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, 2000
Transition Report Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the transition period from ________________ to ________________
Commission file number 1-4125
NORTHERN INDIANA PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
Indiana 35-0552990
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
801 E. 86th Avenue, Merrillville, Indiana 46410-6272
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (219) 853-5200
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
-------- --------
As of July 31, 2000, 73,282,258 common shares were outstanding.
<PAGE>
NORTHERN INDIANA PUBLIC SERVICE COMPANY
PART 1.
FINANCIAL INFORMATION
Item I. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors of NORTHERN INDIANA PUBLIC SERVICE COMPANY:
We have audited the accompanying consolidated balance sheet of Northern
Indiana Public Service Company (an Indiana corporation and a wholly owned
subsidiary of NiSource Inc.) and subsidiaries as of June 30, 2000, and December
31, 1999, and the related consolidated statements of income, retained earnings
and cash flows for the three, six and twelve month periods ended June 30, 2000
and 1999. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Northern
Indiana Public Service Company and subsidiaries as of June 30, 2000, and
December 31, 1999, and the results of their operations and their cash flows for
the three, six and twelve month periods ended June 30, 2000 and 1999, in
conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Chicago, Illinois
August 9, 2000
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
June 30, December 31,
ASSETS 2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
UTILITY PLANT, AT ORIGINAL COST (INCLUDING
CONSTRUCTION WORK IN PROGRESS OF
$217,713 AND $200,011 RESPECTIVELY)
(NOTE 2):
Electric $ 4,281,479 $ 4,237,427
Gas 1,342,606 1,323,528
Common 386,765 381,486
------------ ------------
6,010,850 5,942,441
Less - Accumulated depreciation
and amortization 3,099,717 2,993,412
------------ ------------
Total Utility Plant 2,911,133 2,949,029
------------ ------------
OTHER PROPERTY AND INVESTMENTS 2,662 2,668
------------ ------------
CURRENT ASSETS:
Cash and cash equivalents 10,617 6,145
Accounts receivable, less reserve of
$8,631 and $7,804, respectively (Note 2) 138,439 141,537
Fuel cost adjustment clause (Note 2) 0 4,201
Gas cost adjustment clause (Note 2) 10,396 36,787
Materials and supplies, at average cost 53,173 52,735
Electric production fuel, at average cost 36,489 31,968
Natural gas in storage, at last-in,
first-out cost (Note 2) 31,924 22,966
Price risk management assets 54,008 31,677
Prepayments and other 30,031 28,608
------------ ------------
Total Current Assets 365,077 356,624
------------ ------------
OTHER ASSETS:
Regulatory assets (Note 2) 181,024 186,080
Prepayments and other (Note 6) 194,728 161,053
------------ ------------
Total Other Assets 375,752 347,133
------------ ------------
$ 3,654,624 $ 3,655,454
============ ============
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
June 30, December 31,
CAPITALIZATION AND LIABILITIES 2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
CAPITALIZATION:
Common stock - without par value -
authorized 75,000,000 shares,
issued and outstanding
73,282,258 shares (Note 11) $ 859,488 $ 859,488
Additional paid-in capital 12,525 12,525
Retained earnings (see accompanying
statement) (Note 10) 132,900 136,118
------------ ------------
Common shareholder's equity 1,004,913 1,008,131
Cumulative preferred stocks,
(excluding amounts due within one
year) (Note 7)
Series without mandatory redemption
provisions (Note 8) 81,114 81,114
Series with mandatory redemption
provisions (Note 9) 52,480 54,030
Long-term debt excluding amounts due
within one year (Note 13) 920,626 920,413
------------ ------------
Total Capitalization 2,059,133 2,063,688
------------ ------------
CURRENT LIABILITIES -
Current portion of long-term
debt (Note 14) 3,000 158,000
Short-term borrowings (Note 15) 234,400 96,290
Accounts payable 152,964 129,532
Dividends declared on common and
preferred stocks 57,969 59,017
Customer deposits 25,570 24,264
Taxes accrued 96,407 115,761
Interest accrued 8,632 7,392
Fuel adjustment clause 4,236 0
Accrued employment costs 49,066 51,393
Price risk management liabilities 77,348 54,001
Other accruals 11,014 22,162
------------ ------------
Total Current Liabilities 720,606 717,812
------------ ------------
OTHER:
Deferred income taxes (Note 4) 575,239 592,022
Deferred investment tax credits, being
amortized over life of related property
(Note 4) 82,023 85,566
Deferred credits 54,914 47,105
Accrued liability for postretirement
benefits (Note 6) 142,972 137,211
Other noncurrent liabilities 19,737 12,050
------------ ------------
Total Other Liabilities 874,885 873,954
------------ ------------
COMMITMENTS AND CONTINGENCIES
(Notes 3, 16 and 17)
$ 3,654,624 $ 3,655,454
============ ============
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
Three Months Six Months
Ended June 30, Ended June 30,
---------- ---------- ---------- ----------
2000 1999 2000 1999
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 130,316 $ 104,378 $ 393,849 $ 351,081
Electric 254,968 268,471 508,474 528,354
---------- ---------- ---------- -----------
385,284 372,849 902,323 879,435
---------- ---------- ---------- -----------
Cost of Energy: (Note 2)
Gas costs 84,697 60,271 245,998 198,237
Fuel for electric
generation 56,471 57,630 113,970 115,928
Power purchased 7,029 18,002 15,263 34,784
---------- ---------- ---------- ----------
148,197 135,903 375,231 348,949
---------- ---------- ---------- ----------
Operating Margin 237,087 236,946 527,092 530,486
---------- ---------- ---------- ----------
Operating Expenses and Taxes (except income):
Operation 60,303 65,085 121,446 132,740
Maintenance (Note 2) 20,698 17,458 38,503 35,711
Depreciation and
amortization (Note 2) 59,551 58,060 118,813 116,198
Taxes (except income) 12,462 17,337 32,252 38,056
---------- ---------- ---------- ----------
153,014 157,940 311,014 322,705
---------- ---------- ---------- ----------
Operating Income Before
Utility Income Taxes 84,073 79,006 216,078 207,781
---------- ---------- ---------- ----------
Utility Income Taxes
(Note 4) 23,573 21,355 64,199 61,055
---------- ---------- ---------- ----------
Operating Income 60,500 57,651 151,879 146,726
---------- ---------- ---------- ----------
Other Income (Deductions)
(Note 2) 1,256 1,091) 1,816 20
---------- ---------- ---------- ----------
Interest:
Interest on long-term debt 16,375 16,873 33,578 33,593
Other interest 1,416 77 2,269 934
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 1,028 1,036 2,081 2,071
---------- ---------- ---------- ----------
18,819 17,986 37,928 36,598
---------- ---------- ---------- ----------
Net Income 42,937 40,756 115,767 110,148
Dividend requirements on
preferred shares 1,980 2,026 3,985 4,091
---------- ---------- ---------- ----------
Balance available
for common shares $ 40,957 $ 38,730 $ 111,782 $ 106,057
========== ========== ========== ==========
Dividends declared $ 57,000 $ 53,000 $ 115,000 $ 108,000
========== ========== ========== ==========
<CAPTION>
Twelve Months
Ended June 30,
---------- ----------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
Operating Revenues:
(Notes 2 and 20)
Gas $ 687,455 $ 605,977
Electric 1,087,652 1,092,675
---------- ----------
1,775,107 1,698,652
---------- ----------
Cost of Energy: (Note 2)
Gas costs 427,370 340,896
Fuel for electric
generation 247,206 245,560
Power purchased 47,443 60,727
---------- ----------
722,019 647,183
---------- ----------
Operating Margin 1,053,088 1,051,469
---------- ----------
Operating Expenses and Taxes (except income):
Operation 245,180 254,743
Maintenance (Note 2) 68,254 65,692
Depreciation and
amortization (Note 2) 236,170 231,425
Taxes (except income) 68,359 73,684
---------- ----------
617,963 625,544
---------- ----------
Operating Income Before
Utility Income Taxes 435,125 425,925
---------- ----------
Utility Income Taxes
(Note 4) 130,411 123,490
---------- ----------
Operating Income 304,714 302,435
---------- ----------
Other Income (Deductions)
(Note 2) (452) (1,693)
---------- ----------
Interest:
Interest on long-term debt 67,680 67,954
Other interest 4,687 3,881
Amortization of premium,
reacquisition premium,
discount and expense
on debt, net 4,165 4,155
---------- ----------
76,532 75,990
---------- ----------
Net Income 227,730 224,752
Dividend requirements on
preferred shares 8,025 8,233
---------- ----------
Balance available
for common shares $ 219,705 $ 216,519
========== ==========
Dividends declared $ 231,000 $ 225,000
========== ==========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------- ------------------- --------- ---------
2000 1999 2000 1999 2000 1999
========= ========= ========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
BALANCE AT
BEGINNING OF
PERIOD $ 148,943 $ 158,465 $ 136,118 $ 146,138 $ 144,195 $ 152,676
ADD:
Net income 42,937 40,756 115,767 110,148 $ 227,730 $ 224,752
--------- --------- --------- --------- --------- ---------
191,880 199,221 251,885 256,286 $ 371,925 $ 377,428
--------- --------- --------- --------- --------- ---------
LESS:
Dividends
Cumulative
Preferred
stocks -
4-1/4% series 222 222 444 444 888 888
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 83 102 184 240 405 516
7-3/4% series 59 70 119 140 255 298
8.35% series 96 112 196 225 393 447
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 57,000 53,000 115,000 108,000 231,000 225,000
--------- --------- --------- --------- --------- ---------
58,980 55,026 118,985 112,091 239,025 233,233
--------- --------- --------- --------- --------- ---------
BALANCE AT END
OF PERIOD $ 132,900 $ 144,195 $ 132,900 $ 144,195 $ 132,900 $ 144,195
========= ========= ========= ========= ========= =========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months
Ended June 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 42,937 $ 40,756
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 59,551 58,060
Net changes for price risk management
assets and liabilities 5,900 663
Deferred federal and state income
taxes, net (9,286) (7,673)
Deferred investment tax credits, net (1,771) (1,782)
Other, net (576) 475
Change in certain assets and liabilities -
Accounts receivable, net 4,288 20,745
Electric production fuel (1,099) (1,783)
Materials and supplies (230) 2,260
Natural gas in storage (10,829) (5,920)
Accounts payable 30,438 21,484
Taxes accrued (86,502) (68,398)
Fuel adjustment clause 1,581 (1,286)
Gas cost adjustment clause (5,452) 1,869
Accrued employment costs 3,445 2,348
Other accruals (11,429) (11,884)
Other, net (9,549) (6,854)
---------- ----------
Net cash provided by operating activities 11,417 43,080
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (44,380) (53,236)
Other, net 2,248 3,605
---------- ----------
Net cash used in investing activities (42,132) (49,631)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 207,050 50,200
Retirement of long-term debt (149,000) 0
Retirement of preferred shares (300) (1,251)
Cash dividends paid on common shares (58,000) (55,000)
Cash dividends paid on preferred shares (1,986) (2,065)
Other, net 99 114
---------- ----------
Net cash used in financing activities (2,137) (8,002)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS (32,852) (14,553)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 43,469 23,330
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,617 $ 8,777
========== ==========
<CAPTION>
Six Months
Ended June 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 115,767 $ 110,148
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 118,813 116,198
Net changes for price risk management
assets and liabilities 6,487 4,020
Deferred federal and state operating
income taxes, net (32,178) (34,457)
Deferred investment tax credits, net (3,543) (3,563)
Other, net 2,138 950
Change in certain assets and liabilities -
Accounts receivable, net 457 (5,930)
Electric production fuel (4,521) 5,440
Materials and supplies (438) (40)
Natural gas in storage (8,958) 25,300
Accounts payable 27,663 (8,355)
Taxes accrued (4,923) 15,989
Fuel adjustment clause 8,437 (3,542)
Gas cost adjustment clause 26,391 51,109
Accrued employment costs (2,327) (6,833)
Other accruals (11,148) (10,178)
Other, net (9,205) 5,063
---------- ----------
Net cash provided by operating activities 228,912 261,319
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (81,041) (86,709)
Other, net (5,174) (5,322)
---------- ----------
Net cash used in investing activities (86,215) (92,031)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Net change in short-term debt 138,110 (57,900)
Retirement of long-term debt (155,000) 0
Retirement of preferred shares (1,550) (1,251)
Cash dividends paid on common shares (116,000) (117,000)
Cash dividends paid on preferred shares (3,998) (4,128)
Other, net 213 227
---------- ----------
Net cash used in financing activities (138,225) (180,052)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS 4,472 (10,764)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 6,145 19,541
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,617 $ 8,777
========== ==========
<CAPTION>
Twelve Months
Ended June 30,
------------------------
2000 1999
========== ==========
(Dollars in thousands)
<S> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income $ 227,730 $ 224,752
ADJUSTMENTS TO RECONCILE
NET INCOME TO NET CASH:
Depreciation and amortization 236,170 231,425
Net changes for price risk management
assets and liabilities 24,791 4,020
Deferred federal and state operating
income taxes, net (17,217) (27,058)
Deferred investment tax credits, net (7,106) (7,159)
Other, net (3,717) 1,900
Change in certain assets and liabilities -
Accounts receivable, net (24,778) (30,108)
Electric production fuel (9,527) (10,463)
Materials and supplies (1,579) 952)
Natural gas in storage (6,365) 4,023
Accounts payable 25,778 31,790
Taxes accrued 15,628 13,549
Fuel adjustment clause 1,499 2,112
Gas cost adjustment clause (17,461) 32,056
Accrued employment costs 11,676 1,907
Other accruals (7,354) (6,372)
Other, net (24,039) (6,053)
---------- ----------
Net cash provided by operating activities 424,129 461,273
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
INVESTING ACTIVITIES:
Construction expenditures (187,170) (181,107)
Other, net (6,007) 5,135
---------- ----------
Net cash used in investing activities (193,177) (175,972)
---------- ----------
CASH FLOWS PROVIDED BY (USED IN)
FINANCING ACTIVITIES:
Issuance of long-term debt 0 500
Net change in short-term debt 166,200 (44,100)
Retirement of long-term debt (158,000) (16,509)
Retirement of preferred shares (2,706) (2,408)
Cash dividends paid on common shares (227,000) (221,000)
Cash dividends paid on preferred shares (8,046) (8,290)
Other, net 440 452
---------- ----------
Net cash used in financing activities (229,112) (291,355)
---------- ----------
NET DECREASE IN CASH
AND CASH EQUIVALENTS 1,840 (6,054)
CASH AND CASH EQUIVALENTS AT
BEGINNING OF PERIOD 8,777 14,831
---------- ----------
CASH AND CASH EQUIVALENTS AT
END OF PERIOD $ 10,617 $ 8,777
========== ==========
<FN>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</FN>
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) HOLDING COMPANY STRUCTURE: NiSource Inc.(NiSource), formerly NIPSCO
Industries, Inc., was incorporated in Indiana on September 22, 1987 and became
the parent of Northern Indiana Public Service Company (Northern Indiana) on
March 3, 1988. NIPSCO Industries, Inc. changed its name to NiSource Inc.
