<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 September 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 October 30, 2000, 121,378,548 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 of NiSource Inc. (an
Indiana corporation) and subsidiaries as of September 30, 2000 and December 31,
1999, and the related consolidated statements of income, common shareholders'
equity and cash flows for the three, nine and twelve month periods ended
September 30, 2000 and 1999. These consolidated financial statements are the
responsibility of 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 September 30, 2000 and December 31, 1999, and the
results of their operations and their cash flows for the three, nine and twelve
month periods ended September 30, 2000 and 1999, in conformity with accounting
principles generally accepted in the United States.
Arthur Andersen LLP
Chicago, Illinois
October 30, 2000
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheet
September 30, December 31,
(Dollars in thousands) 2000 1999
Assets ============= =============
Property, Plant and Equipment:
Utility Plant, (including Construction Work in
Progress of $304,726 and $240,637, respectively)
<S> <C> <C>
Electric $ 4,307,752 $ 4,237,427
Gas 2,914,506 2,871,824
Water 788,572 750,376
Common 385,520 381,486
------------- -------------
8,396,350 8,241,113
Less -Accumulated depreciation and amortization 3,622,681 3,444,311
------------- -------------
Net Utility Plant 4,773,669 4,796,802
------------- -------------
Other property, at cost, less accumulated provision for
depreciation of $70,617 and $56,414, respectively 127,841 427,190
------------- -------------
Total Property, Plant and Equipment 4,901,510 5,223,992
------------- -------------
Investments:
Investments, at equity 105,033 118,259
Investments, at cost 60,451 55,851
Other investments 34,345 32,839
------------- -------------
Total Investments 199,829 206,949
------------- -------------
Current Assets:
Cash and cash equivalents 51,029 43,533
Accounts receivable, less reserve of $22,192 and
$30,619, respectively 393,152 381,818
Other receivables 32,064 15,744
Fuel adjustment clause -- 4,201
Gas cost adjustment clause 94,280 86,690
Materials and supplies, at average cost 63,752 64,530
Electric production fuel, at average cost 26,521 31,968
Natural gas in storage 190,928 63,750
Price risk management assets 447,219 90,705
Prepayments and other 45,774 41,884
------------- -------------
Total Current Assets 1,344,719 824,823
------------- -------------
Other Assets:
Regulatory assets 205,958 214,442
Intangible assets, net of accumulated amortization 75,183 139,337
Prepayments and other 356,968 289,061
------------- -------------
Total Other Assets 638,109 642,840
------------- -------------
$ 7,084,167 $ 6,898,604
============= =============
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheet
September 30, December 31,
(Dollars in thousands) 2000 1999
Capitalization and Liabilities ============= =============
Capitalization:
Common shareholders' equity
<S> <C> <C>
(See accompanying statement) $ 1,352,065 $ 1,353,504
Preferred stocks-
Northern Indiana Public Service Company:
Series without mandatory redemption provisions 81,114 81,114
Series with mandatory redemption provisions 52,180 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 1,737,291 1,975,184
------------- -------------
Total Capitalization 3,570,167 3,813,329
------------- -------------
Current Liabilities:
Current portion of long-term debt 89,420 173,721
Short-term borrowings 748,608 679,321
Accounts payable 368,020 277,358
Dividends declared on common and preferred stocks 33,679 34,535
Customer deposits 31,062 28,736
Taxes accrued 26,478 42,853
Interest accrued 27,425 34,157
Fuel adjustment clause 1,421 --
Accrued employment costs 61,717 60,647
Price risk management liabilities 453,302 113,029
Other 126,442 90,245
------------- -------------
Total Current Liabilities 1,967,574 1,534,602
------------- -------------
Other:
Deferred income taxes 931,922 998,682
Deferred investment tax credits, being amortized over
life of related property 89,217 94,946
Deferred credits 112,609 94,058
Customer advances and contributions in aid of construction 157,475 140,562
Accrued liability for postretirement benefits 169,305 157,517
Other noncurrent liabilities 85,898 64,908
------------- -------------
Total Other 1,546,426 1,550,673
------------- -------------
Commitments and Contingencies (see notes)
$ 7,084,167 $ 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
Three Months Nine Months
Ended September 30, Ended September 30,
------------------------ ------------------------
