<PAGE>
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
Commission file number 1-9779
NISOURCE INC.
(Exact name of registrant as specified in its charter)
Indiana 35-1719974
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
801 East 86th Avenue, Merrillville, Indiana 46410
(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, 121,204,429 common shares were outstanding.
<PAGE>
NISOURCE INC.
PART I.
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors of
NiSource Inc.:
We have audited the accompanying consolidated balance sheet and consolidated
statement of capitalization of NiSource Inc. (an Indiana corporation) and
subsidiaries as of June 30, 2000 and December 31, 1999, and the related
consolidated statements of income, common shareholders' equity 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 NiSource'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 NiSource
Inc. 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.
Arthur Andersen LLP
Chicago, Illinois
August 9, 2000
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
June 30, December 31,
(Dollars in thousands) 2000 1999
ASSETS ============= =============
PROPERTY, PLANT AND EQUIPMENT:
Utility Plant, (including Construction Work in
Progress of $273,314 and $283,530, respectively)
<S> <C> <C>
Electric $ 4,281,479 $ 4,237,427
Gas 2,891,424 2,871,824
Water 775,345 750,376
Common 386,765 381,486
------------- -------------
8,335,013 8,241,113
Less -Accumulated depreciation and amortization 3,561,806 3,444,311
------------- -------------
Net Utility Plant 4,773,207 4,796,802
------------- -------------
Other property, at cost, less accumulated provision for
depreciation of $66,687 and $52,016, respectively 445,257 427,190
------------- -------------
Total Property, Plant and Equipment 5,218,464 5,223,992
------------- -------------
INVESTMENTS:
Investments, at equity 105,665 118,259
Investments, at cost 57,484 55,851
Other investments 33,243 32,839
------------- -------------
Total Investments 196,392 206,949
------------- -------------
CURRENT ASSETS:
Cash and cash equivalents 50,905 43,533
Accounts receivable, less reserve of $25,523 and
$56,414, respectively 427,649 390,990
Other receivables 51,801 6,572
Fuel adjustment clause -- 4,201
Gas cost adjustment clause 42,085 92,498
Materials and supplies, at average cost 65,660 64,530
Electric production fuel, at average cost 36,489 31,968
Natural gas in storage 91,317 63,750
Price risk management assets 301,151 90,705
Prepayments and other 46,024 41,884
------------- -------------
Total Current Assets 1,113,081 830,631
------------- -------------
OTHER ASSETS:
Regulatory assets 208,484 208,634
Intangible assets, net of accumulated amortization 134,186 139,337
Prepayments and other 323,068 289,061
------------- -------------
Total Other Assets 665,738 637,032
------------- -------------
$ 7,193,675 $ 6,898,604
============= =============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
June 30, December 31,
(Dollars in thousands) 2000 1999
CAPITALIZATION AND LIABILITIES ============= =============
CAPITALIZATION:
Common shareholders' equity
<S> <C> <C>
(See accompanying statement) $ 1,330,559 $ 1,353,504
Preferred stocks-
Northern Indiana Public Service Company:
Series without mandatory redemption provisions 81,114 81,114
Series with mandatory redemption provisions 52,480 54,030
Indianapolis Water Company:
Series without mandatory redemption provisions 2,517 4,497
Company-obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely Company debentures 345,000 345,000
Long-term debt, excluding amounts due within one year 1,915,820 1,975,184
------------- -------------
Total Capitalization 3,727,490 3,813,329
------------- -------------
CURRENT LIABILITIES:
Current portion of long-term debt 74,568 173,721
Short-term borrowings 870,109 679,321
Accounts payable 349,860 277,358
Dividends declared on common and preferred stocks 33,640 34,535
Customer deposits 30,071 28,736
Taxes accrued 16,717 42,853
Interest accrued 34,038 34,157
Fuel adjustment clause 4,236 --
Accrued employment costs 56,399 60,647
Price risk management liabilities 323,544 113,029
Other 99,155 90,245
------------- --------------
Total Current Liabilities 1,892,337 1,534,602
------------- --------------
OTHER:
Deferred income taxes 982,921 998,682
Deferred investment tax credits, being amortized over
life of related property 91,127 94,946
Deferred credits 121,214 94,058
Customer advances and contributions in aid of construction 150,842 140,562
Accrued liability for postretirement benefits 165,168 157,517
Other noncurrent liabilities 62,576 64,908
------------- -------------
Total Other 1,573,848 1,550,673
------------- -------------
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
$ 7,193,675 $ 6,898,604
============= =============
The accompanying notes to consolidated financial statements are an integral part of this statement.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in thousands, except for per share amounts)
Three Months Six Months
Ended June 30, Ended June 30,
------------------------ ------------------------
2000 1999 2000 1999
=========== =========== =========== ===========
Operating Revenues:
<S> <C> <C> <C> <C>
Gas $ 562,534 $ 308,636 $ 1,289,356 $ 862,532
Electric 259,177 271,307 514,755 535,749
Water 24,983 24,031 47,896 44,900
Products and Services 76,277 71,373 138,513 123,741
----------- ----------- ----------- -----------
922,971 675,347 1,990,520 1,566,922
----------- ----------- ----------- -----------
Cost of Sales:
Gas costs 466,201 225,137 985,106 604,727
Fuel for electric generation 56,471 57,630 113,970 115,928
Power purchased 7,029 17,423 15,263 39,473
Products and Services 44,537 37,022 79,340 62,611
----------- ----------- ----------- -----------
574,238 337,212 1,193,679 822,739
----------- ----------- ----------- -----------
Operating Margin 348,733 338,135 796,841 744,183
----------- ----------- ----------- -----------
Operating Expenses and Taxes (except income):
Operation 129,047 128,427 263,098 255,450
Maintenance 25,171 21,913 47,614 44,222
Depreciation and amortization 84,590 77,593 169,069 150,448
Taxes (except income) 20,578 25,225 48,805 53,234
----------- ----------- ----------- -----------
259,386 253,158 528,586 503,354
----------- ----------- ----------- -----------
Operating Income 89,347 84,977 268,255 240,829
----------- ----------- ----------- -----------
Other Income (Deductions):
Interest expense, net (48,533) (40,314) (96,143) (77,002)
Minority interests (5,000) (5,668) (10,041) (8,376)
Dividend requirements on preferred stock
of subsidiaries (2,008) (2,077) (4,042) (4,193)
Other, net 2,510 (2,318) 5,787 4,823
----------- ----------- ----------- -----------
(53,031) (50,377) (104,439) (84,748)
----------- ----------- ----------- -----------
Income Before Income Taxes 36,316 34,600 163,816 156,081
----------- ----------- ----------- -----------
Income Taxes 12,903 11,656 60,787 56,578
----------- ----------- ----------- -----------
Net Income $ 23,413 $ 22,944 $ 103,029 $ 99,503
=========== =========== =========== ===========
Average common shares outstanding - basic 120,569,530 124,951,321 122,203,747 123,804,922
Basic earnings per average common share $ 0.19 $ 0.18 $ 0.84 $ 0.80
=========== =========== =========== ===========
Diluted earnings per average common share $ 0.18 $ 0.18 $ 0.81 $ 0.80
=========== =========== =========== ===========
Dividends declared per common share $ 0.270 $ 0.255 $ 0.540 $ 0.510
=========== =========== =========== ===========
The accompanying notes to consolidated financial statements are an integral part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF INCOME
Twelve Months
Ended June 30,
---------------------------------
(Dollars in thousands, except for per share amounts) 2000 1999
============= =============
Operating Revenues:
<S> <C> <C>
Gas $ 2,080,274 $ 1,440,044
Electric 1,100,044 1,294,502
Water 101,379 90,313
Products and Services 286,477 243,089
------------- -------------
3,568,174 3,067,948
------------- -------------
Cost of Sales:
Gas costs 1,567,837 1,052,847
Fuel for electric generation 247,206 245,560
Power purchased 47,535 265,751
Products and Services 159,413 120,985
------------- -------------
2,021,991 1,685,143
------------- -------------
Operating Margin 1,546,183 1,382,805
------------- -------------
Operating Expenses and Taxes (except income):
Operation 542,456 460,825
Maintenance 85,600 78,894
Depreciation and amortization 330,025 280,005
Taxes (except income) 99,140 96,903
------------- -------------
1,057,221 916,627
------------- -------------
Operating Income 488,962 466,178
------------- -------------
Other Income (Deductions):
Interest expense, net (185,758) (144,361)
Minority interests (19,358) (9,439)
Dividend requirements on preferred stock
of subsidiaries (8,183) (8,436)
Other, net (17,066) 8,953
------------- -------------
(230,365) (153,283)
------------- -------------
Income Before Income Taxes 258,597 312,895
------------- -------------
Income Taxes 94,657 109,673
------------- -------------
Net Income $ 163,940 $ 203,222
============= =============
Average common shares outstanding - basic 123,545,434 121,166,275
Basic earnings per average common share $ 1.32 $ 1.67
============= =============
Diluted earnings per average common share $ 1.29 $ 1.66
============= =============
Dividends declared per common share $ 1.065 $ 1.005
============= =============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NISOURCE INC.
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
-----------------------------------------------------
Accumulated
Additional Other
Common Treasury Paid-In Retained Comprehensive Comprehensive
Three Months Ended Shares Shares Capital Earnings Other Income Total Income
------------------ ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, April 1, 1999 $ 870,930 $ (459,568) $ 171,586 $ 788,551 $ (1,474) $ 1,590 $1,371,615
Comprehensive Income:
Net income 22,944 22,944 $ 22,944
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $874) 1,431 1,431 1,431
Realized (net of income
tax of $83) 136 136 136
Gain/loss on foreign
currency translation:
Unrealized 166 166 166
Realized - - -
----------
Total Comprehensive Income $ 24,677
==========
Dividends:
Common shares (31,626) (31,626)
Treasury shares acquired (983) (983)
Issued:
Employee stock purchase plan 112 267 379
Long-term incentive plan 2,092 38 (150) 1,980
Bay State Gas Acquisition (15) (34) (49)
COLCOM Acquisition 2,722 939 3,661
Amortization of unearned
compensation 648 648
Equity contract costs (408) (408)
Other (767) (767)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 1999 $ 870,930 $ (455,640) $ 172,388 $ 779,102 $ (976) $ 3,323 $1,369,127
========== ========== ========== ========== ========== ========== ==========
Balance, April 1, 2000 $ 870,930 $(491,286) $ 174,349 $ 819,589 $ (11,625) $ 5,304 $1,367,261
Comprehensive Income:
Net income 23,413 23,413 $ 23,413
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $3) (4) (4) (4)
Realized (net of income
tax of $191) 312 312 312
Gain/loss on foreign
currency translation:
Unrealized 9 9 9
Realized - - -
----------
Total Comprehensive Income $ 23,730
==========
Dividends:
Common shares (32,260) (32,260)
Treasury shares acquired (31,350) (31,350)
Issued:
Employee stock purchase plan 165 185 350
Long-term incentive plan 3,854 3,854
Amortization of unearned
compensation 1,112 1,112
Equity contract costs (939) (939)
Other (1,199) (1,199)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 2000 $ 870,930 $ (518,617) $ 173,595 $ 809,543 $ (10,513) $ 5,621 $1,330,559
========== ========== ========== ========== ========== ========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Three Months Ended Shares Shares
------------------ ---------- ----------
<S> <C> <C>
Balance April 1, 1999 147,784 (22,985)
Treasury shares acquired (36)
Issued:
Employee stock purchase plan 14
Long-term incentive plan 104
Bay State Gas Acquisition (1)
COLCOM Acquisition 134
---------- ----------
Balance June 30, 1999 147,784 (22,770)
========== ==========
Balance April 1, 2000 147,784 (24,978)
Treasury shares acquired (1,839)
Issued:
Employee stock purchase plan 21
Long-term incentive plan 195
---------- ----------
Balance June 30, 2000 147,784 (26,601)
========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NISOURCE INC.
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
-----------------------------------------------------
Accumulated
Additional Other
Common Treasury Paid-In Retained Comprehensive Comprehensive
Six Months Ended Shares Shares Capital Earnings Other Income Total Income
---------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, January 1, 1999 $ 870,930 $ (559,027) $ 94,181 $ 744,309 $ (1,815) $ 1,130 $1,149,708
Comprehensive Income:
Net income 99,503 99,503 $ 99,503
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $1,007) 1,648 1,648 1,648
Realized (net of income
tax of $161) 263 263 263
Gain/loss on foreign
currency translation:
Unrealized 282 282 282
Realized - - -
----------
Total Comprehensive Income $ 101,696
==========
Dividends:
Common shares (63,733) (63,733)
Treasury shares acquired (108,641) (108,641)
Issued:
Employee stock purchase plan 227 593 820
Long-term incentive plan 3,198 159 (532) 2,825
Bay State Gas Acquisition 205,881 109,753 315,634
COLCOM Acquisition 2,722 939 3,661
Amortization of unearned
compensation 1,371 1,371
Equity contract costs (33,237) (33,237)
Other (977) (977)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 1999 $ 870,930 $ (455,640) $ 172,388 $ 779,102 $ (976) $ 3,323 $1,369,127
========== ========== ========== ========== ========== ========== ==========
Balance, January 1, 2000 $ 870,930 $ (472,553) $ 174,405 $ 774,425 $ 1,111 $ 5,186 $1,353,504
Comprehensive Income:
Net income 103,029 103,029 $103,029
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $571) (268) (268) (268)
Realized (net of income
tax of $191) 312 312 312
Gain/loss on foreign
currency translation:
Unrealized 391 391 391
Realized - - -
----------
Total Comprehensive Income $ 103,464
==========
Dividends:
Common shares (65,565) (65,565)
Treasury shares acquired (65,792) (65,792)
Issued:
Employee stock purchase plan 338 402 740
Long-term incentive plan 19,390 (14,061) 5,329
Amortization of unearned
compensation 2,437 2,437
Equity contract costs (2,019) (2,019)
Other 807 (2,346) (1,539)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 2000 $ 870,930 $ (518,617) $ 173,595 $ 809,543 $ (10,513) $ 5,621 $1,330,559
========== ========== ========== ========== ========== ========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Six Months Ended Shares Shares
---------------- ---------- ----------
<S> <C> <C>
Balance January 1, 1999 147,784 (30,254)
Treasury shares acquired (3,883)
Issued:
Employee stock purchase plan 29
Long-term incentive plan 162
Bay State Gas Acquisition 11,042
COLCOM Acquisition 134
---------- ----------
Balance June 30, 1999 147,784 (22,770)
========== ==========
Balance January 1, 2000 147,784 (23,645)
Treasury shares acquired (3,964)
Issued:
Employee stock purchase plan 43
Long-term incentive plan 965
---------- ----------
Balance June 30, 2000 147,784 (26,601)
========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NISOURCE INC.