on April 14, 1999 to reflect its new direction as a multi-state supplier
of energy and 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, 2000 and June 30, 1999.
The depreciation provision for gas utility plant, as a percentage of the
original cost, was 5.4% for the three-month and six-month periods and 5.5% for
the twelve-month period ended June 30, 2000 and 5.4% for the three-month and
six-month periods and 5.5% for the twelve-month period ended June 30, 1999.
Northern Indiana follows the practice of charging maintenance and repairs,
including the cost of removal of minor items of property, to expense as
incurred. When property that represents a retired unit is replaced or removed,
the cost of such property is credited to utility plant, and such cost, together
with the cost of removal less salvage, is charged to the accumulated provision
for depreciation.
AMORTIZATION OF SOFTWARE COSTS. External and incremental internal costs
associated with computer software developed for internal use are capitalized.
Capitalization of such costs commences upon the completion of the preliminary
stage of the project. Once the installed software is ready for its intended use,
such capitalized costs are amortized on a straight-line basis over a period of
five to ten years which the FERC prescribes as reasonable useful life estimates
for capitalized software.
COAL RESERVES. The costs of reserves under a long-term mining contract to
mine coal reserves through the year 2001 are being recovered through the
rate-making process as such coal reserves are used to produce electricity.
ACCOUNTS RECEIVABLE. At June 30, 2000, $100 million of accounts receivable
had been sold under a sales agreement, which expires on May 31, 2002. The June
30, 2000 and December 31, 1999 accounts receivable balances include
approximately $11.0 million and $14.0 million, respectively, due from associated
companies.
STATEMENTS OF CASH FLOWS. Temporary cash investments with an original
maturity of three months or less are considered to be cash equivalents.
Cash paid during the periods reported for income taxes and interest was as
follows:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------ ------------------ ------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 98,428 $ 86,040 $ 98,443 $ 86,086 $137,937 $147,891
Interest, net of
amounts
capitalized $ 25,874 $ 24,663 $ 34,331 $ 33,983 $ 72,083 $ 71,358
</TABLE>
FUEL ADJUSTMENT CLAUSE. All metered electric rates contain a provision for
adjustment in charges for electric energy to reflect increases and decreases in
the cost of fuel and the cost of purchased power through operation of a fuel
adjustment clause. As prescribed by order of the IURC applicable to metered
retail rates, the adjustment factor has been calculated based on the estimated
cost of fuel and the fuel cost of purchased power in a future three-month
period. If two statutory requirements relating to expense and return levels are
satisfied, any under-recovery or over-recovery caused by variances between
estimated and actual cost in a given three-month period will be included in a
future filing. Northern Indiana records any under-recovery or over-recovery as a
current asset or current liability until such time as it is billed or refunded
to its customers. The fuel adjustment factor is subject to a quarterly hearing
by the IURC and remains in effect for a three-month period.
On August 18, 1999, the IURC issued a generic order (Generic Order) which
established new guidelines for the recovery of purchased power costs through
fuel adjustment clauses. The IURC ruled that each utility had to establish a
"benchmark" which is the utility's highest on-system fuel cost per kilowatt-hour
(kwh) during the most recent annual period. The IURC stated that if the weekly
average of a utility's purchased power costs were less than the "benchmark,"
these costs per kwh should be considered net energy costs which are presumed
"fuel costs included in purchased power." If the weekly average of a utility's
purchased power costs exceeded the "benchmark," the utility would need to submit
additional evidence demonstrating the reasonableness of these costs. The Office
of Utility Consumer Counselor (OUCC) has appealed the Generic Order to the
Indiana Court of Appeals. All briefs have been filed and the case is pending
Court decision. Northern Indiana applied the Generic Order's guidelines to
purchased power transactions sought to be recovered for February, March and
April 2000.
By an order issued February 23, 2000, the IURC approved the recovery of
Northern Indiana's purchased power transactions during the months of July,
August and September 1999. Northern Indiana and the OUCC filed petitions for
reconsideration of the February 23, 2000 Order.
On June 30, 2000, Northern Indiana and the OUCC filed a joint motion to
withdraw petitions for reconsideration and requested IURC approval of a
Stipulation and Agreement (Agreement). The Agreement establishes a recovery
mechanism for certain purchase power transactions for the months of July, August
and September 2000 that will be utilized in lieu of the IURC's Generic Order
guidelines. The Agreement also calls for Northern Indiana to return, by an
adjustment to fuel adjustment clause factors, $1.8 million to retail ratepayers
during the period from November 2000 through April 2001. Northern Indiana has
established a reserve for this amount. By its order issued August 9, 2000, the
IURC approved the Agreement. Since the Agreement has been approved, the OUCC
will dismiss, with prejudice, its appeal of the Generic Order.
GAS COST ADJUSTMENT CLAUSE. All metered gas sales rates contain an
adjustment factor, which reflects the increases and decreases in the cost of
purchased gas, contracted gas storage and storage transportation charges. The
gas cost adjustment factor is subject to a quarterly hearing by the IURC and
remains in effect for a three-month period. On August 11, 1999, the IURC
approved a flexible gas cost adjustment mechanism for Northern Indiana. Under
the new procedure, the demand component of the adjustment factor will be
determined, after hearing and IURC approval, and made effective on November 1 of
each year. The demand component will remain in effect for one year until a new
demand component is approved by the IURC. The commodity component of the
adjustment factor will be determined by monthly filings, which will become
effective on the first day of each calendar month, subject to refund. The
monthly filings do not require IURC approval but will be reviewed by the IURC
during the annual hearing that will take place regarding the demand component
filing.
If the statutory requirement relating to the level of return is satisfied,
any under-recovery or over-recovery caused by variances between estimated and
actual cost in a given monthly period will be allocated over a twelve-month
period beginning with the next monthly filing. Any under- recovery or
over-recovery is recorded as a current asset or current liability until such
time it is billed or refunded to its customers.
Northern Indiana's gas cost adjustment factor also includes a gas cost
incentive mechanism (GCIM) which allows or the sharing of any cost savings or
cost increases with customers based upon a comparison of actual gas supply
portfolio cost to a market-based benchmark price.
NATURAL GAS IN STORAGE. Natural gas in storage is valued using the
last-in, first-out (LIFO) inventory methodology. Based on the average cost of
gas purchased in June 2000 and December 1999, the estimated replacement cost of
gas in storage (current and non-current) at June 30, 2000 and December 31, 1999
exceeded the stated LIFO cost by $99.6 million and $48.9 million, respectively.
AFFILIATED COMPANY TRANSACTIONS. Northern Indiana receives executive,
financial, gas supply, sales and marketing, and administrative and general
services from an affiliate, NiSource Management Services Company (NMSC), a
wholly-owned subsidiary of NiSource.
The costs of these services are charged to Northern Indiana based on
payroll costs and expenses incurred by NMSC employees for the benefit of
Northern Indiana. These costs, which totaled $6.5 million, $12.6 million and
$20.9 million for the three-month, six-month and twelve-month periods ended June
30, 2000, respectively, and 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, consist primarily of employee compensation and benefits.
Northern Indiana purchased natural gas and transportation services from
affiliated companies in the amounts of $13.5 million, $17.6 million and $28.0
million representing 15.6%, 8.0% and 7.4% of Northern Indiana's total gas costs
for the three-month, six-month and twelve-month periods ended June 30, 2000,
respectively. 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 subleases a portion of its office facilities to
affiliated companies for a monthly fee, which includes operating expenses, based
on space utilization.
ACCOUNTING FOR PRICE RISK MANAGEMENT. Northern Indiana is exposed to
commodity price risk in its natural gas and electric operations. A variety of
commodity-based derivative financial instruments are utilized to reduce this
price risk. When these derivatives are used to reduce price risk in non-trading
operations such as activities in gas supply for regulated gas utilities and
certain customer choice programs, gains and losses on these derivative financial
instruments are deferred as assets or liabilities and are recognized in earnings
concurrent with the disposition of the underlying physical commodity. In certain
circumstances, a derivative financial instrument will serve to hedge the
acquisition cost of natural gas injected into storage. In this situation, the
gain or loss on the derivative financial instrument is deferred as part of the
cost basis of gas in storage and recognized upon the ultimate disposition of the
gas. If a derivative financial instrument contract is terminated early because
it is probable that a transaction or forecasted transaction will not occur, any
gain or loss as of such date is immediately recognized in earnings. If a
derivative financial instrument is terminated for other economic reasons, any
gain or losses as of the termination date is deferred and recorded when the
associated transaction or forecasted transaction affects earnings.
Northern Indiana also uses derivative financial instruments in connection
with trading activities at its power trading operations. These derivatives,
along with the related physical contracts, are recorded at fair value pursuant
to Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Energy
Trading and Risk Management Activities." Because the majority of our trading
activities started in 1999, the impact of adopting EITF Issue No. 98-10 on
January 1, 1999, was insignificant. Transactions related to electric utility
system load management do not qualify as a trading activity under EITF Issue No.
98-10 and are accounted for on an accrual basis. Northern refers to this
activity as Power Marketing.
IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards Board
(FASB) has issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," in June 1998 and SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities-Deferral of the Effective Date of FASB
Statement No. 133" in June 1999 and SFAS No. 138 "Accounting for Certain
Derivatives Instruments and Certain Hedging Activities - an amendment of FASB
No. 133" in June 2000. Statement No. 133 as amended standardizes the accounting
for derivative instruments, including certain derivative instruments embedded in
other contracts, by requiring that a company recognize those items as assets or
liabilities in the balance sheet and measure them at fair value. The standard
also suggests in certain circumstances commodity based contracts may qualify as
derivatives. Special accounting within this Statement generally provides for
matching of the timing of gain or loss recognition of derivative instruments
qualifying as a hedge with the recognition of changes in the fair value of the
hedged asset or liability through earnings, and requires that a company must
formally document, designate and assess the effectiveness of transactions that
receive hedge accounting treatment. The Statement also provides that the
effective portion of hedging instrument's gain or loss on a forecasted
transaction be initially reported in other comprehensive income and subsequently
reclassified into earnings when the hedged forecasted transaction affects
earnings. Unless those specific hedge accounting criteria are met, SFAS No. 133
requires that changes in derivatives' fair value be recognized currently in
earnings.
