SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
X Quarterly Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 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 July 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 June 30, 1999,
and December 31, 1998, and the related consolidated statements of
income, retained earnings and cash flows for the three, six and twelve month
periods ended June 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 June 30, 1999, and
December 31, 1998, and the results of their operations and their cash flows
for the three, six and twelve month periods ended June 30, 1999 and 1998, in
conformity with generally accepted accounting principles.
/s/ Arthur Andersen LLP
Chicago, Illinois
August 6, 1999
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
ASSETS 1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
UTILITY PLANT, AT ORIGINAL COST (INCLUDING
CONSTRUCTION WORK IN PROGRESS OF
$179,282 AND $149,426 RESPECTIVELY)
(NOTE 2):
Electric $ 4,198,729 $ 4,154,060
Gas 1,291,005 1,272,483
Common 362,861 364,822
------------ ------------
5,852,595 5,791,365
Less - Accumulated depreciation
and amortization 2,890,681 2,804,720
------------ ------------
Total Utility Plant 2,961,914 2,986,645
------------ ------------
OTHER PROPERTY AND INVESTMENTS 328 519
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 8,777 19,541
Accounts receivable, less reserve of
$8,202 and $4,458, respectively (Note 2) 121,262 104,445
Gas cost adjustment clause (Note 2) 0 44,044
Materials and supplies, at average cost 51,594 51,554
Electric production fuel, at average cost 26,962 32,402
Natural gas in storage, at last-in,
first-out cost (Note 2) 25,559 50,859
Prepayments and other 30,929 31,056
------------ ------------
Total Current Assets 265,083 333,901
------------ ------------
OTHER ASSETS:
Regulatory assets (Note 2) 201,778 203,722
Prepayments and other (Note 5) 134,403 127,162
------------ ------------
Total Other Assets 336,181 330,884
------------ ------------
$ 3,563,506 $ 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
June 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) 144,195 146,138
------------ ------------
Common shareholder's equity 1,016,208 1,018,150
Cumulative preferred stocks,
(excluding amounts due within one
year) (Note 7)
Series without mandatory redemption
provisions (Note 8) 81,115 81,116
Series with mandatory redemption
provisions (Note 9) 55,185 56,435
Long-term debt excluding amounts due
within one year (Note 13) 923,186 1,077,959
------------ ------------
Total Capitalization 2,075,694 2,233,660
------------ ------------
CURRENT LIABILITIES -
Current portion of long-term
debt (Note 14) 157,000 2,000
Short-term borrowings (Note 15) 68,200 126,100
Accounts payable 127,879 142,414
Dividends declared on common and
preferred stocks 54,041 63,101
Customer deposits 21,294 20,178
Taxes accrued 81,372 88,401
Interest accrued 9,199 9,118
Gas cost adjustment clause 7,065 0
Fuel adjustment clause 2,737 6,279
Accrued employment costs 37,390 44,223
Other accruals 33,275 28,546
------------ ------------
Total Current Liabilities 599,452 530,360
------------ ------------
OTHER:
Deferred income taxes (Note 4) 603,402 608,935
Deferred investment tax credits, being
amortized over life of related property
(Note 4) 89,129 92,693
Deferred credits 50,995 48,084
Accrued liability for postretirement
benefits (Note 6) 133,316 127,115
Other noncurrent liabilities 11,518 11,102
------------ ------------
Total Other Liabilities 888,360 887,929
------------ ------------
COMMITMENTS AND CONTINGENCIES
(Notes 3, 16 and 17)
$ 3,563,506 $ 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 Six Months
Ended June 30, Ended June 30,
---------------------- ----------------------
1999 1998 1999 1998
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 104,378 $ 98,859 $ 351,081 $ 317,589
Electric 277,380 271,611 537,263 511,797
---------- ---------- ---------- ----------
381,758 370,470 888,344 829,386
---------- ---------- ---------- ----------
Cost of Energy: (Note 2)
Gas costs 60,271 55,204 198,237 178,374
Fuel for electric
generation 57,630 65,423 115,928 121,017
Power purchased 26,936 12,400 43,718 16,047
---------- ---------- ---------- ----------
144,837 133,027 357,883 315,438
---------- ---------- ---------- ----------
Operating Margin 236,921 237,443 530,461 513,948
---------- ---------- ---------- ----------
Operating Expenses and
Taxes (except income):
Operation 65,085 61,814 132,740 123,917
Maintenance (Note 2) 17,458 18,627 35,711 35,321
Depreciation and
amortization (Note 2) 58,060 56,800 116,198 113,320
Taxes (except income) 17,337 17,462 38,056 36,599
---------- ---------- ---------- ----------
157,940 154,703 322,705 309,157
---------- ---------- ---------- ----------
Operating Income Before
Utility Income Taxes 78,981 82,740 207,756 204,791
---------- ---------- ---------- ----------
Utility Income Taxes
(Note 4) 21,355 22,434 61,055 58,351
---------- ---------- ---------- ----------
Operating Income 57,626 60,306 146,701 146,440
---------- ---------- ---------- ----------
Other Income (Deductions)
(Note 2) 1,116 (1,268) 45 (1,876)
---------- ---------- ---------- ----------
Interest:
Interest on long-term debt 16,873 17,461 33,593 35,311
Other interest 77 728 934 1,577
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 1,036 1,047 2,071 2,100
---------- ---------- ---------- ----------
17,986 19,236 36,598 38,988
---------- ---------- ---------- ----------
Net Income 40,756 39,802 110,148 105,576
Dividend requirements on
preferred shares 2,026 2,077 4,091 4,193
---------- ---------- ---------- ----------
Balance available
for common shares $ 38,730 $ 37,725 $ 106,057 $ 101,383
========== ========== ========== ==========
Dividends declared $ 53,000 $ 49,000 $ 108,000 $ 95,000
========== ========== ========== ==========
<CAPTION>
Twelve Months
Ended June 30,
----------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
Operating Revenues:
(Notes 2, 3 and 20)
Gas $ 605,977 $ 638,673
Electric 1,101,584 1,039,002
---------- ----------
1,707,561 1,677,675
---------- ----------
Cost of Energy: (Note 2)
Gas costs 340,896 378,430
Fuel for electric
generation 245,560 246,548
Power purchased 69,661 33,843
---------- ----------
656,117 658,821