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
-----------------------------------------------------
Accumulated
Additional Other
Common Treasury Paid-In Retained Comprehensive Comprehensive
Twelve Months Ended Shares Shares Capital Earnings Other Income Total Income
------------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, July 1, 1998 $ 870,930 $ (456,018) $ 90,704 $ 698,633 $ (2,962) $ 2,602 $1,203,889
Comprehensive Income:
Net income 203,222 203,222 $ 203,222
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $1,118) 1,829 1,829 1,829
Realized (net of income
tax of $559) (917) (917) (917)
Gain/loss on foreign
currency translation:
Unrealized (191) (191) (191)
Realized - - -
----------
Total Comprehensive Income $ 203,943
==========
Dividends:
Common shares (121,692) (121,692)
Treasury shares acquired (214,635) (214,635)
Issued:
Employee stock purchase plan 417 1,125 1,542
Long-term incentive plan 5,993 159 (486) 5,666
Bay State Gas Acquisition 205,881 109,753 315,634
COLCOM Acquisition 2,722 939 3,661
Amortization of unearned
compensation 2,472 2,472
Equity contract costs (33,237) (33,237)
Other 2,945 (1,061) 1,884
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 1999 $ 870,930 $ (455,640) $ 172,388 $ 779,102 $ (976) $ 3,323 $1,369,127
========== ========== ========== ========== ========== ========== ==========
Balance, July 1, 1999 $ 870,930 $ (455,640) $ 172,388 $ 779,102 $ (976) $ 3,323 $1,369,127
Comprehensive Income:
Net income 163,940 163,940 $163,940
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $514) (175) (175) (175)
Realized (net of income
tax of $475) 777 777 777
Gain/loss on foreign
currency translation:
Unrealized 754 754 754
Realized 942 942 942
----------
Total Comprehensive Income $ 166,238
==========
Dividends:
Common shares (130,976) (130,976)
Treasury shares acquired (83,606) (83,606)
Issued:
Employee stock purchase plan 584 893 1,477
Long-term incentive plan 20,045 29 (14,100) 5,974
Amortization of unearned
compensation 4,563 4,563
Equity contract costs (2,783) (2,783)
Other 3,068 (2,523) 545
---------- ---------- ---------- ---------- ---------- ---------- ----------
Balance, June 30, 2000 $ 870,930 $ (518,617) $ 173,595 $ 809,543 $ (10,513) $ 5,621 $1,330,559
========== ========== ========== ========== ========== ========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Twelve Months Ended Shares Shares
------------------- ---------- ----------
<S> <C> <C>
Balance July 1, 1998 147,784 (26,750)
Treasury shares acquired (7,565)
Issued:
Employee stock purchase plan 52
Long-term incentive plan 317
Bay State Gas Acquisition 11,042
COLCOM Acquisition 134
---------- ----------
Balance June 30, 1999 147,784 (22,770)
========== ==========
Balance July 1, 1999 147,784 (22,770)
Treasury shares acquired (4,902)
Issued:
Employee stock purchase plan 74
Long-term incentive plan 997
---------- ----------
Balance June 30, 2000 147,784 (26,601)
========== ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Six Months
Ended June 30, Ended June 30,
------------------------ ------------------------
(Dollars in thousands) 2000 1999 2000 1999
=========== =========== =========== ===========
Cash flows from operating activities:
<S> <C> <C> <C> <C>
Net income $ 23,413 $ 22,944 $ 103,029 $ 99,503
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 84,590 77,539 169,069 150,448
Net changes in price risk
management activities (7,902) (2,593) (11,041) (2,746)
Deferred federal and state
income taxes, net (9,970) (3,822) (33,354) (30,750)
Deferred investment tax credits, net (1,910) (1,920) (3,819) (3,807)
Other, net 4,788 6,005 11,119 (279)
Change in certain assets and liabilities -*
Accounts receivable, net 6,787 148,423 (54,129) 129,445
Other receivables (24,873) (615) (30,398) (4,922)
Natural gas in storage (47,611) (21,261) (27,567) 30,297
Accounts payable 78,440 (86,359) 76,737 (142,277)
Taxes accrued (89,850) (96,598) 805 (2,459)
Gas cost adjustment clause (4,370) (1,900) 44,817 72,447
Accrued employment costs 2,063 4,189 (4,248) (16,439)
Other accruals 11,448 (3,725) 7,589 27,725
Other, net (29,969) (16,356) (18,096) 4,984
----------- ----------- ----------- -----------
Net cash provided by
operating activities (4,926) 23,951 230,513 311,170
----------- ----------- ----------- -----------
Cash flows provided by (used in)
investing activities:
Utility construction expenditures (73,756) (77,977) (125,236) (136,092)
Acquisition of businesses,
net of cash acquired (50) (153,765) (50) (716,031)
Proceeds from disposition of assets 42 2,144 15,632 27,560
Other, net (8,437) (26,355) (16,110) (42,618)
----------- ----------- ----------- -----------
Net cash used in investing activities (82,201) (255,953) (125,764) (867,181)
----------- ----------- ----------- -----------
Cash flows provided by (used in)
financing activities:
Issuance of long-term debt -- 179,516 -- 257,771
Retirement of long-term debt (149,087) (178,354) (158,731) (183,072)
Change in short-term debt 269,014 244,020 190,788 (16,350)
Retirement of preferred shares (300) (1,251) (3,530) (1,251)
Proceeds from Corporate Premium
Income Equity Securities, net -- -- -- 334,650
Issuance of common shares 4,204 6,121 5,679 323,472
Acquisition of treasury shares (31,350) (983) (65,792) (108,641)
Cash dividends paid on common shares (32,699) (31,846) (66,004) (61,826)
Other, net 99 113 213 226
----------- ----------- ----------- -----------
Net cash provided by (used in)
financing activities 59,881 217,336 (97,377) 544,979
----------- ----------- ----------- -----------
Net increase (decrease) in cash and
cash equivalents (27,246) (14,666) 7,372 (11,032)
Cash and cash equivalents at
beginning of the period 78,151 64,482 43,533 60,848
----------- ----------- ----------- -----------
Cash and cash equivalents at
end of the period $ 50,905 $ 49,816 $ 50,905 $ 49,816
=========== =========== =========== ===========
*Net of effect from acquisitions of businesses.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENTS OF CASH FLOWS
Twelve Months
Ended June 30,
---------------------------------
(Dollars in thousands) 2000 1999
============= =============
Cash flows from operating activities:
<S> <C> <C>
Net income $ 163,940 $ 203,222
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 330,025 280,005
Net changes in price risk
management activities (11,938) (2,746)
Deferred federal and state
income taxes, net (10,495) (10,041)
Deferred investment tax credits, net (7,703) (7,526)
Other, net 37,513 1,725
Change in certain assets and liabilities -*
Accounts receivable, net (131,066) 100,278
Other receivables (16,906) (3,537)
Natural gas in storage (10,959) (1,767)
Accounts payable 105,480 (104,862)
Taxes accrued (450) (24,769)
Gas cost adjustment clause (48,290) 53,534
Accrued employment costs 12,443 (5,172)
Other accruals 16,404 27,410
Other, net (55,625) (16,840)
------------- -------------
Net cash provided by
operating activities 372,373 488,914
------------- -------------
Cash flows provided by (used in)
investing activities:
Utility construction expenditures (330,407) (262,116)
Acquisition of businesses,
net of cash acquired (21,888) (716,031)
Proceeds from disposition of assets 17,847 29,729
Other, net (34,572) (51,589)
------------- -------------
Net cash used in investing activities (369,020) (1,000,007)
------------- -------------
Cash flows provided by (used in)
financing activities:
Issuance of long-term debt 11,765 298,776
Retirement of long-term debt (179,616) (241,130)
Change in short-term debt 376,116 140,435
Retirement of preferred shares (4,686) (2,408)
Proceeds from Corporate Premium
Income Equity Securities, net -- 334,650
Issuance of common shares 7,100 326,989
Acquisition of treasury shares (83,606) (214,635)
Cash dividends paid on common shares (129,777) (118,903)
Other, net 440 451
------------- -------------
Net cash provided by (used in)
financing activities (2,264) 524,225
------------- -------------
Net increase (decrease) in cash and
cash equivalents 1,089 13,132
Cash and cash equivalents at
beginning of the period 49,816 36,684
------------- -------------
Cash and cash equivalents at
end of the period $ 50,905 $ 49,816
============= =============
*Net of effect from acquisitions of businesses.
The accompanying notes to consolidated financial statements are an integral part of these statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) HOLDING COMPANY STRUCTURE: NiSource Inc. (NiSource), formerly NIPSCO
Industries, Inc., is an energy and utility-based holding company headquartered
in Merrillville, Indiana, that provides natural gas, electricity, water and
related services to the public for residential, commercial and industrial uses
through a number of regulated and non-regulated subsidiaries. NiSource was
organized as an Indiana holding company in 1987 under the name "NIPSCO
Industries, Inc.," and changed its name to NiSource Inc. on April 14, 1999, to
reflect its new direction as a multi-state supplier of energy and related
services.
NiSource's gas business is comprised primarily of regulated gas
utilities and gas transmission companies that operate throughout northern
Indiana and New England. In addition, NiSource expanded its gas marketing,
trading and storage operations with the April 1999 acquisition of TPC
Corporation, now renamed EnergyUSA-TPC Corp. (TPC) and its 1999 acquisition of
Market Hub Partners, L.P. (MHP). NiSource's electric business is comprised of a
regulated electric utility that operates in northern Indiana. The electric
business also includes wholesale sales and power trading activities. NiSource's
regulated gas and electric subsidiaries are collectively referred to as the
"Energy Utilities." NiSource's regulated water subsidiaries are collectively
called the "Water Utilities." Collectively, the Energy and Water Utilities are
referred to as the "Utilities."
The Utilities are subject to regulation with respect to rates,
accounting and certain other matters by the Indiana Utility Regulatory
Commission (IURC), the Massachusetts Department of Telecommunications and Energy
(MDTE), the New Hampshire Public Utilities Commission (NHPUC), the Maine Public
Utilities Commission (MEPUC) and the Federal Energy Regulatory Commission
(FERC), collectively called the "Commissions." MHP is subject to regulation by
the Texas Railroad Commission and FERC.
Non-regulated energy and utility-related products and services are
provided through the "Products and Services" subsidiaries. Products and Services
subsidiaries perform energy-related services and offer products in connection
with these services, which include pipeline construction, repair and maintenance
of underground gas and water pipelines, locating and marking utility lines, real
estate development activity and development and operation of "inside the fence"
cogeneration plants.
In addition to the Utilities and the Products and Services
subsidiaries, NiSource has a wholly-owned subsidiary, NiSource Capital Markets,
Inc. (Capital Markets), which engages in financing activities for NiSource and
certain of its subsidiaries, excluding Northern Indiana Public Service Company
(Northern Indiana).
On February 28, 2000, NiSource and Columbia Energy Group (CEG) entered
into a merger agreement pursuant to which NiSource agreed to acquire CEG for
approximately $6 billion, plus the assumption of approximately $2.5 billion of
CEG debt. The merger will be accomplished through the creation of a new holding
company. Each NiSource common share will be exchanged for one common share of
the new holding company. Each CEG share will be exchanged for $70.00 in cash
plus $2.60 principal amount of a unit issued by the new holding company
(consisting of a zero coupon debt security coupled with a forward equity
contract) or, at the election of the CEG shareholder, $74.00 in new holding
company stock, based on the average NiSource share price prior to the closing,
but not more than 4.4848 shares of new holding company stock, for each CEG
share. Stock elections will be subject to proration if they are made with
respect to more than 30% of CEG's outstanding shares. No exchange of shares will
occur unless at least 10% of CEG's outstanding shares elect to exchange for
shares of the new holding company. The merger is conditioned upon the receipt of
a number of approvals. Approval of the NiSource and CEG shareholders was
obtained on June 1 and June 2, respectively. As of July 26, 2000, all actions
needed from state utility regulatory commissions and from FERC had been
received. The Securities and Exchange Commission must still approve the merger
under the Public Utility Holding Company Act.
NiSource has accepted a commitment letter under which certain financial
institutions agreed, under specified conditions, to provide up to $6.0 billion
to finance the acquisition of CEG. The commitment letter contemplates a
revolving credit facility expiring in July 2001, with the right to convert loans
outstanding at that time into term loans maturing 364 days thereafter. NiSource
has hedged the interest rate risk associated with $1.1 billion of its
anticipated refinancing of such debt.
CEG, based in Herndon, Va., is one of the nation's leading energy
services companies, with assets of approximately $7 billion. Its operating
companies engage in virtually all phases of the natural gas business, including
exploration and production, transmission, storage and distribution, as well as
propane and petroleum product sales, electric power generation and retail energy
marketing. CEG sells natural gas to about 2 million customers in Kentucky,
Maryland, Ohio, Pennsylvania and Virginia. It owns 16,500 miles of interstate
gas pipelines that run from Louisiana to the Northeast.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION. The consolidated financial statements include the
accounts of NiSource and its majority-owned subsidiaries after the elimination
of significant intercompany accounts and transactions. Investments for which at
least a 20% interest is owned and certain joint ventures are accounted for under
the equity method. Investments with less than a 20% interest are accounted for
under the cost method. Certain reclassifications were made to conform the prior
years' financial statements to the current presentation.
On February 12, 1999, NiSource acquired Bay State Gas Company (BSG) and
its subsidiaries. Accordingly, the consolidated financial statements and
disclosures include operating results from BSG from the date of acquisition.
On April 1, 1999, NiSource acquired the stock of TPC. As a result of
the TPC acquisition, NiSource indirectly owned a 77.3% equity interest in MHP,
which is a leading developer, owner and operator of high deliverability salt
cavern natural gas storage capacity. In the fourth quarter of 1999 NiSource
acquired the remaining interests in MHP. The consolidated financial statements
and disclosures include operating results of TPC from April 1, 1999 and the
consolidated results of MHP from December 1999.
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. Except as discussed below, revenues are recorded as products
and services are delivered. However, utility revenues are billed to customers
monthly on a cycle basis. Effective January 1, 1999, revenues relating to energy
trading operations are recorded based upon changes in the fair values, net of
reserves, of the related energy trading contracts. Construction revenues are
recognized on the percentage of completion method whereby revenues are
recognized in proportion to costs incurred over the life of each project.
Provisions for losses on construction contracts, if any, are recorded in the
period in which such losses become probable.
DEPRECIATION AND MAINTENANCE. The Utilities provide depreciation on a
straight-line method over the remaining service lives of the electric, gas,
water and common properties.
<TABLE>
<CAPTION>
The approximate weighted average remaining lives for major components of
electric, gas, and water utility plant are as follows:
Electric:
=========
<S> <C>
Electric generation plant 24 years
Transmission plant 26 years
Distribution plant 25 years
Other electric plant 24 years
Gas:
====
Gas storage plant 15 years
Transmission plant 18 years
Distribution plant 34 years
Other gas plant 16 years
Water:
======
Water source and treatment plant 34 years
Distribution plant 68 years
Other water plant 13 years
</TABLE>
The depreciation provisions for utility plant, as a percentage of the original
cost, for the three month, six month and twelve month periods ended June 30,
2000 and 1999 were 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
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Electric 3.7% 3.7% 3.7% 3.7% 3.7% 3.7%
Gas 4.5% 4.3% 4.4% 4.5% 4.5% 4.6%
Water 2.3% 2.2% 2.2% 2.1% 2.4% 2.2%
</TABLE>
The Utilities follow 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.
PLANT ACQUISITION ADJUSTMENTS. Net utility plant includes amounts allocated to
utility plant in excess of the original cost as part of the purchase price
allocation associated with the acquisition of utility businesses, net of
accumulated amortization. Net plant acquisition adjustments were $712.2 million
and $722.8 million at June 30, 2000 and December 31, 1999, respectively, and are
being amortized over forty-year periods from the respective dates of
acquisition.
INTANGIBLE ASSETS. The excess of cost over the fair value of the net assets of
non-utility businesses acquired is recorded as goodwill. Goodwill of $139.4
million and $125.7 million at June 30, 2000 and December 31, 1999, respectively,
is being amortized over a weighted average period of 27 years. Other intangible
assets, approximating $12.1 million and $12.8 million at June 30, 2000 and
December 31, 1999, respectively, are being amortized over periods of four to
eight years. The recoverability of intangible assets is assessed on a periodic
basis to confirm that expected future cash flows will be sufficient to support
the recorded intangible assets. Accumulated amortization of intangible assets at
June 30, 2000 and December 31, 1999, was approximately $17.1 million and $9.9
million, respectively.
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.
CUSTOMER ADVANCES AND CONTRIBUTIONS IN AID OF CONSTRUCTION. Certain developers
install and provide for the installation of water main extensions, which will be
transferred to the Water Utilities upon completion. The cost of the main
extensions and the amount of any funds advanced for the cost of water mains
installed are included in customer advances for construction and are generally
refundable to the customer over a period of ten years. Advances not refunded
within ten years are permanently transferred to contributions in aid of
construction.
COMPREHENSIVE INCOME. Comprehensive income is reported in the Consolidated
Statements of Common Shareholders' Equity. The components of accumulated other
comprehensive income include unrealized gains (losses), net of income taxes, on
available for sale securities (securities) and on foreign currency translation
adjustments (foreign currency).
<TABLE>
<CAPTION>
The accumulated amounts for these components are as follows:
(Dollars in millions)
July 1, January 1, April 1, June 30, January 1, April 1, June 30,
1998 1999 1999 1999 2000 2000 2000
------------ ------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Securities $ 4.7 $ 3.6 $ 4.0 $ 5.6 $ 6.1 $ 5.9 $ 6.2
Foreign currency $ 2.1 $ (2.5) $ (2.4) $ (2.3) $ (0.9) $ (0.6) $ (0.6)
</TABLE>
STATEMENTS OF CASH FLOWS. Temporary cash investments with an original maturity
of three months or less are considered to be cash equivalents.
<TABLE>
<CAPTION>
Cash paid during the periods reported for income taxes and interest was as
follows:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 97,604 $ 88,713 $ 98,975 $ 90,178 $124,789 $141,791
Interest, net of amounts capitalized $ 40,462 $ 41,329 $ 88,006 $ 72,680 $175,372 $134,573
</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 fuel 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 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 these amounts. 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. Each gas cost
adjustment factor is subject to a monthly, quarterly, semi-annual or annual
hearing by the state commissions and remains in effect for a one month, three
month, six month or twelve month period. On August 11, 1999, the IURC approved a
flexible gas cost adjustment mechanism for Northern Indiana. Under the new
procedure, the demand component of the adjustment factor will be determined,
after hearings and IURC approval, and made effective on November 1 of each year.
The demand component will remain in effect for one year until a new demand
component is approved by the IURC. The commodity component of the adjustment
factor will be determined by monthly filings, which will become effective on the
first day of each calendar month, subject to refund. The monthly filings do not
require IURC approval but will be reviewed by the IURC during the annual hearing
that will take place regarding the demand component filing.
If the statutory requirement relating to the level of return for the
gas utilities is satisfied, any under-recovery or over-recovery caused by
variances between estimated and actual cost in a given one month, three month,
six month or twelve month period will be included in a future filing. Any
under-recovery or over-recovery is recorded as a current asset or current
liability until such time it is billed or refunded to customers.
Northern Indiana's gas cost adjustment factor also includes a gas cost
incentive mechanism (GCIM) which allows the sharing of any cost savings or cost
increases with customers based on a comparison of actual gas supply portfolio
cost to a market-based benchmark price.
NATURAL GAS IN STORAGE. Both the last-in, first-out (LIFO) inventory methodology
and the weighted average methodology are used to value natural gas in storage.
Based on the average cost of gas using the LIFO method 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. Inventory valued using LIFO was $31.9
million and $23.0 million at June 30, 2000 and December 31, 1999, respectively.
Inventory valued using the weighted average methodology was $59.4 million and
$40.8 million at June 30, 2000 and December 31, 1999, respectively.