SFAS No. 133, as amended, is not effective for Northern Indiana until
January 1, 2001. SFAS No. 133 must be applied to (a) derivative instruments and
(b) certain derivative instruments embedded in hybrid contracts. With respect to
hybrid instruments, a company may elect to apply SFAS No. No. 133, as amended,
to (1) all hybrid instruments, (2) only those hybrid instruments that were
issued, acquired or substantively modified after December 31, 1997, or (3) only
those hybrid instruments that were issued, acquired or substantively modified
after December 31, 1998. Northern Indiana will adopt SFAS No. 133 on January 1,
2001, but has not completed its determination of the impact or method of
adoption. The fair value of derivatives used in price risk management are
described in "Risk Management Activities." The fair value of these derivatives
would be recognized as assets or liabilities on the balance sheet consistent
with the current accounting treatment for certain freestanding derivatives.
Northern Indiana is in the process of projecting the impact of SFAS No. 133 but
has not yet qualified the other effects of adopting SFAS No. 133 on its
financial statements. However, adoption of SFAS No. 133 could increase
volatility in earnings and other comprehensive income.
REGULATORY ASSETS. Northern Indiana's operations are subject to the
regulation of the Commissions. Accordingly, Northern Indiana's accounting
policies are subject to the provisions of SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation." Northern Indiana monitors changes in
market and regulatory conditions and the resulting impact of such changes in
order to continue to apply the provisions of SFAS No. 71 to some or all of its
operations. As of June 30, 2000, and December 31, 1999, the regulatory assets
identified below represent probable future revenues to Northern Indiana as these
costs are recovered through the rate-making process. If a portion of Northern
Indiana's operations becomes no longer subject to the provisions of SFAS No. 71,
a write-off of certain regulatory assets might be required, unless some form of
transition cost recovery is established by the appropriate regulatory body which
would meet the requirements under generally accepted accounting principles for
continued accounting as regulatory assets during such recovery period.
Regulatory assets were comprised of the following items:
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
Unamortized reacquisition premium on
debt (Note 13) $ 37,767 $ 39,499
Unamortized R. M. Schahfer Unit 17 and
Unit 18 carrying charges
and deferred depreciation (See below) 56,003 58,111
Bailly scrubber carrying charges and
deferred depreciation (See below) 7,542 8,010
Deferral of SFAS No. 106 expense not
recovered (Note 6) 69,971 72,769
FERC Order No. 636 transition costs 9,983 13,728
Regulatory income tax asset, net (Note 4) 20,258 18,208
------------- -------------
201,524 210,325
Less: Current portion of regulatory assets 20,500 24,245
------------- -------------
$ 181,024 $ 186,080
============= =============
</TABLE>
CARRYING CHARGES AND DEFERRED DEPRECIATION. Upon completion of R. M.
Schahfer Units 17 and 18, Northern Indiana capitalized the carrying charges and
deferred depreciation in accordance with orders of the IURC until the cost of
each unit was allowed in rates. Such carrying charges and deferred depreciation
are being amortized over the remaining life of each unit.
Northern Indiana has capitalized carrying charges and deferred
depreciation and certain operating expenses relating to its scrubber service
agreement for its Bailly Generating Station in accordance with an order of the
IURC. The accumulated balance of the deferred costs and related carrying charges
is being amortized over the remaining life of the scrubber service agreement.
INCOME TAXES. The liability method of accounting is used for income taxes
under which deferred income taxes are recognized, at currently enacted income
tax rates, to reflect the tax effect of temporary differences between book and
tax bases of assets and liabilities. Deferred investment tax credits are being
amortized over the life of the related property.
(3) ENVIRONMENTAL MATTERS:
GENERAL. The operations of Northern Indiana are subject to extensive and
evolving federal, state and local environmental laws and regulations intended to
protect public health and the environment. Such environmental laws and
regulations affect Northern Indiana's operations as they relate to impacts on
air, water and land.
SUPERFUND. Because Northern Indiana is a "potentially responsible party"
(PRP), under Comprehensive Environmental Response, Compensation and Liability
Act (CERCLA), at several waste disposal sites, as well as at former
manufactured-gas plant sites which it, or its corporate predecessors, own or
owned or operated, it may be required to share in the costs of clean up of such
sites. A program was instituted to investigate former manufactured-gas plant
sites where it is the current or former owner, which investigation has
identified twenty-four of such sites. Initial sampling has been conducted at
nineteen sites. Investigation activities have been completed at fifteen sites
and remedial measures have been selected or implemented at thirteen sites.
Northern Indiana intends to continue to evaluate its facilities and properties
with respect to environmental laws and regulations and take any required
corrective action.
In an effort to recover a portion of the costs related to the former
manufactured gas plants, various companies that provided insurance coverage
which Northern Indiana believed covered costs related to former manufactured-gas
plant sites were approached. Northern Indiana filed claims in Indiana state
court against various insurance companies, seeking coverage for costs associated
with several manufactured-gas plant sites and damages for alleged misconduct by
some of the insurance companies. Settlements have been reached with all
insurance companies. Additionally, agreements have been reached with other
Indiana utilities relating to cost sharing and management of the investigation
and remediation of several former manufactured-gas plant sites at which Northern
Indiana and such utilities or their predecessors were operators or owners.
As of June 30, 2000, a reserve of approximately $17.0 million has been
recorded to cover probable corrective actions. The ultimate liability in
connection with these sites will depend upon many factors, including the volume
of material contributed to the site, the number of other PRP's and their
financial viability, the extent of corrective actions required and rate
recovery. Based upon investigations and management's understanding of current
environmental laws and regulations, Northern Indiana believes that any
corrective actions required, after consideration of insurance coverages existing
reserves, contributions from other PRP's and rate recovery will not have a
material effect on its financial position or results of operations.
CLEAN AIR ACT. The Clean Air Act Amendments of 1990 (CAAA) impose limits
to control acid rain on the emission of sulfur dioxide and nitrogen oxides (NOx)
which become fully effective in 2000. All of Northern Indiana's facilities are
already in compliance with sulfur dioxide limits. Northern Indiana has already
taken the steps necessary to meet the NOx limits.
The CAAA also contain other provisions that could lead to limitations on
emissions of hazardous air pollutants and other air pollutants (including NOx as
discussed below), which may require significant capital expenditures for control
of these emissions. Until specific rules have been issued that affect Northern
Indiana's facilities, what these requirements will be or the costs of complying
with these potential requirements cannot be predicted.
NITROGEN OXIDES. During 1998, the Environmental Protection Agency (EPA)
issued a final rule, the NOx State Implementation Plan (SIP) call, requiring
certain states, including Indiana, to reduce NOx levels from several sources,
including industrial and utility boilers. The EPA stated that the intent of the
rule is to lower regional transport of ozone impacting other states' ability to
attain the federal ozone standard. According to the rule, the State of Indiana
must issue regulations implementing the control program. The State of Indiana,
as well as some other states, filed a legal challenge in December 1998 to the
EPA NOx SIP call rule. Lawsuits have also been filed against the rule by various
groups, including utilities. On May 25, 1999, the United States Circuit Court of
Appeals for the D.C. Circuit Court issued an order staying the NOx SIP call
rule's September 30, 1999 deadline for the state submittals until further order
of the court. In a March 3, 2000 decision, the United States Court of Appeals
for the D.C. Circuit ruled largely in favor of EPA's regional NOx plan. The
state led group requested a hearing of the issue from the full court. On June
22, 2000, the court denied the rehearing and lifted the stay for the state plan
submittals. The states now have until the end of October 2000 to submit their
plans implementing the EPA NOx SIP Call. Further legal challenges are expected,
including an appeal to the United States Supreme Court. The State of Indiana in
February 2000 proposed a moderate NOx control plan designed to address Indiana's
ozone nonattainment areas and regional ozone transport. Any NOx emission
limitations resulting from these actions could be more restrictive than those
imposed on electric utilities under the CAAA's acid rain NOx reduction program
described above. Northern Indiana is evaluating the EPA's final rule and any
potential requirements that could result from the final rule as implemented by
the State of Indiana. Northern Indiana believes that the costs relating to
compliance with the new standards may be substantial, but such costs are
dependent upon the outcome of the current litigation and the ultimate control
program agreed to by the targeted states and the EPA. Northern Indiana is
continuing its programs to reduce NOx emissions and Northern Indiana will
continue to closely monitor developments in this area.
In a related matter to EPA's NOx SIP call, several Northeastern states
have filed petitions with the EPA under Section 126 of the Clean Air Act. The
petitions allege harm and request relief from sources of emissions in the
Midwest that allegedly cause or contribute to ozone nonattainment in their
states. Northern Indiana is monitoring EPA's decisions on these petitions and
existing litigation to determine the impact of these developments on Northern
Indiana's programs to reduce NOx emissions.
The EPA issued final rules revising the National Ambient Air Quality
Standards for ozone and particulate matter in July 1997. On May 14, 1999, the
United States Court of Appeals for the D.C. Circuit remanded the new rules for
both ozone and particulate matter standards to the EPA. Once rectified, the
revised standards could require additional reductions in sulfur dioxide,
particulate matter and NOx emissions from coal-fired boilers (including Northern
Indiana's generating stations) beyond measures discussed above. Final
implementation methods will be set by the EPA as well as state regulatory
authorities. Northern Indiana believes that the costs relating to compliance
with any new limits may be substantial but are dependent upon the ultimate
control program agreed to by the targeted states and the EPA. Northern Indiana
will continue to closely monitor developments in this area and anticipates the
exact nature of the impact of the new limits on its operations will not be known
for some time.
In a letter dated September 15, 1999, the Attorney General of the State of
New York alleged that Northern Indiana violated the Clean Air Act by
constructing a major modification of one of its electric generating stations
without obtaining pre-construction permits required by the Prevention of
Significant Deterioration (PSD) program. The major modification allegedly took
place at the R. M. Schahfer Station when, "in approximately 1995-1997, Northern
Indiana upgraded the coal handling system at Unit 14 at the plant." While
Northern Indiana is investigating these allegation, Northern Indiana does not
believe that the modifications required pre-construction review under the PSD
program and believes that all appropriate permits were acquired.
CARBON DIOXIDE. Initiatives are being discussed both in the United States
and worldwide to reduce so-called "greenhouse gases" such as carbon dioxide, and
other by-products of burning fossil fuels. Reduction of such emissions could
result in significant capital outlays or operating expenses to Northern Indiana.
CLEAN WATER ACT AND RELATED MATTERS. Northern Indiana's wastewater and
water operations are subject to pollution control and water quality control
regulations, including those issued by the EPA and the State of Indiana.
Under the Federal Clean Water Act and Indiana's regulations, Northern
Indiana must obtain National Pollutant Discharge Elimination System permits for
water discharges from various water discharges from various facilities,
including electric generating and water treatment stations. These facilities
either have permits for their water discharge or they have applied for a permit
renewal of any expiring permits. These permits continue in effect pending review
of the current applications.
(4) INCOME TAXES: Deferred income taxes are recognized as costs in the
rate-making process by the Commissions having jurisdiction over rates charged by
Northern Indiana. Deferred income taxes are provided as a result of provisions
in the income tax law that either require or permit certain items to be reported
on the income tax return in a different period than they are reported in the
consolidated financial statements. These taxes are reversed by a debit or credit
to deferred income tax expense as the temporary differences reverse. Investment
tax credits have been deferred and are being amortized to income over the life
of the related property.
To the extent certain deferred income taxes are recoverable or payable
through future rates, regulatory assets and liabilities have been established.
Regulatory assets are primarily attributable to undepreciated allowance for
funds used during construction-equity (AFUDC) and the cumulative net amount of
other income tax timing differences for which deferred taxes had not been
provided in the past, when regulators did not recognize such taxes as costs in
the rate-making process. Regulatory liabilities are primarily attributable to
Northern Indiana's obligation to credit to ratepayers deferred income taxes
provided at rates higher than the current federal tax rate currently being
credited to ratepayers using the average rate assumption method and unamortized
deferred investment tax credits.
Northern Indiana joins in the filing of consolidated tax returns with
NiSource and currently pays to NiSource its separate return tax liability as
defined in the Tax Sharing Agreement between NiSource and its subsidiaries.