---------- ----------
Operating Margin 1,051,444 1,018,854
---------- ----------
Operating Expenses and
Taxes (except income):
Operation 254,743 253,319
Maintenance (Note 2) 65,692 69,302
Depreciation and
amortization (Note 2) 231,425 224,856
Taxes (except income) 73,684 70,694
---------- ----------
625,544 618,171
---------- ----------
Operating Income Before
Utility Income Taxes 425,900 400,683
---------- ----------
Utility Income Taxes
(Note 4) 123,490 113,544
---------- ----------
Operating Income 302,410 287,139
---------- ----------
Other Income (Deductions)
(Note 2) (1,668) (4,090)
---------- ----------
Interest:
Interest on long-term debt 67,954 71,559
Other interest 3,881 4,149
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 4,155 4,205
---------- ----------
75,990 79,913
---------- ----------
Net Income 224,752 203,136
Dividend requirements on
preferred shares 8,233 8,437
---------- ----------
Balance available
for common shares $ 216,519 $ 194,699
========== ==========
Dividends declared $ 225,000 $ 194,775
========== ==========
<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 Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------- ------------------- -------------------
1999 1998 1999 1998 1999 1998
========= ========= ========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT
BEGINNING OF
PERIOD $ 158,465 $ 163,951 $ 146,138 $ 146,293 $ 152,676 $ 152,752
ADD:
Net income 40,756 39,802 110,148 105,576 224,752 203,136
--------- --------- --------- --------- --------- ---------
199,221 203,753 256,286 251,869 377,428 355,888
--------- --------- --------- --------- --------- ---------
LESS:
Dividends
Cumulative
Preferred
stocks -
4-1/4% series 222 223 444 445 888 889
4-1/2% series 89 89 180 180 360 360
4.22% series 111 111 224 224 448 448
4.88% series 122 122 244 244 488 488
7.44% series 79 79 156 156 312 312
7.50% series 65 65 131 131 261 261
8.85% series 102 129 240 295 516 627
7-3/4% series 70 80 140 161 298 340
8.35% series 112 125 225 250 447 497
6.50% series 699 699 1,397 1,397 2,795 2,795
Adjustable
Rate,
Series A 355 355 710 710 1,420 1,420
Common shares 53,000 49,000 108,000 95,000 225,000 194,775
--------- --------- --------- --------- --------- ---------
55,026 51,077 112,091 99,193 233,233 203,212
--------- --------- --------- --------- --------- ---------
BALANCE AT END
OF PERIOD $ 144,195 $ 152,676 $ 144,195 $ 152,676 $ 144,195 $ 152,676
========= ========= ========= ========= ========= =========
<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 June 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 40,756 $ 39,802
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 58,060 56,800
Deferred federal and state income
taxes, net (7,673) (13,307)
Deferred investment tax credits, net (1,782) (1,782)
Advance contract payment 475 475
Change in certain assets and liabilities -
Accounts receivable, net 9,858 16,183
Electric production fuel (1,783) 4,742
Materials and supplies 2,260 2,434
Natural gas in storage (5,920) (11,265)
Accounts payable 21,484 (7,367)
Taxes accrued (68,398) (52,099)
Fuel adjustment clause (1,286) 1,736
Gas cost adjustment clause 1,869 11,465
Accrued employment costs 2,348 (1,788)
Other accruals (334) (6,148)
Other, net (6,854) (12,699)
---------- ----------
Net cash provided by operating activities 43,080 27,182
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (53,236) (46,892)
Other, net 3,605 (779)
---------- ----------
Net cash used in investing activities (49,631) (47,671)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 50,200 93,800
Retirement of long-term debt 0 (35,000)
Retirement of preferred shares (1,251) (1,256)
Cash dividends paid on common shares (55,000) (46,000)
Cash dividends paid on preferred shares (2,065) (2,116)
Other, net 114 117
---------- ----------
Net cash provided by (used in)
financing activities (8,002) 9,545
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS (14,553) (10,944)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 23,330 25,775
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 8,777 $ 14,831
========== ==========
<CAPTION>
Six Months
Ended June 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 110,148 $ 105,576
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 116,198 113,320
Deferred federal and state operating
income taxes, net (34,457) (39,973)
Deferred investment tax credits, net (3,563) (3,564)
Advance contract payment 950 950
Change in certain assets and liabilities -
Accounts receivable, net (16,817) 12,461
Electric production fuel 5,440 2,338
Materials and supplies (40) 1,120
Natural gas in storage 25,300 16,298
Accounts payable (8,355) (23,898)
Taxes accrued 15,989 26,559
Fuel adjustment clause (3,542) 3,304
Gas cost adjustment clause 51,109 61,529
Accrued employment costs (6,833) (15,612)
Other accruals 4,729 (9,311)
Other, net 5,063 (7,787)
---------- ----------
Net cash provided by operating activities 261,319 243,310
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (86,709) (80,202)
Other, net (5,322) (10,129)
---------- ----------
Net cash used in investing activities (92,031) (90,331)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt (57,900) (6,700)
Retirement of long-term debt 0 (35,000)
Retirement of preferred shares (1,251) (1,256)
Cash dividends paid on common shares (117,000) (101,000)
Cash dividends paid on preferred shares (4,128) (4,230)
Other, net 227 238
---------- ----------
Net cash used in financing activities (180,052) (147,948)
---------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (10,764) 5,031
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 19,541 9,800
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 8,777 $ 14,831
========== ==========
<CAPTION>
Twelve Months
Ended June 30,
------------------------
1999 1998
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 224,752 $ 203,136
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 231,425 224,856
Deferred federal and state operating
income taxes, net (27,058) (19,202)
Deferred investment tax credits, net (7,159) (7,182)
Advance contract payment 1,900 1,900
Change in certain assets and liabilities -
Accounts receivable, net (40,995) (8,973)
Electric production fuel (10,463) 12,133
Materials and supplies 952 3,802