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES. NiSource 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, certain
customer choice programs for residential customers and other retail customer
activity, gains and losses on these derivative financial instruments are
deferred as assets and 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
gains or losses as of the termination date is deferred and recorded when the
associated transaction or forecasted transaction affects earnings.
NiSource also uses derivative financial instruments in connection with
trading activities at its power trading and certain gas marketing and 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 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. NiSource
refers to this activity as Power Marketing.
IMPACT OF ACCOUNTING STANDARDS. The Financial Accounting Standards Board (FASB)
has issued Statement of Financial Accounting Standards (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 Derivative Instruments and
Certain Hedging Activities - an amendment of FASB Statement 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 a hedging instrument's gain or loss on a forecasted
transaction be initially reported in other comprehensive income and subsequently
reclassified into earnings when the hedged forecasted transaction affects
earnings. 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 NiSource 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. 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. NiSource will adopt SFAS No. 133 on January 1, 2001, but has
not yet 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. NiSource is in the
process of projecting the impact of SFAS No. 133 but has not yet quantified the
other effects of adopting SFAS No. 133 on its financial statements. However,
adoption of SFAS No. 133 could increase volatility in earnings and other
comprehensive income.
REGULATORY ASSETS. The Utilities' operations are subject to the regulation of
the appropriate state commissions and, in the case of the Energy Utilities, the
FERC. Accordingly, the Utilities' accounting policies are subject to the
provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." The Utilities monitor 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 their operations. As of June 30,
2000, and December 31, 1999, the regulatory assets identified below represent
probable future revenues to the Utilities as these costs are recovered through
the rate-making process. If a portion of the Utilities' 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.
<PAGE>
<TABLE>
<CAPTION>
Regulatory assets were comprised of the following items:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
<S> <C> <C>
Unamortized reacquisition premium on debt (see Note 16) $ 37,962 $ 39,719
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
(see Note 8) 72,622 75,527
FERC Order No. 636 transition costs 9,984 13,728
Regulatory income tax asset, net (see Note 6) 27,543 24,941
Other 17,328 12,843
------------- -------------
228,984 232,879
------------- -------------
Less: Current portion of regulatory assets 20,500 24,245
------------- -------------
$ 208,484 $ 208,634
============= =============
</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.
FOREIGN CURRENCY TRANSLATION. Translation gains or losses are based upon the
end-of-period exchange rate and are recorded as a separate component of other
comprehensive income reflected in the Consolidated Statements of Shareholders'
Equity.
INVESTMENTS IN REAL ESTATE. A series of affordable housing projects are held as
investments and accounted for using the equity method. These investments include
certain tax benefits, including low-income housing tax credits and tax
deductions for operating losses of the housing projects. Investments, at equity,
include $31.9 million and $33.3 million relating to affordable housing projects
at June 30, 2000 and December 31, 1999, respectively.
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 the book and
tax bases of assets and liabilities. Deferred investment tax credits are being
amortized over the life of the related property.
(3) ACQUISITIONS. On February 12, 1999, the acquisition of BSG was completed for
approximately $560.1 million in cash and NiSource common shares. The $237.7
million cash portion was partially financed by the issuance of Corporate Premium
Income Equity Securities (Corporate PIES) and partially financed by the issuance
of the Puttable Reset Securities (PURS). The acquisition was accounted for as a
purchase, and the purchase price was allocated to the assets acquired and
liabilities assumed based on their estimated fair values.
<TABLE>
<CAPTION>
On a pro forma basis, NiSource's consolidated results of operations for the
six months and twelve months ended June 30, 1999, including BSG, would have
been:
UNAUDITED
(Dollars in thousands) Six Months Twelve Months
============= =============
<S> <C> <C>
Operating revenue $ 1,650,540 $ 3,304,150
Operating income $ 246,421 $ 463,621
Net income $ 102,293 $ 189,844
</TABLE>
On April 1, 1999, NiSource acquired the stock of TPC, a Houston-based
natural gas marketing and storage company, for approximately $150 million in
cash. The acquisition was accounted for as a purchase, with the purchase price
allocated to the assets and liabilities acquired based on their estimated fair
values, including estimates with respect to the tax bases of certain assets
acquired. As a result of the TPC acquisition, NiSource had an indirect
investment in the amount of $126.0 million, representing a 77.3% interest in
MHP, the leading developer, owner and operator of high deliverability salt
cavern natural gas storage capacity. During the fourth quarter of 1999, NiSource
purchased the remaining interests in MHP. On a pro forma basis the impact to
operating income and net income to the three month, six month and twelve month
periods ended March 31, 2000 was not significant.
(4) LITIGATION. NISOURCE ENERGY SERVICES CANADA LTD. On October 31, 1996,
NiSource's subsidiary NiSource Energy Services Canada Ltd. (NESI Canada)
acquired 70% of the outstanding shares of Chandler Energy Inc., a gas marketing
and trading company located in Calgary, Alberta, and subsequently renamed it
NESI Energy Marketing Canada Ltd. (NEMC). Between November 1 and November 27,
1996, gas prices in the Calgary market increased dramatically. As a result, NEMC
was selling gas, pursuant to contracts entered into prior to the acquisition
date, at prices substantially below its costs to acquire such gas. On November
27, 1996, NEMC ceased doing business and sought protection from its creditors
under the Companies' Creditors Arrangement Act, a Canadian corporate
reorganization statute. NEMC was declared bankrupt as of December 12, 1996.
Certain creditors of NEMC filed claims in the Canadian courts against
NiSource, Capital Markets, NI Energy Services, Inc. and NESI Canada, alleging
that misrepresentations were made relating to NEMC's financial condition and
claiming damages. In addition, certain creditors of NEMC, through the Canadian
bankruptcy court, asserted fraudulent transfer, breach of contract, breach of
fiduciary duty and other claims on behalf of NEMC against NiSource, Capital
Markets, NI Energy Services, Inc., NESI Canada and the directors of NEMC. The
Court of Queen's Bench of Alberta recently ordered that the latter claims should
proceed to hearing on certain agreed liability issues (with proceedings to
determine damages, if necessary, to commence later), and ordered that such
hearing would be dispositive of all disputes among the parties. NiSource intends
to vigorously defend against such claims and any other claims seeking to assert
that any party other than NEMC is responsible for NEMC's liabilities. Management
believes that any loss relating to NEMC will not be material to the financial
position or results of operations of NiSource.
POWER COMPANY OF AMERICA L.P. (PCA) BANKRUPTCY. On July 12, 2000,
counsel for the trustee to the Power Company of America Liquidating Trust
(Trustee), the successor of PCA under a plan of reorganization demanded that
NESI Power Marketing, Inc. (NPM) pay $16.1 million, plus interest, and withdraw
its proof of claim in the amount of $1.6 million by filing an adversary
proceeding against NPM in the United States Bankruptcy Court District of
Connecticut. The trustee's claim asserted that NPM received fraudulent
conveyances, fraudulent transfers, and preferential transfers during 1998 when
NPM received payments in connection with its consent to the assignment by PCA to
third parties of PCA's interest in certain power transactions for the sale of
electric power by NPM to PCA and when PCA and NPM closed out certain forward
contracts between them for the supply of electric power during various time
periods between September 1, 1998 and March 31, 1999. These transactions
occurred following NPM's demand for adequate assurance of future performance
following a disruption in the over-the-counter market for electric power in late
June and early July 1998 which impaired PCA's ability to perform. NPM disputes
any liability to the Trustee and intends to vigorously defend against any
matters asserted in the adversary proceeding. Management believes that any loss
relating to PCA will not be material to the financial position and results of
operations of NiSource.
(5) ENVIRONMENTAL MATTERS:
GENERAL. The operations of NiSource are subject to extensive and evolving
federal, state and local environmental laws and regulations intended to protect
the public health and the environment. Such environmental laws and regulations
affect operations as they relate to impacts on air, water and land.
SUPERFUND. Because several NiSource subsidiaries are "potentially responsible
parties" (PRPs) under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) at several waste disposal sites, as well as at former
manufactured-gas plant sites which it, or its corporate predecessors, own or
owned or operated, it may be required to share in the costs of clean up of such
sites. A program was instituted to investigate former manufactured-gas plant
sites where it is the current or former owner, which investigation has
identified forty-six such sites. Initial sampling has been conducted at
thirty-three sites. Investigation activities have been completed at twenty-five
sites and remedial measures have been selected or implemented at eighteen sites.
NiSource 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 NiSource 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.
BSG and Northern Utilities have rate recovery for environmental
response costs in Maine, Massachusetts and New Hampshire. The rate treatment
allows for the recovery of 100% of prudently incurred costs for investigation
and remediation over a 5-7 year period from date of payment. Recoveries from
third parties or insurance companies in Maine and Massachusetts are allocated
50% to rate payers and 50% to shareholders. In New Hampshire 100% of any
recoveries from third parties or insurance companies are returned to rate
payers.
As of June 30, 2000, a reserve of approximately $23.7 million has been
recorded to cover probable corrective actions. The ultimate liability in
connection with these sites will depend upon many factors, including the volume
of material contributed to the site, the number of the other PRPs 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, NiSource believes that any corrective
actions required, after consideration of insurance coverages, contributions from
other PRPs 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 NiSource's facilities are already
in compliance with the sulfur dioxide limits. NiSource 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
NiSource'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 Court of Appeals for the
D.C. Circuit 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. NiSource is
evaluating the court decision and any potential requirements that could result
from the rules as implemented by the State of Indiana. NiSource 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 NiSource 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. NiSource 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 matters 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. NiSource
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. NiSource will continue to closely monitor
developments in this area and anticipates the exact nature of the impact of the
new standards 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 allegations, 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 NiSource.
CLEAN WATER ACT AND RELATED MATTERS. NiSource's wastewater and water operations
are subject to pollution control and water quality control regulations,
including those issued by the EPA and the States of Indiana, Louisiana,
Massachusetts and Texas.
Under the Federal Clean Water Act and state regulations, NiSource must
obtain National Pollutant Discharge Elimination System permits for water
discharges from various facilities, including electric generating and water
treatment stations and a propane plant. 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.
Under the Federal Safe Drinking Water Act (SDWA), the Water Utilities
are subject to regulation by the EPA for the quality of water sold and treatment
techniques used to make the water potable. The EPA promulgates
nationally-applicable maximum contaminant levels (MCLs) for contaminants found
in drinking water. Management believes the Water Utilities are currently in
compliance with all MCLs promulgated to date. The EPA has continuing authority,
however, to issue additional regulations under the SDWA. In August 1996,
Congress amended the SDWA to allow the EPA more authority to weigh the costs and
benefits of regulations being considered in some, but not all, cases. In
December 1998, EPA promulgated two National Primary Drinking Water rules, the
Interim Enhanced Surface Water Treatment Rule and the Disinfectants and
Disinfection Byproducts Rule. The Water Utilities must comply with these rules
by December 2001. Management does not believe that significant changes will be
required to the Water Utilities' operations to comply with these rules; however,
some cost expenditures for equipment modifications or enhancements may be
necessary to comply with the Interim Enhanced Surface Water Treatment Rule.
Additional rules are anticipated to be promulgated under the 1996 amendments.
Compliance with such standards could be costly and require substantial changes
in the Water Utilities' operations.
Under a 1991 law enacted by the Indiana legislature, a water utility
may petition the IURC for prior approval of its plans and estimated expenditures
required to comply with the provisions of, and regulations under, the Federal
Clean Water Act and SDWA. Upon obtaining such approval, a water utility may
include such costs in its rate base for rate-making purposes, to the extent of
its estimated costs as approved by the IURC, and recover its costs of developing
and implementing the approved plans if statutory standards are met. The capital
costs for such new systems, equipment or facilities or modifications of existing
facilities may be included in a water utility's rate base upon completion of
construction of the project or any part thereof. Such an addition to rate base,
however, would effect a change in water rates. NiSource's principal water
utility, Indianapolis Water Company (IWC), has agreed to a moratorium on water
rate increases until 2002. Therefore, recovery of any increased costs discussed
above may not be timely.
(6) INCOME TAXES: Deferred income taxes are recognized as costs in the
rate-making process by the Commissions having jurisdiction over the rates
charged by the Utilities. 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 of the Utilities 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 the Utilities' obligation to credit to ratepayers
deferred income taxes provided at rates higher than the current federal income
tax rate currently being credited to ratepayers using the average rate
assumption method and unamortized deferred investment tax credits.
<PAGE>
<TABLE>
<CAPTION>
The components of the net deferred income tax liability at June 30, 2000 and
December 31, 1999, were as follows:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Deferred tax liabilities--
Accelerated depreciation and other
<S> <C> <C>
property differences $ 1,117,973 $ 1,129,011
AFUDC-equity 29,195 31,274
Adjustment clauses 2,523 16,730
Other regulatory assets 26,554 27,616
Prepaid pension and other benefits 64,590 64,853
Reacquisition premium on debt 15,224 15,919
Deferred tax assets--
Deferred investment tax credits (35,604) (36,650)
Removal costs (177,961) (171,645)
Other postretirement/postemployment benefits (60,521) (58,645)
Other, net (33,512) (27,300)
------------- -------------
948,461 991,163
Less: Deferred income taxes related to current
assets and liabilities (34,460) (7,519)
------------- -------------
Deferred income taxes--noncurrent $ 982,921 $ 998,682
============= =============
</TABLE>
<TABLE>
<CAPTION>
Federal and state income taxes as set forth in the Consolidated Statements of
Income were comprised of the following:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
Current income taxes -
<S> <C> <C> <C> <C> <C> <C>
Federal $ 21,931 $ 15,028 $ 85,393 $ 78,541 $ 98,751 $110,310
State 2,852 2,370 12,569 12,594 14,106 16,930
-------- -------- -------- -------- -------- --------
24,783 17,398 97,962 91,135 112,857 127,240
-------- -------- -------- -------- -------- --------
Deferred income taxes, net -
Federal (8,930) (3,545) (30,487) (28,334) (10,030) (9,260)
State (1,040) (277) (2,868) (2,416) (466) (781)
-------- -------- -------- -------- -------- --------
(9,970) (3,822) (33,355) (30,750) (10,496) (10,041)
-------- -------- -------- -------- -------- --------
Deferred investment tax
credits, net (1,910) (1,920) (3,820) (3,807) (7,704) (7,526)
-------- -------- -------- -------- -------- --------
Total income taxes $ 12,903 $ 11,656 $ 60,787 $ 56,578 $ 94,657 $109,673
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
A reconciliation of total income tax expense to an amount computed by applying
the statutory federal income tax rate to pretax income is as follows:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Net income $ 23,413 $ 22,944 $103,029 $ 99,503 $163,940 $203,222
Add - Income taxes 12,903 11,656 60,787 56,578 94,657 109,673
Dividend requirements on
preferred stocks of subsidiaries 2,008 2,077 4,042 4,193 8,183 8,436
-------- -------- -------- -------- -------- --------
Income before preferred dividend
requirements of subsidiaries
and income taxes $ 38,324 $ 36,677 $167,858 $160,274 $266,780 $321,331
======== ======== ======== ======== ======== ========
Amount derived by multiplying pre-tax
income by the statutory rate $ 13,413 $ 12,837 $ 58,750 $ 56,096 $ 93,373 $112,466
Reconciling items multiplied by the
statutory rate:
Book depreciation over related tax
depreciation 917 968 1,835 1,937 3,832 3,933
Amortization of deferred investment
tax credits (1,910) (1,920) (3,820) (3,807) (7,704) (7,526)
State income taxes, net of federal
income tax benefit 814 1,264 5,302 5,770 8,703 10,224
Reversal of deferred taxes provided
at rates in excess of the current
federal income tax rate (919) (721) (1,838) (1,442) (5,853) (5,372)
Low-income housing credits (1,267) (1,128) (2,534) (2,256) (4,790) (4,176)
Nondeductible amounts related to
amortization of intangible assets
and plant acquisition adjustments 619 619 1,238 1,238 2,476 2,496
Other, net 1,236 (263) 1,854 (958) 4,620 (2,372)
-------- -------- -------- -------- -------- --------
Total income taxes $ 12,903 $ 11,656 $ 60,787 $ 56,578 $ 94,657 $109,673
======== ======== ======== ======== ======== ========
</TABLE>
(7) PENSION PLANS: Noncontributory, defined benefit retirement plans cover the
majority of employees. Benefits under the plans reflect the employees'
compensation, years of service and age at retirement.
<TABLE>
<CAPTION>
The change in the benefit obligation for the years 1999 and 1998 was as follows:
(Dollars in thousands) 1999 1998
============= =============
<S> <C> <C>
Benefit obligation at beginning of year (January 1,) $ 949,039 $ 875,756
Service cost 19,811 17,093
Interest cost 69,610 60,686
Plan amendments -- 14,655
Actuarial (gain) loss (60,108) 38,773
Acquisition of Bay State 78,684 --
Benefits paid (66,687) (57,924)
------------- -------------
Benefit obligation at end of the year (December 31,) $ 990,349 $ 949,039
============= =============
</TABLE>
<TABLE>
<CAPTION>
The change in the fair value of the plans' assets for the years 1999 and 1998
was as follows:
(Dollars in thousands) 1999 1998
============= =============
<S> <C> <C>
Fair value of plan assets at beginning of year (January 1,) $ 987,030 $ 924,857
Actual return on plan assets 170,814 85,254
Employer contributions 42,641 34,843
Acquisition of Bay State 92,070 --
Benefits paid (66,687) (57,924)
------------- -------------
Plan assets at fair value at end of the year (December 31,) $ 1,225,868 $ 987,030
============= =============
The plans' assets are invested primarily in common stocks, bonds and notes.