The components of the net deferred income tax liability at June 30, 2000
and December 31, 1999 were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
============= =============
(Dollars in thousands)
<S> <C> <C>
Deferred tax liabilities -
Accelerated depreciation
and other property differences $ 704,370 $ 714,246
AFUDC-equity 29,856 30,748
Adjustment clauses 2,336 15,545
Other regulatory assets 26,536 27,598
Prepaid pension and other benefits 56,227 56,227
Reacquisition premium on debt 14,323 14,980
Deferred tax assets -
Deferred investment tax credits (31,107) (32,451)
Removal costs (177,961) (171,645)
Other postretirement/postemployment
benefits (54,222) (53,061)
Other, net (27,313) (27,928)
------------- -------------
543,045 574,259
Less: Deferred income taxes related to
current assets and liabilities (32,194) (17,763)
------------- -------------
Deferred income taxes - noncurrent $ 575,239 $ 592,022
============= =============
</TABLE>
Federal and state income taxes as set forth in the Consolidated Statements
of Income are comprised of the following:
<TABLE>
<CAPTION>
Three Months Six Months
Ended June 30, Ended June 30,
-------------------- --------------------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Current income taxes -
Federal $ 30,546 $ 27,071 $ 88,002 $ 86,653
State 4,084 3,739 11,918 12,422
--------- --------- --------- ---------
34,630 30,810 99,920 99,075
--------- --------- --------- ---------
Deferred income taxes, net -
Federal (8,569) (7,109) (29,695) (31,855)
State (717) (564) (2,483) (2,602)
--------- --------- --------- ---------
(9,286) (7,673) (32,178) (34,457)
--------- --------- --------- ---------
Deferred investment tax credits,
net (1,771) (1,782) (3,543) (3,563)
--------- --------- --------- ---------
Total utility operating income
taxes 23,573 21,355 64,199 61,055
Income tax applicable to non-
operating activities and income
of subsidiaries 644 638 972 (6)
--------- --------- --------- ---------
Total income taxes $ 24,217 $ 21,993 $ 65,171 $ 61,049
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended June 30,
--------------------
2000 1999
========= =========
(Dollars in thousands)
<S> <C> <C>
Current income taxes -
Federal $ 137,136 $ 138,270
State 17,598 19,437
--------- ---------
154,734 157,707
--------- ---------
Deferred income taxes, net -
Federal (16,031) (25,178)
State (1,186) (1,880)
--------- ---------
(17,217) (27,058)
--------- ---------
Deferred investment tax credits,
net (7,106) (7,159)
--------- ---------
Total utility operating income
taxes 130,411 123,490
Income tax applicable to non-
operating activities and income
of subsidiaries (607) (711)
--------- ---------
Total income taxes $ 129,804 $ 122,779
========= =========
</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 Six Months
Ended June 30, Ended June 30,
--------- --------- --------- ---------
2000 1999 2000 1999
========= ========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Net income $ 42,937 $ 40,756 $ 115,767 $ 110,148
Add-Income taxes 24,217 21,993 65,171 61,049
--------- --------- --------- ---------
Net income before income taxes $ 67,154 $ 62,749 $ 180,938 $ 171,197
========= ========= ========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 23,504 $ 21,962 $ 63,328 $ 59,919
Reconciling items multiplied by the statutory rate:
Book depreciation over related
tax depreciation 917 968 1,835 1,937
Amortization of deferred
investment tax credits (1,771) (1,782) (3,543) (3,563)
State income taxes, net of
federal income tax benefit 1,938 1,866 5,264 5,472
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (919) (721) (1,838) (1,442)
Other, net 548 (300) 125 (1,274)
--------- --------- --------- ---------
Total income taxes $ 24,217 $ 21,993 $ 65,171 $ 61,049
========= ========= ========= =========
<CAPTION>
Twelve Months
Ended June 30,
--------- ---------
2000 1999
========= =========
(Dollars in thousands)
<S> <C> <C>
Net income $ 227,730 $ 224,752
Add-Income taxes 129,804 122,779
--------- ---------
Net income before income taxes $ 357,534 $ 347,531
========= =========
Amount derived by multiplying
pre-tax income by the statutory
rate $ 125,137 $ 121,636
Reconciling items multiplied by the statutory rate:
Book depreciation over related
tax depreciation 3,832 3,933
Amortization of deferred
investment tax credits (7,106) (7,159)
State income taxes, net of
federal income tax benefit 10,253 10,753
Reversal of deferred taxes
provided at rates in excess
of the current federal income
tax rate (5,853) (5,372)
Other, net 3,541 (1,012)
--------- ---------
Total income taxes $ 129,804 $ 122,779
========= =========
</TABLE>
(5) PENSION PLANS: NiSource has a noncontributory, defined benefit
retirement plan covering substantially all employees of Northern Indiana.
Benefits under the plan reflect the employees' compensation, years of service
and age at retirement.
The change in the benefit obligation for 1999 and 1998 is as follows:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Benefit obligation at beginning $ 914,273 $ 843,049
of year (January 1,)
Service cost 15,858 15,347
Interest cost 61,613 58,337
Plan amendments 0 14,655
Actuarial (gain) loss (50,217) 37,247
Benefits paid (54,823) (54,362)
--------- ---------
Benefit obligation at end of
the year (December 31,) $ 886,704 $ 914,273
========= =========
</TABLE>
The change in the fair value of the plan's assets for years 1999 and 1998
is as follows:
<TABLE>
<CAPTION>
1999 1998
=========== ===========
(Dollars in thousands)
<S> <C> <C>
Fair value of plan assets at $ 958,435 $ 896,950
beginning of year January 1,)
Actual return on plan's assets 158,775 82,547
Employer contributions 35,000 33,300
Benefits paid (54,823) (54,362)
----------- -----------
Plan assets at fair value at
end of the year (December 31,) $ 1,097,387 $ 958,435
=========== ===========
</TABLE>
The plan's assets are invested primarily in common stocks, bonds and
notes.
The plan's funded status as of December 31,1999 and 1998 is as follows:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Plan assets in excess of $ 210,683 $ 44,162
benefit obligation
Unrecognized net actuarial (gain) (140,665) (16,162)
Unrecognized prior service cost 50,165 55,761
Unrecognized transition amount
being recognized over
seventeen years 21,953 27,442
--------- ---------
Prepaid pension costs $ 142,136 $ 111,203
========= =========
</TABLE>
The benefit obligation is the present value of future pension benefit
payments and is based on a plan benefit formula which considers expected future
salary increases. Discount rates of 7.75% and 7.00% and rate of increase in
compensation levels of 4.5% and 4.5% were used to determine the benefit
obligation at December 31, 1999 and December 31, 1998, respectively.
The long-term portion of prepaid pension costs were $179.3 million and
$141.5 million at June 30, 2000 and December 31, 1999, respectively, and are
reported under the caption "Prepayments and Other" in the Consolidated Balance
Sheet.
The following items are the components of provisions for pensions for the
three-month, six-month and twelve-month periods ended June 30, 2000 and June 30,
1999:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
-------- -------- -------- -------- -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 4,266 $ 3,665 $ 8,531 $ 8,248 $ 16,141 $ 11,602
Interest costs 16,898 15,162 33,797 30,806 64,604 46,997
Expected return
on plan assets (25,621) (21,135) (48,734) (42,244) (90,978) (66,632)
Amortization of
transition
obligation 1,372 1,372 2,744 2,744 5,488 4,428
Amortization of
prior service
cost 1,399 1,413 2,798 2,798 5,596 4,145
Amortization of
gain (687) 0 (1,374) 0 (1,374) 0
-------- -------- -------- -------- -------- --------
$ (2,373) $ 477 $ (2,238) $ 2,352 $ (523) $ 540
======== ======== ======== ======== ======== ========
</TABLE>
Assumptions used in the valuation and determination of 2000 and 1999
pension expense were as follows:
<TABLE>
<CAPTION>
2000 1999
===== =====
<S> <C> <C>
Discount rate 7.75% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Expected long-term rate of return on assets 9.00% 9.00%
</TABLE>
(6) POSTRETIREMENT BENEFITS: Northern Indiana provides certain health care and
life insurance benefits for retired employees are provided. Substantially all
Northern Indiana's employees may become eligible for those benefits if they
reach retirement age while working for Northern Indiana.
The expected cost of such benefits is accrued during the employees' years
of service. Current rates include postretirement benefit costs on an accrual
basis, including amortization of the regulatory assets that arose prior to
inclusion of these costs in rates.
The following table sets forth the change in the plan's accumulated
postretirement benefit obligation (APBO) as of December 31, 1999 and 1998:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Accumulated postretirement $ 207,079 $ 195,003
benefit obligation at
beginning of year (January 1,)
Service cost 3,010 3,314
Interest cost 14,217 13,685
Plan amendments 1,191 0
Actuarial (gain) loss (15,959) 6,260
Benefits paid (13,883) (11,183)
--------- ---------
Accumulated postretirement
benefit obligation at
end of the year (December 31,) $ 195,655 $ 207,079
========= =========
</TABLE>
The change in the fair value of the plan's assets for the years 1999 and
1998 is as follows:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Fair value of plan assets at $ 2,903 $ 2,400
beginning of year (January 1,)
Actual return on plan assets 704 1,103
Employer contributions 12,477 9,301
Participant contributions 1,191 1,282
Benefits paid (13,883) (11,183)
--------- ---------
Plan assets at fair value at
end of the year (December 31,) $ 3,392 $ 2,903
========= =========
</TABLE>
Following is the funded status for postretirement benefits as of December
31, 1999 and 1998:
<TABLE>
<CAPTION>
1999 1998
========= =========
(Dollars in thousands)
<S> <C> <C>
Funded status $(192,262) $(204,176)
Unrecognized actuarial (gain) (103,623) (90,700)
Unrecognized prior service cost 3,178 3,458
Unrecognized transition amount
being recognized over
twenty years 139,719 150,466
--------- ---------
Accrued liability for
postretirement benefits $(152,988) $(140,952)
========= =========
</TABLE>
In order to determine the APBO at December 31, 1999 a discount rate of
7.75% and a pre-Medicare medical trend rate of 6% declining to a long-term rate
of 5% was used, and at December 31, 1998, a discount rate of 7% and a
pre-Medicare medical trend rate of 7% declining to a long-term rate of 5% was
used. The accrued liability for postretirement benefits was $152.0 million at
June 30, 2000.
Net periodic postretirement benefits costs, before consideration of the
rate-making discussed previously, for the three-month, six-month and twelve-
month periods ended June 30, 2000 and June 30, 1999 include the following
components:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------- ------- ------- ------- ------- -------
2000 1999 2000 1999 2000 1999
======= ======= ======= ======= ======= =======
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 622 $ 1,350 $ 1,423 $ 1,827 $ 2,910 $ 3,335
Interest costs 3,900 3,850 7,800 7,700 13,785 14,085
Expected return
on plan assets (50) (50) (100) (100) (216) (216)
Amortization of
transition
obligation
over twenty years 2,700 2,675 5,400 5,350 10,798 10,748
Amortization of
prior service cost 75 75 150 150 279 279
Amortization of
actuarial (gain) (1,375) (1,150) (2,750) (2,300) (6,236) (5,336)
------- ------- ------- ------- ------- -------
$ 5,872 $ 6,750 $11,923 $12,627 $21,320 $22,895
======= ======= ======= ======= ======= =======
</TABLE>
Assumptions used in the determination of 2000 and 1999 net periodic
postretirement benefit costs were as follows:
<TABLE>
<CAPTION>
2000 1999
===== =====
<S> <C> <C>
Discount rate 7.75% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Assumed annual rate of increase in health
care benefits 7.00% 7.00%
Assumed ultimate trend rate 5.00% 5.00%
</TABLE>
The effect of a 1% increase in the assumed health care cost trend rates
for each future year would increase the APBO at January 1, 2000 by approximately
$21.9 million, and increase the aggregate of the service and interest cost
components of plan costs by approximately $0.6 million and $1.2 million for the
three-month period and six-month periods ended June 30, 2000. The effect of a 1%
decrease in the assumed health care cost trend rates for each future year would
decrease the APBO at January 1, 2000 by approximately $18.1 million, and
decrease the aggregate of the service and interest cost components of plan costs
by approximately $0.5 million and $1.0 million for the three-month and six-month
periods ended June 30,2000. Amounts disclosed above could be changed
significantly in the future by changes in health care costs, work force
demographics, interest rates, or plan changes.
(7) AUTHORIZED CLASSES OF CUMULATIVE PREFERRED AND PREFERENCE STOCKS
OF NORTHERN INDIANA:
2,400,000 shares - Cumulative Preferred - $100 par value 3,000,000
shares - Cumulative Preferred - no par value 2,000,000 shares -
Cumulative Preference - $50 par value
(none outstanding)
3,000,000 shares - Cumulative Preference - no par value
(none issued)
Note 8 sets forth the preferred stocks which are redeemable solely at the
option of Northern Indiana and Note 9 sets forth the preferred stocks which are
subject to mandatory redemption requirements or whose redemption is outside the
control of Northern Indiana.
The preferred shareholders of Northern Indiana have no voting rights,
except in the event of 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, 2000 AND DECEMBER 31, 1999 (SEE NOTE 7):
<TABLE>
<CAPTION>
Redemption
Price at
June 30, December 31, June 30,
2000 1999 2000
============ ============ ============
(Dollars in thousands)
<S> <C> <C> <C>
Cumulative preferred stock -
$100 par value -
4-1/4% series - 209,035 shares
outstanding $ 20,903 $ 20,903 $101.20
4-1/2% series - 79,996 shares
outstanding 8,000 8,000 $100.00
4.22% series - 106,198 shares
outstanding 10,620 10,620 $101.60
4.88% series - 100,000 shares
outstanding 10,000 10,000 $102.00
7.44% series - 41,890 shares
outstanding 4,189 4,189 $101.00
7.50% series - 34,842 shares
outstanding 3,484 3,484 $101.00
Premium on preferred stock 254 254
Cumulative preferred stock -
no par value -
Adjustable rate (6.00% at June 30, 2000), Series A (stated value $50 per
share)
473,285 shares outstanding 23,664 23,664 $50.00
------------ ------------
$ 81,114 $ 81,114
============ ============
</TABLE>
During the period July 1, 1998 to June 30, 2000 there were no additional
issuances of the above preferred stocks. The foregoing preferred stocks are
redeemable in whole or in part, at any time upon thirty days' notice at the
option of Northern Indiana at the redemption prices shown.
