. Under-recovery or over-recovery is recorded
as a current asset or current liability until such time as it is billed or
refunded to its customers. The fuel adjustment factor is subject to a
quarterly hearing by the IURC and remains in effect for a three-month period.
On August 18, 1999, the IURC issued a generic order which established
new guidelines for the recovery of purchased power costs through fuel
adjustment clauses. The IURC ruled that each utility had to establish a
"benchmark" which is the utility's highest on-system fuel cost per kilowatt-
hour (kwh) during the most recent annual period. The IURC stated that if the
weekly average of a utility's purchased power costs were less than the
"benchmark," these costs per kwh should be considered net energy costs which
are presumed "fuel costs included in purchased power." If the weekly average
of a utility's purchased power costs exceeded the "benchmark," the utility
would need to submit additional evidence demonstrating the reasonableness of
these costs. The Office of Utility Consumer Counselor has appealed the
August 18 order to the Indiana Court of Appeals.
GAS COST ADJUSTMENT CLAUSE. All metered gas sales rates contain an
adjustment factor, which reflects the increases and decreases in the cost of
purchased gas, contracted gas storage and storage transportation charges. The
gas cost adjustment factor is subject to a quarterly hearing by the IURC and
remains in effect for a three-month period. On August 11, 1999, the IURC
approved a flexible gas cost adjustment mechanism for Northern Indiana. Under
the new procedure, the demand component of the adjustment factor will be
determined, after hearing and IURC approval, and made effective on November 1
of each year. The demand component will remain in effect for one year until a
new demand component is approved by the IURC. The commodity component of the
adjustment factor will be determined by monthly filings, which will become
effective on the first day of each calendar month, subject to refund. The
monthly filings do not require IURC approval but will be reviewed by the IURC
during the annual hearing that will take place regarding the demand component
filing. If the statutory requirement relating to the level of return is
satisfied, any under-recovery or over-recovery caused by variances between
estimated and actual cost in a given monthly period will be allocated over a
twelve-month period beginning with the next monthly filing. Any
under-recovery or over-recovery is recorded as a current asset or current
liability until such time it is billed or refunded to its customers. Northern
Indiana's gas cost adjustment factor includes a gas cost incentive mechanism
(GCIM) which allows or the sharing of any cost savings or cost increases with
customers based upon a comparison of actual gas supply portfolio cost to a
market-based benchmark price.
NATURAL GAS IN STORAGE. Natural gas in storage is valued using the
last-in, first-out (LIFO) inventory methodology. Based on the average cost
of gas purchased in September 1999 and December 1998, the estimated
replacement cost of gas in storage (current and non-current) at September 30,
1999 and December 31, 1998 exceeded the stated LIFO cost by $67.6 million and
$33.7 million, respectively.
AFFILIATED COMPANY TRANSACTIONS. Northern Indiana receives executive,
financial, gas supply, sales and marketing, and administrative and general
services from an affiliate, NiSource Management Services Company (NMSC), a
wholly-owned subsidiary of NiSource.
The costs of these services are charged to Northern Indiana based on
payroll costs and expenses incurred by NMSC employees for the benefit of
Northern Indiana. These costs, which totaled $4.7 million, $14.2 million and
$19.1 million for the three-month, nine-month and twelve-month periods ended
September 30, 1999, respectively, and totaled $4.3 million, $15.9 million and
$20.5 million for the three-month, nine-month and twelve-month periods ended
September 30, 1998, respectively, consist primarily of employee compensation
and benefits.
Northern Indiana purchased natural gas and transportation services
from affiliated companies in the amounts of $6.4 million, $12.3 million and
$14.7 million representing 15.1%, 5.6% and 4.7% of Northern Indiana's total
gas costs for the three-month, nine-month and twelve-month periods ended
September 30, 1999, respectively. Northern Indiana purchased natural gas and
transportation services from affiliated companies in the amounts of $9.8
million, $18.4 million and $21.4 million representing 18.2%, 8.7% and 5.9% of
Northern Indiana's total gas costs for the three-month, nine-month and
twelve-month periods ended September 30, 1998, respectively.
Northern Indiana subleases a portion of its office facilities to
affiliated companies for a monthly fee, which includes operating expenses,
based on space utilization.
DERIVATIVES. A variety of commodity-based derivative financial
instruments are utilized to reduce (hedge) the price risk inherent in natural
gas and electric operations. The gains and losses on these derivative
financial instruments are deferred as assets or liabilities and are recognized
in earnings concurrent with the disposition of the underlying physical
commodity. In certain circumstances, a derivative financial instrument will
serve to hedge the acquisition cost of natural gas injected into storage. In
this situation, the gain or loss on the derivative financial instrument is
deferred as part of the cost basis of gas in storage and recognized upon the
ultimate disposition of the gas. If a derivative financial instrument
contract is terminated early because it is probable that a transaction or
forecasted transaction will not occur, any gain or loss as of such date is
immediately recognized in earnings. If a derivative financial instrument is
terminated for other economic reasons, any gain or loss of the termination
date is deferred and recorded when the associated transaction or forecasted
transaction affects earnings.
ACCOUNTING FOR ENERGY TRADING ACTIVITIES. Energy trading contracts
are accounted for in accordance with the Emerging Issues Task Force Issue
No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." This change in accounting effective January 1, 1999
was insignificant. Such contracts are recorded at their fair value with
changes in their value included in earnings (other income and deductions).
IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards
Board (FASB) has issued SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," and SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities-Deferral of the Effective Date of FASB
Statement No. 133." Statement No. 133 standardizes the accounting for
derivative instruments, including certain derivative instruments embedded in
other contracts, by requiring that a company recognize those items as assets
or liabilities in the balance sheet and measure them at fair value. The
Statement generally provides for matching of the timing of gain or loss
recognition of derivative instruments designated as a hedge with the
recognition of changes in the fair value of the hedged asset or liability
through earnings. The Statement also provides that the effective portion of a
hedging instrument's gain or loss on a forecasted transaction be initially
reported in other comprehensive income and subsequently reclassified into
earnings when the hedged forecasted transaction affects earnings. Statement
No. 137, which was issued June 1999, deferred implementation of Statement
No. 133 until January 1, 2001. The impact of adopting the accounting
prescribed in Statement No. 133 is currently being assessed.
REGULATORY ASSETS. Northern Indiana's operations are subject to the
regulation of the Commissions. Accordingly, Northern Indiana's accounting
policies are subject to the provisions of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." Northern Indiana monitors changes in
market and regulatory conditions and the resulting impact of such changes in
order to continue to apply the provisions of SFAS No. 71 to some or all of its
operations. As of September 30, 1999, and December 31, 1998, the regulatory
assets identified below represent probable future revenues to Northern Indiana
as these costs are recovered through the rate-making process. If a portion of
Northern Indiana's operations becomes no longer subject to the provisions of
SFAS No. 71, a write-off of certain regulatory assets might be required,
unless some form of transition cost recovery is established by the appropriate
regulatory body which would meet the requirements under generally accepted
accounting principles for continued accounting as regulatory assets during
such recovery period. Regulatory assets were comprised of the following
items:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
============= =============
(Dollars in thousands)
<S> <C> <C>
Unamortized reacquisition premium on
debt (Note 13) $ 40,365 $ 42,962
Unamortized R. M. Schahfer Unit 17 and
Unit 18 carrying charges
and deferred depreciation (See below) 59,166 62,329
Bailly scrubber carrying charges and
deferred depreciation (See below) 8,243 8,945
Deferral of SFAS No. 106 expense not
recovered (Note 6) 74,169 78,367
FERC Order No. 636 transition costs 15,504 22,093
Regulatory income tax asset, net (Note 4) 29,532 21,635
------------- -------------
226,979 236,331
Less: Current portion of regulatory assets 26,021 32,609
------------- -------------
$ 200,958 $ 203,722
============= =============
</TABLE>
CARRYING CHARGES AND DEFERRED DEPRECIATION. Upon completion of R. M.
Schahfer Units 17 and 18, Northern Indiana carrying charges and deferred
depreciation were capitalized in accordance with orders of the IURC until the
cost of each unit was allowed in rates. Such carrying charges and deferred
depreciation are being amortized over the remaining life of each unit.
Northern Indiana has capitalized carrying charges and deferred
depreciation and certain operating expenses relating to its scrubber service
agreement for its Bailly Generating Station in accordance with an order of
the IURC. The accumulated balance of the deferred costs and related carrying
charges is being amortized over the remaining life of the scrubber service
agreement.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION. Allowance for funds
used during construction (AFUDC) is charged to construction work in progress
during the period of construction and represents the net cost of borrowed
funds used for construction purposes and a reasonable rate upon other (equity)
funds. Under established regulatory rate practices, after the construction
project is placed in service, Northern Indiana is permitted to include in the
rates charged for utility services (a) a fair return on and (b) depreciation
of such AFUDC included in plant in service.
AFUDC was calculated using a pre-tax rate of 6.0% in 1999, 5.75% in 1998
and 5.5% in 1997.
INCOME TAXES. The liability method of accounting is used for income
taxes under which deferred income taxes are recognized, at currently enacted
income tax rates, to reflect the tax effect of temporary differences between
book and tax bases of assets and liabilities. Deferred investment tax credits
are being amortized over the life of the related property.
(3) ENVIRONMENTAL MATTERS:
GENERAL. The operations of Northern Indiana are subject to extensive
and evolving federal, state and local environmental laws and regulations
intended to protect public health and the environment. Such environmental
laws and regulations affect Northern Indiana's operations as they relate to
impacts on air, water and land.