</TABLE>
<TABLE>
<CAPTION>
The plans' funded status as of December 31, 1999 and 1998 is as follows:
(Dollars in thousands) 1999 1998
============= =============
<S> <C> <C>
Plan assets in excess of benefit obligation $ 235,519 $ 37,991
Unrecognized net actuarial loss (150,984) (10,938)
Unrecognized prior service cost 55,662 57,193
Unrecognized transition amount 22,113 26,813
------------- -------------
Prepaid pension costs $ 162,310 $ 111,059
============= =============
</TABLE>
The benefit obligation is the present value of future pension benefit
payments and is based on a plan benefit formula which considers expected future
salary increases. Discount rates of 7.75% and 7.00% and rates of increase in
compensation levels of 4.5% were used to determine the benefit obligations at
December 31, 1999 and 1998.
Prepaid pension costs were $193.1 million at June 30, 2000 and are reported
under the captions "Prepayments and Other" in the Consolidated Balance Sheets.
<TABLE>
<CAPTION>
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:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 5,227 $ 4,301 $ 10,455 $ 9,720 $ 20,546 $ 13,776
Interest costs 18,876 16,278 37,752 33,492 73,870 50,610
Expected return on plan assets (28,474) (22,404) (54,440) (45,399) (104,269) (69,564)
Amortization of transition obligation 1,472 1,416 2,944 2,895 6,218 4,523
Amortization of prior service costs 1,581 1,571 3,161 3,158 6,513 3,721
Amortization of (gain)/loss (720) -- (1,440) -- (1,440) --
-------- -------- -------- -------- -------- --------
$ (2,038) $ 1,162 $ (1,568) $ 3,866 $ 1,438 $ 3,066
======== ======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Assumptions used in the valuation and determination of 2000 and 1999 pension
expense were as follows:
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>
Certain union employees participate in industry-wide, multi-employer
pension plans which provide for monthly benefits based on length of service.
Specified amounts per compensated hour for each employee are contributed to the
trustees of these plans. Contributions of $0.6 million, $1.1 million and $2.3
million were made to these plans for the three month, six month and twelve month
periods ended June 30, 2000, respectively. The relative position of each
employer participating in these plans with respect to the actuarial present
value of accumulated plan benefits and net assets available for benefits is not
available.
(8) POSTRETIREMENT BENEFITS: NiSource provides certain health care and life
insurance benefits for certain retired employees. The majority of employees may
become eligible for these benefits if they reach retirement age while working
for NiSource.
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. Cash contributions are remitted to grantor
trusts.
<TABLE>
<CAPTION>
The following table sets forth the change in the plans' accumulated
postretirement benefit obligation (APBO) as of December 31, 1999 and 1998:
(Dollars in thousands) 1999 1998
============= =============
Accumulated postretirement benefit obligation at
<S> <C> <C>
beginning of year (January 1,) $ 240,601 $ 223,908
Service cost 5,531 5,249
Interest cost 18,101 15,793
Participant contributions 1,204 --
Plan amendments -- (283)
Actuarial (gain) loss (17,627) 8,453
Acquisition of Bay State 23,205 --
Benefits paid (17,116) (12,519)
------------- -------------
Accumulated postretirement benefit obligation
at end of the year (December 31,) $ 253,899 $ 240,601
============= =============
</TABLE>
<TABLE>
<CAPTION>
The change in the fair value of the plan assets for the years 1999 and 1998 is
as follows:
(Dollars in thousands) 1999 1998
============= =============
<S> <C> <C>
Fair value of plan assets at beginning of year (January 1,) $ 2,903 $ 2,400
Actual return of plan assets 2,521 1,103
Employer contributions 13,877 10,637
Participant contributions 1,204 1,282
Acquisition of Bay State 26,620 --
Benefits paid (17,116) (12,519)
------------- -------------
Plan assets at fair value at end of the year (December 31,) $ 30,009 $ 2,903
============= =============
</TABLE>
<TABLE>
<CAPTION>
Following is the funded status for postretirement benefits as of December 31,
1999 and 1998:
(Dollars in thousands) 1999 1998
============= =============
<S> <C> <C>
Funded status $ (223,890) $ (237,698)
Unrecognized net actuarial gain (106,161) (87,087)
Unrecognized prior service cost 3,550 3,873
Unrecognized transition amount 167,322 164,436
------------- -------------
Accrued liability for postretirement benefits $ (159,179) $ (156,476)
============= =============
</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% 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 $170.4 million at June 30, 2000.
<TABLE>
<CAPTION>
Net periodic postretirement benefit 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:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 1,523 $ 1,652 $ 3,044 $ 2,648 $ 4,587 $ 5,223
Interest costs 4,979 4,865 9,959 9,375 14,801 17,022
Expected return on plan assets (579) (854) (1,159) (1,233) (187) (1,349)
Amortization of transition obligation 3,216 3,287 6,431 6,328 10,851 12,214
Amortization of prior service costs 86 86 172 172 279 344
Amortization of (gain) loss (1,414) (1,220) (2,826) (2,396) (5,986) (5,357)
-------- -------- -------- -------- -------- --------
$ 7,811 $ 7,816 $ 15,621 $ 14,894 $ 24,345 $ 28,097
======== ======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
Assumptions used in the determination of 2000 and 1999 net periodic
postretirement benefit costs were as follows:
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 6.00% 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 $25.6 million, and increase the aggregate of the service and
interest cost components of plan costs by approximately $1.3 million and $2.6
million for the three month 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 $21.1
million, and decrease the aggregate of the service and interest cost components
of plan costs by approximately $1.0 million and $2.0 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.
(9) AUTHORIZED CLASSES OF CUMULATIVE PREFERRED AND PREFERENCE STOCKS:
NISOURCE -
20,000,000 shares-Preferred -without par value
4,000,000 of NiSource's Series A Junior Participating Preferred Shares
are reserved for issuance pursuant to the Share Purchase Rights Plan
described in Note 14, Common Shares.
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)
INDIANAPOLIS WATER COMPANY (IWC) -
300,000 shares-Cumulative Preferred -$100 par value
Note 10 sets forth the preferred stocks which are redeemable solely at the
option of the issuer, and Note 11 sets forth the preferred stocks which are
subject to mandatory redemption requirements or whose redemption is outside the
control of the issuer.
The preferred shareholders of Northern Indiana and IWC have no voting
rights, except in the event of default on the payment of four consecutive
quarterly dividends, or as required by Indiana law to authorize additional
preferred shares, or by the Articles of Incorporation in the event of certain
merger transactions.
(10) PREFERRED STOCKS, REDEEMABLE SOLELY AT THE OPTION OF THE ISSUER:
<TABLE>
<CAPTION>
Redemption
Price at
June 30, December 31, June 30,
(Dollars in thousands, except Redemption Prices) 2000 1999 2000
============= ============= =============
NORTHERN INDIANA PUBLIC SERVICE COMPANY:
CUMULATIVE PREFERRED STOCK - $100 PAR VALUE -
<S> <C> <C> <C>
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 N/A
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
INDIANAPOLIS WATER COMPANY:
CUMULATIVE PREFERRED STOCK- $100 PAR VALUE
4% to 5%, 25,166 shares outstanding 2,517 4,497 $100.00-$105.00
------------- -------------
$ 83,631 $ 85,611
============= =============
</TABLE>
During the period July 1, 1999 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 the issuer at the redemption prices shown.
(11) PREFERRED STOCKS, REDEMPTION OUTSIDE CONTROL OF ISSUER:
<TABLE>
<CAPTION>
Preferred stocks subject to mandatory redemption requirements or whose
redemption is outside the control of issuer, excluding sinking fund payments due
within one year were as follows:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
NORTHERN INDIANA PUBLIC SERVICE COMPANY:
CUMULATIVE PREFERRED STOCK -$100 PAR VALUE -
<S> <C> <C>
8.85% series - 25,000 shares outstanding $ 2,500 $ 3,750
7-3/4% series - 27,798 shares outstanding 2,780 2,780
8.35% series - 42,000 shares outstanding 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>
<TABLE>
<CAPTION>
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:
Sinking Fund or
Series Redemption Price Per Share Mandatory Redemption Provisions
============== ========================== =================================
Cumulative preferred stock -$100 par value -
<S> <C> <C> <C>
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>
<TABLE>
<CAPTION>
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:
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 the Current Liabilities in the Consolidated Balance
Sheet.
(12) COMMON DIVIDEND: NiSource's ability to pay dividends depends primarily upon
dividends it receives from Northern Indiana. 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 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.
(13) EARNINGS PER SHARE: The weighted average shares outstanding for diluted
earnings per share include the incremental effect of the various long-term
incentive compensation plans and the incremental effect of common shares
associated with the equity forward share purchase contract calculated under the
reverse treasury stock method. See Note "Equity Forward Share Contract" for
description of the contract.
<TABLE>
<CAPTION>
The net income, preferred dividends and shares used to compute basic and diluted
earnings per share is presented in the following table:
(Dollars in thousands, except share amounts)
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
------------------------ ------------------------ ------------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
=========== =========== =========== =========== =========== ===========
BASIC
Weighted Average Number of Common
<S> <C> <C> <C> <C> <C> <C>
Shares Outstanding 120,569,530 124,951,321 122,203,747 123,804,922 123,545,434 121,166,275
=========== =========== =========== =========== =========== ===========
Net Income to be Used to Compute Basic
Earnings per Share:
Net Income $ 23,413 $ 22,944 $ 103,029 $ 99,503 $ 163,940 $ 203,222
=========== =========== =========== =========== =========== ===========
Basic Earnings per Average Common
Share $ 0.19 $ 0.18 $ 0.84 $ 0.80 $ 1.32 $ 1.67
=========== =========== =========== =========== =========== ===========
DILUTED
Weighted Average Number of Common
Shares Outstanding 120,569,530 124,951,321 122,203,747 123,804,922 123,545,434 121,166,275
Dilutive Shares 4,085,406 675,425 4,191,800 560,493 2,742,024 751,312
----------- ----------- ----------- ----------- ----------- -----------
Weighted Average Shares 124,654,936 125,626,746 126,395,547 124,365,415 126,287,458 121,917,587
=========== =========== =========== =========== =========== ===========
Net Income to be Used to Compute
Diluted Earnings per Share:
Net Income $ 23,413 $ 22,944 $ 103,029 $ 99,503 $ 163,940 $ 203,222
=========== =========== =========== =========== =========== ===========
Diluted Earnings per Average
Common Share $ 0.18 $ 0.18 $ 0.81 $ 0.80 $ 1.29 $ 1.66
=========== =========== =========== =========== =========== ===========
</TABLE>
(14) COMMON SHARES: As of June 30, 2000 NiSource has 400,000,000 of authorized
common shares without par value. All references to numbers of common shares
reported, including per share amounts and stock option data, have been adjusted
to reflect the two-for-one stock split paid February 20, 1998.
SHARE PURCHASE RIGHTS PLAN. On February 17, 2000, the Board of Directors of
NiSource adopted a new Share Purchase Rights Plan which has substantially the
same terms as a previously effective Share Purchase Rights Plan. Each Right,
when exercisable, would initially entitle the holder to purchase from NiSource
one one-hundredth of a share of Series A Junior Participating Preferred Share,
without par value, at a price of $60 per one one-hundredth of a share. In
certain circumstances, if an acquirer obtained 25% of NiSource's outstanding
shares, or merged into NiSource or merged NiSource into the acquirer, the Rights
would entitle the holders to purchase NiSource's or the acquirer's common shares
for one-half of the market price. The Rights will not dilute NiSource's common
shares nor affect earnings per share unless they become exercisable for common
shares. The Plan was not adopted in response to any specific attempt to acquire
control of NiSource. The Rights are not currently exercisable.
COMMON SHARE REPURCHASES. The Board has authorized the repurchase of 62.1
million common shares, subject to certain limits. At June 30, 2000,
approximately 60.2 million shares had been repurchased at an average price of
$16.95 per share.
EQUITY FORWARD SHARE PURCHASE CONTRACT. During the second quarter of 1999, a
forward purchase contract was entered into covering the purchase of up to 5% of
NiSource's outstanding common shares. At the end of each quarterly period during
the term of the forward purchase contract, NiSource has the option, but not the
obligation, to settle the forward purchase contract with respect to all or a
portion of the common shares held by the counterparty. As of December 31, 1999,
the counterparty informed NiSource that approximately 5.6 million shares had
been purchased at a weighted average cost of $26.90 per share. NiSource has the
option to settle with the counterparty by means of physical, net cash or net
share settlement. On a quarterly basis, NiSource pays the counterparty a fee
based on the amount paid for common shares purchased by the counterparty, and
the counterparty remits dividends received on shares owned. All such amounts
paid and remitted under the contract are reflected in equity contract costs of
common shareholders' equity. The net amount was a charge of $0.9 million, $2.0
million and $2.8 million for the three month, six month and twelve month periods
ended June 30, 2000.
NiSource will be obligated to settle the forward purchase contract with
respect to all the remaining common shares in May 2003, or under certain
circumstances after an extension period of up to six months, at NiSource's
option. As of June 30, 2000, the nominal amount and fair value of the equity
forward purchase contract was approximately $150 million and a loss of $(46)
million, respectively. NiSource's forward purchase contract is currently
accounted for in permanent equity.
In March 2000, the Emerging Issues Task Force (EITF) released Issue No.
00-07, "Application of EITF Issue No. 96-13, "Accounting for Derivative
Financial Instruments Indexed to, and Potentially Settled in, a Company's Own
Stock," to Equity Derivative Transactions That Contain Certain Provisions That
Require Cash Settlement if Certain Events Outside the Control of the Issuer
Occur." The final consensus in EITF Issue No. 00-07 generally stated that equity
derivative contracts that contained provisions that implicitly or explicitly
required net cash settlement outside the control of the company must be treated
as assets and liabilities and carried at fair value rather than as equity
instruments carried at original cost and reported as part of permanent equity,
as provided for in EITF Issue No. 96-13.Similarly, the EITF reached consensus
that equity derivative contracts with any provisions that could require physical
settlement by a cash payment to the counterparty in exchange for the issuer's
shares should be classified as temporary equity. For contracts that existed
before March 16, 2000, the provisions of the consensus shall be applied on
December 31, 2000, to those contracts that remain outstanding at that date,
based on the contract terms then in place. The applying EITF No. 00-07 will
require asset/liability treatment for contracts with net cash settlement
provisions to be recalculated as of December 31, 2000, and presented on that
date as a cumulative effect of a change in accounting principles. Any
reclassification of amounts from permanent equity to temporary equity as a
result of settlement provisions requiring physical cash settlement shall be made
for balance sheets as of and subsequent to December 31, 2000.
As part of EITF Issue No. 00-19, "Determination of Whether Share
Settlement is Within the Control of the Issuer for Purposes of Applying Issue
No. 96-13," the EITF developed a model governing how certain settlement features
affect the accounting for equity derivative contracts entered into by a company
with respect to its own stock. The EITF also tentatively provided an extended
transition period for amending existing contracts (June 30, 2001). Consensus has
not yet been reached. Management of NiSource continues to review possible
amendments to contract provisions with the counterparty. There continue to be
discussions related to the accounting for such contracts by the EITF and other
authoritative bodies. NiSource expects to adopt the provisions of the ultimate
consensus within the transition period. However, the ultimate resolution and
impact of the accounting for the contract will be dependent upon the results of
the review of contract provisions with the counterparty, possible future
changes in authoritative guidance and fluctuations in NiSource's share price.
(15) LONG-TERM INCENTIVE PLANS: There are two long-term incentive plans
for key management employees that were approved by shareholders on April 13,
1988 (1988 Plan) and April 13, 1994 (1994 Plan), each of which provided for the
issuance of up to 5.0 million 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. The Plans permit the following types of grants, separately or in
combination: nonqualified stock options, incentive stock options, restricted
stock awards, stock appreciation rights and performance units. Under the Plans,
the exercise price of each option equals the market price of common stock on the
date of grant. Each option has a maximum term of ten years and vests one year
from the date of grant.
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, stock appreciation rights (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.
In connection with the acquisition of BSG (see Note 3), all outstanding
BSG nonqualified stock options were replaced with NiSource nonqualified stock
options. The replacement of such options did not change their original vesting
provisions, terms or fair values. Information regarding these options can be
found in the following tables about changes in nonqualified stock options under
the caption "converted."
SARs may be granted only in tandem with stock options on a one-for-one
basis and are payable in cash, common shares, or a combination thereof.
Restricted stock awards are restricted as to transfer and are subject to
forfeiture for specific periods from the date of grant. Restrictions on shares
awarded in 1995 lapsed on January 27, 2000 and vested at 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% of the number awarded, subject to specific performance goals. If a
participant's employment is terminated prior to vesting other than by reason of
death, disability or retirement, restricted shares are forfeited. There were
683,500 and 513,500 restricted shares outstanding at June 30, 2000 and December
31, 1999, respectively.
The Nonemployee Director Stock Incentive Plan, which was approved by
shareholders, provides for the issuance of up to 200,000 common shares to
nonemployee directors. The Plan provides for awards of common shares which vest
in 20% per year increments, with full vesting after five years. The Plan also
allows for the award of nonqualified stock options, subject to immediate vesting
in the event of the director's death or disability, or a change in control of
NiSource. If a director's service on the Board is terminated for any reason
other than retirement at or after age seventy, death or disability, any common
shares not vested as of the date of termination are forfeited. As of June 30,
2000, 81,500 shares had been issued under the Plan.