2000 1999 2000 1999
=========== =========== =========== ===========
(Dollars in thousands, except for per share amounts)
Operating Revenues:
<S> <C> <C> <C> <C>
Gas $ 606,889 $ 265,393 $ 1,896,245 $ 1,127,925
Electric 294,677 329,267 809,432 865,016
Water 28,926 29,894 76,822 74,794
Products and Services 75,054 68,415 213,567 192,156
----------- ----------- ----------- -----------
1,005,546 692,969 2,996,066 2,259,891
----------- ----------- ----------- -----------
Cost of Sales:
Gas costs 526,443 208,032 1,511,549 812,759
Fuel for electric generation 64,824 72,092 178,794 188,020
Power purchased 6,958 28,204 22,221 67,677
Products and Services 43,987 37,523 123,327 100,134
----------- ----------- ----------- -----------
642,212 345,851 1,835,891 1,168,590
----------- ----------- ----------- -----------
Operating Margin 363,334 347,118 1,160,175 1,091,301
----------- ----------- ----------- -----------
Operating Expenses and Taxes (except income):
Operation 131,081 120,065 394,131 375,515
Maintenance 16,468 18,450 64,082 62,672
Depreciation and amortization 84,100 78,006 253,217 228,454
Taxes (except income) 24,365 24,572 73,170 77,806
----------- ----------- ----------- -----------
256,014 241,093 784,600 744,447
----------- ----------- ----------- -----------
Operating Income 107,320 106,025 375,575 346,854
----------- ----------- ----------- -----------
Other Income (Deductions):
Interest expense, net (50,161) (42,376) (146,304) (119,378)
Minority interests (5,225) (5,563) (15,266) (13,939)
Dividend requirements on preferred stock
of subsidiaries (2,003) (2,071) (6,045) (6,264)
Other, net 54,074 (14,279) 59,861 (9,456)
----------- ----------- ----------- -----------
(3,315) (64,289) (107,754) (149,037)
----------- ----------- ----------- -----------
Income Before Income Taxes 104,005 41,736 267,821 197,817
----------- ----------- ----------- -----------
Income Taxes 52,005 13,781 112,792 70,359
----------- ----------- ----------- -----------
Net Income $ 52,000 $ 27,955 $ 155,029 $ 127,458
=========== =========== =========== ===========
Average common shares outstanding - basic 120,559,039 125,030,566 121,651,509 124,217,959
Basic earnings per average common share $ 0.43 $ 0.22 $ 1.27 $ 1.02
=========== =========== =========== ===========
Diluted earnings per average common share $ 0.42 $ 0.22 $ 1.23 $ 1.02
=========== =========== =========== ===========
Dividends declared per common share $ 0.270 $ 0.255 $ 0.810 $ 0.765
=========== =========== =========== ===========
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 September 30,
---------------------------------
(Dollars in thousands, except for per share amounts) 2000 1999
============= =============
Operating Revenues:
<S> <C> <C>
Gas $ 2,421,770 $ 1,506,002
Electric 1,065,454 1,155,454
Water 100,411 95,833
Products and Services 293,116 255,836
------------- -------------
3,880,751 3,013,125
------------- -------------
Cost of Sales:
Gas costs 1,886,248 1,100,962
Fuel for electric generation 239,938 245,406
Power purchased 26,289 114,310
Products and Services 165,877 129,398
------------- -------------
2,318,352 1,599,076
------------- -------------
Operating Margin 1,562,399 1,423,049
------------- -------------
Operating Expenses and Taxes (except income):
Operation 553,424 476,525
Maintenance 83,618 78,244
Depreciation and amortization 336,167 293,594
Taxes (except income) 98,933 99,431
------------- -------------
1,072,142 947,794
------------- -------------
Operating Income 490,257 475,255
------------- -------------
Other Income (Deductions):
Interest expense, net (193,543) (153,660)
Minority interests (19,020) (14,717)
Dividend requirements on preferred stock
of subsidiaries (8,115) (8,385)
Other, net 51,287 (8,481)
------------- -------------
(169,391) (185,243)
------------- -------------
Income Before Income Taxes 320,866 290,012
------------- -------------
Income Taxes 132,881 101,962
------------- -------------
Net Income $ 187,985 $ 188,050
============= =============
Average common shares outstanding - basic 122,422,589 122,577,821
Basic earnings per average common share $ 1.53 $ 1.53
============= =============
Diluted earnings per average common share $ 1.49 $ 1.52
============= =============
Dividends declared per common share $ 1.080 $ 1.020
============= =============
</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, July 1, 1999 $ 870,930 $(455,640) $ 172,388 $ 779,102 $ (976) $ 3,323 $ 1,369,127
Comprehensive Income:
Net income 27,955 27,955 $ 27,955
Other comprehensive income
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $1,068) (1,749) (1,749) (1,749)
Realized (net of income