SUPERFUND. Because Northern Indiana is a "potentially responsible
party" (PRP), under Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA), at several waste disposal sites, as well as at former
manufactured-gas plant sites which it, or its corporate predecessors, own or
owned or operated, it may be required to share in the costs of clean up of
such sites. A program was instituted to investigate former manufactured-gas
plant sites where it is the current or former owner, which investigation has
identified wenty-four of such sites. Initial sampling has been conducted at
seventeen sites. Investigation activities have been completed at twelve sites
and remedial measures have been selected or implemented at seven sites.
Northern Indiana intends to continue to evaluate its facilities and properties
with respect to environmental laws and regulations and take any required
corrective action.
In an effort to recover a portion of the costs related to the former
manufactured gas plants, various companies that provided insurance coverage
which Northern Indiana believed covered costs related to former
manufactured-gas plant sites were approached. Northern Indiana filed claims
in Indiana state court against various insurance companies, seeking coverage
for costs associated with several manufactured-gas plant sites and damages
for alleged misconduct by some of the insurance companies. Settlements have
been reached with several insurance companies including $13.0 million in the
third quarter 1999. Additionally, agreements have been reached with other
Indiana utilities relating to cost sharing and management of the investigation
and remediation of several former manufactured-gas plant sites at which
Northern Indiana and such utilities or their predecessors were operators or
owners.
As of September 30, 1999, a reserve of approximately $18 million has
been recorded to cover probable corrective actions. The ultimate liability in
connection with these sites will depend upon many factors, including the
volume of material contributed to the site, the number of other PRP's and
their financial viability, the extent of corrective actions required and rate
recovery. Based upon investigations and management's understanding of current
environmental laws and regulations, Northern Indiana believes that any
corrective actions required, after consideration of insurance coverages
and contributions from other PRP's and rate recovery will not have a material
effect on its financial position or results of operations.
CLEAN AIR ACT. The Clean Air Act Amendments of 1990 (CAAA) impose
limits to control acid rain on the emission of sulfur dioxide and nitrogen
oxides (NOx) which become fully effective in 2000. All of Northern Indiana's
facilities are already in compliance with sulfur dioxide limits. Northern
Indiana has already taken most of the steps necessary to meet the NOx limits.
The CAAA also contain other provisions that could lead to limitations
on emissions of hazardous air pollutants and other air pollutants (including
NOx as discussed below), which may require significant capital expenditures
for control of these emissions. Until specific rules have been issued that
affect Northern Indiana's facilities, what these requirements will be or the
costs of complying with these potential requirements cannot be predicted.
NITROGEN OXIDES. During 1998, the Environmental Protection Agency (EPA)
issued a final rule, the NOx State Implementation Plan (SIP) call, requiring
certain states, including Indiana, to reduce NOx levels from several sources,
including industrial and utility boilers. The EPA stated that the intent of
the rule is to lower regional transport of ozone impacting other states'
ability to attain the federal ozone standard. According to the rule, the
State of Indiana must issue regulations implementing the control program. The
State of Indiana, as well as some other states, filed a legal challenge in
December 1998 to the EPA NOx SIP call rule. Lawsuits have also been filed
against the rule by various groups. On May 25, 1999, the D.C. Circuit Court
of Appeals issued an order staying the NOx SIP call rule's September 30, 1999
deadline for the state submittals until further order of the court. Any
resulting NOx emissions limitations could be more restrictive than those
imposed on electric utilities under the CAAA's acid rain NOx reduction program
described above. Northern Indiana is evaluating the EPA's final rule and any
potential requirements that could result from the final rule as implemented by
the State of Indiana. Northern Indiana believes that the costs relating to
compliance with the new standards may be substantial, but such costs depend
upon the outcome of the current litigation and the ultimate control program
agreed to by the targeted states and the EPA. Northern Indiana is continuing
its programs to reduce NOx emissions and will continue to closely monitor
developments in this area.
The EPA issued final rules revising the National Ambient Air Quality
Standards for ozone and particulate matter in July 1997. On May 14, 1999,
the United States Court of Appeals for the D.C. Circuit remanded the new rules
for both ozone and particulate matter standards to the EPA. Once rectified,
the revised standards could require additional reductions in sulfur dioxide,
particulate matter and NOx emissions from coal-fired boilers (including
Northern Indiana's generating stations) beyond measures discussed above.
Final implementation methods will be set by the EPA as well as state
regulatory authorities. Northern Indiana believes that the costs relating to
compliance with any new limits may be substantial but are dependent upon the
ultimate control program agreed to by the targeted states and the EPA.
Northern Indiana will continue to closely monitor developments in this area
and anticipates the exact nature of the impact of the new limits on its
operations will not be known for some time.
In a letter dated September 15, 1999, the Attorney General of the State
of New York alleged that Northern Indiana violated the Clean Air Act by
constructing a major modification of one of its electric generating stations
without obtaining pre-construction permits required by the Prevention of
Significant Deterioration (PSD) program. The major modification allegedly
took place at the R. M. Schahfer Station when, "in approximately 1995-1997,
Northern Indiana upgraded the coal handling system at Unit 14 at the plant."
While Northern Indiana is investigating these allegation, Northern Indiana
does not believe that the modifications required pre-construction review under
the PSD program and believes that all appropriate permits were acquired.
CARBON DIOXIDE. Initiatives are being discussed both in the United
States and worldwide to reduce so-called "greenhouse gases" such as carbon
dioxide, and other by-products of burning fossil fuels. Reduction of such
emissions could result in significant capital outlays or operating expenses
to Northern Indiana.
CLEAN WATER ACT AND RELATED MATTERS. Northern Indiana's wastewater and
water operations are subject to pollution control and water quality control
regulations, including those issued by the EPA and the State of Indiana.
Under the Federal Clean Water Act and Indiana's regulations, Northern
Indiana must obtain National Pollutant Discharge Elimination System (NPDES)
permits for water discharges from various water discharges from various
facilities, including electric generating and water treatment stations. These
facilities either have permits for their water discharge or they have applied
for a permit renewal of any expiring permits. These permits continue in
effect pending review of the current applications.
(4) INCOME TAXES: Deferred income taxes are recognized as costs in the
rate-making process by the Commissions having jurisdiction over rates charged
by Northern Indiana. Deferred income taxes are provided as a result of
provisions in the income tax law that either require or permit certain items
to be reported on the income tax return in a different period than they are
reported in the consolidated financial statements. These taxes are reversed
by a debit or credit to deferred income tax expense as the temporary
differences reverse. Investment tax credits have been deferred and are being
amortized to income over the life of the related property.
To the extent certain deferred income taxes are recoverable or payable
through future rates, regulatory assets and liabilities have been established.
Regulatory assets are primarily attributable to undepreciated AFUDC-equity and
the cumulative net amount of other income tax timing differences for which
deferred taxes had not been provided in the past, when regulators did not
recognize such taxes as costs in the rate-making process. Regulatory
liabilities are primarily attributable to Northern Indiana's obligation to
credit to ratepayers deferred income taxes provided at rates higher than the
current federal tax rate currently being credited to ratepayers using the
average rate assumption method and unamortized deferred investment tax
credits.
Northern Indiana joins in the filing of consolidated tax returns with
NiSource and currently pays to NiSource its separate return tax liability
as defined in the Tax Sharing Agreement between NiSource and its
subsidiaries.