These plans are accounted for under Accounting Principles Board Opinion
No. 25, under which no compensation cost has been recognized for nonqualified
stock options. The compensation cost that was charged against net income for
restricted stock awards was $1.1 million and $0.6 million for the three month,
$2.4 million and $1.4 million for the six month and $4.6 million and $2.5
million for the twelve month periods ended June 30, 2000 and 1999, respectively.
<TABLE>
<CAPTION>
Had compensation cost for nonqualified stock options been determined consistent
with SFAS No. 123 "Accounting for Stock-Based Compensation," net income and
earnings per average common share would have been reduced to the following pro
forma amounts:
(Dollars in thousands, except per share data)
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
NET INCOME:
<S> <C> <C> <C> <C> <C> <C>
As reported $ 23,413 $ 22,944 $103,029 $ 99,503 $163,940 $203,222
Pro forma $ 22,753 $ 22,540 $101,793 $ 98,695 $161,873 $201,725
EARNINGS PER AVERAGE COMMON SHARE:
Basic:
As reported $ 0.19 $ 0.18 $ 0.84 $ 0.80 $ 1.32 $ 1.67
Pro forma $ 0.18 $ 0.18 $ 0.83 $ 0.79 $ 1.27 $ 1.66
Diluted:
As reported $ 0.18 $ 0.18 $ 0.81 $ 0.80 $ 1.30 $ 1.66
Pro forma $ 0.18 $ 0.17 $ 0.80 $ 0.79 $ 1.25 $ 1.65
</TABLE>
<TABLE>
<CAPTION>
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:
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 (in years) 5.4 5.25 5.4
Volatility 28.98% 15.72% 13.09%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Changes in outstanding shares under option and SARs for the three month, six
month and twelve month periods ended June 30, 2000 and June 30, 1999 were as
follows:
NONQUALIFIED STOCK OPTIONS
-----------------------------------------------------
Weighted Weighted
Average Average
Option Option
Three Months Ended June 30, 2000 Price 1999 Price
=========================== =========== =========== =========== ===========
<S> <C> <C> <C> <C>
Balance, beginning of period 4,327,956 $ 19.76 3,346,163 $ 18.63
Exercised (194,811) 13.59 (97,957) 12.40
Canceled (20,000) 24.11 (5,000) 29.22
----------- -----------
Balance, end of period 4,113,145 $ 20.03 3,243,206 $ 18.81
=========== ===========
Shares exercisable 2,983,895 $ 19.14 2,644,706 $ 16.45
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
-----------------------------------------------------
Weighted Weighted
Average Average
Option Option
Six Months Ended June 30, 2000 Price 1999 Price
========================= =========== =========== =========== ===========
<S> <C> <C> <C> <C>
Balance, beginning of period 3,950,456 $ 19.09 2,651,300 $ 19.61
Converted -- -- 740,780 15.03
Granted 408,000 18.44 -- --
Exercised (205,811) 13.73 (142,374) 13.71
Canceled (39,500) 23.79 (6,500) 29.22
----------- -----------
Balance, end of period 4,113,145 $ 20.03 3,243,206 $ 18.81
=========== ===========
Shares exercisable 2,983,895 $ 19.41 2,644,706 $ 16.45
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
-----------------------------------------------------
Weighted Weighted
Average Average
Option Option
Twelve Months Ended June 30, 2000 Price 1999 Price
============================ =========== =========== =========== ===========
<S> <C> <C> <C> <C>
Balance, beginning of period 3,243,206 $ 18.81 2,193,600 $ 16.79
Converted -- -- 740,780 15.03
Granted 1,152,750 22.41 607,000 29.22
Exercised (234,811) 13.96 (289,674) 15.44
Canceled (48,000) 24.51 (8,500) 29.22
----------- -----------
Balance, end of period 4,113,145 $ 20.03 3,243,206 $ 18.81
=========== ===========
Shares exercisable 2,983,895 $ 19.14 2,644,706 $ 16.45
=========== ===========
Weighted average fair value
of options granted $ 3.69 $ 4.28
=========== ===========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
The following table summarizes information about nonqualified stock options:
OPTIONS OUTSTANDING AND EXERCISABLE BY PRICE RANGE AS OF JUNE 30, 2000
Options Outstanding Options Exercisable
--------------------------------------------------------------- -----------------------------------
Weighted
Average Weighted
Remaining Average Weighted
Range of Outstanding as of Contractual Exercise Exercisable as of Average
Exercise Prices June 30, 2000 Life Price June 30, 2000 Exercise Price
--------------- ----------------- ----------- -------- ----------------- --------------
<S> <C> <C> <C> <C> <C>
$ 8.53-$12.76 139,500 0.8 $10.35 139,500 $10.35
$12.77-$19.15 2,123,308 4.9 $16.46 1,715,308 $15.99
$19.16-$28.74 1,265,337 8.3 $22.83 544,087 $20.48
$28.75-$29.22 585,000 8.1 $29.22 585,000 $29.22
--------------- ----------------- ----------- -------- ----------------- --------------
4,113,145 6.2 $20.03 2,983,895 $19.14
</TABLE>
<TABLE>
<CAPTION>
(16) LONG-TERM DEBT:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
First mortgage bonds -
Weighted average interest rate of 6.69% and
various maturities between April 1, 2002 and
<S> <C> <C>
July 15, 2028 $ 171,500 $ 183,100
Pollution control notes and bonds-
Weighted average interest rate of 3.91% and
various maturities between October 1, 2003 and
April 1, 2019 237,000 237,000
Medium-term notes -
Weighted average interest rate of 7.12% and
various maturities between August 15, 2001
and September 1, 2031 1,172,858 1,180,892
Subordinated Debentures -7-3/4%, due
March 31, 2026 75,000 75,000
Senior Notes Payable - 6.78%, due
December 1, 2027 75,000 75,000
Notes payable -
Weighted average interest rate of 8.61% and
various maturities between December 31, 2001
and December 1, 2018 181,761 196,704
Variable bank loans - interest rate of 7.48%, due
August 7, 2003 5,600 30,600
Unamortized premium and discount on
long-term debt, net (2,899) (3,112)
------------- -------------
Total long-term debt, excluding amounts due
within one year $ 1,915,820 $ 1,975,184
============= =============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Sinking fund requirements and maturities of long-term debt outstanding at June
30, 2000 for the twelve month periods subsequent to June 30, 2001, were as
follows:
Twelve Months Ended June 30, (Dollars in thousands)
=========================================================
<S> <C>
2002 $ 130,928
2003 $ 113,304
2004 $ 182,692
2005 $ 116,220
</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 have been deferred and are being amortized. These
premiums are not earning a return during the recovery period.
The first mortgage bonds constitute a direct first mortgage lien upon
certain utility property and franchises. Certain trust indentures require annual
sinking or improvement payments amounting to .50% of the maximum aggregate
amount outstanding. As permitted, this requirement has been satisfied by
substituting a portion of permanent additions to utility plant.
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 these medium-term notes had been issued with various
interest rates and maturities.
The financial obligations of Capital Markets are subject to a Support
Agreement between NiSource and Capital Markets, under which NiSource has
committed to make payments of interest and principal on Capital Markets'
obligations in the event of a failure to pay by Capital Markets. Restrictions in
the Support Agreement prohibit recourse on the part of Capital Markets'
creditors against the stock and assets of Northern Indiana that are owned by
NiSource. Under the terms of the Support Agreement, in addition to the cash flow
of cash dividends paid to NiSource by any of its consolidated subsidiaries, the
assets of NiSource, other than the stock and assets of Northern Indiana, are
available as recourse for the benefit of Capital Markets' creditors. The
carrying value of the assets of NiSource, other than the assets of Northern
Indiana, were approximately $3.5 billion at June 30, 2000.
(17) CURRENT PORTION OF LONG-TERM DEBT:
<TABLE>
<CAPTION>
At June 30, 2000 and December 31, 1999, the current portion of long-term debt
due within one year was as follows:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Medium-term notes--
<S> <C> <C>
Weighted average interest rate of 5.70% $ 27,851 $ 166,254
Notes payable--
Weighted average interest rate of 6.74% 18,717 4,467
Sinking funds due within one year 3,000 3,000
Revolving Credit Agreement 5.75%,
due March 17, 2001 25,000 --
------------- -------------
Total current portion of long-term debt $ 74,568 $ 173,721
============= =============
</TABLE>
(18) SHORT-TERM BORROWINGS: NiSource and its subsidiaries may borrow under two
five-year $100 million revolving credit agreements that terminate on September
23, 2003 and two 364-day $100 million revolving credit agreements that terminate
on September 23, 2000. NiSource expects that the 364-day agreements will 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 short-term periods. These
agreements provide financing flexibility and working capital requirements and
may be used to support the issuance of commercial paper. At June 30, 2000, there
were no borrowings outstanding under these agreements.
In addition, various NiSource subsidiaries maintain lines of credit for
up to an aggregate of $159.7 million with lenders at either the lender's
commercial prime or market lending rates. As of June 30, 2000, there were $50.8
million of borrowings outstanding under these lines of credit with a weighted
average interest rate of 4.85%. As of December 31, 1999, there were $54.1
million of borrowings outstanding under these lines of credit.
NiSource and its subsidiaries maintain money market lines of credit for
up to $379.5 million. As of June 30, 2000, there were $248.9 million outstanding
under these money market lines of credit with a weighted average interest rate
of 7.08%. At December 31, 1999, there were $156.2 million of borrowings
outstanding under these money market lines of credit.
In September 1999, Capital Markets issued $160 million PURS in an
underwritten public offering. The PURS are unsecured debentures of Capital
Markets and rank equally with all other unsecured and unsubordinated debt of
Capital Markets. The PURS are subject to a call option under which the
underwriters may purchase all of the outstanding PURS from the holders on
September 28, 2000. The net proceeds from the sale of the PURS and the call
option of $162.4 million were used to refinance short-term indebtedness incurred
in connection with the acquisition of BSG in February 1999. Until September 28,
2000, the PURS will accrue interest at a rate based on LIBOR plus 1.25%. On
September 28, 2000, if the underwriters do not exercise their call option,
Capital Markets will be obligated to repurchase all of the outstanding PURS. If
the underwriters purchase all of the outstanding PURS pursuant to their call
option, the interest rate will be reset to a fixed rate based on then current
market rates plus a fixed margin and the PURS will remain outstanding until
2010.
<TABLE>
<CAPTION>
At June 30, 2000 and December 31, 1999, short-term borrowings were as follows:
June 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Commercial paper--
Weighted average interest rate of 6.61%
<S> <C> <C>
at June 30, 2000 $ 408,000 $ 299,565
Notes payable--
Weighted average interest rate of 6.45%
at June 30, 2000 462,109 379,756
------------- -------------
Total short-term borrowings $ 870,109 $ 679,321
============= =============
</TABLE>
(19) CORPORATE PREMIUM INCOME EQUITY SECURITIES AND COMPANY-OBLIGATED
MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST HOLDING SOLELY COMPANY
DEBENTURES In February 1999 NiSource completed an underwritten public offering
of Corporate PIES. The net proceeds of approximately $334.7 million were
primarily used to fund the cash portion of the consideration payable in the
acquisition of BSG, and to repay short-term indebtedness.
The Corporate PIES were offered as one unit comprised of two separable
instruments. The first component consists of stock purchase contracts to
purchase, four years from the date of issuance, common shares at a face value of
$50. The second component consists of mandatorily redeemable preferred
securities (Preferred Securities) which represent an undivided beneficial
ownership interest in the assets of NIPSCO Capital Trust I (Capital Trust). The
Preferred Securities have a stated liquidation amount of $50. The sole assets of
Capital Trust are subordinated debentures (Debentures) of Capital Markets that
earn interest at the same rates as the Preferred Securities to which they
relate, and certain rights under related guarantees by Capital Markets. The
Preferred Securities have been pledged to secure the holders' obligation to
purchase common shares under the stock purchase contracts.
The distributions paid on Preferred Securities are presented under the
caption "minority interests" in NiSource's Consolidated Statements of Income.
The amounts outstanding are presented under the caption "Company-obligated
mandatorily redeemable preferred securities of subsidiary trust holding solely
company debentures" in NiSource's Consolidated Balance Sheet. At June 30, 2000,
there were 6.9 million 5.9% Preferred Securities outstanding with Capital Trust
assets of $345 million.
(20) OPERATING LEASES:
<TABLE>
<CAPTION>
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:
Twelve Months Ended June 30, (Dollars in thousands)
=========================================================
<S> <C>
2001 $ 34,679
2002 66,540
2003 31,352
2004 78,626
2005 24,322
Later years 206,189
---------
Total minimum payments required $ 441,708
=========
</TABLE>
<TABLE>
<CAPTION>
The Consolidated Financial Statements include rental expense for all operating
leases as follows:
June 30, June 30,
(Dollars in thousands) 2000 1999
============= =============
<S> <C> <C>
Three months ended $ 12,372 $ 14,891
Six months ended $ 24,618 $ 24,198
Twelve months ended $ 50,697 $ 36,366
</TABLE>
(21) COMMITMENTS: NiSource expects that approximately $1.6 billion will be
expended for construction purposes for the period from January 1, 2000 to
December 31, 2004. Substantial commitments have been made in connection with
this construction 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 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 the agreement are approximately $20 million.
Primary Energy, Inc. (Primary) arranges energy-related projects for
large energy-intensive customers and offers such customers nationwide expertise
in managing the engineering, construction, operation and maintenance of such
projects. Through its subsidiaries, Primary has entered into agreements with
several of NiSource's largest industrial customers, principally steel mills and
a refinery, to service a portion of their energy needs. In order to serves its
customers under the agreements, Primary, through its subsidiaries, has entered
into certain operating lease commitments to lease these energy-related projects
which have a combined capacity of 393 megawatts. NiSource, principally through
Capital Markets, guarantees certain of Primary's obligations under each lease,
which are included in the amount disclosed in the Operating Leases in Note 20.
Primary has advanced approximately $64.5 million and $36.6 million, at
June 30, 2000 and December 31, 1999, respectively, to the lessors of the
energy-related projects discussed above. These net advances are included in
"Other Receivables" in the Consolidated Balance Sheet and as a component of
operating activities in the Consolidated Statement of Cash Flows.
(22) RISK MANAGEMENT ACTIVITIES: NiSource uses certain commodity-based
derivative financial instruments to manage certain risks inherent in its
business. NiSource'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.
NiSource 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 utilities, certain customer choice programs for residential
customers and other retail customer activity. At June 30, 2000, NiSource had
futures contracts representing the hedge of natural gas sales in the notional
amount of 1.5 billion cubic feet (BCF) resulting in a deferred loss of $3.3
million.
NiSource's trading operations include the activities of its power
trading business and non-affiliated transactions associated with TPC. NiSource
employs a VaR model to assess the market risk of its energy trading portfolios.
NiSource estimates the one-day VaR across all trading groups which utilize
derivatives using either Monte Carlo simulation or variance/covariance at a 95%
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, $0.5 million, $1.8 million and $0.004 million
and $0.5 million, $1.8 million and $0.004 million for the three month, six month
and twelve month periods ended June 30, 2000, respectively. The daily VaR for
the gas trading portfolio on an average, high and low basis was $3.4 million,
$8.1 million and $0.7 million, $2.7 million, $8.1 million and $0.5 million and
$2.4 million, $8.1 million and $0.4 million for the three month, six month and
twelve month periods ended June 30, 2000, respectively. NiSource implemented
a VaR methodology in 1999 to introduce additional market sophistication and to
recognize the developing complexity of its businesses.
Unrealized gains and losses on NiSource'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
$309.0 million and $90.7 million at June 30, 2000 and December 31, 1999,
respectively, of which $301.2 million and $90.7 million were included in "Price
risk management assets" and $22.8 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 $335.9 million and $113.0 million of which $323.5 million
and $113.0 million were included in "Price risk management liabilities" and
$18.4 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. NiSource 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 month periods ended June 30, 1999, respectively.
<TABLE>
<CAPTION>
Included in these net amounts are revenues and costs of sales related to
physical forward sales and purchase contracts as follows:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<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>
Realized Activities with respect to gas trading are reflected on a gross
basis with revenues and costs of goods sold consistent with the physical nature
of the trades.
<TABLE>
<CAPTION>
The amounts recorded as gas trading revenues and costs of goods sold were as follows:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Gas Trading Revenues $370,247 $ 92,158 $656,429 $ 92,158 $954,651 $ 92,158
Gas Trading Cost of Sales $368,773 $ 91,562 $648,009 $ 91,562 $944,645 $ 91,562
</TABLE>
In June and August of 2000, NiSource entered into forward starting interest
rate swaps with notional amounts of $600 million and $500 million, respectively,
to hedge the interest rate risk exposure associated with $1.1 billion of its
anticipated financing of the CEG acquisition debt. The swaps have an effective
date of March 30, 2001. The interest rate swaps on $600 million amount terminate
on March 30, 2006, and the interest rate swap on the $500 million amount
terminates on March 30, 2011. Gains or losses associated with the interest rate
swaps will be amortized over the life of the debt.
(23) 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. Where feasible, the fair value of investments is estimated based on
market prices for those or similar investments.
LONG-TERM DEBT/PREFERRED STOCK AND PREFERRED SECURITIES. The fair values of
these securities are estimated based on the 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.