(9) REDEEMABLE PREFERRED STOCKS OUTSTANDING AT JUNE 30, 2000 AND
DECEMBER 31, 1999 (SEE NOTE 7):
Preferred stocks subject to mandatory redemption requirements or whose
redemption is outside the control of Northern Indiana, excluding sinking fund
payments due within one year were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Preferred stocks subject to mandatory redemption
requirements or whose redemption is outside the
control of Northern Indiana:
Cumulative preferred stock - $100 par value - 8.85% series - 25,000 and 37,500
shares
outstanding, respectively, excluding sinking
fund payments due within one year $ 2,500 $ 3,750
7-3/4% series - 27,798 shares outstanding,
excluding sinking fund payments due within
one year 2,780 2,780
8.35% series - 42,000 and 45,000 shares
outstanding, respectively, excluding sinking
fund payments due within one year 4,200 4,500
Cumulative preferred stock - no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
------------ ------------
$ 52,480 $ 54,030
============ ============
</TABLE>
The redemption prices at June 30, 2000, as well as sinking fund provisions
for the cumulative preferred stocks subject to mandatory redemption
requirements, or whose redemption is outside the control of Northern Indiana,
were as follows:
<TABLE>
<CAPTION>
Sinking Fund Or
Mandatory Redemption
Series Redemption Price Per Share Provisions
====== ========================== =============================
<S> <C> <C>
Cumulative preferred stock - $100 par value -
8.85% $100.37, reduced periodically 12,500 shares on or before
April 1.
7-3/4% $103.88, reduced periodically 2,777 shares on or
before December 1;
noncumulative option
to double amount each
year.
8.35% $103.20, reduced periodically 3,000 shares on or before
July 1; increasing to 6,000
shares beginning in 2004;
noncumulative option
to double amount each
year.
Cumulative preferred stock - no par value -
6.50% $100.00 on October 14, 2002 430,000 shares on October 14,
2002.
</TABLE>
Sinking fund requirements with respect to redeemable preferred stocks
outstanding at June 30, 2000 for each of the twelve-month periods subsequent to
June 30, 2001 were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
==================================
(Dollars in thousands)
<S> <C>
2002 $ 1,828
2003 $ 44,828
2004 $ 578
2005 $ 878
</TABLE>
Sinking fund payments due within one year are reported under the caption
"Other" included in Current Liabilities in the Consolidated Balance Sheet.
(10) COMMON SHARE DIVIDEND: Northern Indiana's Indenture dated August 1, 1939,
as amended and supplemented (Indenture), provides that it will not declare or
pay any dividends on any class of capital stock (other than preferred or
preference stock) except out of the earned surplus or net profits of Northern
Indiana. At June 30, 2000, Northern Indiana had approximately $132.9 million of
retained earnings (earned surplus) available for the payment of dividends.
Future dividends will depend upon adequate retained earnings, adequate future
earnings and the absence of adverse developments.
(11) COMMON SHARES: Effective with the exchange of common shares on March 3,
1988, all of Northern Indiana's common shares are owned by NiSource.
(12) LONG-TERM INCENTIVE PLAN: NiSource has two long-term incentive plans for
key management employees, including management of Northern Indiana, that were
approved by shareholders on April 13, 1988 (1988 Plan) and April 13, 1994 (1994
Plan), each of which provides for the issuance of up to 5.0 million of NiSource
common shares to key employees through April 1998 and April 2004, respectively.
The 1988 Plan, as amended and restated, and the 1994 Plan, as amended and
restated, were re-approved by shareholders on April 14, 1999.
On January 29, 2000, the Board of Directors of NiSource approved
certain additional amendments to the 1994 Plan and on June 1, 2000, the 1994
Plan, as amended and restated, was approved by shareholders at the 2000 Annual
Meeting of Shareholders of NiSource. The amended and restated 1994 Plan provides
for the number of common shares subject to the plan to increase from 5.0 million
to 11.0 million, and permits contingent stock awards and dividend equivalents
payable on grants of options, nonqualified stock options (SARs), performance
units and contingent stock awards. At June 30, 2000, there were 6,807,836 shares
reserved for future awards under the amended and restated 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, 2000. Under the
Plans, the exercise price of each option equals the market price of common stock
on the date of grant. Each option has a maximum term of ten years and vests one
year from the date of grant.
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, 2000. Restricted stock
awards are restricted as to transfer and are subject to forfeiture for specific
periods from the date of grant. Restrictions on shares awarded in 1995 lapsed on
January 27, 2000 and vested 116% of the number awarded, due to attaining
specific earnings per share and stock appreciation goals. Restrictions on shares
awarded in 1998 lapsed two years from date of grant and vested at 100% of the
number awarded. Restrictions on shares awarded in 2000 lapse three years from
date of grant and vesting may vary from 0% to 200% if the number awarded,
subject to specific performance goals. If a participant's employment is
terminated prior to vesting other than by reason of death, disability or
retirement, restricted shares are forfeited. There were 684,834 and 513,500
restricted shares outstanding at June 30, 2000 and December 31, 1999,
respectively.
Northern Indiana accounts for its allocable portion of these plans under
Accounting Principles Board Opinion No. 25, under which no compensation cost has
been recognized for nonqualified stock options. The compensation cost that has
been charged against income for restricted stock awards was 0.2 million and $0.2
million for the three-month, $0.3 million and $0.4 million for the six-month and
$1.1 million and $0.8 million for the twelve-month periods ending June 30, 2000
and June 30, 1999, respectively.
Had compensation cost for non-qualified stock options been determined
consistent with SFAS No. 123 "Accounting for Stock-Based Compensation," net
income would have been reduced to the following pro forma amounts:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
------------------ ------------------ -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Net Income:
As reported $ 42,937 $ 44,957 $115,767 $110,148 $227,730 $224,752
Pro forma $ 42,277 $ 46,736 $114,531 $109,340 $225,663 $223,255
</TABLE>
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions used
for grants in 2000, 1999 and 1998:
<TABLE>
<CAPTION>
2000 1999 1998
========== ========== ==========
<S> <C> <C> <C>
Interest Rate 6.60% 5.87% 5.29%
Expected Dividend Yield $1.08 $1.02 $0.96
Expected Life 5.4 years 5.25 years 5.4 years
Volatility 28.98% 15.72% 13.09%
</TABLE>
The weighted average fair value of options granted to all plan
participants was $3.69 and $4.28 for the twelve-month periods ended June 30,
2000 and June 30, 1999, respectively. There were no non-qualified stock options
granted to all plan participants for the twelve-month periods ended June 30,
2000. There were 607,000 non-qualified stock options granted to all plan
participants for the twelve-month periods ended June 30, 1999.
(13) LONG-TERM DEBT: At June 30, 2000 and December 31, 1999, the long-term debt
of Northern Indiana, excluding amounts due within one year, issued and not
retired or canceled was as follows:
<TABLE>
<CAPTION>
AMOUNT OUTSTANDING
---------------------------
June 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
First mortgage bonds -
Series T, 7-1/2%, due April 1, 2002 $ 38,500 $ 38,500
Series NN, 7.10%, due July 1, 2017 55,000 55,000
------------ ------------
Total 93,500 93,500
------------ ------------
Pollution control notes and bonds -
Series A Note -
City of Michigan City, 5.70% due
October 1, 2003 14,000 14,000
Series 1988 Bonds - Jasper County -
Series A, B and C - 4.55% weighted
average at June 30, 2000, due
November 1, 2016 130,000 130,000
Series 1988 Bonds - Jasper County -
Series D - 4.56% weighted average at
June 30, 2000, due November 1, 2007 24,000 24,000
Series 1994 Bonds - Jasper County -
Series A - 4.55% at June 30, 2000,
due August 1, 2010 10,000 10,000
Series 1994 Bonds - Jasper County -
Series B - 4.55% at June 30, 2000,
due June 1, 2013 18,000 18,000
Series 1994 Bonds - Jasper County -
Series C - 4.55% at June 30, 2000,
due April 1, 2019 41,000 41,000
------------ ------------
Total 237,000 237,000
------------ ------------
Medium-term notes -
Interest rates between 6.50% and 7.69% with a weighted average interest rate of
7.05% and various maturities between
August 15, 2001 and August 4, 2027 593,025 593,025
------------ ------------
Unamortized premium and discount
on long-term debt, net (2,899) (3,112)
------------ ------------
Total long-term debt excluding
amounts due in one year $ 920,626 $ 920,413
============ ============
</TABLE>
The sinking fund requirements and maturities of long-term debt outstanding
at June 30, 2000 for each of the twelve-month periods subsequent to June 30,
2001 were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
=================================
(Dollars in thousands)
<S> <C>
2002 $ 73,500
2003 $ 58,500
2004 $ 76,000
2005 $ 71,275
</TABLE>
Unamortized debt expense, premium and discount on long-term debt
applicable to outstanding bonds are being amortized over the lives of such
bonds. Reacquisition premiums are being deferred and amortized. These premiums
are not earning a return during the recovery period.
Northern Indiana's Indenture, pursuant to which first mortgage bonds have
been issued, constitutes a direct first mortgage lien upon substantially all of
Northern Indiana's property and franchises, other than expressly excepted
property.
Northern Indiana is authorized to issue and sell up to $217,692,000
Medium-Term Notes, Series E, with various maturities, for purposes of
refinancing certain first mortgage bonds and medium-term notes. As of June 30,
2000, $139.0 million of the medium-term notes had been issued with various
interest rates and maturities.
(14) CURRENT PORTION OF LONG-TERM DEBT: At June 30, 2000 and December 31,
1999, Northern Indiana's current portion of long-term debt due within one
year was as follows:
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Medium-term notes -
Interest rate 6.10% and 6.90% with a weighted average interest rate of 6.80%
and maturities between
March 20, 2000 and June 1, 2000 $ 0 $ 155,000
Sinking funds due within one year 3,000 3,000
------------ ------------
Total current portion of long-term debt $ 3,000 $ 158,000
============ ============
</TABLE>
(15) SHORT-TERM BORROWINGS: Northern Indiana entered into a five-year $100
million credit agreement and a 364-day $100 million revolving credit agreement
with several banks. These agreements terminate on September 23, 2003 and
September 23, 2000, respectively. The 364-day agreements may be extended at
expiration for additional periods of 364 days. Under these agreements, funds are
borrowed at a floating rate of interest or, under certain circumstances, at a
fixed rate of interest for a short-term periods. These agreements provide
financing flexibility and may be used to support the issuance of commercial
paper. As of June 30, 2000, there were no borrowings outstanding under these
agreements.
In addition, Northern Indiana has $11.4 million in lines of credit which
run until May 31, 2000. The credit pricing of each of the lines varies from
either the lending banks' commercial prime or market rates. As of June 30, 2000,
there were no borrowings under these lines of credit. The credit agreements and
lines of credit are also available to support the issuance of commercial paper.
Northern Indiana also has $201.5 million of money market lines of credit.
As of June 30, 2000 and December 31, 1999, $107.4 million and $33.7 million,
respectively, were outstanding under these lines of credit.
At June 30, 2000 and December 31, 1999, Northern Indiana's short-term
borrowings were as follows:
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Commercial paper -
Weighted average interest rate of 6.67% $ 127,000 $ 62,565
at June 30, 2000
Notes payable -
Issued at interest rates between 6.77% and 8.00% with a weighted average
interest rate of 6.84% and maturities
of July 3, 2000 and August 11, 2000 107,400 33,725
------------ ------------
Total short-term borrowings $ 234,400 $ 96,290
============ ============
</TABLE>
(16) OPERATING LEASES: On April 1, 1990, Northern Indiana entered into a
twenty-year agreement for the rental of office facilities from NiSource
Development Company, Inc., a subsidiary of NiSource, at a current annual
rental payment of approximately $3.5 million.