The components of the net deferred income tax liability at September 30,
1999 and December 31, 1998 were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
============= =============
(Dollars in thousands)
<S> <C> <C>
Deferred tax liabilities -
Accelerated depreciation
and other property differences $ 731,657 $ 735,589
AFUDC-equity 31,367 33,029
Adjustment clauses 6,971 14,322
Other regulatory assets 28,129 29,721
Prepaid pension and other benefits 33,179 34,170
Reacquisition premium on debt 15,308 16,293
Deferred tax assets -
Deferred investment tax credits (33,127) (35,154)
Removal costs (168,745) (157,728)
Other postretirement/postemployment
benefits (51,977) (48,208)
Other, net (16,720) (23,682)
------------- -------------
576,042 598,352
Less: Deferred income taxes related to
current assets and liabilities (24,628) (10,583)
------------- -------------
Deferred income taxes - noncurrent $ 600,670 $ 608,935
============= =============
</TABLE>
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,
-------------------- --------------------
1999 1998 1999 1998
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Current income taxes -
Federal $ 27,636 $ 31,551 $ 114,289 $ 120,298
State 3,888 4,866 16,310 18,007
--------- --------- --------- ---------
31,524 36,417 130,599 138,305
--------- --------- --------- ---------
Deferred income taxes, net -
Federal 3,006 (6,090) (28,849) (43,057)
State 281 (467) (2,321) (3,473)
--------- --------- --------- ---------
3,287 (6,557) (31,170) (46,530)
--------- --------- --------- ---------
Deferred investment tax credits,
net (1,782) (1,783) (5,345) (5,347)
--------- --------- --------- ---------
Total utility operating income
taxes 33,029 28,077 94,084 86,428
Income tax applicable to non-
operating activities and income
of subsidiaries 1,049 (620) 1,043 (1,852)
--------- --------- --------- ---------
Total income taxes $ 34,078 $ 27,457 $ 95,127 $ 84,576
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended September 30,
--------------------
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Current income taxes -
Federal $ 134,355 $ 133,777
State 18,459 20,534
--------- ---------
152,814 154,311
--------- ---------
Deferred income taxes, net -
Federal (16,082) (23,071)
State (1,132) (1,729)
--------- ---------
(17,214) (24,800)
--------- ---------
Deferred investment tax credits,
net (7,158) (7,172)
--------- ---------
Total utility operating income
taxes 128,442 122,339
Income tax applicable to non-
operating activities and income
of subsidiaries 958 (3,646)
--------- ---------
Total income taxes $ 129,400 $ 118,693
========= =========
</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,
-------------------- --------------------
1999 1998 1999 1998
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Net income $ 62,115 $ 51,229 $ 172,263 $ 156,805
Add-Income taxes 34,078 27,457 95,127 84,576
--------- --------- --------- ---------
Net income before income taxes $ 96,193 $ 78,686 $ 267,390 $ 241,381
========= ========= ========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 33,668 $ 27,540 $ 93,587 $ 84,483
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 969 998 2,906 2,994
Amortization of deferred
investment tax credits (1,782) (1,783) (5,345) (5,347)
State income taxes, net of
federal income tax benefit 2,809 2,696 8,281 8,232
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (721) (1,271) (2,163) (3,813)
Other, net (865) (723) (2,139) (1,973)
--------- --------- --------- ---------
Total income taxes $ 34,078 $ 27,457 $ 95,127 $ 84,576
========= ========= ========= =========
<CAPTION>
Twelve Months,
Ended September 30,
--------------------
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Net income $ 235,638 $ 220,366
Add-Income taxes 129,400 118,693
--------- ---------
Net income before income taxes $ 365,038 $ 339,059
========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 127,763 $ 118,671
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 3,904 3,957
Amortization of deferred
investment tax credits (7,158) (7,172)
State income taxes, net of
federal income tax benefit 10,866 11,618
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (2,734) (3,807)
Other, net (3,241) (4,574)
--------- ---------
Total income taxes $ 129,400 $ 118,693
========= =========
</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 1998 and 1997 was as follows:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Benefit obligation at beginning $ 843,049 $ 732,870
of year (January 1,)
Service cost 15,347 13,325
Interest cost 58,336 55,920
Plan amendments 14,655 25,096
Actuarial loss 37,248 67,975
Benefits paid (54,362) (52,137)
--------- ---------
Benefit obligation at end of
the year (December 31,) $ 914,273 $ 843,049
========= =========
</TABLE>
The change in the fair value of the plan's assets for years 1998 and
1997 was as follows:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Fair value of plan assets at $ 896,950 $ 782,162
beginning of year January 1,)
Actual return on plan's assets 82,547 122,537
Employer contributions 33,300 44,388
Benefits paid (54,362) (52,137)
--------- ---------
Plan assets at fair value at
end of the year (December 31,) $ 958,435 $ 896,950
========= =========
</TABLE>
Plan assets are invested primarily in common stocks, bonds and notes.
The plan's funded status as of 1998 and 1997 is as follows:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Plan assets in excess of $ 44,162 $ 53,901
benefit obligation
Unrecognized net actuarial loss (16,162) (51,191)
Unrecognized prior service cost 55,761 45,502
Unrecognized transition amount
being recognized over
seventeen years 27,442 32,930
--------- ---------
Prepaid pension costs $ 111,203 $ 81,142
========= =========
</TABLE>
The benefit obligation is the present value of future pension benefit
payments and is based on a plan benefit formula which considers expected
future salary increases. A discount rate of 7.00% and rate of increase in
compensation levels of 4.5% were used to determine the benefit obligation at
December 31, 1998 and December 31, 1997.
Northern Indiana's prepaid pension costs were $132.6 million at
September 30, 1999 and are reported under the caption "Prepayments and Other"
in the Consolidated Balance Sheets.
The following items are the components of provisions for pensions for
the three-month, nine-month and twelve-month periods ended September 30, 1999
and September 30, 1998:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 4,123 $ 4,234 $ 12,371 $ 16,227 $ 15,725 $ 14,349
Interest costs 15,403 14,883 46,209 57,029 62,400 49,143
Expected return
on plan assets (21,121) (19,754) (63,365) (75,695) (87,753) (65,755)
Amortization of
transition
obligation 1,373 1,344 4,117 5,148 5,801 4,373
Amortization of
prior service
cost 1,398 1,077 4,196 4,127 5,543 3,657
-------- -------- -------- -------- -------- --------
$ 1,176 $ 1,784 $ 3,528 $ 6,836 $ 1,716 $ 5,767
======== ======== ======== ======== ======== ========
</TABLE>
Assumptions used in the valuation and determination of 1999 and 1998
pension expense were as follows:
<TABLE>
<CAPTION>
1999 1998
===== =====
<S> <C> <C>
Discount rate 7.00% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Expected long-term rate of return on assets 9.00% 9.00%
</TABLE>
(6) POSTRETIREMENT BENEFITS: Certain health care and life insurance
benefits for retired employees are provided. Substantially all Northern
Indiana employees may become eligible for those benefits if they reach
retirement age while working for Northern Indiana. The expected cost of such
benefits is accrued during the employees' years of service. Current rates
include postretirement benefit costs on an accrual basis, including
amortization of the regulatory assets that arose prior to inclusion of these
costs in rates.
The following table sets forth the change in the plan's accumulated
postretirement benefit obligation (APBO) as of December 31, 1998 and 1997:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Accumulated postretirement $ 195,003 $ 194,937
benefit obligation at
beginning of year (January 1,)
Service cost 3,314 3,068
Interest cost 13,685 14,523
Plan amendments 0 4,015
Actuarial (gain) loss 6,260 (12,534)
Benefits paid (11,183) (9,006)
--------- ---------
Accumulated postretirement
benefit obligation at
end of the year (December 31,) $ 207,079 $ 195,003
========= =========
</TABLE>
The change in the fair value of the plan's assets for the years 1998 and
1997 was as follows:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Fair value of plan assets at $ 2,400 $ 0
beginning of year (January 1,)
Actual return on plan assets 1,103 0
Employer contributions 9,301 11,406
Participant contributions 1,282 0
Benefits paid (11,183) (9,006)
--------- ---------
Plan assets at fair value at
end of the year (December 31,) $ 2,903 $ 2,400
========= =========
</TABLE>
Following is the funded status for postretirement benefits as of
December 31, 1998 and December 31, 1997:
<TABLE>
<CAPTION>
1998 1997
========= =========
(Dollars in thousands)
<S> <C> <C>
Funded status $(204,176) $(192,603)
Unrecognized actuarial gain (90,700) (99,262)
Unrecognized prior service cost 3,458 3,737
Unrecognized transition amount
being recognized over
twenty years 150,466 161,214
--------- ---------
Accrued liability for
postretirement benefits $(140,952) $(126,914)
========= =========
</TABLE>
In order to determine the APBO at December 31, 1998, a discount rate of
7% and a pre-Medicare medical trend rate of 7% declining to a long-term rate
of 5% was used, and at December 31, 1997, a discount rate of 7% and a
pre-Medicare medical trend rate of 8% declining to a long-term rate of 5% was
used. The accrued liability for postretirement benefits was $146.1 million at
September 30, 1999.
Net periodic postretirement benefits costs, before consideration of the
rate-making discussed previously, for the three-month, nine-month and
twelve-month periods ended September 30, 1999 and September 30, 1998 include
the following components:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
---------------- ---------------- ----------------
1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 781 $ 1,084 $ 2,608 $ 2,890 $ 3,032 $ 3,169
Interest costs 3,850 3,650 11,550 10,950 14,285 12,345
Expected return
on plan assets (50) (50) (150) (150) (216) (150)
Amortization of
transition
obligation
over twenty years 2,675 2,675 8,025 8,025 10,748 10,666
Amortization of
prior service cost 75 75 225 225 279 504
Amortization of
actuarial (gain) (1,150) (1,375) (3,450) (4,125) (5,111) (6,924)
------- ------- ------- ------- ------- -------
$ 6,181 $ 6,059 $18,808 $17,815 $23,017 $19,610
======= ======= ======= ======= ======= =======
</TABLE>
Assumptions used in the determination of 1999 and 1998 net periodic
postretirement benefit costs were as follows:
<TABLE>
<CAPTION>
1999 1998
===== =====
<S> <C> <C>
Discount rate 7.00% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Assumed annual rate of increase in health
care benefits 7.00% 8.00%
Assumed ultimate trend rate 5.00% 5.00%
</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, 1999 by
approximately $25.8 million, and increase the aggregate of the service and
interest cost components of plan costs by approximately $0.6 million and $1.8
million for the three-month and nine-month periods ended September 30, 1999.
The effect of a 1% decrease in the assumed health care cost trend rates for
each future year would decrease the APBO at January 1, 1999 by approximately
$20.0 million, and decrease the aggregate of the service and interest cost
components of plan costs by approximately $0.5 million and $1.4 million for
the three-month and nine-month periods ended September 30, 1999. Amounts
disclosed above could be changed significantly in the future by changes in
health care costs, work force demographics, interest rates, or plan changes.
(7) AUTHORIZED CLASSES OF CUMULATIVE PREFERRED AND PREFERENCE STOCKS
OF NORTHERN INDIANA:
2,400,000 shares - Cumulative Preferred - $100 par value
3,000,000 shares - Cumulative Preferred - no par value
2,000,000 shares - Cumulative Preference - $50 par value
(none outstanding)
3,000,000 shares - Cumulative Preference - no par value
(none issued)
Note 8 sets forth the preferred stocks which are redeemable solely at
the option of Northern Indiana and Note 9 sets forth the preferred stocks
which are subject to mandatory redemption requirements or whose redemption is
outside the control of Northern Indiana.
The preferred shareholders of Northern Indiana have no voting rights,
except in the event of a default on the payment of four consecutive quarterly
dividends, or as required by Indiana law to authorize additional preferred
shares, or by the Articles of Incorporation in the event of certain merger
transactions.