<TABLE>
<CAPTION>
The carrying values and estimated fair values of financial instruments were as
follows:
June 30, 2000 December 31,1999
------------------------ ------------------------
Carrying Estimated Carrying Estimated
(Dollars in thousands) Amount Fair Value Amount Fair Value
=========== =========== =========== ===========
<S> <C> <C> <C> <C>
Investments $ 49,658 $ 50,977 $ 49,064 $ 49,352
Long-term debt (including current portion) $ 1,990,388 $ 1,826,433 $ 2,148,905 $1,992,348
Preferred stock (including current portion) $ 137,639 $ 109,110 $ 141,469 $ 119,702
Company-obligated mandatorily redeemable
preferred securities of subsidiary trust
holding solely Company debentures $ 345,000 $ 272,985 $ 345,000 $ 248,831
</TABLE>
A substantial portion of the long-term debt relates to utility
operations. The Utilities are 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.
(24) CUSTOMER CONCENTRATIONS: The Utilities supply natural gas, electric energy
and water. Natural gas and electric energy are supplied to the northern third of
Indiana and natural gas is supplied in portions of Massachusetts, New Hampshire
and Maine. The Water Utilities serve Indianapolis, Indiana, and surrounding
areas. Although the Energy Utilities have a diversified base of residential and
commercial customers, a portion of gas and a substantial portion of their
electric industrial deliveries are dependent upon the basic steel industry.
<TABLE>
<CAPTION>
The following table shows the basic steel industry percentage of gas revenue
(including transportation services) and electric revenue for 2000 and 1999:
Twelve Months Twelve Months
Ended June 30, Ended June 30,
Basic Steel Industry 2000 1999
-------------------- ============= =============
<S> <C> <C>
Gas revenue percentage 2% 2%
Electric revenue percentage 19% 14%
</TABLE>
(25) 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.
There are four reportable operating segments: Gas Utilities, Electric,
Water and Gas Marketing and Storage. The Gas Utilities segment includes
regulated gas utilities which provide natural gas distribution and
transportation services. The Electric segment is comprised principally of
Northern Indiana, a regulated electric utility, which generates, transmits and
distributes electricity. In addition, the Electric segment includes a wholesale
power marketing and trading operation which markets wholesale power to other
utilities and electric power marketers. The Water segment includes regulated
water utilities which provide distribution of water supply to the public. The
Gas Marketing and Storage segment provides natural gas marketing, trading,
storage and sales to wholesale and industrial customers.
Reportable segments are operations that are managed separately and meet
certain quantitative thresholds. The Other Products and Services column includes
a variety of businesses, such as installation, repair and maintenance of
underground pipelines, utility line locating and marking, the development and
operation of energy-related projects for large energy-intensive facilities, and
other products and services, which collectively do not constitute a segment for
reporting purposes.
Revenues for each segment are principally attributable to customers in
the United States. Additional revenues, which are insignificant to consolidated
revenues, are attributable to customers in Canada and the United Kingdom.
The following tables provide information about business segments.
NiSource uses income before interest and income taxes as its primary measurement
for each of the reported segments. NiSource makes decisions on finance,
dividends and taxes at the corporate level. These topics are addressed on a
consolidated basis. 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 and the elimination of intercompany transactions.
The accounting policies of the operating segments are the same as those
described in "Summary of Significant Accounting Policies."
<PAGE>
<TABLE>
<CAPTION>
For the three months ended June 30, 2000
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 229,484 $ 259,709 $ 25,131 $ 387,463 $ 78,828 $ (57,644) $ 922,971
Other Net $ 327 $ 98 $ 79 $ 455 $ 3,882 $ (2,329) $ 2,512
Depreciation and
Amortization $ 32,379 $ 40,043 $ 4,293 $ 3,010 $ 4,056 $ 857 $ 84,638
Income before Interest
and Other Charges
and Income Taxes $ (6,940) $ 90,826 $ 6,227 $ 8,691 $ 3,435 $ (10,381) $ 91,858
Assets $ 2,696,475 $ 2,764,794 $ 704,872 $ 948,960 $ 609,083 $ (530,509) $ 7,193,675
Capital Expenditures $ 24,929 $ 32,788 $ 9,863 $ 7,893 $ 5,578 $ -- $ 81,051
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 8,402 $ 97,263 $ -- $ 105,665
</TABLE>
<TABLE>
<CAPTION>
For the three months ended June 30, 1999
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 187,348 $ 272,072 $ 24,061 $ 160,011 $ 74,993 $ (43,138) $ 675,347
Other Net $ (509) $ 210 $ 267 $ 1,835 $ (4,850) $ 728 $ (2,319)
Depreciation and
Amortization $ 29,743 $ 39,593 $ 4,790 $ 800 $ 2,021 $ 646 $ 77,593
Income before Interest
and OtherCharges
and Income Taxes $ (11,155) $ 88,915 $ 5,871 $ 662 $ 810 $ (2,444) $ 82,659
Assets $ 2,297,127 $ 2,743,524 $ 643,283 $ 285,977 $ 694,450 $ (262,470) $ 6,401,891
Capital Expenditures $ 25,990 $ 41,244 $ 10,560 $ 277 $ 8,333 $ -- $ 86,404
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 91,217 $ 151,605 $ -- $ 242,822
</TABLE>
<TABLE>
<CAPTION>
For the six months ended June 30, 2000
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 712,136 $ 516,093 $ 48,081 $ 697,040 $ 143,769 $ (126,599) $ 1,990,520
Other Net $ 2,331 $ 77 $ 227 $ 655 $ 6,843 $ (4,346) $ 5,787
Depreciation and
Amortization $ 64,819 $ 80,160 $ 8,532 $ 6,044 $ 7,909 $ 1,653 $ 169,117
Income before Interest
and Other Charges
and Income Taxes $ 91,952 $ 173,512 $ 9,954 $ 18,409 $ 3,317 $ (23,102) $ 274,042
Assets $ 2,696,475 $ 2,764,794 $ 704,872 $ 948,960 $ 609,083 $ (530,509) $ 7,193,675
Capital Expenditures $ 45,947 $ 57,734 $ 19,231 $ 12,729 $ 11,188 $ -- $ 146,829
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 8,402 $ 97,263 $ -- $ 105,665
</TABLE>
<TABLE>
<CAPTION>
For the six months ended June 30, 1999
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 583,522 $ 537,371 $ 44,959 $ 375,372 $ 130,759 $ (105,060) $ 1,566,923
Other Net $ 1,237 $ 338 $ 463 $ 2,238 $ 1,592 $ (1,046) $ 4,822
Depreciation and
Amortization $ 56,121 $ 79,248 $ 7,015 $ 884 $ 5,921 $ 1,259 $ 150,448
Income before Interest
and Other Charges
and Income Taxes $ 77,309 $ 162,521 $ 10,837 $ 1,554 $ 3,462 $ (10,032) $ 245,651
Assets $ 2,297,127 $ 2,743,524 $ 643,283 $ 285,977 $ 694,450 $ (262,470) $ 6,401,891
Capital Expenditures $ 52,977 $ 67,882 $ 16,826 $ 318 $ 13,282 $ -- $ 151,285
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 91,217 $ 151,605 $ -- $ 242,822
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
For the twelve months ended June 30, 2000
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 1,210,909 $ 1,102,879 $ 101,623 $ 1,093,445 $ 296,536 $ (237,219) $ 3,568,173
Other Net $ 5,256 $ 495 $ 1,746 $ 3,624 $ (16,901) $ (11,284) $ (17,064)
Depreciation and
Amortization $ 124,844 $ 159,889 $ 16,945 $ 8,296 $ 15,098 $ 5,001 $ 330,073
Income before Interest
and Other Charges
and Income Taxes $ 134,228 $ 374,666 $ 28,256 $ 16,370 $ (16,066) $ (65,558) $ 471,896
Assets $ 2,696,475 $ 2,764,794 $ 704,872 $ 948,960 $ 609,083 $ (530,509) $ 7,193,675
Capital Expenditures $ 138,152 $ 123,871 $ 66,995 $ 13,144 $ 11,905 $ -- $ 354,067
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 8,402 $ 97,263 $ -- $ 105,665
</TABLE>
<TABLE>
<CAPTION>
For the twelve months ended June 30, 1999
Gas Other
Gas Marketing Products Corporate &
(Dollars in thousands) Utilities Electric Water & Storage & Services Adjustments Total
---------------------- ----------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 871,690 $ 1,297,885 $ 90,431 $ 718,267 $ 257,388 $ (167,713) $ 3,067,948
Other Net $ 3,125 $ 718 $ 956 $ 3,083 $ 1,537 $ (468) $ 8,951
Depreciation and
Amortization $ 94,145 $ 158,368 $ 11,003 $ 1,099 $ 13,573 $ 1,819 $ 280,007
Income before Interest
and Other Charges
and Income Taxes $ 99,637 $ 353,175 $ 26,463 $ 4,427 $ 7,913 $ (16,484) $ 475,131
Assets $ 2,297,127 $ 2,743,524 $ 643,283 $ 285,977 $ 694,450 $ (262,470) $ 6,401,891
Capital Expenditures $ 86,337 $ 129,189 $ 45,869 $ 689 $ 30,304 $ -- $ 292,388
Investment in
Equity-Method Investees $ -- $ -- $ -- $ 91,217 $ 151,605 $ -- $ 242,822
</TABLE>
<TABLE>
<CAPTION>
The following table reconciles total reportable segment income before interest
and other charges and income taxes to net income for three month, six month and
twelve month periods ended June 30, 2000 and 1999:
Three Months Six Months Twelve Months
Ended June 30, Ended June 30, Ended June 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Total Segment profit (loss) $ 91,857 $ 82,659 $274,042 $245,652 $471,896 $475,131
Interest expense, net (48,533) (40,314) (96,143) (77,002) (185,758) (144,361)
Minority interests (5,000) (5,668) (10,041) (8,376) (19,358) (9,439)
Dividends requirements on
preferred stock of subsidiaries (2,008) (2,077) (4,042) (4,193) (8,183) (8,436)
-------- -------- -------- -------- -------- --------
Income before income taxes 36,316 34,600 163,816 156,081 258,597 312,895
Less: Income taxes 12,903 11,656 60,787 56,578 94,657 109,673
-------- -------- -------- -------- -------- --------
Net Income $ 23,413 $ 22,944 $103,029 $ 99,503 $163,940 $203,222
======== ======== ======== ======== ======== ========
</TABLE>
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
HOLDING COMPANY
NiSource Inc. (NiSource), formerly NIPSCO Industries, Inc., is an
energy and utility-based holding company headquartered in Merrillville, Indiana,
that provides natural gas, electricity, water and related services to the public
for residential, commercial and industrial uses through a number of regulated
and non-regulated subsidiaries. NiSource was organized as an Indiana holding
company in 1987 under the name "NIPSCO Industries, Inc.," and 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.
NiSource's gas business is comprised primarily of regulated
gas utilities and gas transmission companies that operate throughout northern
Indiana and New England. In addition, NiSource expanded its gas marketing,
trading and storage operations with the April 1999 acquisition of TPC
Corporation, now renamed EnergyUSA-TPC Corp. (TPC) and its 1999 acquisition of
Market Hub Partners, L.P. (MHP). NiSource's electric business is comprised of a
regulated electric utility that operates in northern Indiana. The electric
business also includes wholesale sales and power trading activities. NiSource's
regulated gas and electric subsidiaries are collectively referred to as the
"Energy Utilities." NiSource's regulated water subsidiaries are collectively
called the "Water Utilities." Collectively, the Energy and Water Utilities are
referred to as the "Utilities."
Non-regulated energy and utility-related products and services are
provided through the "Products and Services" subsidiaries. Products and Services
subsidiaries perform energy-related services and offer products in connection
with these services, which include pipeline construction, repair and maintenance
of underground gas and water pipelines, locating and marking utility lines, real
estate development activity and development and operation of "inside the fence"
cogeneration plants.
In addition to the Utilities and the Products and Services
subsidiaries, NiSource has a wholly-owned subsidiary, NiSource Capital Markets,
Inc. (Capital Markets), which engages in financing activities for NiSource and
certain of its subsidiaries, excluding Northern Indiana Public Service Company
(Northern Indiana).
NET INCOME
Net income decreased $39.3 million from the twelve months ended June
30, 1999 to $164.0 million for the twelve months ended June 30, 2000 and
increased $3.5 million from the six months ended June 30, 1999 to $103.0 million
for the six months ended June 30, 2000 and increased $0.5 million from the three
months ended June 30, 1999 to $23.4 million for the three months ended June 30,
2000. Results for the three periods ended June 30 are not directly comparable
year to year due to the acquisition of BSG, TPC and MHP in 1999. NiSource
established its New England presence when it acquired BSG in February 1999. The
natural gas marketing, asset optimization and natural gas storage units of TPC
and MHP were also acquired in 1999.
GAS REVENUES
The gas revenues represent the combined revenues of gas utilities and
gas marketing and storage segments adjusted for intercompany transactions. Gas
revenues were $2.1 billion for the twelve months ended June 30, 2000 (after
elimination of intercompany transmission, marketing and storage revenue of
approximately $219.7 million), an increase of $640.2 million from the comparable
period ended June 30, 1999. This increase was primarily due to increased gas
revenues from BSG of $228.4 million reflecting a full twelve months of results,
increased gas marketing, storage and trading revenues of $349.9 as a result of
the TPC and MHP acquisitions in 1999, and increased pass through gas costs of
$95.2 million partially offset by decreased sales to the residential and
commercial customers of the Energy Utilities located in northern Indiana as a
result of warmer weather during the period. During the period, gas deliveries in
dekatherms (dth), which include transportation services, increased due to
increased gas marketing and storage activities and inclusion of BSG deliveries
partially offset by decreased deliveries to the those Energy Utilities located
in northern Indiana (Indiana Energy Utilities) residential and commercial
customers reflecting heating degree-days 3% lower than 1999.
Gas revenues were $1.3 billion for the six months ended June 30, 2000
(after elimination of intercompany transmission, marketing and storage revenue
of approximately $118.9 million) an increase of $426.8 million from the
comparable period ended June 30, 1999. This increase is attributable to
increased gas marketing, storage and trading revenues as a result of the TPC and
MHP acquisitions in 1999, inclusion of a full six months results from BSG in the
2000 period and the pass-through of increased gas costs partially offset by
decreased sales to the residential and commercial customers of the Indiana
Energy Utilities due to warmer weather than 1999. During the period, gas
deliveries in dth, which include transportation services, increased due to
increased gas marketing and storage activities and BSG deliveries, partially
offset by decreased gas deliveries to the Indiana Energy Utilities residential
and commercial customers reflecting heating degree-days 7% lower than 1999.
Gas revenues were $562.5 million for the three months ended June 30,
2000 (after elimination of intercompany transmission, marketing and storage
revenue of approximately $54.0 million) an increase of $253.9 million from the
comparable period ended June 30, 1999. This increase is attributable to
increased gas marketing, storage and trading revenues as a result of the TPC and
MHP acquisitions in 1999 and the pass-through of increased gas costs and
increased sales to residential and commercial customers. During the period, gas
deliveries in dth, which include transportation services, increased due to
increased gas marketing, storage and trading activities and increased deliveries
to residential and commercial customers.
Large commercial and industrial customers continue to utilize
transportation services provided by the Energy Utilities. 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 the Energy
Utilities' systems. The Energy Utilities transported 54.3, 122.4 and 236.1
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 16% of natural gas delivered
(including volumes transported) during the twelve months ended June 30, 2000.
<TABLE>
<CAPTION>
The components of the changes in gas revenues are shown in the following table:
-------------------------------------------
Ended June 30, 2000
-------------------------------------------
Three Six Twelve
(Dollars in thousands) Months Months Months
=========== =========== ===========
Gas Revenue Changes
Pass through of net changes in purchased gas costs,
<S> <C> <C> <C>
gas storage and storage transportation costs $ 37,603 $ 63,259 $ 95,156
Changes in sales levels 508 (26,667) (35,147)
Bay State Gas Acquisition -- 81,082 228,379
Gas transported 3,846 1,522 1,962
Gas marketing, storage and trading 211,942 307,628 349,880
----------- ----------- -----------
Gas Revenue Change $ 253,899 $ 426,824 $ 640,230
=========== =========== ===========
</TABLE>
GAS COSTS OF SALES
The gas costs represent the combined costs of the gas utilities and gas
marketing and storage segments adjusted for intercompany transactions. The gas
costs increased $515.0 million (48%) to $1.6 billion for the twelve months ended
June 30, 2000 from the comparable period ended June 30, 1999, due to the
increased gas costs of $114.3 million for BSG reflecting a full twelve months of
operations, increased gas marketing, storage and trading activities of $344.5
million as a result of the TPC and MHP acquisitions in 1999, and increased
purchased gas costs per dth for the Energy Utilities. The average cost for the
Energy Utilities' purchased gas for the period, after adjustment for gas
transition costs billed to transport customers, was $3.14 per dth, excluding
purchased gas costs of BSG, as compared to $2.41 per dth for the comparable
period ended June 30, 1999.
Gas costs increased $380.4 million (63%) to $985.1 million for the six
months ended June 30, 2000 from the comparable period ended June 30, 1999,
mainly due to increased gas purchases of $292.7 million related to gas marketing
and storage activities as a result of the TPC and MHP acquisitions in 1999,
increased gas cost of $47.3 million for BSG reflecting a full six months of
operations and deliveries and increased gas costs per dth for the Energy
Utilities. The average cost for the Energy Utilities' purchased gas for the
period, after adjustment for gas transition costs billed to transport customers,
was $3.16 per dth, excluding purchased gas costs of BSG, as compared to $2.33
per dth for the comparable period ended June 30, 1999.