tax of $113) 186 186 186
Gain/loss on foreign
currency translation:
Unrealized 150 150 150
Realized -- -- --
-------------
Total Comprehensive Income $ 26,542
=============
Dividends:
Common shares (31,891) (31,891)
Treasury shares acquired (346) (346)
Issued:
Employee stock purchase plan 112 252 364
Long-term incentive plan 655 29 (39) 645
Amortization of unearned
compensation 877 877
Equity contract costs (302) (302)
Other (177) (177)
--------- --------- ---------- ---------- --------- ------------- ----------- -------------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138) $ 1,910 $ 1,364,839
========= ========= ========== ========== ========= ============= ===========
Balance, July 1, 2000 $ 870,930 $(518,617) $ 173,595 $ 809,543 $ (10,513) $ 5,621 $ 1,330,559
Comprehensive Income:
Net income 52,000 52,000 $ 52,000
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $435) (714) (714) (714)
Realized (net of income
tax of $596) 976 976 976
Gain/loss on foreign
currency translation:
Unrealized 7 7 7
Realized -- -- --
-------------
Total Comprehensive Income $ 52,269
=============
Dividends:
Common shares (32,756) (32,756)
Treasury shares acquired (60) (60)
Issued:
Employee stock purchase plan 152 206 358
Long-term incentive plan 2,460 2,460
Amortization of unearned
compensation 1,112 1,112
Equity contract costs (1,152) (1,152)
Other (725) (725)
--------- --------- ---------- ---------- ---------- ------------- ----------- -------------
Balance, September 30, 2000 $ 870,930 $(516,065) $ 172,649 $ 828,062 $ (9,401) $ 5,890 $ 1,352,065
========= ========= ========== ========== ========= ============= ===========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Three Months Ended Shares Shares
------------------ --------- ---------
<S> <C> <C>
Balance July 1, 1999 147,784 (22,770)
Treasury shares acquired (16)
Issued:
Employee stock purchase plan 14
Long-term incentive plan 32
--------- ---------
Balance September 30, 1999 147,784 (22,740)
========= =========
Balance July 1, 2000 147,784 (26,601)
Treasury shares acquired (8)
Issued:
Employee stock purchase plan 19
Long-term incentive plan 126
--------- ---------
Balance September 30, 2000 147,784 (26,464)
========= =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NISOURCE INC.
CONSOLIDATED STATEMENT OF COMMON SHAREHOLDERS' EQUITY
-----------------------------------------------------------------------------------------------------------------------------------
Accumulated
Additional Other
Common Treasury Paid-In Retained Comprehensive Comprehensive
Nine 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 127,458 127,458 $ 127,458
Other comprehensive income
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $2,075) (101) (101) (101)
Realized (net of income
tax of $274) 449 449 449
Gain/loss on foreign
currency translation:
Unrealized 432 432 432
Realized -- -- --
-------------
Total Comprehensive Income $ 128,238
=============
Dividends:
Common shares (95,624) (95,624)
Treasury shares acquired (108,987) (108,987)
Issued:
Employee stock purchase plan 339 845 1,184
Long-term incentive plan 3,853 188 (571) 3,470
Bay State Gas Acquisition 205,881 109,753 315,634
Other Acquisitions 2,722 939 3,661
Amortization of unearned
compensation 2,248 2,248
Equity contract costs (33,539) (33,539)
Other (1,154) (1,154)
--------- --------- ---------- ---------- --------- ------------- ----------- -------------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138) $ 1,910 $ 1,364,839
========= ========= ========== ========== ========= ============= ===========
Balance, January 1, 2000 $ 870,930 $(472,553) $ 174,405 $ 774,423 $ 1,111 $ 5,186 $ 1,353,504
Comprehensive Income:
Net income 155,029 155,029 $ 155,029
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $1,006) (982) (982) (982)
Realized (net of income
tax of $787) 1,288 1,288 1,288
Gain/loss on foreign
currency translation:
Unrealized 398 398 398
Realized -- -- --
-------------
Total Comprehensive Income $ 155,733
=============
Dividends:
Common shares (98,321) (98,321)
Treasury shares acquired (65,852) (65,852)
Issued:
Employee stock purchase plan 490 608 1,098
Long-term incentive plan 21,850 (14,061) 7,789
Amortization of unearned
compensation 3,549 3,549
Equity contract costs (3,171) (3,171)
Other 807 (3,071) (2,264)
--------- --------- ---------- ---------- ---------- ------------- ----------- -------------
Balance, September 30, 2000 $ 870,930 $(516,065) $ 172,649 $ 828,062 $ (9,401) $ 5,890 $ 1,352,065
========= ========= ========== ========== ========= ============= ===========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Nine Months Ended Shares Shares