The following is a schedule, by years, of future minimum rental payments,
excluding those to associated companies, required under operating leases that
have initial or remaining noncancelable lease terms in excess of one year as of
June 30, 2000:
<TABLE>
<CAPTION>
Twelve Months Ended June 30,
================================
(Dollars in thousands)
<S> <C>
2001 $ 7,030
2002 7,030
2003 7,031
2004 6,386
2005 4,060
Later years 29,430
--------
Total minimum
payments required $ 60,967
========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
June 30, June 30,
2000 1999
============ ============
(Dollars in thousands)
<S> <C> <C>
Three months ended $ 2,696 $ 2,625
Six months ended $ 5,406 $ 5,291
Twelve months ended $11,253 $10,203
</TABLE>
(17) COMMITMENTS: Northern Indiana estimates that approximately $1.1 billion
will be expended for construction purposes for the period from January 1, 2000
to December 31, 2004. Substantial commitments have been made by Northern Indiana
in connection with this program.
Northern Indiana has entered into a service agreement with Pure Air, a
general partnership between Air Products and Chemicals, Inc. and Mitsubishi
Heavy Industries America, Inc., under which Pure Air provides scrubber services
to reduce sulfur dioxide emissions for Units 7 and 8 at its Bailly Generating
Station. Services under this contract commenced on June 15, 1992 with annual
charges approximating $20 million. The agreement provides that, assuming various
performance standards are met by Pure Air, a termination payment would be due if
Northern Indiana terminates the agreement prior to the end of the twenty-year
contract period.
A ten-year agreement to outsource all data center, application development
and maintenance, and desktop management expires in 2005. Annual fees under this
agreement are approximately $20 million.
(18) RISK MANAGEMENT ACTIVITIES: Northern Indiana uses certain commodity- based
derivative financial instruments to manage certain risks inherent in its
business. Northern Indiana's senior management takes an active role in the risk
management process and has developed policies and procedures that require
specific administrative and business functions to assist in the identification,
assessment and control of various risks. The open positions resulting from risk
management activities are managed in accordance with strict policies which limit
exposure to market risk and require daily reporting to management of potential
financial exposure.
Northern Indiana uses futures contracts, options and swaps to hedge a
portion of its price risk associated with its non-trading activities in gas
supply for its regulated gas utility, certain customer choice programs. At June
30, 2000, Northern Indiana futures contracts representing the hedge of natural
gas sales and the resulting gain were not material.
Northern Indiana's trading operations include the activities of its power
trading business. Northern Indiana employs a value-at-risk (VaR) model to assess
the market risk of its energy trading portfolios. Northern Indiana estimates the
one-day VaR for its trading group which utilizes derivatives using either a
Monte Carlo simulation or variance/covariance at 95 percent confidence level.
Based on the results of the VaR analysis, the daily market exposure for power
trading on an average, high and low basis was $0.7 million, $1.8 million and
$0.004 million for the three-month, and $0.5 million, $1.8 million and $0.004
million for the six-month and $0.5 million, $1.8 million and $0.004 million for
the twelve-month periods ended June 30, 2000, respectively.
Unrealized gains and losses on Northern Indiana's portfolio are recorded
as price risk management assets and liabilities. The market prices used to value
price risk management activities reflect the best estimate of market prices
considering various factors, including closing exchange and over-the- counter
quotations and price volatility factors underlying the commitments. The
accompanying Consolidated Balance Sheet reflects price risk management assets of
$56.7 million and $31.7 million at June 30, 2000 and December 31, 1999,
respectively, of which $54.0 million and $31.7 million were included in "Price
risk management assets" and $2.7 million and $0.0 million were included under
the caption "Prepayments and other" included in the Other Assets at June 30,
2000 and December 31, 1999, respectively. The accompanying Consolidated Balance
Sheet also reflects price risk management liabilities (including net option
premiums) of $85.5 million and $54.0 million of which $77.3 million and $54.0
million were included in "Price risk management liabilities" and $8.2 million
and $0.0 million were included in "Other noncurrent liabilities" at June 30,
2000 and December 31, 1999, respectively. Power trading results are reflected on
a net basis in the accompanying Consolidated Statements of Income, consistent
with the guidance in EITF Issue No. 98-10 with respect to the use of written
options and its settlement methodology with respect to physical forward sales
and purchase contracts. Northern Indiana has recorded as a component of electric
revenues a realized net profit of $4.8 million, $7.6 million and $15.0 million
for the three-month, six-month and twelve-month periods ended June 30, 2000,
respectively, and $3.5 million, $3.6 million and $3.6 million for the
three-month, six-month and twelve-months ended June 30, 1999, respectively.
Included in these net amounts are revenues and costs of sales related to
physical forward sales and purchase contracts as follows:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended Ended Ended
June 30, June 30, June 30,
-------- -------- -------- -------- -------- --------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Power trading
revenues $ 93,075 $ 44,957 $152,072 $ 44,957 $304,190 $ 44,957
Power trading
cost of sales $ 93,564 $ 46,736 $152,464 $ 46,736 $306,995 $ 46,736
</TABLE>
(19) FAIR VALUE OF FINANCIAL INSTRUMENTS: The following methods and assumptions
were used to estimate the fair value of each class of financial instruments for
which it is practicable to estimate fair value:
CASH AND CASH EQUIVALENTS. The carrying amount approximates fair
value due to the short maturity of those instruments.
INVESTMENTS. Investments are carried at cost, which approximates
market value.
LONG-TERM DEBT AND PREFERRED STOCK. The fair value of these securities
are estimated based on quoted market prices for the same or similar
issues or on the rates offered for securities of the same remaining
maturities. Certain premium costs associated with the early settlement
of long-term debt are not taken into consideration in determining fair
value.
The carrying values and estimated fair values of financial instruments
were as follows:
<TABLE>
<CAPTION>
June 30, 2000 December 31, 1999
---------------------- ----------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
========== ========== ========== ==========
(Dollars in thousands)
<S> <C> <C> <C> <C>
Cash and cash equivalents $ 10,617 $ 10,617 $ 6,145 $ 6,145
Investments $ 251 $ 251 $ 251 $ 251
Long-term debt (including
current portion) $ 923,626 $ 839,541 $1,078,413 $ 997,196
Preferred stock (including
current portion) $ 135,122 $ 107,852 $ 136,972 $ 116,464
</TABLE>
Northern Indiana is subject to regulation, and gains or losses may be
included in rates over a prescribed amortization period, if in fact settled at
amounts approximating those above.
(20) CUSTOMER CONCENTRATIONS: Northern Indiana is a public utility operating
company supplying natural gas and electrical energy in the northern third of
Indiana. Although Northern Indiana has a diversified base of residential and
commercial customers, a substantial portion of its electric and gas industrial
deliveries are dependent upon the basic steel industry. The basic steel industry
accounted for 3% of gas revenues (including transportation services) and 19% of
electric revenues for the twelve months ended June 30, 2000 as compared to 3%
and 16%, respectively, for the twelve months ended June 30,1999.
(21) SEGMENTS OF BUSINESS: Operating segments are defined as components of an
enterprise for which separate financial information is available and is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. Northern Indiana makes all
decisions on finance, dividends and taxes at the corporate level.
Northern Indiana's reportable operating segments include regulated gas and
electric services. Northern Indiana supplies gas and electric services to
residential, commercial and industrial customers. In addition, the electric
segment includes Northern Indiana's wholesale power marketing operation which
markets wholesale power to other utilities and electric power marketers. The
other category includes gas exploration, real estate transactions, and non-
utility revenues and expenses.
Reportable segments are operations that are managed separately and meet
the quantitative thresholds.
Revenues for each segments are attributable to customers in the United
States.
The following tables provide information about business segments. In
addition, adjustments have been made to the segment information to arrive at
information included in the results of operations and financial position. These
adjustments include unallocated corporate assets, revenues and expenses. The
accounting policies of the operating segments are the same as those described in
"Summary of Significant Accounting Policies."
<TABLE>
<CAPTION>
For the Three Months Adjust-
Ended June 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $130,316 $ 254,968 $ 0 $ 0 $ 385,284
Other income (deductions)$ (32) $ 98 $ 1,222 $ (32) $ 1,256
Depreciation and
amortization $ 19,385 $ 40,166 $ 0 $ 0 $ 59,551
Income before interest
and utility income
taxes $ (2,879) $ 87,018 $ 1,225 $ (35) $ 85,329
Assets $895,676 $2,758,948 $ 0 $ 0 $3,654,624
Capital expenditures $ 11,592 $ 32,788 $ 0 $ 0 $ 44,380
<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 Six Months Adjust-
Ended June 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $393,849 $ 508,474 $ 0 $ 0 $ 902,323
Other income (deductions)$ 467 $ 77 $ 1,304 $ (32) $ 1,816
Depreciation and
amortization $ 38,655 $ 80,158 $ 0 $ 0 $ 118,813
Income before interest
and utility income
taxes $ 49,181 $ 167,441 $ 1,307 $ (35) $ 217,894
Assets $895,676 $2,758,948 $ 0 $ 0 $3,654,624
Capital expenditures $ 23,307 $ 57,734 $ 0 $ 0 $ 81,041
<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 Twelve Months Adjust-
Ended June 30, 2000 Gas Electric Other ments Total
------------------------ -------- ---------- -------- -------- ----------
(Dollars in thousands)
<S> <C> <C> <C> <C> <C>
Operating revenues $687,455 $1,087,652 $ 0 $ 0 $1,775,107
Other income (deductions)$ 1,555 $ 446 $ (2,438) $ (15) $ (452)
Depreciation and
amortization $ 76,521 $ 159,649 $ 0 $ 0 $ 236,170
Income before interest
and utility income
taxes $ 73,338 $ 363,788 $ (2,471) $ 18 $ 434,673
Assets $895,676 $2,758,948 $ 0 $ 0 $3,654,624
Capital expenditures $ 63,449 $ 123,721 $ 0 $ 0 $ 187,170
<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
</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, 2000 and 1999:
<TABLE>
<CAPTION>
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------ ------------------ ------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income before
interest and
utility income
taxes $ 85,329 $ 80,097 $217,894 $207,801 $434,673 $424,232
Interest 18,819 17,986 37,928 36,598 $ 76,532 $ 75,990
Utility income
taxes 23,573 21,355 64,199 61,055 $130,411 $123,490
-------- -------- -------- -------- -------- --------
Net income $ 42,937 $ 40,756 $115,767 $110,148 $227,730 $224,752
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE>
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OPERATING REVENUES -
GAS REVENUES. Gas revenues were $687.5 million for the twelve months ended
June 30, 2000, an increase of $81.5 million from the comparable period ended
twelve months ended June 30, 1999. This increase was mainly due to the
pass-through increased gas costs, increased gas transportation services and
increased wholesale gas sales, partially offset by decreased sales to
residential and commercial customers as a result of warmer weather during the
period and decreased gas transition costs. During the period, gas deliveries in
dekatherms (dth) increased mainly as a result of increased gas transportation
services, partially offset by decreased deliveries to residential and commercial
customers reflecting heating degree days being 3% lower than 1999.
Gas revenues were $393.8 million for the six months ended June 30, 2000,
an increase of $42.8 million from the comparable period ended June 30, 1999.
This increase was mainly due to the pass-through increased gas costs, increased
industrial sales and increased gas transportation services, partially offset by
decreased sales to residential and commercial customers due to a significantly
warmer weather during the period. During the period, gas deliveries in dth
decreased mainly as a result of decreased gas deliveries to residential and
commercial customers reflecting heating degree days 7% lower than 1999,
partially offset by increased industrial sales and increased gas transportation
services
Gas revenues were $130.3 million for the three months ended June 30, 2000,
an increase of $25.9 million from the comparable period ended June 30, 1999.
This increase was mainly due to the pass-through increased gas costs, increased
industrial sales and increased sales to residential and commercial customers due
to cooler weather during the period, partially offset by decreased wholesale gas
sales and decreased transportation services. During the period, gas deliveries
in dth decreased mainly as a result of decreased wholesale gas sales and
decreased gas transportation services, partially offset by increased industrial
sales and increased gas deliveries to residential and commercial customers
reflecting heating degree days 13% higher than 1999.
Large commercial and industrial customers continue to utilize
transportation services provided by Northern Indiana. Gas transportation
customers purchase much of their gas directly from producers and marketers and
then pay a transportation fee to have their gas delivered over Northern
Indiana's system. Northern Indiana transported 42.5 million, 95.7 million and
281.2 million dth for others during the three-month, six-month and twelve month
periods ended June 30, 2000, respectively.
The basic steel industry accounted for 42% of natural gas delivered
(including volumes transported) during the twelve months ended June 30, 2000.
The components of the changes in gas operating revenues are shown in the
following table:
<TABLE>
<CAPTION>
June 30, 2000
Compared to
June 30, 1999
---------------------------------
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 $ 16,968 $ 63,541 $ 100,228
Gas transition costs (126) (448) (2,711)
Changes in sales levels 10,225 (25,014) (35,272)
Gas transported (575) 1,303 2,084
Wholesale gas (554) 3,386 17,149
--------- --------- ---------
Total Gas Revenue Change $ 25,938 $ 42,768 $ 81,478
========= ========= =========
</TABLE>
GAS COSTS OF ENERGY. Gas costs increased $86.5 million (25%) to $427.4
million for the twelve months ended June 30, 2000 from the comparable period
ended June 30, 1999, due to increased purchased gas costs per dth, partially
offset by decreased gas transition costs. The average cost for purchased gas for
the period, after adjustment for gas transition costs billed to transport
customers, was $3.09 per dth as compared to $2.28 for the comparable period
ended June 30, 1999.