Gas costs increased $241.1 million (107%) to $466.2 million for the
three months ended June 30, 2000 from the comparable period ended June 30, 1999,
mainly due to increased gas purchases of $214.2 million related to gas marketing
and storage activities as a result of the TPC and MHP acquisitions in 1999, and
increased gas costs per dth for the Energy Utilities. The average cost for the
Energy Utilities' purchased gas for the period, after adjustment for gas
transition costs billed to transport customers, was $4.14 per dth as compared to
$3.13 per dth for the comparable period ended June 30, 1999.
GAS OPERATING MARGIN
Gas operating margin for the twelve months ended June 30, 2000
increased $125.2 million to $512.4 million from the comparable period ended June
30, 1999. This increase mainly reflects an increase of $113.6 million reflecting
a full twelve months of gas operating margin from BSG and increased gas
marketing, storage and trading activities, partially offset by decreased
deliveries to Indiana Energy Utilities residential and commercial customers
reflecting a warmer heating season during the period.
Gas operating margin increased $46.4 million to $304.3 million during
the six months ended June 30, 2000 from the comparable period ended June 30,
1999. This increase mainly reflects an increase of $33.3 million reflecting
a full six months of gas operating margin from BSG and increased gas marketing,
storage and trading activities, partially offset by decreased deliveries to
Indiana Energy Utilities residential and commercial customers reflecting the
warmer heating season during the first quarter of 2000 from the comparable
period ended June 30, 1999.
Gas operating margin increased $12.8 million to $96.3 million during
the three months ended June 30, 2000 from the comparable period ended June 30,
1999. This increase mainly reflects an increase of $12.7 million of gas
marketing, storage and trading activities.
ELECTRIC REVENUES
Electric revenues were $1.1 billion for the twelve months ended June
30, 2000 (after elimination of intercompany transactions of approximately $2.6
million), a decrease of $194.5 million from the comparable period ended June 30,
1999. Sales of electricity in kilowatt-hours (kwh) decreased 26% from the
comparable period ended June 30, 1999. Electric revenues decreased as a result
of significantly reduced non-regulated wholesale sales and power marketing
transactions, partially offset by increased electric sales to commercial
customers due to warmer weather during the third quarter of 1999, and increased
industrial sales.
Electric revenues were $514.8 million for the six months ended June 30,
2000 (after elimination of intercompany transactions of approximately $1.3
million), a decrease of $21.0 million from the comparable period ended June 30,
1999. Sales of electricity in kwh decreased 8% from the comparable period ended
June 30, 1999. Electric revenues decreased as a result of reduced regulated and
non-regulated wholesale sales and power marketing transactions partially offset
by increased electric sales to commercial and industrial customers.
Electric revenues were $259.2 million for the three months ended June
30, 2000 (after elimination of intercompany transactions of approximately $0.6
million), a decrease of $12.1 million from the comparable period ended June 30,
1999. Sales of electricity in kwh decreased 6% from the comparable period ended
June 30, 1999. Electric revenues decreased as a result of reduced regulated and
non-regulated wholesale sales and power marketing transactions and reduced
residential sales partially offset by increased electric sales to commercial and
industrial customers.
The basic steel industry accounted for 33% of electric sales during the
twelve months ended June 30, 2000.
<TABLE>
<CAPTION>
The components of the changes in electric revenues are shown in the following
table:
-------------------------------------------
Ended June 30, 2000
-------------------------------------------
Three Six Twelve
(Dollars in thousands) Months Months Months
=========== =========== ===========
Electric Revenue Changes
<S> <C> <C> <C>
Pass through of net changes in fuel costs $ (2,724) $ (5,540) $ 2,716
Changes in sales levels (1,931) 8,261 36,090
Wholesale sales and power marketing (7,475) (23,716) (233,265)
----------- ----------- -----------
Electric Revenue Change $ (12,130) $ (20,995) $ (194,459)
=========== =========== ===========
</TABLE>
ELECTRIC COST OF SALES
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, for the six months ended June
30, 2000.
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, for the three
months ended June 30, 2000.
POWER PURCHASED
Power purchased decreased $218.2 million to $47.5 million for the
twelve months ended June 30, 2000 from the comparable period ended June 30,
1999. The decrease is a result of decreased wholesale sales and power marketing
activities.
Power purchased decreased $24.2 million and $10.4 million to $15.3
million and $7.0 million, respectively, for the six and three months ended June
30, 2000 from the comparable periods ended June 30, 1999. The decrease is a
result of decreased cost per kwh, decreased wholesale sales and power marketing
activities.
ELECTRIC OPERATING MARGIN
Operating margin from electric sales increased $22.1 million to $805.3
million for the twelve months ended June 30, 2000 from the comparable period
ended June 30, 1999. This increase occurred mainly due to improved margins on
wholesale sales and power marketing transactions and increased sales to
commercial and industrial customers offset by decreased residential sales.
Operating margin from electric sales increased $5.2 million to $385.5
million for the six months ended June 30, 2000 from the comparable period ended
June 30, 1999. This increase occurred mainly due to improved margins on
wholesale sales and power marketing transactions and increased sales to
commercial and industrial customers offset by decreased residential sales.
Operating margin from electric sales decreased $0.6 million to $195.7
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 also due to decreased sales to residential
customers partially offset by improved margins on wholesale sales and power
marketing transactions and increased sales to commercial and industrial
customers.
WATER REVENUE
Water revenues were $101.4 million for the twelve months ended June 30,
2000 (after elimination of intercompany transactions of approximately $0.2
million for the twelve months ended June 30, 2000), an increase of $11.1 million
from the comparable period ended June 30, 1999. This increase was primarily due
to increased water volumes sold and the increase in base rates for IWC.
Water revenues were $47.9 million for the six months ended June 30,
2000 (after elimination of intercompany transactions of approximately $0.2
million for the six months ended June 30, 2000), an increase of $3 million from
the comparable period ended June 30, 1999. This increase was primarily due to
increased water volumes sold and the increase in base rates for IWC.
Water revenues were $24.9 million for the three months ended June 30,
2000 (after elimination of intercompany transactions of approximately $0.1
million for the three months ended June 30, 2000), an increase of $1 million
from the comparable period ended June 30, 1999. This increase was primarily due
to increased water volumes sold.
<TABLE>
<CAPTION>
The components of the changes in water revenues are shown in the following
table:
-------------------------------------------
Ended June 30, 2000
-------------------------------------------
Three Six Twelve
(Dollars in thousands) Months Months Months
=========== =========== ===========
Water Revenue Changes
<S> <C> <C> <C>
Rate increase $ -- $ 1,160 $ 5,102
Changes in sales levels 952 1,836 5,964
----------- ----------- -----------
Water Revenue Change $ 952 $ 2,996 $ 11,066
=========== =========== ===========
</TABLE>
PRODUCTS AND SERVICES REVENUES
Products and Services revenues were $286.5 million for the twelve
months ended June 30, 2000 (after elimination of intercompany transactions of
approximately $14.7 million), an increase of $43.4 million from the comparable
period ended June 30, 1999. This increase reflects increased line locating and
marking activity, increased pipeline construction activity, increased revenue
from a new cogeneration facility, which began commercial operations in August
1998, and the inclusion of revenue of BSG's unregulated subsidiaries commencing
in February 1999.
Products and Services revenues were $138.5 million for the six months
ended June 30, 2000 (after elimination of intercompany transactions of
approximately $6.2 million), an increase of $14.8 million from the comparable
period ended June 30, 1999. This increase reflects $12.3 million of increased
line locating and marking activity, increased pipeline construction activity and
increased revenue from the cogeneration facility offset by lower revenue from
the energy-related service companies.
Products and Services revenues were $76.3 million for the three months
ended June 30, 2000 (after elimination of intercompany transactions of
approximately $2.9 million), an increase of $4.9 million from the comparable
period ended June 30, 1999. This increase reflects increased line locating and
marking activity, increased revenue from the cogeneration facility, and
increased pipeline construction activity offset by lower revenue from the
energy-related service companies and lower real estate sales.
<TABLE>
<CAPTION>
The components of the changes in operating revenues at Products and Services are
shown in the following table:
-------------------------------------------
Ended June 30, 2000
-------------------------------------------
Three Six Twelve
(Dollars in thousands) Months Months Months
=========== =========== ===========
Products and Services Revenue Changes
<S> <C> <C> <C>
Pipeline construction $ 2,879 $ 5,325 $ 10,734
Locate and marking 7,033 12,332 16,064
Cogeneration project 3,613 3,068 10,381
Other (8,621) (5,953) 6,208
----------- ----------- -----------
Products and Services Revenue Change $ 4,904 $ 14,772 $ 43,387
=========== =========== ===========
</TABLE>
PRODUCTS AND SERVICES COST OF SALES
The cost of sales for Products and Services increased $38.4 million to
$159.4 million for the twelve months ended June 30, 2000 from the comparable
period ended June 30, 1999. This increase reflects the inclusion of cost of
sales from February 1999 for certain subsidiaries acquired in connection with
the BSG acquisition, and increased pipeline construction activity and line
locating and marking activities.
The cost of sales for Products and Services increased $16.7 million to
$79.3 million for the six months ended June 30, 2000 from the comparable period
ended June 30, 1999 mainly due to the increase in the cost of sales for the line
locating and marking subsidiaries and pipeline construction partially offset by
decreased project costs at the energy-related service subsidiaries.
The cost of sales for Products and Services increased $7.5 million to
$44.5 million for the three months ended June 30, 2000 from the comparable
period ended June 30, 1999 mainly due to the increase in the cost of sales for
the line locating and marking subsidiaries and pipeline construction partially
offset by decreased project costs at the energy-related service subsidiaries.
PRODUCTS AND SERVICES OPERATING MARGIN
Products and Services operating margin increased $5.0 million to $127.1
million for the twelve months ended June 30, 2000, reflecting a new cogeneration
facility, which began commercial operations in August 1998, increased pipeline
construction activity and the inclusion of the operating margin of certain
subsidiaries acquired in connection with the BSG acquisition, offset by a
decrease in line locating and marking subsidiary margin.
Products and Services operating margin decreased $2.0 million to $59.2
million for the six months ended June 30, 2000, reflecting increased
cogeneration facility margin and pipeline construction activity and the
inclusion of certain subsidiaries acquired in connection with the BSG
acquisition offset by a decrease in line locating and marking subsidiary
margin and a decrease in real estate sales activity.
Products and Services operating margin decreased $2.6 million to $31.7
million for the three months ended June 30, 2000, reflecting increased
cogeneration facility margin offset by decreased pipeline construction activity
and a decrease in line locating and marking subsidiary margin and a decrease
in real estate sales activity.
OPERATING EXPENSES AND TAXES (EXCEPT INCOME)
Operating expenses and taxes (except income) increased $140.6 million
to $1,057.2 million for the twelve months ended June 30, 2000 from the
comparable period ended June 30, 1999. Operating expenses and taxes (except
income) increased $25.2 million to $528.6 million for the six months ended
June 30, 2000 from the comparable period ended June 30, 1999. Operating
expenses and taxes (except income) increased $6.2 million to $259.4 million for
the three months ended June 30, 2000 from the comparable period ended June 30,
1999.
The operation and maintenance expenses of the Energy Utilities
increased $42.7 million to $424.5 million for the twelve months ended June 30,
2000 from the comparable period ended June 30, 1999. The increase was primarily
due to an increase of $53.2 million of operation expenses from BSG reflecting a
full twelve months expenses, increased expenses for distributed generation and
fuel cell research and development of $1.9 million and increased employee
related costs of $9.2 million partially offset by a $13 million insurance
settlement in the 1999 period related to manufactured gas plants site cleanup
costs and decreased operating costs for electric production facilities of $2.3
million. The unregulated gas and electric businesses operation expenses
increased $10.2 million to $18.1 million for the twelve months ended June 30,
2000 primarily due to the inclusion of $12.9 million of TPC operation costs.
Operation expenses at the Water Utilities increased $3.9 million to $50.2
million for the twelve months ended June 30, 2000 from the comparable period
ended June 30, 1999 due to increased water treatment and employee related costs.
Operation expenses for Products and Services increased $3.6 million to $113.5
million for the twelve months ended June 30, 2000 from the comparable period
ended June 30, 1999 reflecting the inclusion of operation expense of BSG's
unregulated subsidiaries from February 1999, and a full year of operation costs
for a new cogeneration facility which began commercial operation during 1998.
Operation expenses for the twelve months ended June 30, 2000 also
include charges of $13.1 million for professional fees and filing costs incurred
during 1999 in connection with the tender offer for CEG.
The operation and maintenance expenses of the Energy Utilities
increased $1.2 million to $218.5 million for the six months ended June 30, 2000
from the comparable period ended June 30, 1999. This increase was primarily due
to increased operation expenses from BSG of $11.1 million reflecting a full six
months expenses, partially offset by decreased employee related costs of $6.2
million and other decreased operation costs. The unregulated gas and electric
businesses operation expenses increased $5.2 million to $10.5 million for the
six month ended June 30, 2000 from the comparable period ended June 30, 1999
primarily due to the inclusion of a full six months of TPC operation costs.
Operation expenses at the Water Utilities increased $1.9 million to $25.3
million for the six months ended June 30, 2000 from the comparable period ended
June 30, 1999 due to increased employee related costs. Operation expenses for
Products and Services decreased $0.04 million to $56.4 million for the six month
ended June 30, 2000 from the comparable period ended June 30, 1999 reflecting
increased operating expenses at the cogeneration facility and an increase in
line locating and marking subsidiary and pipeline construction operation
subsidiaries expenses.
The operation and maintenance expenses of the Energy Utilities
decreased $0.2 million to $109.6 million for the three months ended June 30,
2000 from the comparable period ended June 30, 1999. This decrease was primarily
due to decreased employee related costs and other decreased operation costs.
The unregulated gas and electric businesses operation expenses increased $1.7
million to $5.0 million for the three month ended June 30, 2000 from the
comparable period ended June 30, 1999 primarily due to the inclusion of a full
three months of TPC operation costs. Operation expenses at the Water Utilities
increased $0.9 million to $12.5 million for the three months ended June 30, 2000
from the comparable period ended June 30, 1999 due to increased employee related
costs. Operation expenses for Products and Services increased $0.6 million to
$29.0 million for the three month ended June 30, 2000 from the comparable
period ended June 30, 1999 reflecting increased operating expenses at the
cogeneration facility and an increase in line locating and marking subsidiary
operation expenses.
Depreciation and amortization expenses increased $50.0 million to
$330.0 million for the twelve months ended June 30, 2000 from the comparable
period ended June 30, 1999, primarily resulting from increased depreciation and
amortization expense from BSG of $26.7 million reflecting a full twelve months
expenses, increased depreciation and amortization from TPC of $7.3 million as a
result of the acquisitions of TPC and increased depreciation expense at the
Energy and Water Utilities due to plant additions.
Depreciation and amortization expenses increased $18.7 million to
$169.1 million for the six months ended June 30, 2000 from the comparable
periods ended June 30, 1999, primarily resulting from increased depreciation and
amortization expense from BSG of $7.1 million and from TPC of $5.2 million
reflecting a full six months expenses and increased depreciation expense at the
Energy and Water Utilities due to plant additions.
Depreciation and amortization expenses increased $7.0 million to $84.6
million for the three months ended June 30, 2000 from the comparable periods
ended June 30, 1999, primarily resulting from increased depreciation and
amortization expense from TPC of $2.2 million reflecting a full three months
expenses, increased depreciation and amortization expense from BSG of $1.9
million and increased depreciation expense at the Energy and Water Utilities due
to plant additions.
Taxes (except income) increased $2.2 million to $99.1 million for the
twelve months ended June 30, 2000, from the comparable period ended June 30,
1999 primarily as the result of the inclusion of a full twelve months expenses
from BSG, offset by decreased property tax expense at Northern Indiana..
Taxes (except income) decreased $4.4 million to $48.8 million for the
six months ended June 30, 2000 from the comparable period ended June 30, 1999,
primarily as the result of decreased property tax expense at Northern Indiana.
Taxes (except income) decreased $4.6 million to $20.6 million for the
three months ended June 30, 2000 from the comparable period ended June 30, 1999,
primarily as the result of decreased property tax expense at Northern Indiana
partially offset by increased expenses from BSG and TPC.
INTEREST EXPENSE, NET
Interest expense, net increased $41.4 million to $185.8 million for the
twelve months ended June 30, 2000 from the comparable period ended June 30,1999.
This increase reflects the inclusion of a full twelve months of interest expense
from BSG of $22.8 million, interest on the September 1999 issuance of $160
million in Puttable Reset Securities (PURS) and increased interest expense on
higher short-term borrowings.
Interest expense, net increased $19.1 million to $96.1 million for the
six months ended June 30, 2000 from the comparable periods ended June 30,1999.
This increase reflects the inclusion of six months of interest charges for BSG,
interest on the September 1999 issuance of $160 million in Puttable Reset
Securities (PURS) and increased interest expense on higher short-term borrowings
Interest expense, net increased $8.2 million to $48.5 million for the
three months ended June 30, 2000 from the comparable periods ended June 30,1999.