(8) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF NORTHERN INDIANA,
OUTSTANDING AT SEPTEMBER 30, 1999 AND DECEMBER 31, 1998 (SEE NOTE 7):
<TABLE>
<CAPTION>
Redemption
Price at
September 30, December 31, September 30,
1999 1998 1999
============ ============ ============
(Dollars in thousands)
<S> <C> <C> <C>
Cumulative preferred stock -
$100 par value -
4-1/4% series - 209,035 and
209,051 shares outstanding,
respectively $ 20,903 $ 20,905 $101.20
4-1/2% series - 79,996 shares
outstanding 8,000 8,000 $100.00
4.22% series - 106,198 shares
outstanding 10,620 10,620 $101.60
4.88% series - 100,000 shares
outstanding 10,000 10,000 $102.00
7.44% series - 41,890 shares
outstanding 4,189 4,189 $101.00
7.50% series - 34,842 shares
outstanding 3,484 3,484 $101.00
Premium on preferred stock 254 254
Cumulative preferred stock -
no par value -
Adjustable rate (6.00% at
September 30, 1999), Series A
(stated value $50 per share)
473,285 shares outstanding 23,664 23,664 $50.00
------------ ------------
$ 81,114 $ 81,116
============ ============
</TABLE>
During the period October 1, 1997 to September 30, 1999 there were no
additional issuances of the above preferred stocks. The foregoing preferred
stocks are redeemable in whole or in part, at any time upon thirty days'
notice at the option of Northern Indiana at the redemption prices shown.
(9) REDEEMABLE PREFERRED STOCKS OUTSTANDING AT SEPTEMBER 30, 1999 AND
DECEMBER 31, 1998 (SEE NOTE 7):
Preferred stocks subject to mandatory redemption requirements or whose
redemption is outside the control of Northern Indiana, excluding sinking
fund payments due within one year were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
============ ============
(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 - 37,500 and 50,000 shares
outstanding, respectively, excluding sinking
fund payments due within one year $ 3,750 $ 5,000
7-3/4% series - 33,352 shares outstanding,
excluding sinking fund payments due within
one year 3,335 3,335
8.35% series - 45,000 and 51,000 shares
outstanding, respectively, excluding sinking
fund payments due within one year 4,500 5,100
Cumulative preferred stock - no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
------------ ------------
$ 54,585 $ 56,435
============ ============
</TABLE>
The redemption prices at September 30, 1999, as well as sinking fund
provisions for the cumulative preferred stocks subject to mandatory redemption
requirements, or whose redemption is outside the control of Northern Indiana,
were as follows:
<TABLE>
<CAPTION>
Sinking Fund Or
Mandatory Redemption
Series Redemption Price Per Share Provisions
====== ========================== =============================
<S> <C> <C>
Cumulative preferred stock - $100 par value -
8.85% $100.74, reduced periodically 12,500 shares on or before
April 1.
7-3/4% $104.06, reduced periodically 2,777 shares on or
before December 1;
noncumulative option
to double amount each
year.
8.35% $103.20, reduced periodically 3,000 shares on or before
July 1; increasing to 6,000
shares beginning in 2004;
noncumulative option
to double amount each
year.
Cumulative preferred stock - no par value -
6.50% $100.00 on October 14, 2002 430,000 shares on October 14,
2002.
</TABLE>
Sinking fund requirements with respect to redeemable preferred stocks
for the next five years, not reflecting redemptions made after September 30,
1999, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
==================================
(Dollars in thousands)
<S> <C>
2000 $ 1,828
2001 $ 1,828
2002 $ 1,828
2003 $44,828
2004 $ 878
</TABLE>
Sinking fund payments due within one year are reported under the caption
"Other accruals" in the Consolidated Balance Sheets.
(10) COMMON SHARE DIVIDEND: Northern Indiana's Indenture dated August 1,
1939, as amended and supplemented (Indenture), provides that it will not
declare or pay any dividends on any class of capital stock (other than
preferred or preference stock) except out of the earned surplus or net profits
of Northern Indiana. At September 30, 1999, Northern Indiana had
approximately $146.3 million of retained earnings (earned surplus) available
for the payment of dividends. Future dividends will depend upon adequate
retained earnings, adequate future earnings and the absence of adverse
developments.
(11) COMMON SHARES: Effective with the exchange of common shares on March 3,
1988, all of Northern Indiana's common shares are owned by NiSource.
(12) LONG-TERM INCENTIVE PLAN: NiSource has two long-term incentive plans
for key management employees, including management of Northern Indiana,
that were approved by shareholders on April 13, 1988 (1988 Plan) and
April 13, 1994 (1994 Plan), each of which provides for the issuance of up to
5.0 million NiSource common shares to key employees through April 1998 and
April 2004, respectively. The 1988 Plan, as amended and restated, and the
1994 Plan, as amended and restated, were re-approved by shareholders at
NiSource's 1999 Annual Meeting of Shareholders, held April 14, 1999.
At September 30, 1999, there were 1.8 million shares reserved for future
awards under the 1994 Plan. The Plans permit the following types of grants,
separately or in combination: nonqualified stock options, incentive stock
options, restricted stock awards, stock appreciation rights and performance
units. No incentive stock options or performance units were outstanding at
September 30, 1999. Under the Plans, the exercise price of each option equals
the market price of NiSource's common stock on the date of grant. Each option
has a maximum term of ten years and vests one year from the date of grant.
Stock appreciation rights (SARs) may be granted only in tandem with
stock options on a one-for-one basis and are payable in cash, NiSource's
common shares, or a combination thereof. There were no SARs outstanding at
September 30, 1999. Restricted stock awards are restricted as to transfer and
are subject to forfeiture for specific periods from the date of grant.
Restrictions on shares awarded in 1995 lapse five years from date of grant,
and vesting varies from 0% to 200% of the number awarded, subject to specific
earnings per share and stock appreciation goals. Restrictions on shares
awarded in 1998 and 1999 lapse two years from date of grant and vesting is
variable from 0% to 100% of the number awarded, subject to specific
performance goals. If a participant's employment is terminated prior to
vesting other than by reason of death, disability or retirement, restricted
shares are forfeited. There were 513,500 and 534,666 restricted shares
outstanding at September 30, 1999 and December 31, 1998, respectively.
Northern Indiana accounts for its allocable portion of these plans
under Accounting Principles Board Opinion No. 25, under which no compensation
cost has been recognized for nonqualified stock options. The compensation
cost that has been charged against income for restricted stock awards was
0.3 million and $0.2 million for the three-month, $0.7 and $0.6 million for
the nine-month and $0.9 million and $0.7 million for the twelve-month periods
ending September 30, 1999 and September 30, 1998, respectively. Had
compensation cost for non-qualified stock options been determined consistent
with SFAS No. 123 "Accounting for Stock-Based Compensation," net income would
have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended Ended Ended
September 30, September 30, September 30,
------------------ ------------------ -------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Net Income:
As reported $ 62,115 $ 51,229 $172,263 $156,805 $235,638 $220,366
Pro forma $ 61,724 $ 50,941 $171,065 $156,091 $234,036 $219,439
</TABLE>
The fair value of each option granted as used to determine pro forma net
income is estimated as of the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions used for grants
in the twelve-month periods ended September 30, 1999 and September 30, 1998:
risk-free interest rate of 5.87% and 5.29%, respectively; expected dividend
yield per share of $1.02 and $0.96, respectively; expected option term of 5.22
and 5.4 years, respectively; and expected volatilities of 15.72% and 13.09%,
respectively. The weighted average fair value of options granted to all plan
participants was $3.66 and $4.28 for the twelve-month periods ended
September 30, 1999 and September 30, 1998, respectively. There were 744,750
and 607,000 non-qualified stock options granted to all plan participants for
the twelve-month periods ended September 30, 1999 and September 30, 1998,
respectively.
(13) LONG-TERM DEBT: At September 30, 1999 and December 31, 1998, the
long-term debt of Northern Indiana, excluding amounts due within one year,
issued and not retired or canceled was as follows:
<TABLE>
<CAPTION>
AMOUNT OUTSTANDING
---------------------------
September 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
First mortgage bonds -
Series T, 7-1/2%, due April 1, 2002 $ 38,500 $ 39,000
Series NN, 7.10%, due July 1, 2017 55,000 55,000
------------ ------------
Total 93,500 94,000
------------ ------------
Pollution control notes and bonds -
Series A Note -
City of Michigan City, 5.70% due
October 1, 2003 16,500 16,500
Series 1988 Bonds - Jasper County -
Series A, B and C - 3.81% weighted
average at September 30, 1999, due
November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County -
Series D - 3.53% weighted average at
September 30, 1999, due November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County -
Series A - 3.80% at September 30, 1999,
due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County -
Series B - 3.80% at September 30, 1999,
due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County -
Series C - 3.80% at September 30, 1999,
due April 1, 2019 41,000 41,000
------------ ------------
Total 239,500 239,500
------------ ------------
Medium-term notes -
Interest rates between 6.50% and 7.69% with
a weighted average interest rate of 7.05%
and various maturities between
August 15, 2001 and August 4, 2027 593,025 748,025
------------ ------------
Unamortized premium and discount
on long-term debt, net (3,225) (3,566)
------------ ------------
Total long-term debt excluding
amounts due in one year $ 922,800 $ 1,077,959
============ ============
</TABLE>
The sinking fund requirements and maturities of long-term debt for the
next five years were as follows as of September 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
=================================
(Dollars in thousands)
<S> <C>
2000 $157,000
2001 $ 18,000
2002 $ 58,000
2003 $128,500
2004 $ 38,000
</TABLE>
Unamortized debt expense, premium and discount on long-term debt
applicable to outstanding bonds are being amortized over the lives of such
bonds. Reacquisition premiums are being deferred and amortized. These
premiums are not earning a return during the recovery period.