Gas costs increased $47.8 million (24%) to $246.0 million for the six
months ended June 30, 2000, from the comparable period ended June 30, 1999,
mainly due to increased gas costs per dth. The average cost for purchased gas
for the period, after adjustment for gas transition costs billed to transport
customers, was $3.11 per dth as compared to $2.21 for the comparable period
ended June 30, 1999.
Gas costs increased $24.4 million (41%) to $84.7 million for the three
months ended June 30, 2000, from the comparable period ended June 30, 1999,
mainly due to increased gas costs per dth. The average cost for purchased gas
for the period, after adjustment for gas transition costs billed to transport
customers, was $3.74 per dth as compared to $2.51 for the comparable period
ended June 30, 1999.
GAS OPERATING MARGIN. The gas operating margin for the twelve months ended
June 30, 2000 decreased $5.0 million from the comparable period ended June 30,
1999. This decrease is due to decreased deliveries to residential and commercial
customers reflecting warmer heating season during the period, partially offset
by increased transportation services and increased wholesale gas sales.
Gas operating margin decreased $5.0 million to $147.8 million during the
six months ended June 30, 2000 from the comparable period ended June 30, 1999.
This decrease is due to decreased deliveries to residential and commercial
customers reflecting the warmer heating season during the first quarter of 2000,
partially offset by increased industrial sales and increased transportation
services.
Gas operating margin increased $1.5 million to $45.6 million during the
three months ended June 30, 2000 from the comparable period ended June 30, 1999.
This increase is due to increased industrial sales and increased sales to
residential and commercial customers reflecting the cooler weather during the
second quarter of 2000, partially offset by decreased wholesale sales and
decreased transportation services.
ELECTRIC REVENUES. Electric revenues were $1.1 billion for the twelve
months ended June 30, 2000, a decrease of $5.0 million from the comparable
period ended June 30, 1999. The decrease in electric revenues was mainly due to
decreased sales to residential customers and decreased wholesale transactions,
partially offset by increased sales to commercial and industrial customers.
Electric revenues were $508.5 million for the six months ended June 30,
2000, a decrease of $19.9 million from the comparable period ended June 30,
1999. Sales of electricity in kilowatt-hours (kwh) decreased 6% from the
comparable period ended June 30, 1999. The decrease in electric revenues was
mainly due to decreased sales to residential customers, decreased wholesale
transactions and decreased fuel costs, partially offset by increased sales to
commercial and industrial customers.
Electric revenues were $255.0 million for the three months ended June 30,
2000, a decrease of $13.5 million from the comparable period ended June 30,
1999. Sales of electricity in kwh decreased 6% from the comparable period ended
June 30, 1999. The decrease in electric revenues was mainly due to decreased
sales to residential customers, decreased wholesale transactions and decreased
fuel costs, partially offset by increased sales to commercial and industrial
customers.
The basic steel industry accounted for 33% of electric sales during the
twelve months ended June 30, 2000.
The components of the changes in electric operating revenues are shown in
the following table:
<TABLE>
<CAPTION>
June 30, 2000
Compared to
June 30, 1999
---------------------------------
Three Six Twelve
Months Months Months
========= ========= =========
(Dollars in thousands)
<S> <C> <C> <C>
Electric Revenue Changes-
Pass through of net changes in
fuel costs $ (2,724) $ (5,540) $ 2,716
Changes in sales levels (1,927 8,209 35,539
Wholesale electric (8,852) (22,549) (43,278)
--------- --------- ---------
Total Electric Revenue Change $ (13,503) $ (19,880) $ (5,023)
========= ========= =========
</TABLE>
ELECTRIC COST OF ENERGY. Cost of fuel for electric generation increased
$1.6 million to $247.2 million for the twelve months ended June 30, 2000 from
the comparable period ended June 30, 1999. The increase is primarily due to
increased generation. The average cost per kwh generated decreased 5% from the
comparable period ended June 30, 1999, to 1.42 cents per kwh, for the twelve
months ended June 30, 2000.
Cost of fuel for electric generation decreased $2.0 million to $114.0
million for the six months ended June 30, 2000 from the comparable period ended
June 30, 1999. The decrease is primarily due to decreased fuel costs per kwh
generated. The average cost per kwh generated decreased 7% from the comparable
period ended June 30, 1999, to 1.37 cents per kwh.
Cost of fuel for electric generation decreased $1.2 million to $56.5
million for the three months ended June 30, 2000 from the comparable period
ended June 30, 1999. The decrease is primarily due to decreased fuel costs per
kwh generated. The average cost per kwh generated decreased 7% from the
comparable period ended June 30, 1999, to 1.37 cents per kwh.
POWER PURCHASED. Power purchased decreased $13.3 million to $47.4 million
for the twelve months ended June 30, 2000 from the comparable period ended in
June 30, 1999. The decrease is a result of decreased cost per kwh and decreased
bulk power purchases.
Power purchased decreased $19.5 million to $15.3 million for the six
months ended June 30, 2000 from the comparable period ended June 30, 1999. The
decrease is as a result of decreased cost per kwh and decreased bulk power
purchases.
Power purchased decreased $11.0 million to $7.0 million for the three
months ended June 30, 2000 from the comparable period ended June 30, 1999. The
decrease is as a result of decreased bulk power purchases and decreased cost per
kwh.
ELECTRIC OPERATING MARGIN. Operating margin from electric sales increased
$6.6 million to $793.3 million for the twelve months ended June 30, 2000 from
the comparable period ended June 30, 1999. This increase occurred mainly due to
increased sales to commercial and industrial sales, partially offset by
decreased sales to residential customers and decreased wholesale transactions.
Operating margin from electric sales increased $1.6 million to $379.2
million for the six months ended June 30, 2000 from the comparable period ended
June 30, 1999. This increase is due to increased sales to commercial and
industrial customers, partially offset by decreased sales to residential
customers and decreased wholesale transaction.
Operating margin from electric sales decreased $1.4 million to $191.5
million for the three months ended June 30, 2000 from the comparable period
ended June 30, 1999. The quarter results included a $1.8 million charge to
earnings due to a change in the regulatory mechanism for recovery of purchased
power costs. This decrease is due to decreased sales to residential customers
and decreased wholesale transactions, partially offset by increased sales to
commercial and industrial customers.
OPERATING EXPENSES AND TAXES (EXCEPT INCOME). Operating expenses and taxes
(except income) decreased $7.6 million to $618.0 million for the twelve months
ended June 30, 2000 from the comparable period ended June 30, 1999. Operating
expenses and taxes (except income) decreased $11.7 million to $311.0 million for
the six months ended June 30, 2000 from the comparable period ended June 30,
1999. Operating expenses and taxes (except income) decreased $4.9 million to
$153.0 million for the three months ended June 30, 2000 from the comparable
period ended June 30, 1999.
Operation expenses decreased $9.6 million to $245.2 million for the twelve
months ended June 30, 2000 from the comparable period ended June 30, 1999. The
decrease is due to a $13 million insurance settlement received relating to
manufactured gas plants site cleanup costs, decreased operating costs for
electric production facilities expenses of $2.3 million and other decreased
operating costs, partially offset by increased employee related costs of $9.2
million and increased expenses for distributed generation and fuel cell research
and development of $1.9 million.
Operation expenses decreased $11.3 million to $121.4 million for the six
months ended June 30, 2000 from the comparable period ended June 30, 1999. The
decrease is mainly due to lower employee related costs of $6.2 million and other
decreased operating costs.
Operation expenses decreased $4.8 million to $60.3 million for the three
months ended June 30, 2000 from the comparable period ended June 30, 1999. The
decrease is mainly due to lower employee related costs of $2.2 million and other
decreased operating costs.
Maintenance expenses increased $2.6 million to $68.3 million for the
twelve months ended June 30, 2000 from comparable period ended June 30, 1999 due
to increased maintenance activity for electric production facilities and
electric distribution facilities.
Maintenance expenses increased $2.8 million to $38.5 million for the six
months ended June 30, 2000 from comparable period ended June 30, 1999 due to
increased maintenance activity for electric and gas distribution facilities.
Maintenance expenses increased $3.2 million to $20.7 million for the three
months ended June 30, 2000 from comparable period ended June 30, 1999 due to
increased maintenance activity for electric production facilities and electric
and gas distribution facilities.
Depreciation and amortization expenses increased $4.7 million to $236.2
million, $2.6 million to $118.8 million and $1.5 million to $60.0 million for
the twelve-month, six-month and three month periods ended June 30, 2000,
respectively, from the comparable periods ended June 30, 1999, resulting from
plant additions.
Taxes (except income) decreased $5.3 million to $68.4 million, $5.8
million to $32.3 million and $4.9 million to $12.5 million for the twelve-
month, six-month and three month periods ended June 30, 2000, respectively, from
the comparable periods ended June 30, 1999 mainly as a result of decreased
property tax expense.
Utility income taxes increased $6.9 million to $130.4 million, $3.1
million to $64.2 million and $2.2 million to $23.6 million for the twelve-
month, six-month and three month periods ended June 30, 2000, respectively, from
the comparable periods ended June 30, 1999 mainly as a result of increased
pre-tax income.
Other Income (Deductions) increased $1.2 million to $(0.5) million for the
twelve months ended June 30, 2000 from the comparable period ended June 30,
1999, as a result of increased power trading activities, partially offset by
Northern Indiana deciding to abandon certain business facilities that were not
consistent with its strategic direction. Other Income (Deductions) increased
$1.8 million to $1.8 million for the six months ended June 30, 2000 from the
comparable period ended June 30, 1999, as a result of increased power trading
activities. Other Income (Deductions) for the three months ended June 30, 2000
were relatively unchanged from the comparable period ended June 30, 1999.
Interest charges for the twelve months ended relatively unchanged from the
comparable period ended June 30, 1999. Interest charges increased $1.3 million
to $37.9 million and $0.8 million to $18.8 million for the six-month and three
month periods ended June 30, 2000, respectively, from the comparable period
ended June 30, 1999, due to increased short-term borrowing.
LIQUIDITY AND CAPITAL RESOURCES. Generally, cash flow from operations has
provided sufficient liquidity to meet current operating requirements. Because
the utility and utility construction business is seasonal in nature, commercial
paper is issued for short-term financing. As of June 30, 2000 and December 31,
1999, $127.0 million and $62.6 million of commercial paper was outstanding,
respectively. The weighted average interest rate of commercial paper outstanding
as of June 30, 2000 was 6.67%.
Northern Indiana entered into a five-year $100 million credit agreement
and a 364-day $100 million revolving credit agreement with several banks. These
agreements terminate on September 23, 2003 and September 23, 2000, respectively.
The 364-day agreements may be extended at expiration for additional periods of
364 days. Under these agreements, funds are borrowed at a floating rate of
interest or, under certain circumstances, at a fixed rate of interest for a
short-term periods. These agreements provide financing flexibility and may be
used to support the issuance of commercial paper. As of June 30, 2000, there
were no borrowings outstanding under these agreements.
In addition, Northern Indiana has $11.4 million in lines of credit which
run until May 31, 2000. The credit pricing of each of the lines varies from
either the lending banks' commercial prime or market rates. As of June 30, 2000,
there were no borrowings outstanding 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 $201.5 million of money market lines of credit.
As of June 30, 2000 and December 31, 1999, $107.4 million and $33.7 million,
respectively, were outstanding under these lines of credit.
On January 27, 2000, the Citizens Action Coalition (CAC), a private
consumer organization, filed a petition before the Indiana Utility Regulatory
Commission (IURC). The petition does not seek a specified amount of rate
reduction, but rather alleges that the existing Northern Indiana electric rates
are "unreasonable and unsafe," and seeks to have the IURC force Northern Indiana
to produce detailed financial calculations that would justify its electric
rates. Northern Indiana intends to oppose the petition on both legal and factual
grounds, and believes that its current rates are just and reasonable as required
by statute. On May 17, 2000 the IURC issued an order agreeing with Northern
Indiana that the type of investigation requested by CAC could only be conducted
by the IURC itself. As of August 11, 2000, no further orders have been issued in
this proceeding.
CONSTRUCTION PROGRAM. Future commitments with respect to its
construction program are expected to be met through internally generated
funds.