Natural gas in storage 4,023 (3,319)
Accounts payable 31,790 (20,106)
Taxes accrued 13,549 12,950
Fuel adjustment clause 2,112 8,882
Gas cost adjustment clause 32,056 19,638
Accrued employment costs 1,907 (3,482)
Other accruals 8,535 (13,040)
Other, net (6,053) (11,852)
---------- ----------
Net cash provided by operating activities 461,273 400,141
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (181,107) (153,056)
Other, net 5,135 (13,112)
---------- ----------
Net cash used in investing activities (175,972) (166,168)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Issuance of long-term debt 500 40,000
Net change in short-term debt (44,100) 31,850
Retirement of long-term debt (16,509) (102,247)
Retirement of preferred shares (2,408) (2,411)
Cash dividends paid on common shares (221,000) (189,775)
Cash dividends paid on preferred shares (8,290) (8,482)
Other, net 452 203
---------- ----------
Net cash used in financing activities (291,355) (230,862)
---------- ----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS (6,054) 3,111
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 14,831 11,720
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 8,777 $ 14,831
========== ==========
<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, six-month and twelve-month
periods ended June 30, 1999 and was 3.7% for three-month, 3.6% for the six-
month and twelve-month periods ended June 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 six-month periods and 5.5%
for the twelve-month periods ended June 30, 1999 and 5.4% for the three-month,
six-month and twelve-month periods ended June 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 June 30, 1999, $100 million of accounts
receivable had been sold under a sales agreement, which expires on May 31,
2002. The June 30, 1999 and December 31, 1998 accounts receivable balances
include approximately $8.1 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 Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 86,040 $ 73,320 $ 86,086 $ 73,340 $147,891 $128,149
Interest, net of
amounts
capitalized $ 24,663 $ 26,736 $ 33,983 $ 34,270 $ 71,358 $ 73,555
</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.
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. If the statutory requirement
relating to the level of return is satisfied, any under-recovery or
over-recovery caused by variances between estimated and actual cost in a
given three-month period will be included in a future filing. 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 for 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 June 1999 and December 1998, the estimated replacement
cost of gas in storage (current and non-current) at June 30, 1999 and
December 31, 1998 exceeded the stated LIFO cost by $38.5 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, $9.5 million and
$19.3 million for the three-month, six-month and twelve-month periods ended
June 30, 1999, respectively, and totaled $4.6 million, $11.6 million and $23.2
million for the three-month, six-month and twelve-month periods ended June 30,
1998, respectively, consist primarily of employee compensation and benefits.
Northern Indiana purchased natural gas and transportation services
from affiliated companies in the amounts of $2.3 million, $5.9 million and
$18.1 million representing 2.9%, 3.3% and 5.8% of Northern Indiana's total gas
costs for the three-month, six-month and twelve-month periods ended June 30,
1999, respectively. Northern Indiana purchased natural gas and transportation
services from affiliated companies in the amounts of $6.7 million, $8.6
million and $14.8 million representing 8.8%, 5.1% and 4.2% of Northern
Indiana's total gas costs for the three-month, six-month and twelve-month
periods ended June 30, 1998, respectively.
Northern Indiana 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 June 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>
June 30, December 31,
1999 1998
============= =============
(Dollars in thousands)
<S> <C> <C>
Unamortized reacquisition premium on
debt (Note 13) $ 41,231 $ 42,962
Unamortized R.M. Schahfer Unit 17 and
Unit 18 carrying charges
and deferred depreciation (See below) 60,220 62,329
Bailly scrubber carrying charges and
deferred depreciation (See below) 8,477 8,945
Deferral of SFAS No. 106 expense not
recovered (Note 6) 75,568 78,367
FERC Order No. 636 transition costs 16,852 22,093
Regulatory income tax asset, net (Note 4) 26,799 21,635
------------- -------------
229,147 236,331
Less: Current portion of regulatory assets 27,369 32,609
------------- -------------
$ 201,778 $ 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 the 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, owned
and operated, it may be required to share in the costs of clean up of such
sites. A program was instituted to investigate former manufactured-gas plant
sites where it is the current or former owner, which investigation has
identified twenty-four of these sites. Initial sampling has been conducted at
seventeen sites. Follow-up investigations have been conducted at twelve sites
and remedial measures have been selected 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 remediation costs to be
incurred at the manufactured gas plants, various companies that provided
insurance coverage which Northern Indiana believed covered costs related to
actions taken and to be taken at former manufactured-gas plant sites were
approached. Northern Indiana has 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. Cash settlements have been received from
several insurance companies. Additionally, agreements have been reached with
other 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 June 30, 1999, a reserve of approximately $19 million has been
recorded to cover probable corrective actions. The ultimate liability in
connection with those 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, and 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, will not have a significant impact 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 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 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 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 both the new
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.