Northern Indiana's Indenture, pursuant to which first mortgage bonds
have been issued, constitutes a direct first mortgage lien upon substantially
all of Northern Indiana's property and franchises, other than expressly
excepted property.
Northern Indiana is authorized to issue and sell up to $217,692,000
Medium-Term Notes, Series E, with various maturities, for purposes of
refinancing certain first mortgage bonds and medium-term notes. As of
September 30, 1999, $139.0 million of the medium-term notes had been issued
with various interest rates and maturities. The proceeds from these issuances
were used to pay short-term debt incurred to redeem its First Mortgage Bonds,
Series N, and to pay at maturity various issues of Medium-Term Notes, Series
D.
(14) CURRENT PORTION OF LONG-TERM DEBT: At September 30, 1999 and
December 31, 1998, Northern Indiana's current portion of long-term debt due
within one year was as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
Medium-term notes -
Interest rate 6.10% and 6.90% with
a weighted average interest rate of
6.80% and maturities between
October 20, 2000 and June 1, 2000 $ 155,000 $ 0
Sinking funds due within one year 2,000 2,000
------------ ------------
Total current portion of long-term debt $ 157,000 $ 2,000
============ ============
</TABLE>
(15) SHORT-TERM BORROWINGS: Northern Indiana entered into a five-year $100
million credit agreement and a 364-day $100 million revolving credit agreement
with several banks. These agreements terminate on September 23, 2003 and
September 23, 2000, respectively. The 364-day agreement may be extended at
expiration for additional periods of 364-days. Under these agreements, funds
are borrowed at a floating rate of interest or, under certain circumstances,
at a fixed rate of interest for a short-term periods. These agreements
provide financing flexibility and may be used to support the issuance of
commercial paper. As of September 30, 1999, there were no borrowings
outstanding under these agreements.
In addition, Northern Indiana has $13.2 million in lines of credit which
run until May 31, 2000. The credit pricing of each of the lines varies from
either the lending banks' commercial prime or market rates. As of
September 30, 1999, there were no borrowings under these lines of credit. The
credit agreements and lines of credit are also available to support the
issuance of commercial paper.
Northern Indiana also has $220 million of money market lines of credit.
As of September 30, 1999 and December 31, 1998, $45.9 million and $40.5
million of borrowings were outstanding, respectively, under these lines of
credit.
At September 30, 1999 and December 31, 1998, Northern Indiana's short-
term borrowings were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
Commercial paper -
Weighted average interest rate of 5.36%
at September 30, 1999 $ 43,250 $ 85,600
Notes payable -
Issued at interest rates between 5.38%
and 5.73% with a weighted average
interest rate of 5.46% and maturities
of October 1, 1999 and October 18, 1999 45,860 40,500
------------ ------------
Total short-term borrowings $ 89,110 $ 126,100
============ ============
</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 $3.4 million.
The following is a schedule, by years, of future minimum rental
payments, excluding those to associated companies, required under operating
leases that have initial or remaining noncancelable lease terms in excess of
one year as of September 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
================================
(Dollars in thousands)
<S> <C>
2000 $ 7,357
2001 7,107
2002 7,107
2003 7,107
2004 5,714
Later years 33,065
--------
Total minimum
payments required $ 67,457
========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
September 30, September 30,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
Three months ended $ 2,919 $ 2,485
Nine months ended $ 8,210 $ 6,964
Twelve months ended $10,637 $ 8,802
</TABLE>
(17) COMMITMENTS: Northern Indiana estimates that approximately $802 million
will be expended for construction purposes for the period from January 1, 1999
to December 31, 2003. Substantial commitments have been made by Northern
Indiana in connection with this program.
Northern Indiana has entered into a service agreement with Pure Air, a
general partnership between Air Products and Chemicals, Inc. and Mitsubishi
Heavy Industries America, Inc., under which Pure Air provides scrubber
services to reduce sulfur dioxide emissions for Units 7 and 8 at its Bailly
Generating Station. Services under this contract commenced on June 15, 1992
with annual charges approximating $20 million. The agreement provides that,
assuming various performance standards are met by Pure Air, a termination
payment would be due if Northern Indiana terminates the agreement prior to the
end of the twenty-year contract period.
A ten-year agreement to outsource all data center, application
development and maintenance, and desktop management expires in 2005. Annual
fees under this agreement are estimated at $20 million.
(18) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT: A variety of commodity-based
derivative financial instruments are utilized to reduce the price risk
inherent in natural gas and electric operations, as well as for energy trading
activities. The use of these derivative financial instruments is governed by
a risk management policy, which includes as its objective that commodity-based
derivative financial instruments will be used primarily for hedging. The
risk management policy also governs energy trading activities and is generally
designed to allow for such activities within defined risk limits.
NATURAL GAS COMMODITY RISK MANAGEMENT. Commodity futures, options and
swaps are used to hedge the impact of natural gas price fluctuations related
to business activities, including price risk related to the physical location
of the natural gas (basis risk). As of September 30, 1999, open derivative
financial instruments represented hedges of natural gas sales of 0.4 billion
cubic feet (Bcf). The net deferred gains on these derivative financial
instruments was not material.
ENERGY TRADING ACTIVITIES. Energy trading contracts, which include
forwards, futures, options and swaps, are used in connection with energy
trading activities and may involve the delivery of energy. The net open
positions for these energy trading contracts were not significant as of
September 30, 1999.
(19) FAIR VALUE OF FINANCIAL INSTRUMENTS: The following methods and
assumptions were used to estimate the fair value of each class of financial
instruments for which it is practicable to estimate fair value:
CASH AND CASH EQUIVALENTS. The carrying amount approximates fair
value due to the short maturity of those instruments.
INVESTMENTS. Investments are carried at cost, which approximates
market value.
LONG-TERM DEBT AND PREFERRED STOCK. The fair value of these
securities are estimated based on quoted market prices for the same
or similar issues or on the rates offered for securities of the same
remaining maturities. Certain premium costs associated with the
early settlement of long-term debt are not taken into consideration
in determining fair value.
The carrying values and estimated fair values of financial instruments
were as follows:
<TABLE>
<CAPTION>
September 30, 1999 December 31, 1998
---------------------- ----------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Cash and cash equivalents $ 7,813 $ 7,813 $ 19,541 $ 19,541
Investments $ 251 $ 251 $ 251 $ 251
Long-term debt (including
current portion) $1,079,800 $1,026,098 $1,079,959 $1,137,657
Preferred stock (including
current portion) $ 137,527 $ 122,100 $ 139,379 $ 136,316
</TABLE>
Northern Indiana is subject to regulation, and gains or losses may be
included in rates over a prescribed amortization period, if in fact settled at
amounts approximating those above.
(20) CUSTOMER CONCENTRATIONS: Northern Indiana is a public utility
operating company supplying natural gas and electrical energy in the northern
third of Indiana. Although Northern Indiana has a diversified base of
residential and commercial customers, a substantial portion of its electric
and gas industrial deliveries are dependent upon the basic steel industry.
The basic steel industry accounted for 3% of gas revenues (including
transportation services) and 17% of electric revenues for the twelve months
ended September 30, 1999 and September 30, 1998.
(21) SEGMENTS OF BUSINESS: Operating segments are defined as components of an
enterprise for which separate financial information is available and is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance.
Northern Indiana's reportable operating segments include regulated gas
and electric services. Northern Indiana supplies gas and electric services to
residential, commercial and industrial customers. The other category includes
gas exploration, real estate transactions, and non-utility revenues and
expenses.
Reportable segments are operations that are managed separately and meet
the quantitative thresholds.
Revenues for each segments are attributable to customers in the United
States.
The following tables provide information about business segments. In
addition, adjustments have been made to the segment information to arrive at
information included in the results of operations and financial position.
These adjustments include unallocated corporate assets, revenues and expenses.
The accounting policies of the operating segments are the same as those
described in Note 2, "Summary of Significant Accounting Policies."