This increase reflects the interest on the September 1999 issuance of $160
million in Puttable Reset Securities (PURS) and increased interest expense on
higher short-term borrowings
MINORITY INTERESTS
Minority interest increased $9.9 million and $1.7 million and decreased
$0.7 million for the twelve months, six months and three months ended June 30,
2000, respectively, from the comparable periods ended June 30, 1999. The
increases for the twelve month and six month periods reflect the inclusion of
dividends paid on Company-obligated mandatorily redeemable Preferred Securities
issued in February 1999.
OTHER, NET
Other, net decreased $26.0 million to a loss of $17.1 million for the
twelve months ended June 30, 2000 from the comparable period ended June 30,
1999, primarily reflecting the impact of adverse economic conditions on certain
equity investments, the most significant of which was in oil and gas
development. NiSource also decided to abandon certain businesses and facilities
that were not consistent with its strategic direction.
Other, net increased $1.0 million and $4.8 million to $5.8 million and $2.5
million for the six months and three months ended June 30, 2000 from the
comparable period ended June 30, 1999. This increase reflects improved operating
results from a cogeneration facility equity investment.
INCOME TAXES
Income taxes decreased $15.0 million to $94.7 million for the twelve
months ended June 30, 2000 from the comparable period ended June 30, 1999. This
decrease is primarily a result of decreased pre-tax income.
Income taxes increased $4.2 million to $60.8 million for the six months
ended June 30, 2000 from the comparable period ended June 30, 1999. This
increase is primarily as a result of an increase in pre-tax income and higher
effective income tax rate.
Income taxes increased $1.2 million to $12.9 million for the three
months ended June 30, 2000 from the comparable period ended June 30, 1999. This
increase is primarily as a result of an increase in pre-tax income and higher
effective income tax rate.
See Notes to Consolidated Financial Statements for a discussion of
accounting policies and transactions impacting this analysis.
ENVIRONMENTAL MATTERS
The operations of NiSource are subject to extensive and evolving
federal, state and local environmental laws and regulations intended to protect
the public health and the environment. Such environmental laws and regulations
affect NiSource's operations as they relate to impacts on air, water and land.
Refer to "Environmental Matters" in the Notes to Consolidated Financial
Statements for information regarding certain environmental issues.
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, $408.0 million
and $299.6 million of commercial paper was outstanding, respectively. The
weighted average interest rate on commercial paper outstanding as of June 30,
2000 was 6.92%.
NiSource and its subsidiaries may borrow under two five-year, $100
million revolving credit agreements that terminate on September 23, 2003 and two
364-day $100 million revolving credit agreements that terminate on September 23,
2000. NiSource expects that the 364-day agreements will 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 short-term periods. These agreements provide
financing flexibility and may be used to support the issuance of commercial
paper. At June 30, 2000, there were no borrowings outstanding under these
agreements.
In addition, various NiSource subsidiaries maintain lines of credit for
up to an aggregate of $159.7 million with lenders at either the lender's
commercial prime or market lending rates. As of June 30, 2000, there were $33.3
million of borrowings outstanding under these lines of credit with a weighted
average interest rate of 7.40%. As of December 31, 1999, there were $54.1
million of borrowings outstanding under these lines of credit.
NiSource and its subsidiaries maintain money market lines of credit for
up to $379.5 million. As of June 30, 2000, there were $248.9 million outstanding
under these money market lines of credit at a weighted average interest rate of
7.08%. At December 31, 1999, there were $156.2 million of borrowings outstanding
under these money market lines of credit.
Eighty million dollars in medium-term notes were issued in February
1999. The medium-term notes, which were used in part to reduce existing credit
facilities, consist of $35.0 million in ten-year notes that bear interest at
5.99% interest per annum and $45.0 million in twenty-year notes that bear
interest at 6.61% per annum.
In February 1999 an underwritten public offering of Corporate Premium
Income Equity Securities (Corporate PIES) was completed. The net proceeds of
approximately $334.7 million were primarily used to refinance the short-term
borrowings incurred to pay the cash portion of the acquisition cost of BSG, and
repay other short-term indebtedness. In September 1999, Capital Markets issued
$160 million of PURS in an underwritten public offering and the underwriters
acquired a call option to purchase the PURS on September 28, 2000. The net
proceeds from the sale of the PURS of $162.4 million were also used to refinance
short-term indebtedness incurred in connection with the acquisition of BSG in
February 1999. See "Short-Term Borrowings" in the Notes to the Consolidated
Financial Statements for a description of the Corporate PIES and the PURS. (See
Note 18 and 19)
On February 28, 2000, NiSource and Columbia Energy Group (CEG) entered
into a merger agreement pursuant to which NiSource agreed to acquire CEG for
approximately $6 billion, plus the assumption of approximately $2.5 billion of
CEG debt. The merger will be accomplished through the creation of a new holding
company. Each NiSource common share will be exchanged for one common share of
the new holding company. Each CEG share will be exchanged for $70.00 in cash
plus $2.60 principal amount of a unit issued by the new holding company
(consisting of a zero coupon debt security coupled with a forward equity
contract) or, at the election of the CEG shareholder, $74.00 in new holding
company stock, based on the average NiSource share price prior to the closing,
but not more than 4.4848 shares of new holding company stock, for each CEG
share. Stock elections will be subject to proration if they are made with
respect to more than 30% of CEG's outstanding shares. No exchange of shares will
occur unless at least 10% of CEG's outstanding shares elect to exchange for
shares of the new holding company. The merger is conditioned upon the receipt of
a number of approvals. Approval of the NiSource and CEG shareholders was
obtained on June 1 and June 2, respectively. As of July 26, 2000, all actions
needed from state utility regulatory commissions and from FERC had been
received. The Securities and Exchange Commission must still approve the merger
under the Public Utility Holding Company Act.
NiSource has accepted a commitment letter under which certain financial
institutions agreed, under specified conditions, to provide up to $6.0 billion
to finance the acquisition of CEG. The commitment letter contemplates a
revolving credit facility expiring in July 2001, with the right to convert loans
outstanding at that time into term loans maturing 364 days thereafter. NiSource
has hedged the interest rate risk associated with $1.1 billion of its
anticipated refinancing of such debt.
The Energy Utilities do not anticipate the need to file for retail gas
or electric base rate increases in the near future. IWC has agreed to a
moratorium on water rate increases until 2002. BSG has a rate freeze until
November 2004.
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 9, 2000, no further orders have been issued in
this proceeding.
CONSTRUCTION PROGRAM. Future Commitments with respect to the 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 NiSource's energy businesses and
activities. The extent to which NiSource properly and effectively identifies,
assesses, monitors and manages each of the various types of risk involved in its
businesses is critical to its profitability. NiSource seeks to identify, assess,
monitor and manage, in accordance with defined policies and procedures, the
following principal risks involved in NiSource's energy businesses: commodity
market risk, interest rate risk, credit risk and foreign currency risk. Risk
management at NiSource is a multi-faceted process with independent oversight
that requires constant communication, judgment and knowledge of specialized
products and markets. NiSource'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, NiSource's risk management
policies and procedures are evolving and subject to ongoing review and
modification.
NiSource is exposed to risk through various daily business activities,
including specific trading risks and non-trading risks. The non-trading risks to
which NiSource is exposed include interest rate risk, foreign currency risk and
commodity price risk of its Energy Utilities and certain gas marketing
activities. The market risk resulting from trading activities consists primarily
of commodity price risk. NiSource'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 NiSource 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. NiSource 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. NiSource employs a VaR model to assess the market risk of
its energy trading portfolios. NiSource estimates the one-day VaR across all
trading groups which utilize derivatives using either Monte Carlo simulation or
variance/covariance at a 95% 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, $0.5 million, $1.8
million and $0.004 million and $0.5 million, $1.8 million and $0.004 million for
the three month, six month and twelve month periods ended June 30, 2000,
respectively. The daily VaR for the gas trading portfolio on an average, high
and low basis was $3.4 million, $8.1 million and $0.7 million, $2.7 million,
$8.1 million and $0.5 million and $2.4 million, $8.1 million and $0.4 million
for the three month, six month and twelve month periods ended June 30, 2000,
respectively. NiSource 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 at the Energy Utilities is limited, since current
regulations allow the Energy Utilities to recoup any prudently incurred
purchased power, fuel and gas costs through rate-making. As the utility industry
undergoes deregulation, however, the Energy Utilities will be providing services
without the benefit of the traditional rate-making and, therefore, will be more
exposed to commodity price risk. Additionally, NiSource 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.
NiSource utilizes derivative financial instruments to reduce the commodity price
risk based on modeling techniques to anticipate these future supply
requirements.
INTEREST RATE RISK. NiSource 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 $870 million and
$679 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 $7.3 million and $3.7
million for the three months, $13.8 million and $7.0 million for the six months
and $25.4 million and $14.0 million for the twelve months ending June 30, 2000
and June 30, 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 NiSource's business activities. In
sales and trading activities, credit risk arises because of the possibility that
a counterparty will not be able or willing to fulfill its obligations on a
transaction on or before settlement date. In derivative activities, credit risk
arises when counterparties to derivative contracts, such as interest rate swaps,
are obligated to pay NiSource 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 NiSource's exposures vary with changes
in market prices, NiSource also estimates the potential credit exposure over the
remaining term of transactions through statistical analyses of market prices. In
determining exposure, NiSource considers collateral and master netting
agreements, which are used to reduce individual counterparty risk, primarily in
connection with derivative products.
FOREIGN CURRENCY RISK. NiSource is exposed to foreign currency risk arising from
equity investments in businesses owned and operated in foreign countries.
Exposures to these investments are periodically reviewed by management and are
not material to consolidated results.
Refer to Consolidated Statement of Long-Term Debt for detailed
information related to NiSource's long-term debt outstanding and "Fair Value of
Financial Instruments" in Notes to the Consolidated Financial Statements for
current market valuation of long-term debt. Refer to "Summary of Significant
Accounting Policies--Accounting for Price Risk Management Activities" in Notes
to the Consolidated Financial Statements for further discussion of NiSource's
risk management.
Refer to "Risk Management Activities" in Notes to the Consolidated
Financial Statements for a discussion of commodity-based derivative financial
instruments and risk management.
COMPETITION AND REGULATORY CHANGES
The regulatory frameworks applicable to the Energy Utilities, at both
the state and federal levels, are undergoing fundamental changes. These changes
have previously had, and will continue to have an impact on NiSource'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 partnering on energy
projects with major industrial customers, converting some of its generating
units to allow use of lower cost, low sulfur coal, providing its gas customers
with increased choice for new products and services, acquiring companies which
increase NiSource's scale and establishing subsidiaries that provide gas and
develop new energy-related products for residential, commercial and industrial
customers, including the development of distributed generation technologies.
THE ELECTRIC INDUSTRY. At the Federal level, the Federal Energy Regulatory
Commission (FERC) issued Order No. 888-A in 1996 which required all public
utilities owning, controlling or operating transmission lines to file
non-discriminatory open-access tariffs and offer wholesale electricity suppliers
and marketers the same transmission service they provide themselves. On June 30,
2000, the D. C. Circuit Court of Appeals upheld FERC's open access orders in all
major respects. In 1997, FERC approved Northern Indiana's open-access
transmission tariff. On December 20, 1999, FERC issued a final rule addressing
the formation and operation of Regional Transmission Organizations (RTOs). The
rule is intended to eliminate pricing inequities in the provision of wholesale
transmission service. NiSource is committed to joining a RTO. NiSource 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, NiSource announced in 1997 and 1998 that if a
consensus could be reached regarding electric utility restructuring legislation,
NiSource would support a restructuring bill before the Indiana General Assembly.
During 1999, discussions were held with the other investor-owned utilities in
Indiana and with other segments of the Indiana electric industry regarding the
technical and economic aspects of possible legislation leading to greater
customer choice. A consensus was not reached. Therefore, NiSource 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-1980s 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 the Energy Utilities or directly from competing producers
and marketers, which would then use the Energy Utilities' 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 NiSource
service area the right to choose alternative gas suppliers. Phase II of Northern
Indiana's Customer Choice Pilot Program commenced 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 NiSource's natural gas marketing subsidiary to participate as a
supplier of choice to Northern Indiana customers. In addition, as Northern
Indiana has allowed residential and commercial customers to designate
alternative gas suppliers, it has also offered new services to all classes of
customers including price protection, negotiated sales and services, gas lending
and parking, and new storage services.
In Massachusetts, BSG implemented new unbundled rates and services for
all commercial-industrial customers in 1993, and launched one of the nation's
earliest residential and small commercial-industrial customer choice pilot
programs in 1996. The BSG pilot, concluded on June 1, 2000 when all
Massachusetts gas utilities began making unbundled gas service available to all
customer classes pursuant to new statewide model terms and conditions that are
currently awaiting approval by the Massachusetts Department of
Telecommunications and Energy.
In New Hampshire, Northern Utilities introduced unbundled tariffs and
services for all commercial-industrial customers in 1994. In 1998, the New
Hampshire Public Utilities Commission (NHPUC) formed a collaborative group to
investigate the merits of further unbundling and advise the NHPUC accordingly.
The collaborative group has recommended new model terms and conditions and
regulations designed to make unbundled services available to all
commercial-industrial customers statewide on November 1, 2000, with
consideration of residential unbundling at a later date. A hearing before the
NHPUC regarding the recommendations was held in April.
In Maine, Northern Utilities introduced unbundled rates and services
for large commercial-industrial customers in December 1995 and expanded the
availability to all daily metered commercial and industrial customers on
November 1, 1999. In June 1999 the Maine Public Utilities Commission opened an
inquiry into the potential merits of further regulatory changes related to
unbundling. Comments from all participating parties were submitted at the time
of the technical session in July 1999. This inquiry is intended to investigate
all the key elements of full customer choice and will include a review of
customer choice programs in Massachusetts and New Hampshire. Northern Utilities
is currently awaiting the Commission's proposed model terms and conditions as
the next step.
To date, the Energy Utilities have not been materially affected by
competition and management does not foresee substantial adverse affects in the
near future unless the current regulatory structure is substantially altered.
NiSource 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. NiSource 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 these
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 NiSource's subsidiaries, 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 NiSource's control.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For a discussion of primary market risks and risk management policy, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations- Market Risk Sensitive Instruments and Positions."
<PAGE>
PART II.
OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
NiSource and its subsidiaries are parties to various pending proceedings,
including suits and claims against them for personal injury, death and property
damage. Such proceedings and suits, and the amounts involved, are routine
litigation and proceedings for the kinds of businesses conducted by NiSource and
its subsidiaries, except as described under Note 4 (Litigation) and Note 5
(Environmental Matters) in the notes to consolidated financial statements under
Part I, Item 1 of this Report on Form 10-Q, which notes are incorporated by
reference. No other material legal proceedings against NiSource or its
subsidiaries are pending or, to the knowledge of NiSource, contemplated by
governmental authorities or other parties.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES.
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
On June 1, 2000, at the Annual Meeting of Shareholders, the shareholders 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, John
W. Thompson and Roger A. Young, whose terms expire at the 2002 Annual Meeting of
Shareholders, and Steven C. Beering, Dennis E. Foster, James T. Morris and
Carolyn Y. Woo, whose terms expire at the 2001 Annual Meeting of Shareholders.
<TABLE>
<CAPTION>
There were no abstentions or broker non-votes for any of the nominees
for director. The number of votes cast for, or withheld, for each director was
as follows:
VOTES VOTES
RECEIVED WITHHELD
<S> <C> <C>
ARTHUR J. DECIO 96,389,067 2,774,601
GARY L. NEALE 96,406,544 2,757,124
ROBERT J. WELSH 96,467,992 2,695,675
</TABLE>
Additionally at the Annual Meeting of Shareholders, the shareholders
approved the merger agreement between the Company and Columbia Energy Group
which provides for the formation of a new Delaware holding company which will
acquire Columbia Energy Group and into which the Company will be merged. The
shareholders also approved a change in the name of the new Delaware holding
company to NiSource Inc. which will occur immediately following the merger of
the Company into the new holding company. The proposal was approved by a vote of
79,091,253 shares in favor of the proposal, with 3,377,498 shares voted against
or withheld.
Also at the Annual Meeting of Shareholders, the shareholders approved
an Amended and Restated 1994 Long-Term Incentive Plan by a vote of 66,142,495
shares in favor of the proposal, with 16,319,200 shares voted against or
withheld.
ITEM 5. OTHER INFORMATION.
None
<PAGE>
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 10.1 - NiSource Inc. 1994 Long-Term Incentive Plan (Amended and
Restated) Effective January 1, 2000.
Exhibit 23 - Consent of Arthur Andersen LLP
Exhibit 27 - Financial Data Schedule
Pursuant to Item 601(b)(4)(iii) of Regulation S-K, NiSource hereby
agrees to furnish the SEC, upon request, any instrument defining the
rights of holders of long-term debt of NiSource not filed as an exhibit
herein. No such instrument authorizes long-term debt securities in
excess of 10% of the total assets of NiSource and its subsidiaries on a
consolidated basis.
(b) Reports on Form 8-K.
A report on Form 8-K was filed April 3, 2000. All events were reported
under Item 5, Other Events. A report on Form 8-K was filed April 25,
2000. All events were reported under Item 5, Other Events. A report on
Form 8-K was filed June 13, 2000. All events were reported under Item
5, Other Events.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NiSource Inc.
(Registrant)
/s/ STEPHEN P. ADIK
---------------------------------------------------------
Stephen P. Adik
Senior Executive Vice President, Chief Financial Officer,
Treasurer and Chief Accounting Officer
Date: August 11, 2000