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 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 June 30,
1999 and December 31, 1998 were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
============= =============
(Dollars in thousands)
<S> <C> <C>
Deferred tax liabilities -
Accelerated depreciation
and other property differences $ 732,961 $ 735,589
AFUDC-equity 31,921 33,029
Adjustment clauses 3,717 14,322
Other regulatory assets 28,659 29,721
Prepaid pension and other benefits 33,742 34,170
Reacquisition premium on debt 15,637 16,293
Deferred tax assets -
Deferred investment tax credits (33,802) (35,154)
Removal costs (165,073) (157,728)
Other postretirement/postemployment
benefits (50,560) (48,208)
Other, net (27,401) (23,682)
------------- -------------
569,801 598,352
Less: Deferred income taxes related to
current assets and liabilities (33,601) (10,583)
------------- -------------
Deferred income taxes - noncurrent $ 603,402 $ 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 Six Months
Ended June 30, Ended June 30,
-------------------- --------------------
1999 1998 1999 1998
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Current income taxes -
Federal $ 27,071 $ 32,618 $ 86,653 $ 88,747
State 3,739 4,905 12,422 13,141
--------- --------- --------- ---------
30,810 37,523 99,075 101,888
--------- --------- --------- ---------
Deferred income taxes, net -
Federal (7,109) (12,319) (31,855) (36,967)
State (564) (988) (2,602) (3,006)
--------- --------- --------- ---------
(7,673) (13,307) (34,457) (39,973)
--------- --------- --------- ---------
Deferred investment tax credits,
net (1,782) (1,782) (3,563) (3,564)
--------- --------- --------- ---------
Total utility operating income
taxes 21,355 22,434 61,055 58,351
Income tax applicable to non-
operating activities and income
of subsidiaries 638 (827) (6) (1,232)
--------- --------- --------- ---------
Total income taxes $ 21,993 $ 21,607 $ 61,049 $ 57,119
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended June 30,
--------------------
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Current income taxes -
Federal $ 138,270 $ 121,229
State 19,437 18,699
--------- ---------
157,707 139,928
--------- ---------
Deferred income taxes, net -
Federal (25,178) (17,923)
State (1,880) (1,279)
--------- ---------
(27,058) (19,202)
--------- ---------
Deferred investment tax credits,
net (7,159) (7,182)
--------- ---------
Total utility operating income
taxes 123,490 113,544
Income tax applicable to non-
operating activities and income
of subsidiaries (711) (3,645)
--------- ---------
Total income taxes $ 122,779 $ 109,899
========= =========
</TABLE>
A reconciliation of total income tax expense to an amount computed by
applying the statutory federal income tax rate to pre-tax income is as
follows:
<TABLE>
<CAPTION>
Three Months Twelve Months
Ended June 30, Ended June 30,
-------------------- --------------------
1999 1998 1999 1998
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Net income $ 40,756 $ 39,802 $ 110,148 $ 105,576
Add-Income taxes 21,993 21,607 61,049 57,119
--------- --------- --------- ---------
Net income before income taxes $ 62,749 $ 61,409 $ 171,197 $ 162,695
========= ========= ========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 21,962 $ 21,493 $ 59,919 $ 56,943
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 968 998 1,937 1,996
Amortization of deferred
investment tax credits (1,782) (1,782) (3,563) (3,564)
State income taxes, net of
federal income tax benefit 1,866 2,201 5,472 5,536
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (721) (1,271) (1,442) (2,542)
Other, net (300) (32) (1,274) (1,250)
--------- --------- --------- ---------
Total income taxes $ 21,993 $ 21,607 $ 61,049 $ 57,119
========= ========= ========= =========
<CAPTION>
Twelve Months,
Ended June 30,
--------------------
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Net income $ 224,752 $ 203,136
Add-Income taxes 122,779 109,899
--------- ---------
Net income before income taxes $ 347,531 $ 313,035
========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 121,636 $ 109,562
Reconciling items multiplied by
the statutory rate:
Book depreciation over related
tax depreciation 3,933 3,980
Amortization of deferred
investment tax credits (7,159) (7,182)
State income taxes, net of
federal income tax benefit 10,753 10,875
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (3,284) (3,569)
Other, net (3,100) (3,767)
--------- ---------
Total income taxes $ 122,779 $ 109,899
========= =========
</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 $117.4 million at June 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, six-month and twelve-month periods ended June 30, 1999 and
June 30, 1998:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 4,584 $ 5,997 $ 9,167 $ 11,993 $ 12,521 $ 16,386
Interest costs 15,644 21,073 31,288 42,146 47,479 65,416
Expected return
on plan assets (21,110) (27,971) (42,219) (55,941) (66,607) (85,807)
Amortization of
transition
obligation 1,372 1,902 2,744 3,804 4,428 6,084
Amortization of
prior service
cost 1,385 1,525 2,770 3,050 4,117 4,554
-------- -------- -------- -------- -------- --------
$ 1,875 $ 2,526 $ 3,750 $ 5,052 $ 1,938 $ 6,633
======== ======== ======== ======== ======== ========
</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. In order to determine the APBO 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 $142.3 million at June 30, 1999.
Net periodic postretirement benefits costs, before consideration of the
rate-making discussed above, for the three-month, six-month and twelve-month
periods ended June 30, 1999 and June 30, 1998 include the following
components:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
---------------- ---------------- ----------------
1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 1,350 $ 1,069 $ 1,827 $ 1,806 $ 3,335 $ 3,016
Interest costs 3,850 3,650 7,700 7,300 14,085 13,071
Expected return
on plan assets (50) (50) (100) (100) (216) (100)
Amortization of
transition
obligation
over twenty years 2,675 2,675 5,350 5,350 10,748 10,693
Amortization of
prior service cost 75 75 150 150 279 429
Amortization of
actuarial (gain) (1,150) (1,375) (2,300) (2,750) (5,336) (6,542)
------- ------- ------- ------- ------- -------
$ 6,750 $ 6,044 $12,627 $11,756 $22,895 $20,567
======= ======= ======= ======= ======= =======
</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, 1998 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 $1.2
million for the three-month and six-month periods ended June 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 $0.4 million and $0.9 million for
the three-month and six-month periods ended June 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 JUNE 30, 1999 AND DECEMBER 31, 1998 (SEE NOTE 7):
<TABLE>
<CAPTION>
Redemption
Price at
June 30, December 31, June 30,
1999 1998 1999
============ ============ ============
(Dollars in thousands)
<S> <C> <C> <C>
Cumulative preferred stock -
$100 par value -
4-1/4% series - 209,044 and
209,051 shares outstanding,
respectively $ 20,904 $ 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
June 30 1999), Series A
(stated value $50 per share)
473,285 shares outstanding 23,664 23,664 $50.00
------------ ------------
$ 81,115 $ 81,116
============ ============
</TABLE>
During the period July 1, 1997 to June 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 JUNE 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>
June 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 - 51,000 shares outstanding,
excluding sinking fund payments due within
one year 5,100 5,100
Cumulative preferred stock - no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
------------ ------------
$ 55,185 $ 56,435
============ ============
</TABLE>
The redemption prices at June 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.