<TABLE>
<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 $ 223 $ 0 $ 112,840
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 21,801 $ 24,646 $ 0 $ 0 $ 46,447
<CAPTION>
For the Three Months Adjust-
Ended September 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 71,773 $ 311,512 $ 0 $ 0 $ 383,285
Other income (deductions)$ 56 $ 180 $ (1,267) $ (30) $ (1,061)
Depreciation and
amortization $ 17,890 $ 39,437 $ 0 $ 0 $ 57,327
Income before interest
and utility income
taxes $(15,350) $ 115,701 $ (1,341) $ 44 $ 99,054
Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710
Capital expenditures $ 15,450 $ 35,878 $ 0 $ 0 $ 51,328
<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 $ 862,203 $ 0 $ 0 $1,297,440
Other income (deductions)$ 908 $ 696 $ 161 (39) $ 1,726
Depreciation and
amortization $ 55,835 $ 118,785 $ 0 $ 0 $ 174,620
Income before interest
and utility income
taxes $ 45,610 $ 275,909 $ 110 $ 12 $ 321,641
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 42,995 $ 90,161 $ 0 $ 0 $ 133,156
<CAPTION>
For the Nine Months Adjust-
Ended September 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $389,362 $ 823,309 $ 0 $ 0 $1,212,671
Other income (deductions)$ 809 $ 350 $ (4,013) $ (83) $ (2,937)
Depreciation and
amortization $ 53,488 $ 117,159 $ 0 $ 0 $ 170,647
Income before interest
and utility income
taxes $ 25,991 $ 280,074 $ (4,124) $ 28 $ 301,969
Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710
Capital expenditures $ 38,900 $ 92,630 $ 0 $ 0 $ 131,530
<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 $1,115,012 $ 0 $ 0 $1,733,372
Other income (deductions)$ 1,495 $ 894 $ (1,209) $ (106) $ 1,074
Depreciation and
amortization $ 74,054 $ 158,466 $ 0 $ 0 $ 232,520
Income before interest
and utility income
taxes $ 78,982 $ 361,351 $ (1,303) $ (12) $ 439,018
Assets $842,476 $2,769,900 $ 0 $ 0 $3,612,376
Capital expenditures $ 60,638 $ 127,962 $ 0 $ 0 $ 188,600
<CAPTION>
For the Twelve Months Adjust-
Ended September 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $628,940 $1,071,293 $ 0 $ 0 $1,700,233
Other income (deductions)$ 1,144 $ 627 $ (5,747) $ (134) $ (4,110)
Depreciation and
amortization $ 70,807 $ 154,815 $ 0 $ 0 $ 225,622
Income before interest
and utility income
taxes $ 67,532 $ 360,252 $ (5,929) $ 48 $ 421,903
Assets $863,945 $2,699,765 $ 0 $ 0 $3,563,710
Capital expenditures $ 57,139 $ 107,054 $ 0 $ 0 $ 164,193
</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, 1999 and 1998:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C <C>
Income before
interest and
utility income
taxes $113,840 $ 99,054 $321,641 $301,969 $439,018 $421,903
Interest 18,696 19,748 55,294 58,736 74,938 79,198
Utility income
taxes 33,029 28,077 94,084 86,428 128,442 122,339
-------- -------- -------- -------- -------- --------
Net income $ 62,115 $ 51,229 $172,263 $156,805 $235,638 $220,366
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OPERATING REVENUES -
TWELVE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for
the twelve months ended September 30, 1999 were $33.1 million higher than for
the twelve months ended September 30, 1998, representing a 1.9% increase. Gas
revenues were $618.4 million, which represented a $10.6 million decrease from
the comparable period for 1998. This decrease occurred mainly due to decreased
sales to residential and commercial customers as a result of unusually warm
weather during the fourth quarter of 1998, decreased industrial sales,
decreased gas cost per dekatherm (dth) and decreased gas transition costs,
partially offset by increased wholesale sales and increased deliveries of gas
transported for others. Electric revenues were $1.1 billion, which represented
a $43.7 million increase from the comparable period for 1998. This increase
occurred mainly due to increased sales to residential and commercial customers
as a result of warmer weather during the third quarter of 1999, increased
wholesale transactions and increased fuel costs.
NINE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for the
nine months ended September 30, 1999 were $84.8 million higher than for the
nine months ended September 30, 1999, representing a 7.0% increase. Gas
revenues were $435.2 million, which represented a 11.8% increase from the
comparable period for 1998. This increase occurred primarily due to increased
sales to residential customers as a result of colder weather during the
period, increased deliveries of gas transported for others and increased
wholesale sales partially offset by decreased gas cost per dth and decreased
gas transition costs. Electric revenues were $862.2 million, which
represented a $38.9 million increase from the comparable period for 1998.
This increase was mainly attributable to increased sales to residential,
commercial and industrial customers, increased wholesale transactions and
increased fuel costs.
THREE MONTHS ENDED SEPTEMBER 30, 1999. Total operating revenues for
the three months ended September 30, 1999 were $25.8 million higher than for
the three months ended September 30, 1999, representing a 6.7% increase. Gas
revenues were $84.2 million, which represented a 17.3% increase from the
comparable period for 1998. This increase occurred primarily due to increased
wholesale sales and increased gas cost per dth, partially offset by decreased
industrial sales, decreased deliveries of gas transported for others and
decreased gas transition costs. Electric revenues were $324.9 million, which
represented a $13.4 million increase from the comparable period for 1998.
This increase was mainly attributable to increased sales to residential and
commercial customers, increased sales to industrial customers, increased fuel
costs, partially offset by decreased wholesale transactions
The basic steel industry accounted for 39% of natural gas delivered
(including volumes transported) and 27% of electric sales during the twelve
months ended September 30, 1999.
The components of the variations in gas and electric revenues are
shown in the following table:
<TABLE>
<CAPTION>
Variations
from
Prior Periods
---------------------------------
September 30, 1999
Compared to
September 30, 1998
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 $ 9,298 $ (14,737) $ (44,620)
Gas transition costs (1,156) (3,382) (6,815)
Changes in sales levels 563 40,399 8,161
Gas transported (62) 460 6,069
Wholesale gas 3,740 23,135 26,625
--------- --------- ---------
Total Gas Revenue Change $ 12,383 $ 45,875 $ (10,580)
--------- --------- ---------
Electric Revenue Changes-
Pass through of net changes in
fuel costs $ 12,128 $ 9,312 $ 9,078
Changes in sales levels 14,149 25,333 24,600
Wholesale electric (12,849) 4,249 10,041
--------- --------- ---------
Total Electric Revenue Change $ 13,428 $ 38,894 $ 43,719
--------- --------- ---------
Total Revenue Change $ 25,811 $ 84,769 $ 33,139
========= ========= =========
</TABLE>
You can find information about the gas adjustment factor that Northern
Indiana applies to its sales rates in Note 2, "Summary of Accounting Policies
- - Gas Cost Adjustment Clause" to the Consolidated Financial Statements.
COST OF SALES -
Cost of sales consists of gas costs, costs of fuel for electric
production and costs of power purchased.
GAS COSTS. Gas costs for the twelve months ended September 30, 1999
decreased by $13.4 million, or by 3.7%, from the twelve months ended
September 30, 1998. This decrease resulted due to decreased gas cost per dth
and decreased gas transition costs, partially offset by increased gas
purchased. Gas costs for the nine months ended September 30, 1999 increased
by $33.3 million, or by 15.3%, from the nine months ended September 30, 1998.
This increase occurred as a result of increased gas purchases during the
period, partially offset by decreased gas cost per dth and decreased gas
transition costs. Gas costs for the three months ended September 30, 1999
increased by $13.5 million, or by 34.2%, from the three months ended
September 30, 1998. This increase occurred as a result of increased gas cost
per dth and increased gas purchases during the period, partially offset by
decreased gas transition costs.
FUEL AND PURCHASED POWER. The cost of fuel used for electric generation
during the twelve months ended September 30, 1999 was $8.4 million lower
than the cost of fuel used during the twelve months ended September 30, 1998,
mainly due to decreased fuel costs per kilowatt-hour (kwh). The average cost
per kwh generated decreased by 3.4% from 1.54 cents per kwh during the twelve
months ended September 30, 1998, to 1.48 cents per kwh for the comparable
period for 1999. The cost of fuel used for electric generation during the
nine months ended September 30, 1999 was $5.2 million lower than the cost of
fuel used during the nine months ended September 30, 1998, mainly due to
decreased fuel costs of 2.7%, partially offset by increased electric
generation of 0.7%. The average cost per kwh generated during the nine months
ended September 30, 1999 decreased by 3.4% from 1.53 cents per kwh to 1.48
cents per kwh from the comparable period for 1998. The cost of fuel used for
electric generation during the three months ended September 30, 1999 was
relatively unchanged from the three months ended September 30, 1998. The
average cost per kwh generated during the three months ended September 30,
1999 decreased by 4.3% from 1.57 cents per kwh to 1.50 cents per kwh from the
comparable period for 1998.
Northern Indiana spent $43.1 million more during the twelve months ended
September 30, 1999 than during the comparable period in 1998 to purchase
power, primarily due to increased purchases of 153.6%, partially offset by an
15.4% decrease in the cost per kwh. Power purchased increased by $38.9 million
for the nine-month period ended September 30, 1998, reflecting increased bulk
power purchases of 162.8%, partially offset by an 17.1% decrease in the cost
per kwh. Power purchased increased by $11.2 million for the three-month period
ended September 30, 1998, reflecting 169.9% increase in the cost per kwh,
partially offset by decreased bulk power purchases of 38.6%
OPERATING MARGINS -
TWELVE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the
twelve months ended September 30, 1999 were $11.8 million higher than for the
twelve months ended September 30, 1998, representing a 1.1% increase. Gas
operating margin was $2.9 million higher than in the comparable period for
1998. This increase occurred mainly as a result of increased wholesale sales
and increased deliveries of gas transported for others, partially offset by
decreased sales to residential customers, reflecting unusually warm weather
during the fourth quarter of 1998 and decreased sales to industrial customers.
Electric operating margin was $788.8 million, which represented a $8.9 million
increase from the comparable for 1998. This increase occurred mainly due to
increased sales to residential and commercial customers, partially offset by
decreased margins on wholesale transactions.
NINE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the nine
months ended September 30, 1999 were $17.8 million higher than the nine
months ended September 30, 1998, representing a 2.3% increase. Gas operating
margin was $12.5 million higher than in the comparable period for 1998. This
increase occurred mainly as a result of increased sales to residential
customers reflecting colder weather during the first quarter of 1999,
increased wholesale sales and increased deliveries of gas transported for
others. Electric operating margin was $602.3 million, which represented a
$5.3 million increase from the comparable period for 1998. This increase
occurred mainly due to increased sales to residential, commercial and
industrial customers, partially offset by decreased margins on wholesale
transactions.