MARKET RISK SENSITIVE INSTRUMENTS AND POSITIONS -
RISK MANAGEMENT
Risk is an inherent part of Northern Indiana's energy businesses and
activities. The extent to which Northern Indiana properly and effectively
identifies, assesses, monitors and manages each of the various types of risk
involved in its businesses is critical to its profitability. Northern Indiana
seeks to identify, assess, monitor and manage, in accordance with defined
policies and procedures, the following principal risks involved in Northern
Indiana's energy businesses: commodity market risk, interest rate risk and
credit risk. Risk management at Northern Indiana is a multi-faceted process with
independent oversight that requires constant communication, judgment and
knowledge of specialized products and markets. Northern Indiana's senior
management takes an active role in the risk management process and has developed
policies and procedures that require specific administrative and business
functions to assist in the identification, assessment and control of various
risks. In recognition of the increasingly varied and complex nature of the
energy business, Northern Indiana's risk management policies and procedures are
evolving and subject to ongoing review and modification.
Northern Indiana is exposed to risk through various daily business
activities, including specific trading risks and non-trading risks. The non-
trading risks to which Northern Indiana is exposed include interest rate risk
and commodity price risk. The market risk resulting from trading activities
consists primarily of commodity price risk. Northern Indiana's risk management
policy permits the use of certain financial instruments to manage its market
risk, including futures, forwards, options and swaps. Risk management at
Northern Indiana is defined as the process by which the organization ensures
that the risks to which it is exposed are the risks to which it desires to be
exposed to achieve its primary business objectives. Northern Indiana employs
various analytic techniques to measure and monitor its market risks, including
value-at-risk (VaR) and instrument sensitivity to market factors. VaR represents
the potential loss for an instrument or portfolio from adverse changes in market
factors, for a specified time period and at a specified confidence level.
TRADING RISKS
COMMODITY MARKET RISK. Market risk refers to the risk that a change in the
level of one or more market prices, rates, indices, volatilities, correlations
or other market factors, such as liquidity, will result in losses for a
specified position or portfolio. Northern Indiana employs a VaR model to assess
the market risk of its energy trading portfolios. Northern Indiana estimates the
one-day VaR across all trading groups which utilize derivatives using either
Monte Carlo simulation or variance/covariance at a 95 percent confidence level.
Based on the results of the VaR analysis, the daily market risk exposure for
power trading on an average, high, and low basis was $0.7 million, $1.8 million
and $0.004 million for the three-month, and $0.5 million, $1.8 million and
$0.004 million for the six-month and $0.5 million, $1.8 million and $0.004
million for twelve-month periods ended June 30, 2000, respectively. Northern
Indiana implemented a VaR methodology in 1999 to introduce additional market
sophistication and to recognize the developing complexity of its businesses.
NON-TRADING RISKS
COMMODITY MARKET RISK. Currently, commodity price risk resulting from
non-trading activities is relatively limited, since current regulations allow
Northern Indiana to recoup any prudently incurred fuel and gas costs through
rate-making. As the utility industry undergoes deregulation, however, Northern
Indiana will be providing services without the benefit of the traditional
rate-making and, therefore, will be more exposed to commodity price risk.
Additionally, Northern Indiana enters into certain sales contracts with
customers based upon a fixed sales price and varying volumes which are
ultimately dependent upon the customer's supply requirements. Northern Indiana
utilizes derivative financial instruments to reduce the commodity price risk
based on modeling techniques to anticipate these future supply requirements.
INTEREST RATE RISK. Northern Indiana is exposed to interest rate risk as a
result from changes in interest rates on borrowings under the revolving credit
agreements and lines of credit. These instruments have interest rates that are
indexed to short-term market interest rates. At June 30, 2000 and December 31,
1999, the combined borrowings outstanding under these facilities totaled $234.4
million and $96.3 million, respectively. Based upon average borrowings under
these agreements during 2000 and 1999, an increase in short- term interest rates
of 100 basis points (1%) would have increased interest expense by $1.3 million
and $0.5 million for the three months, $1.9 million and $1.2 million for the six
months and $3.6 million and $3.3 million for the twelve months ending June 30,
2000 and 1999, respectively.
Long-term debt is utilized as a primary source of capital. A significant
portion of this long-term debt consists of medium-term notes. In addition,
longer term fixed-price debt instruments have been used that in the past have
been refinanced when interest rates decreased. To the extent that such
refinancing is economical, refinancing these fixed-price instruments will
continue.
CREDIT RISK. Credit risk arises in many of Northern Indiana's business
activities. In sales and trading activities, credit risk arises because of the
possibility that a counterparty will not be able or willing to fulfill its
obligations on a transaction on or before settlement date. In derivative
activities, credit risk arises when counterparties to derivative contracts are
obligated to pay Northern Indiana the positive fair value or receivable
resulting from the execution of contract terms. Exposure to credit risk is
measured in terms of both current and potential exposure. Current credit
exposure is generally measured by the notional or principal value of financial
instruments and direct credit substitutes, such as commitments and standby
letters of credit and guarantees. Current credit exposure includes the positive
fair value of derivative instruments. Because many of Northern Indiana's
exposures vary with changes in market prices, Northern Indiana also estimates
the potential credit exposure over the remaining term of transactions through
statistical analyses of market prices. In determining exposure, Northern Indiana
considers collateral and master netting agreements, which are used to reduce
individual counterparty risk, primarily in connection with derivative products.
Refer to Consolidated Statement of Long-Term Debt for detailed information
related to Northern Indiana's long-term debt outstanding and "Fair Value of
Financial Instruments" in Notes to Consolidated Financial Statements for current
market valuation of long-term debt. Refer to "Summary of Significant Accounting
Policies-Accounting for Price Risk Management Activities" for further discussion
of Northern Indiana's risk management.
Refer to "Financial Instruments and Risk Management," in Notes to
Consolidated Financial Statements for a discussion of the types of commodity-
based derivative financial instruments and risk management.
COMPETITION AND REGULATORY CHANGES -
The regulatory frameworks applicable to Northern Indiana, at both state
and federal levels, are undergoing fundamental changes. These changes have
impacted and will continue to have an impact on Northern Indiana's operations,
structure and profitability. At the same time, competition within the electric
and gas industries will create opportunities to compete for new customers and
revenues. Management has taken steps to become more competitive and profitable
in this changing environment, including converting some of its generating units
to allow use of lower cost, low sulfur coal and providing its gas customers with
increased choice for new products and services throughout the service territory.
THE ELECTRIC INDUSTRY. At the Federal level, the Federal Regulatory
Commission (FERC) issued Order No. 888-A in 1996 which required all public
utilities owning, controlling, or operating transmission lines to file non-
discriminatory open-access tariffs and offer wholesale electricity suppliers and
marketers the same transmission service they provide themselves. On June 30,
2000, the D.C. Circuit Court of Appeals upheld FERC's open access orders in all
major respects. In 1997, FERC approved Northern Indiana's open-access
transmission tariff. On December 20, 1999, FERC issued a final rule addressing
the formation and operation of Regional Transmission Organizations (RTOs). The
rule is intended to eliminate pricing inequities in the provision of wholesale
transmission service. Northern Indiana does not believe that compliance with the
new rules will be material to future earnings. Although wholesale customers
currently represent a small portion of Northern Indiana's electricity sales, it
intends to continue its efforts to retain and add wholesale customers by
offering competitive rates and also intends to expand the customer base for
which it provides transmission services.
At the state level, Northern Indiana announced in 1997 and 1998 that if a
consensus could be reached regarding electric utility restructuring legislation,
Northern Indiana would support a restructuring bill before the Indiana General
Assembly. During 1999, discussions were held with other investor-owned utilities
in Indiana regarding the technical and economic aspects of possible legislation
leading to greater customer choice. A consensus was not reached. Therefore,
Northern Indiana did not support legislation regarding electric restructuring
during the 2000 session of the Indiana General Assembly. During 2000,
discussions will continue with all segments of the Indiana electric industry in
an attempt to reach a consensus on electric restructuring legislation for
introduction during the 2001 session of the Indiana General Assembly.
THE GAS INDUSTRY. At the Federal level, gas industry deregulation began in
the mid-1980's when FERC required interstate pipelines to provide
nondiscriminatory transportation services pursuant to unbundled rates. This
regulatory change permitted large industrial and commercial customers to
purchase their gas supplies either from Northern Indiana or directly from
competing producers and marketers, which would then use Northern Indiana's
facilities to transport the gas. More recently, the focus of deregulation in the
gas industry has shifted to the states.
At the state level, the IURC approved in 1997 Northern Indiana's
Alternative Regulatory Plan (ARP), which implemented new rates and services that
included, among other things, unbundling of services for additional customer
classes (primarily residential and commercial users), negotiated services and
prices, a gas cost incentive mechanism, and a price protection program. The gas
cost incentive mechanism allows Northern Indiana to share any cost savings or
cost increases with its customers based upon a comparison of Northern Indiana's
actual gas supply portfolio cost to a market-based benchmark price. The gas cost
incentive mechanism will be reviewed by parties to the ARP proceeding for
possible revision. Phase I of Northern Indiana's Customer Choice Pilot Program
ended on March 31, 1999. This pilot program offered 82,000 residential customers
within St. Joseph County and 10,000 commercial customers throughout the Northern
Indiana service area the right to choose alternative gas suppliers. Phase II of
Northern Indiana's Customer Choice Pilot Program commenced on April 1, 1999 and
will continue for a one-year period. During this phase, Northern Indiana is
offering customer choice to all 660,000 residential and 50,000 commercial
customers throughout its gas service territory. A limit of 150,000 residential
and 20,000 commercial customers are eligible to enroll in Phase II of the
program. The IURC order allows a specific NiSource natural gas marketing
subsidiary to participate as a supplier of choice to Northern Indiana customers.
In addition, as Northern Indiana has allowed residential and commercial
customers to designate alternative gas suppliers, it has also offered new
services to all classes of customers including, price protection, negotiated
sales and services, gas lending and parking, and new storage services.
To date, Northern Indiana has not been materially affected by competition,
and management does not foresee substantial adverse effects in the near future
unless the current regulatory structure is substantially altered. Northern
Indiana believes the steps that it has taken to deal with increased competition
have had and will continue to have significant positive effects in the next few
years.
IMPACT OF ACCOUNTING STANDARDS. Refer to "Summary of Significant
Accounting Policies-Impact of Accounting Standards" in the Notes to Consolidated
Financial Statements for information regarding impact of accounting standards
not yet adopted.
FORWARD LOOKING STATEMENTS. This report contains forward looking
statements within the meaning of the securities laws. Forward looking statements
include terms such as "may," "will," "expect," "believe," "plan" and other
similar terms. Northern Indiana cautions that, while it believes such statements
to be based on reasonable assumptions and makes such statements in good faith,
you cannot be assured that the actual results will not differ materially from
such assumptions or that the expectations set forth in the forward looking
statements derived from such assumptions will be realized. You should be aware
of important factors that could have a material impact on future results. These
factors include, weather, the federal and state regulatory environment, the
economic climate, regional, commercial, industrial and residential growth in the
service territories served by Northern Indiana, customers' usage patterns and
preferences, the speed and degree to which competition enters the utility
industry, the timing and extent of changes in commodity prices, changing
conditions in the capital and equity markets and other uncertainties, all of
which are difficult to predict, and many of which are beyond Northern Indian's
control.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For a discussion of primary market risks and risk management policy, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations-Market Risk Sensitive Instruments and Positions."
<PAGE>
PART II.
OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS.
Northern Indiana is a party to various pending proceedings, including
suits and claims against it for personal injury, death and property damage. Such
proceedings and suits, and the amounts involved, are routine for the kind of
business conducted by Northern Indiana, except as described under Note 4
"Environmental Matters," in the Notes to Consolidated Financial Statements under
Part I, Item 1 of this Report on Form 10-Q, which note is incorporated by
reference. No other material legal proceedings against Northern Indiana or its
subsidiaries are pending or, to the knowledge of Northern Indiana, contemplated
by governmental authorities and other parties.
Item 2. CHANGES IN SECURITIES.
None
Item 3. DEFAULTS UPON SENIOR SECURITIES.
None
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
On June 1, 2000, by written consent in leu of the Annual Meeting of
Shareholders, the sole shareholder of Northern Indiana elected Arthur J. Decio
Gary L. Neale and Robert J. Welsh to serve as directors until the 2003 Annual
Meeting of Shareholders. Directors whose terms of office continue after the 2000
Annual Meeting of Shareholders are Ian M. Rolland and John W. Thompson whose
terms expire at the 2002 Annual Meeting of Shareholders, and Steven C. Beering
and Carolyn Y. Woo, whose terms expire at the 2001 Annual Meeting of
Shareholders.
Item 5. OTHER INFORMATION.
None
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
Exhibit 23 - Consent of Arthur Andersen LLP
Exhibit 27 - Financial Data Schedule
(b) Reports on Form 8-K.
None
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
Northern Indiana Public Service Company
(Registrant)
/s/ David J. Vajda
----------------------------------------------------
David J. Vajda,
Vice President, Finance and Chief Accounting Officer
Date August 11, 2000