8.35% $103.44, reduced periodically 3,000 shares on or before
July 1; increasing to 6,000
shares beginning in 2004;
noncumulative option
to double amount each
year.
7-3/4% $104.06, reduced periodically 2,777 shares on or
before December 1;
noncumulative option
to double amount each
year.
Cumulative preferred stock - no par value -
6.50% $100.00 on October 14, 2002 430,000 shares on October 14,
2002.
</TABLE>
Sinking fund requirements with respect to redeemable preferred stocks
for the next five years, not reflecting redemptions made after June 30, 1999,
were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
==================================
(Dollars in thousands)
<S> <C>
2000 $ 1,828
2001 $ 1,828
2002 $ 1,828
2003 $44,828
2004 $ 578
</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 June 30, 1999, Northern Indiana had approximately
$144.2 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 June 30, 1999, there were 2.5 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
June 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
June 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 1997 and 1998 lapse two years from date of grant and vesting is
variable from 0% to 100% of the number awarded, subject to specific
performance goals. If a participant's employment is terminated prior to
vesting other than by reason of death, disability or retirement, restricted
shares are forfeited. There were 537,166 and 534,666 restricted shares
outstanding at June 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 non-qualified stock options. The compensation
cost that has been charged against income for restricted stock awards was
$0.2 million and $0.2 million for the three-month, $0.4 and $0.4 million for
the six-month and $0.8 million and $0.7 million for the twelve-month periods
ending June 30, 1999 and June 30, 1998, respectively. Had compensation cost
for non-qualified stock options been determined consistent with SFAS No. 123
"Accounting for Stock-Based Compensation," Northern Indiana's net income would
have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------------------ ------------------ -------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Net Income:
As reported $ 40,756 $ 39,802 $110,148 $105,576 $224,752 $203,136
Pro forma $ 40,352 $ 39,588 $109,340 $105,148 $223,255 $202,282
</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 June 30, 1999 and June 30, 1998: risk-free
interest rate of 5.29% and 6.29%, respectively; expected dividend yield per
share of $0.96 and $0.87, respectively; expected option term of 5.4 and 5.25
years, respectively; and expected volatilities of 13.09% and 12.7%,
respectively. The weighted average fair value of options granted to all plan
participants was $4.28 and $2.66 for the twelve-month periods ended June 30,
1999 and June 30, 1998, respectively. There were 607,000 and 533,600
non-qualified stock options granted to all plan participants for the
twelve-month periods ended June 30, 1999 and June 30, 1998, respectively.
(13) LONG-TERM DEBT: At June 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
---------------------------
June 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
First mortgage bonds -
Series T, 7-1/2%, due April 1, 2002 $ 39,000 $ 39,000
Series NN, 7.10%, due July 1, 2017 55,000 55,000
------------ ------------
Total 94,000 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 - 3.18% weighted
average at June 30, 1999, due
November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County -
Series D - 3.25% weighted average at
June 30, 1999, due November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County -
Series A - 3.45% at June 30, 1999,
due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County -
Series B - 3.45% at June 30, 1999,
due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County -
Series C - 3.45% at June 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 (3,339) (3,566)
------------ ------------
Total long-term debt excluding
amounts due in one year $ 923,186 $ 1,077,959
============ ============
</TABLE>
The sinking fund requirements and maturities of long-term debt for the
next five years were as follows as of June 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
=================================
(Dollars in thousands)
<S> <C>
2000 $157,000
2001 $ 3,000
2002 $ 73,500
2003 $ 58,500
2004 $ 76,000
</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 of
its Medium-Term Notes, Series E, with various maturities, for purposes of
refinancing certain first mortgage bonds and medium-term notes. As of
June 30, 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 June 30, 1999 and December 31,
1998, Northern Indiana's current portion of long-term debt due within one
year was as follows:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
First mortgage bonds -
Series P, 6-7/8% - due October 1, 1998 $ 0 $ 0
Medium-term notes -
Interest rate 6.10% and 6.90% with
a weighted average interest rate of
6.80% and maturities of March 20, 2000
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, 1999, respectively. The 364-day agreement may be extended at
expiration for additional periods of 364-days upon the request of Northern
Indiana and agreements by the banks. 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 June 30, 1999, there were no borrowings outstanding under
these agreements.
In addition, Northern Indiana has $14.2 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 June 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 $273.5 million of money market lines of
credit. As of June 30, 1999 and December 31, 1998, $18.2 million and $40.5
million of borrowings were outstanding, respectively, under these lines of
credit.
Northern Indiana has a $50 million uncommitted finance facility. At
June 30, 1999 and December 31, 1998, there were no borrowings outstanding
under this facility.
At June 30, 1999 and December 31, 1998, Northern Indiana's short-
term borrowings were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
Commercial paper -
Weighted average interest rate of 5.05%
at June 30, 1999 $ 50,000 $ 85,600
Notes payable -
Issued at interest rates between 4.95%
and 5.06% with a weighted average
interest rate of 5.11% and maturities
of July 1, 1999 and July 8, 1999 18,200 40,500
------------ ------------
Total short-term borrowings $ 68,200 $ 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 June 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
=============================
(Dollars in thousands)
<S> <C>
2000 $ 6,472
2001 6,036
2002 6,036
2003 6,036
2004 5,388
Later years 28,561
--------
Total minimum
payments required $ 58,529
========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
June 30, June 30,
1999 1998
============ ============
(Dollars in thousands)
<S> <C> <C>
Three months ended $ 2,625 $ 2,331
Six months ended $ 5,291 $ 4,479
Twelve months ended $10,203 $ 8,127
</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.