THREE MONTHS ENDED SEPTEMBER 30, 1999. Operating margins for the three
months ended September 30, 1999 were $1.3 million higher than the three months
ended September 30, 1998. Gas operating margin was $1.1 million lower than
in the comparable period in 1998. This decrease occurred mainly as a result
of decreased sales to industrial customers and lower margins on wholesale
transactions. Electric operating margin was $224.7 million, which represented
a $2.4 million increase from the comparable period for 1998. This increase
occurred mainly due to increased sales to residential customers, partially
offset by decreased wholesale transactions.
OPERATING EXPENSES AND TAXES -
Operating expenses and taxes (except income) consists of operations
expenses, maintenance expenses, depreciation and amortization expenses and
taxes (except income).
OPERATIONS EXPENSE. Operation expenses for the twelve months ended
September 30, 1999 were $4.6 million lower than in the twelve months ended
September 30, 1998. Operation expenses were lower primarily as a result of
$13.0 million insurance settlement related to manufactured gas plant site
cleanup costs partially offset by increased employee related costs of $2.2
million, increased property and liability claims of $1.9 million, increased
write-offs for uncollectible accounts of $1.2 million and increased consulting
services. Operation expenses for the nine months ended September 30, 1999
were $2.2 million lower than for the nine months ended September 30, 1998.
Operation expenses were lower in the nine-month period primarily as a result
of a $13.0 million insurance settlement related to manufactured gas plant
site cleanup costs, partially offset increased employee related costs of $6.2
million, increased property and liability claims of $1.9 million and increased
consulting services of $2.0 million. Operation expenses for the three months
ended September 30, 1999 were $11.0 million lower than for the three months
ended September 30, 1998. Operation expenses were lower in the three-month
period primarily as a result of a $13.0 million insurance settlement related
to manufactured gas plant site cleanup costs, partially offset by increased
consulting services of $1.8 million.
MAINTENANCE EXPENSE. Maintenance expenses for the twelve months ended
September 30, 1999 were $3.7 million lower than in the twelve months ended
September 30, 1998. Maintenance expenses were lower primarily as a result of
decreased electric production facility maintenance costs of $1.9 million and
decreased electric and gas distribution facilities maintenance of $2.0
million. Maintenance expenses for the three and nine months ended
September 30, 1999 were relatively unchanged from the three and nine months
ended September 30, 1998.
DEPRECIATION AND AMORTIZATION EXPENSE. Depreciation and amortization
expenses for the three-month, nine-month and twelve-months periods ended
September 30, 1999 were $1.1, $4.0 and $6.9 million, respectively, higher
than in the comparable period for 1998. These higher expenses primarily
related to increased depreciation expense as a result of increased depreciable
plant.
OTHER INCOME (DEDUCTIONS)
Other Income (Deductions) for the three-month, nine-month and twelve-
month periods ended September 30, 1999 increased by $2.7, $4.7 and $5.2
million, respectively, from the comparable periods for 1998 primarily as a
result of power trading activities which began in early 1999.
INTEREST CHARGES -
Interest charges for the three-month, nine-month and twelve-month
periods ended September 30, 1999 were $1.1, $3.4 and $4.3 million lower,
respectively, than in the comparable periods for 1998. These decreases
resulted primarily due to decreased short-term and long term debt outstanding
during the three-month, nine-month and twelve-month periods ended
September 30, 1999.
LIQUIDITY AND CAPITAL RESOURCES -
Generally, cash flow from operations has provided sufficient liquidity
to meet current operating requirements. But because the utility and utility
construction business is seasonal in nature, commercial paper is issued for
short-term financing. As of September 30, 1999 and December 31, 1998, $43.3
million and $85.6 million of commercial paper was outstanding, respectively.
The weighted average interest rate of commercial paper outstanding as of
September 30, 1999 was 5.36%.
Northern Indiana entered into a five-year $100 million credit agreement
and a 364-day $100 million revolving credit agreement with several banks.
These agreements terminate on September 23, 2003 and September 23, 2000,
respectively. The 364-day agreement may be extended at expiration for
additional periods of 364-days. Under these agreements, funds are borrowed at
a floating rate of interest or, under certain circumstances, at a fixed rate
of interest for a short-term periods. These agreements provide financing
flexibility and may be used to support the issuance of commercial paper. As
of September 30, 1999, there were no borrowings outstanding under these
agreements.
In addition, Northern Indiana has $13.2 million in lines of credit which
run until May 31, 2000. The credit pricing of each of the lines varies from
either the lending banks' commercial prime or market rates. As of
September 30, 1999, there were no borrowings under these lines of credit. The
credit agreements and lines of credit are also available to support the
issuance of commercial paper.
Northern Indiana also has $220 million of money market lines of credit.
As of September 30, 1999 and December 31, 1998, $45.9 million and $40.5
million of borrowings were outstanding, respectively, under these lines of
credit.
CONSTRUCTION PROGRAM. Future commitments with respect to its
construction program are expected to be met through internally generated
funds.
MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS -
See Note 18, "Financial Instruments and Risk Management," to the
consolidated financial statements for a discussion of the types of commodity-
based derivative financial instruments and risk management.
There are two primary market risks, commodity price risk and interest
rate risk, to which Northern Indiana is exposed.
COMMODITY PRICE RISK. Price risk management activities are designed
to address price fluctuations in electricity and natural gas commodity prices
that are sensitive to changes in supply and demand. These changes are
actively monitored and derivative financial and commodity instruments are used
to reduce, or hedge, exposure to price risks. Part of these price risks
includes differences in price based on geography. Geographic price
differentials result primarily from transportation costs and local supply and
demand factors. To hedge a portion of this exposure, basis swaps are used
from time to time. However, not all basis exposure is hedged.
A portion of customer sales contracts are based upon a fixed sales price
with varying volumes that ultimately depend on a customer's supply
requirements. Financial derivatives are used based on modeling techniques in
order to anticipate future supply requirements. Nonetheless, Northern Indiana
remains exposed to price risk for the difference between a customer's actual
supply requirements and those requirements predicted by the models.
Currently, commodity price risk of Northern Indiana business is
relatively limited, since current regulations allow Northern Indiana to recoup
any prudently incurred fuel and gas costs through rate-making. As the utility
industry undergoes deregulation, however, Northern Indiana will be providing
services without the benefit of the traditional rate-making and, therefore,
will be more exposed to commodity price risk.
Because derivative financial and commodity instruments are substantially
the same commodities that are bought and sold in the physical market, Northern
Indiana believes that its price management activities do not require any
special correlation studies, other than monitoring the degree of convergence
between the derivative and cash markets.
INTEREST RATE RISK. Long-term debt is utilized as a primary source of
capital. A significant portion of this long-term debt consists of medium-term
notes. In addition, longer term fixed-price debt instruments have been used
that in the past have been refinanced when interest rates decreased. To the
extent that such refinancing is economical, refinancing these fixed-price
instruments will continue.
Information about long-term debt is in Note 13 to the consolidated
financial statements, "Long-term Debt." Information about the current market
valuation of long-term debt is in Note 19 to the consolidated financial
statements "Fair Value of Financial Instruments." Information about the use
of derivatives and risk management policy is in Note 2 to the consolidated
financial statements, "Summary of Significant Accounting Policies-Derivaties."
YEAR 2000 COSTS -
RISKS. Year 2000 issues address the ability of electronic processing
equipment to process date sensitive information and recognize the last two
digits of a date as occurring in or after the year 2000. Any failure in any
system may result in material operational and financial risks. Possible
scenarios include a system failure in a generating plant, an operating
disruption or delay in transmission or distribution, or an inability to
interconnect with the systems of other utilities. In addition, while Northern
Indiana anticipates that mission-critical systems will be year 2000 compliant
in a timely fashion, it cannot guarantee the compliance of systems operated by
other companies upon which it depends. For example, the ability of an
electric company to provide electricity to its customers depends upon a
regional electric transmission grid, which connects the systems of neighboring
utilities to support the reliability of electric power within the region. If
one company's system is not year 2000 compliant, then a failure could affect
the reliability of all providers within the grid, including Northern Indiana.
Similarly, gas operations depend on natural gas pipelines that are not owned
or controlled by Northern Indiana, and any non-compliance by a company owning
or controlling those pipelines may affect Northern Indiana's ability to
provide gas to its customers. Failure to achieve year 2000 readiness could
have a material adverse affect on results of operations, financial position
and cash flows.
The program to address risks associated with the year 2000 is
continuing. The focus is on both information technology (IT) and non-IT
systems, and substantial progress has been made in preparing these systems for
proper functioning in the year 2000.
STATE OF READINESS. The year 2000 program consists of four phases:
inventory (identifying systems potentially affected by the year 2000),
assessment (testing identified systems), remediation (correcting or replacing
non-compliant systems) and validation (evaluating and testing remediated
systems to confirm compliance). Northern Indiana has completed the
remediation and validation phases for all of its mission-critical systems.
Northern Indiana has completed the inventory and assessment phases for all
of its non-IT mission-critical systems and has scheduled remediation
(including replacement) and validation for its non-IT mission-critical systems
throughout 1999. Substantial completion of mission-critical year 2000 efforts
was completed in June 1999, with the year 2000 program concluding in the
fourth quarter of 1999.
Because outside suppliers and vendors with similar year 2000 issues are
depended upon, the ability of those suppliers and vendors to provide it with
an uninterrupted supply of goods and services is being assessed. Critical
vendors and suppliers have been contacted in order to investigate their year
2000 efforts. In addition, electricity and gas industry groups such as the
North American Electric Reliability Council, the Electric Power Research
Institute, and the American Gas Association are being worked with to discuss
and evaluate the potential impact of year 2000 problems upon the electric grid
systems and pipeline networks that interconnect within each of those
industries.