During 1995, Northern Indiana entered into a ten-year agreement with IBM
to perform all data center, application development and maintenance, and
desktop management. Annual fees under this agreement are estimated at $20
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 June 30, 1999, open derivative
financial instruments represented hedges of natural gas sales of 4.1 billion
cubic feet (Bcf), and natural gas purchases and inventories of 3.1 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
June 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 long-term debt
and preferred stock is estimated using the quoted market prices for
the same or similar issues or on the rates offered to Northern
Indiana for securities of the same remaining maturities. Certain
premium costs associated with the early settlement of long-term debt
are not taken into consideration in determining fair value.
The carrying values and estimated fair values of financial instruments
were as follows:
<TABLE>
<CAPTION>
June 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 $ 8,777 $ 8,777 $ 19,541 $ 19,541
Investments $ 251 $ 251 $ 251 $ 251
Long-term debt (including
current portion) $1,080,186 $1,056,240 $1,079,959 $1,137,657
Preferred stock (including
current portion) $ 138,128 $ 126,887 $ 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 16% of electric revenues for the twelve months
ended June 30, 1999 as compared to 3% and 19%, respectively, for the
twelve months ended June 30, 1998.
(21) BUSINESS SEGMENTS: 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 June 30, 1999 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $104,378 $ 277,380 $ 0 $ 0 $ 381,758
Other income (deductions)$ 169 $ 236 $ 749 $ (38) $ 1,116
Depreciation and
amortization $ 18,587 $ 39,473 $ 0 $ 0 $ 58,060
Income before interest
and utility income
taxes $ (5,746) $ 85,132 $ 699 $ 12 $ 80,097
Assets $824,797 $2,738,709 $ 0 $ 0 $3,563,506
Capital expenditures $ 11,999 $ 41,237 $ 0 $ 0 $ 53,236
<CAPTION>
For the Three Months Adjust-
Ended June 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 98,859 $ 271,611 $ 0 $ 0 $ 370,470
Other income (deductions)$ 171 $ 85 $ (1,502) $ (22) $ (1,268)
Depreciation and
amortization $ 17,845 $ 38,955 $ 0 $ 0 $ 56,800
Income before interest
and utility income
taxes $ (3,968) $ 86,964 $ (1,475) $ (49) $ 81,472
Assets $854,059 $2,713,033 $ 0 $ 0 $3,567,092
Capital expenditures $ 14,237 $ 32,655 $ 0 $ 0 $ 46,892
<CAPTION>
For the Six Months Adjust-
Ended June 30, 1999 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $351,081 $ 537,263 $ 0 $ 0 $ 888,344
Other income (deductions)$ 782 $ 364 $ (1,063) $ (38) $ 45
Depreciation and
amortization $ 37,150 $ 79,048 $ 0 $ 0 $ 116,198
Income before interest
and utility income
taxes $ 49,944 $ 158,958 $ (1,113) $ 12 $ 207,801
Assets $824,797 $2,738,709 $ 0 $ 0 $3,563,506
Capital expenditures $ 21,194 $ 65,515 $ 0 $ 0 $ 86,709
<CAPTION>
For the Six Months Adjust-
Ended June 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $317,589 $ 511,797 $ 0 $ 0 $ 829,386
Other income (deductions)$ 753 $ 170 $ (2,746) $ (53) $ (1,876)
Depreciation and
amortization $ 35,598 $ 77,722 $ 0 $ 0 $ 113,320
Income before interest
and utility income
taxes $ 41,341 $ 164,373 $ (2,783) $ (16) $ 202,915
Assets $854,059 $2,713,033 $ 0 $ 0 $3,567,092
Capital expenditures $ 23,450 $ 56,752 $ 0 $ 0 $ 80,202
<CAPTION>
For the Twelve Months Adjust-
Ended June 30, 1999 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $605,977 $1,101,584 $ 0 $ 0 $1,707,561
Other income (deductions)$ 1,425 $ 743 $ (3,700) $ (136) $ (1,668)
Depreciation and
amortization $ 73,259 $ 158,166 $ 0 $ 0 $ 231,425
Income before interest
and utility income
taxes $ 67,966 $ 360,102 $ (3,721) $ (115) $ 424,232
Assets $824,797 $2,738,709 $ 0 $ 0 $3,563,506
Capital expenditures $ 54,288 $ 126,819 $ 0 $ 0 $ 181,107
<CAPTION>
For the Twelve Months Adjust-
Ended June 30, 1998 Gas Electric Other ments Total
- ------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $638,673 $1,039,002 $ 0 $ 0 $1,677,675
Other income (deductions)$ 1,002 $ 547 $ (5,515) $ (124) $ (4,090)
Depreciation and
amortization $ 70,395 $ 154,461 $ 0 $ 0 $ 224,856
Income before interest
and utility income
taxes $ 64,740 $ 337,492 $ (5,603) $ (36) $ 396,593
Assets $854,059 $2,713,033 $ 0 $ 0 $3,567,092
Capital expenditures $ 55,118 $ 97,938 $ 0 $ 0 $ 153,056
</TABLE>
The following table reconciles total reportable segment income before
interest and utility income taxes to net income for three-month, six-month
and twelve-month periods ended June 30, 1999 and 1998:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------ ------------------ ------------------
1999 1998 1999 1998 1999 1998
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C <C>
Income before
interest and
utility income
taxes $ 80,097 $ 81,472 $207,801 $202,915 $424,232 $396,593
Interest 17,986 19,236 36,598 38,988 75,990 79,913
Utility income
taxes 21,355 22,434 61,055 58,351 123,490 113,544
-------- -------- -------- -------- -------- --------
Net income $ 40,756 $ 39,802 $110,148 $105,576 $224,752 $203,136
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OPERATING REVENUES -
TWELVE MONTHS ENDED JUNE 30, 1999. Total operating revenues for the
twelve months ended June 30, 1999 were $29.9 million higher than for the
twelve months ended June 30, 1998, representing a 1.8% increase. Gas revenues
were $606.0 million, which represented a $32.7 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 $1,101.6 million, which
represented a $62.6 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 1998 and
increased wholesale transactions, partially offset by decreased sales to
industrial customers and decreased fuel costs.
SIX MONTHS ENDED JUNE 31, 1999. Total operating revenues for the six
months ended June 30, 1999 were $59.0 million higher than for the six months
ended June 30, 1999, representing a 7.1% increase. Gas revenues were $351.0
million, which represented a 10.5% 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 $537.3 million, which represented a $25.5
million increase from the comparable period for 1998. This increase was
mainly attributable to increased sales to residential and commercial customers
and increased wholesale transactions, partially offset by decreased fuel costs
decreased industrial sales.
THREE MONTHS ENDED JUNE 30, 1999. Total operating revenues for the
three months ended June 30, 1999 were $11.3 million higher than for the three
months ended June 30, 1999, representing a 3.0% increase. Gas revenues were
$104.4 million, which represented a 5.6% 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, increased wholesale sales
and increased gas cost per dth, partially offset by decreased gas transition
costs. Electric revenues were $277.4 million, which represented a $5.8
million increase from the comparable period for 1998. This increase was
mainly attributable to increased sales to commercial customers, increased
wholesale transactions partially offset by decreased fuel costs and decreased
industrial sales.
The basic steel industry accounted for 37% of natural gas delivered
(including volumes transported) and 26% of electric sales during the twelve
months ended June 30, 1999.
The components of the variations in gas and electric revenues are
shown in the following table:
<TABLE>
<CAPTION>
Variations
from
Prior Periods
---------------------------------
June 30, 1999
Compared to
June 30, 1998
Three Six 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 $ (7,083) $ (24,035) $ (63,345)
Gas transition costs (1,078) (2,226) (10,921)
Changes in sales levels 13,075 39,836 12,853
Gas transported (3,026) 522 6,211
Wholesale gas 3,631 19,395 22,506
--------- --------- ---------
Total Gas Revenue Change $ 5,519 $ 33,492 $ (32,696)
--------- --------- ---------
Electric Revenue Changes-
Pass through of net changes in
fuel costs $ (3,500) $ (2,816) $ (8,652)
Changes in sales levels 4,209 11,184 26,302
Wholesale electric 5,060 17,098 44,932
--------- --------- ---------
Total Electric Revenue Change $ 5,769 $ 25,466 $ 62,582
--------- --------- ---------
Total Revenue Change $ 11,288 $ 58,958 $ 29,886
========= ========= =========
</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 June 30, 1999,
decreased by $37.5 million, or by 9.9%, from the twelve months ended June 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 six months ended June 30, 1999 increased by $19.9 million, or by
11.1%, from the six months ended June 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 June 30, 1999 increased by $5.1 million, or by 9.2%,
from the three months ended June 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.
FUEL AND PURCHASED POWER. The cost of fuel used for electric generation
during the twelve months ended June 30, 1999 was $1.0 million lower than the
cost of fuel used during the twelve months ended June 30, 1998, mainly due to
decreased fuel costs per kilowatt-hour (kwh), partially offset by increased
electric generation of 2.6%. The average cost per kwh generated decreased by
2.9% from 1.55 cents per kwh during the twelve months ended June 30, 1998, to
1.50 cents per kwh for the comparable period for 1999. The cost of fuel used
for electric generation during the six months ended June 30, 1999 was $5.1
million lower than the cost of fuel used during the six months ended June 30,
1998, mainly due to decreased fuel costs of 4.2% and decreased electric
generation of 1.3%. The average cost per kwh generated during the six months
ended June 30, 1999 decreased by 2.9% from 1.52 cents per kwh to 1.47 cents
per kwh from the comparable period for 1998. The cost of fuel used for
electric generation during the three months ended June 30, 1999 was $7.8
million lower than the cost of fuel used during the three months ended
June 30, 1998, mainly due to decreased fuel costs of 11.9% and decreased
electric generation of 7.1%. The average cost per kwh generated during the
three months ended June 30, 1999 decreased by 5.2% from 1.55 cents per kwh to
1.47 cents per kwh from the comparable period for 1998.
Northern Indiana spent $35.8 million more during the twelve months ended
June 30, 1999 than during the comparable period in 1998 to purchase power,
primarily due to increased purchases of 179.8%, partially offset by an 26.4%
decrease in the cost per kwh. Power purchased increased by $27.7 million for
the six-month period ended June 30, 1998, reflecting increased bulk power
purchases of 371.4%, partially offset by an 42.2% decrease in the cost per
kwh. Power purchased increased by $14.5 million for the three-month period
ended June 30, 1998, reflecting increased bulk power purchases of 336.4%,
partially offset by an 50.2% decrease in the cost per kwh.
OPERATING MARGINS -
TWELVE MONTHS ENDED JUNE 30, 1999. Operating margins for the twelve
months ended June 30, 1999 were $32.6 million higher than for the twelve
months ended June 30, 1998, representing a 3.2% increase. Gas operating
margin was $4.8 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 and commercial customers, reflecting unusually
warm weather during the fourth quarter of 1998 and decreased sales to
industrial customers. Electric operating margin was $786.4 million, which
represented a $27.8 million increase from the comparable for 1998. This
increase occurred mainly due to increased sales to residential and commercial
customers due to warmer weather during the third quarter of 1998 and increased
wholesale transactions, partially offset by decreased industrial sales.
SIX MONTHS ENDED JUNE 30, 1999. Operating margins for the six months
ended June 30, 1999 were $16.5 million higher than the six months ended
June 30, 1998, representing a 3.2% increase. Gas operating margin was $13.6
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 $377.6 million, which represented a $2.9 million increase from the
comparable period for 1998. This increase occurred mainly due to increased
sales to residential and commercial customers and wholesale transactions,
partially offset by decreased industrial sales.