COSTS. The total cost of the year 2000 program is estimated to be $19
million. These costs have been, and will continue to be, funded from
operations. Costs related to the maintenance or modification of existing
systems are expensed as incurred. Costs related to the acquisition of
replacement systems are capitalized. These costs are not anticipated to have
a material impact on results of operations.
CONTINGENCY PLANS. Northern Indiana currently is in the process of
structuring its contingency plans to address the possibility that any mission-
critical system upon which it depends, including those controlled by outside
parties, will be non-compliant. This includes identifying alternative
suppliers and vendors, conducting staff training and developing communication
plans. In addition, the ability to maintain or restore service in the event
of a power failure or operating disruption or delay is being evaluated, along
with the limited ability to mitigate the effects of a network failure by
isolating its own network from the non-compliant segments of the greater
network. These contingency plans were completed during the second quarter
1999; however, the contingency plans will be under review during the fourth
quarter of 1999.
ALL STATEMENTS REGARDING YEAR 2000 MATTERS CONTAINED IN THIS REPORT ARE
"YEAR 2000 READINESS DISCLOSURES" WITHIN THE MEANING OF THE YEAR 2000
INFORMATION AND READINESS DISCLOSURE ACT.
COMPETITION AND REGULATORY CHANGES -
The regulatory frameworks applicable to Northern Indiana, at both state
and federal levels, are undergoing fundamental change. These changes have
had and will continue to have an impact on operations, structure and
profitability. At the same time, competition within the electric and gas
industries will create opportunities to compete for new customers and
revenues. Management has taken steps to become more competitive and
profitable in this changing environment, including converting some of its
generating units to allow use of lower cost, low sulfur coal, providing its
gas customers with increased customer choice for new products and services
throughout the service territory.
THE ELECTRIC INDUSTRY. At the Federal level, FERC issued Order No.
888-A in 1996 which required all public utilities owning, controlling, or
operating transmission lines to file non-discriminatory open-access tariffs
and offer wholesale electricity suppliers and marketers the same transmission
service they provide themselves. In 1997, FERC approved Northern Indiana's
open-access transmission tariff. Although wholesale customers currently
represent a small portion of Northern Indiana's electricity sales, it intends
to continue its efforts to retain and add wholesale customers by offering
competitive rates and also intends to expand the customer base for which it
provides transmission services.
At the state level, it was announced in 1997 that if a consensus could
be reached regarding electric utility restructuring legislation, a
restructuring bill during the 1999 session of the Indiana General Assembly
would be supported. During 1998, discussions were held with other investor-
owned utilities in Indiana regarding the technical and economic aspects of
possible legislation leading to greater customer choice. A consensus was not
reached. Therefore, no legislation was supported regarding electric
restructuring during the 1999 session of the Indiana General Assembly. During
1999, discussions will continue with all segments of the Indiana electric
industry in an attempt to reach a consensus on electric restructuring
legislation for introduction during the 2000 Session of the Indiana General
Assembly.
THE GAS INDUSTRY. At the Federal level, gas industry deregulation began
in the mid-1980's when FERC required interstate pipelines to provide
nondiscriminatory transportation services pursuant to unbundled rates. This
regulatory change permitted large industrial and commercial customers to
purchase their gas supplies either from Northern Indiana or directly from
competing producers and marketers, which would then use Northern Indiana's
facilities to transport the gas. More recently, the focus of deregulation in
the gas industry has shifted to the states.
At the state level, the Indiana Utility Regulatory Commission (IURC)
approved in 1997 Northern Indiana's Alternative Regulatory Plan (ARP), which
implemented new rates and services that included, among other things,
unbundling of services for additional customer classes (primarily residential
and commercial users), negotiated services and prices, a gas cost incentive
mechanism, and a price protection program. The gas cost incentive mechanism
allows Northern Indiana to share any cost savings or cost increases with its
customers based upon a comparison of Northern Indiana's actual gas supply
portfolio cost to a market-based benchmark price. Phase I of Northern
Indiana's Customer Choice Pilot Program ended on March 31, 1999. This pilot
program offered 82,000 residential customers within St. Joseph County and
10,000 commercial customers throughout the Northern Indiana service area the
right to choose alternative gas suppliers. Phase II of Northern Indiana's
Customer Choice Pilot Program will commence on April 1, 1999 and continue for
a one-year period. During this phase, Northern Indiana is offering customer
choice to all 660,000 residential and 50,000 commercial customers throughout
its gas service territory. A limit of 150,000 residential and 20,000
commercial customers are eligible to enroll in Phase II of the program. The
IURC order allows NiSource's natural gas marketing subsidiary to participate
as a supplier of choice to Northern Indiana customers. In addition, as
Northern Indiana has allowed residential and commercial customers to designate
alternative gas suppliers, it has also offered new services to all classes of
customers including, price protection, negotiated sales and services, gas
lending and parking, and new storage services.
To date, Northern Indiana's system has not been materially affected
by competition, and management does not foresee substantial adverse effects
in the near future unless the current regulatory structure is substantially
altered. Northern Indiana believes the steps it is taking to deal with
increased competition has had and will continue to have significant positive
effects in the next few years.
IMPACT OF ACCOUNTING STANDARDS -
Information about the impact of anticipated accounting standards that
have not yet been adopted upon accounting policy can be found in Note 2,
"Summary of Significant Accounting Policies-Impact of Accounting Standards" to
the consolidated financial statements.
FORWARD LOOKING STATEMENTS -
This report contains forward looking statements within the meaning of
the securities laws. Forward looking statements include terms such as "may,"
"will," "expect," "believe," "plan" and other similar terms. Northern Indiana
cautions that, while it believes such statements to be based on reasonable
assumptions and makes such statements in good faith, you cannot be assured
that the actual results will not differ materially from such assumptions or
that the expectations set forth in the forward looking statements derived from
such assumptions will be realized. You should be aware of important factors
that could have a material impact on future results. These factors include,
weather, the federal and state regulatory environment, year 2000 issues, the
economic climate, regional, commercial, industrial and residential growth in
the service territories served by Northern Indiana, customers' usage patterns
and preferences, the speed and degree to which competition enters the utility
industry, the timing and extent of changes in commodity prices, changing
conditions in the capital and equity markets and other uncertainties, all of
which are difficult to predict, and many of which are beyond Northern
Indiana's control.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For a discussion of primary market risks and risk management policy,
see "Management's Discussion and Analysis of Financial Condition and Results
of Operations-Market Risk Sensitive Instruments and Positions."
<PAGE>
PART II.
OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS.
Northern Indiana is a party to various pending proceedings, including
suits and claims against it for personal injury, death and property damage.
Such proceedings and suits, and the amounts involved, are routine for the kind
of business conducted by Northern Indiana, except as described under Note 4
"Environmental Matters," in the notes to consolidated financial statements
under Part I, Item 1 of this Report on Form 10-Q, which note is incorporated
by reference. No other material legal proceedings against Northern Indiana or
its subsidiaries are pending or, to the knowledge of Northern Indiana,
contemplated by governmental authorities and other parties.
Item 2. CHANGES IN SECURITIES.
None
Item 3. DEFAULTS UPON SENIOR SECURITIES.
None
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
Item 5. OTHER INFORMATION.
None
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit 23 - Consent of Arthur Andersen LLP
Exhibit 27 - Financial Data Schedule
(b) Reports on Form 8-K.
None
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized.
Northern Indiana Public Service Company
(Registrant)
/s/ David J. Vajda
---------------------------------------
David J. Vajda,
Controller and Chief Accounting Officer
Date November 12, 1999
<PAGE>
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 10-Q into Northern Indiana
Public Service Company's previously filed Form S-3 Registration Statement
No. 333-26847.
/s/ Arthur Andersen LLP
Chicago, Illinois
November 12, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
financial statements of Northern Indiana Public Service Company for three
months ended September 30, 1999 and is qualified in its entirety by
reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JUL-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,950,342
<OTHER-PROPERTY-AND-INVEST> 2,636
<TOTAL-CURRENT-ASSETS> 308,949
<TOTAL-DEFERRED-CHARGES> 149,491
<OTHER-ASSETS> 200,958
<TOTAL-ASSETS> 3,612,376
<COMMON> 859,488
<CAPITAL-SURPLUS-PAID-IN> 12,525
<RETAINED-EARNINGS> 146,289
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,018,302
54,585
81,114
<LONG-TERM-DEBT-NET> 316,500
<SHORT-TERM-NOTES> 45,860
<LONG-TERM-NOTES-PAYABLE> 611,025
<COMMERCIAL-PAPER-OBLIGATIONS> 43,250
<LONG-TERM-DEBT-CURRENT-PORT> 157,000
1,828
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,282,912
<TOT-CAPITALIZATION-AND-LIAB> 3,612,376
<GROSS-OPERATING-REVENUE> 409,096
<INCOME-TAX-EXPENSE> 33,029
<OTHER-OPERATING-EXPENSES> 296,937
<TOTAL-OPERATING-EXPENSES> 329,966
<OPERATING-INCOME-LOSS> 79,130
<OTHER-INCOME-NET> 1,681
<INCOME-BEFORE-INTEREST-EXPEN> 80,811
<TOTAL-INTEREST-EXPENSE> 18,696
<NET-INCOME> 62,115
2,021
<EARNINGS-AVAILABLE-FOR-COMM> 60,094
<COMMON-STOCK-DIVIDENDS> 58,000
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 84,464
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