THREE MONTHS ENDED JUNE 30, 1999. Operating margins for the three
months ended June 30, 1999 were $0.5 million lower than the three months ended
June 30, 1998. Gas operating margin was relatively unchanged. Electric
operating margin was $192.8 million, which represented a $1.0 million decrease
from the comparable period for 1998. This decrease occurred mainly due to
decreased sales to residential customers and 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
June 30, 1999 were $1.4 million higher than in the twelve months ended
June 30, 1998. Operation expenses were higher primarily as a result of
increased employee related costs. Operation expenses for the six months ended
June 30, 1999 were $8.8 million higher than for the six months ended June 30,
1998. Operation expenses were higher in the six-month period primarily as a
result of increased employee related costs of $5.7 million and increased
property and liability claims of $1.7 million. Operation expenses for the
three months ended June 30, 1999 were $3.3 million higher than for the three
months ended June 30, 1998. Operation expenses were higher in the three-month
period primarily as a result of increased employee related costs of $1.7
million and sales activity of $1.3 million.
MAINTENANCE EXPENSE. Maintenance expenses for the twelve months ended
June 30, 1999 were $3.6 million lower than in the twelve months ended June 30,
1998. Maintenance expenses were lower primarily as a result of decreased
electric production facility maintenance costs of $2.9 million and decreased
gas distribution facility maintenance of $1.0 million. Maintenance expenses
for the six months ended June 30, 1999 were relatively unchanged from the six
months ended June 30, 1998. Maintenance expenses for the three months ended
June 30, 1999 were $1.2 million lower than in the three months ended June 30,
1998. Maintenance expenses were lower primarily as a result of decreased
electric production facility maintenance costs.
DEPRECIATION AND AMORTIZATION EXPENSE. Depreciation and amortization
expenses for the twelve months ended June 30, 1999 were $6.6 million higher
than in the comparable period for 1998. These higher expenses primarily
related to increased depreciation expense as a result of increased depreciable
plant. Depreciation and amortization expenses for the six months ended
June 30, 1999 were $2.9 million higher than in the comparable period for
1998. These higher expenses primarily related to increased depreciation
expense as a result of increased depreciable plant. Depreciation and
amortization expenses for the three months ended June 30, 1999 were $1.3
million 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, six-month and twelve-
month periods ended June 30, 1999 increased by $2.4, $1.9 and $2.4 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, six-month and twelve-month periods
ended June 30, 1999 were $1.3, 2.4 and $3.9 million lower, respectively, than
in the comparable periods for 1998. These decreases resulted primarily due to
decreased long term debt outstanding during the three-month, six-month and
twelve-month periods ended June 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 occasionally
issued for short-term financing. As of June 30, 1999 and December 31, 1998,
$50.0 million and $85.6 million of commercial paper was outstanding,
respectively. The weighted average interest rate of commercial paper
outstanding as of June 30, 1999 was 5.05%.
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, 1999,
respectively. The 364-day agreement may be extended at expiration for
additional periods of 364-days upon the request of Northern Indiana and
agreements by the banks. 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 June 30, 1999, there were no borrowings outstanding under these
agreements.
In addition, Northern Indiana has $14.2 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 June 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 $273.5 million of money market lines of
credit. As of June 30, 1999 and December 31, 1998, $18.2 million and $40.5
million of borrowings were outstanding, respectively, under these lines of
credit.
Northern Indiana has a $50 million uncommitted finance facility. At
June 30, 1999 and December 31, 1998, there were no borrowings outstanding
under this facility.
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 used.
Two primary market risks, commodity price risk and interest rate risk,
are addressed by a risk management policy.
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, all basis exposure is not 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."
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 it is
anticipated 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, 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 third and
fourth quarters 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 in the midst of a period of fundamental change. These
changes have impacted and will continue to impact the 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 make the company 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 plans to offer
customer choice to all 660,000 residential and 50,000 commercial customers
throughout its gas service territory. Only 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, but not limited to, 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 the consolidated financial statements 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, there can be no assurance
that the actual results will not differ materially from such assumptions or
that the expectations set forth in the forward looking statements derived from
such assumptions will be realized. You should be aware of important factors
that could have a material impact on future results. These factors include,
but are not limited to, weather, the federal and state regulatory environment,
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. To the knowledge of
Northern Indiana, no other material legal proceedings against Northern Indiana
or its subsidiaries are contemplated by governmental authorities and other
parties.
Item 2. CHANGES IN SECURITIES.
None
Item 3. DEFAULTS UPON SENIOR SECURITIES.
None
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
Item 5. OTHER INFORMATION.
None
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit 23 - Consent of Arthur Andersen LLP
Exhibit 27 - Financial Data Schedule
(b) Reports on Form 8-K.
None
<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 August 13, 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
August 13, 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 June 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> APR-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,961,914
<OTHER-PROPERTY-AND-INVEST> 328
<TOTAL-CURRENT-ASSETS> 265,083
<TOTAL-DEFERRED-CHARGES> 134,403
<OTHER-ASSETS> 201,778
<TOTAL-ASSETS> 3,563,506
<COMMON> 859,488
<CAPITAL-SURPLUS-PAID-IN> 12,525
<RETAINED-EARNINGS> 144,195
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,016,208
55,185
81,115
<LONG-TERM-DEBT-NET> 317,000
<SHORT-TERM-NOTES> 18,200
<LONG-TERM-NOTES-PAYABLE> 611,025
<COMMERCIAL-PAPER-OBLIGATIONS> 50,000
<LONG-TERM-DEBT-CURRENT-PORT> 157,000
1,828
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,255,945
<TOT-CAPITALIZATION-AND-LIAB> 3,565,506
<GROSS-OPERATING-REVENUE> 381,758
<INCOME-TAX-EXPENSE> 21,355
<OTHER-OPERATING-EXPENSES> 302,777
<TOTAL-OPERATING-EXPENSES> 324,132
<OPERATING-INCOME-LOSS> 57,626
<OTHER-INCOME-NET> 1,116
<INCOME-BEFORE-INTEREST-EXPEN> 58,742
<TOTAL-INTEREST-EXPENSE> 17,986
<NET-INCOME> 40,756
2,026
<EARNINGS-AVAILABLE-FOR-COMM> 38,730
<COMMON-STOCK-DIVIDENDS> 53,000
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 43,080
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