----------------- --------- ---------
<S> <C> <C>
Balance January 1, 1999 147,784 (30,254)
Treasury shares acquired (3,899)
Issued:
Employee stock purchase plan 43
Long-term incentive plan 194
Bay State Gas Acquisition 11,042
Other Acquisitions 134
--------- ---------
Balance September 30, 1999 147,784 (22,740)
========= =========
Balance January 1, 2000 147,784 (23,645)
Treasury shares acquired (3,971)
Issued:
Employee stock purchase plan 62
Long-term incentive plan 1,090
--------- ---------
Balance September 30, 2000 147,784 (26,464)
========= =========
</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, October 1, 1998 $ 870,930 $(538,228) $ 90,955 $ 713,561 $ (2,325) $ (175) $ 1,134,718
Comprehensive Income:
Net income 188,050 188,050 $ 188,050
Other comprehensive income
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $671) 1,097 1,097 1,097
Realized (net of income
tax of $274) 449 449 449
Gain/loss on foreign
currency translation:
Unrealized 539 539 539
Realized -- -- --
-------------
Total Comprehensive Income $ 190,135
=============
Dividends:
Common shares (125,439) (125,439)
Treasury shares acquired (130,461) (130,461)
Issued:
Employee stock purchase plan 429 1,155 1,584
Long-term incentive plan 4,438 159 (571) 4,026
Bay State Gas Acquisition 205,881 109,753
Other Acquisitions 2,722 939
Amortization of unearned
compensation 2,758 2,758
Equity contract costs (33,539) (33,539)
Other 2,945 (1,183) 1,762
--------- --------- ---------- ---------- --------- ------------- ----------- -------------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138) $ 1,910 $ 1,364,839
========= ========= ========== ========== ========= ============= ===========
Balance, October 1, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138) $ 1,910 $ 1,364,839
Comprehensive Income:
Net income 187,985 187,985 $ 187,985
Other comprehensive income,
net of tax:
Gain/loss on available for
sale securities:
Unrealized (net of income
tax of $697) 860 860 860
Realized (net of income
tax of $958) 1,567 1,567 1,567
Gain/loss on foreign
currency translation:
Unrealized 611 611 611
Realized 942 942 942
-------------
Total Comprehensive Income $ 191,965
=============
Dividends:
Common shares (131,841) (131,841)
Treasury shares acquired (82,158) (82,158)
Issued:
Employee stock purchase plan 624 811 1,435
Long-term incentive plan 20,688 36 (14,061) 6,663
Amortization of unearned
compensation 4,798 4,798
Equity contract costs (3,633) (3,633)
Other 3,068 (3,071) (3)
--------- --------- ---------- ---------- ---------- ------------- ----------- -------------
Balance, September 30, 2000 $ 870,930 $(516,065) $ 172,649 $ 828,062 $ (9,401) $ 5,890 $ 1,352,065
========= ========= ========== ========== ========= ============= ===========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SHARES
Common Treasury
Twelve Months Ended Shares Shares
------------------- --------- ---------
<S> <C> <C>
Balance October 1, 1998 147,784 (29,607)
Treasury shares acquired (4,589)
Issued:
Employee stock purchase plan 54
Long-term incentive plan 226
Bay State Gas Acquisition 11,042
Other Acquisition 134
--------- ---------
Balance September 30, 1999 147,784 (22,740)
========= =========
Balance October 1, 1999 147,784 (22,740)
Treasury shares acquired (4,893)
Issued:
Employee stock purchase plan 79
Long-term incentive plan 1,090
--------- ---------
Balance September 30, 2000 147,784 (26,464)
========= =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Three Months Nine Months
Ended September 30, Ended September 30,
------------------------ ------------------------
(Dollars in thousands) 2000 1999 2000 1999
=========== =========== =========== ===========
Cash flows from operating activities:
<S> <C> <C> <C> <C>
Net income $ 52,00 $ 27,955 $ 155,029 $ 127,458
Adjustments to reconcile net income to net
cash:
Depreciation and amortization 84,100 78,006 253,169 228,454
Net changes in price risk management
activities (8,330) -- (19,371) --
Deferred federal and state income taxes, net 1,466 3,978 (31,888) (26,772)
Deferred investment tax credits, net (1,910) (1,921) (5,729) (5,728)
Gain on sale of Market Hub Partners (Pre-tax) (51,870) -- (51,870) --
Other, net (3,972) 2,810 7,147 (215)
Change in certain assets and liabilities -*
Accounts receivable, net 79,502 (4,692) 25,373 124,753
Other receivables (29,139) 56 (59,537) (4,866)
Natural gas in storage (99,611) (38,759) (127,178) (8,462)
Accounts payable 19,523 20,799 96,260 (121,478)
Taxes accrued (3,322) (18,232) (2,517) (20,691)
Gas cost adjustment clause (52,195) (39,860) (7,378) 32,587
Accrued employment costs 5,318 5,428 1,070 (11,011)
Other accruals 29,854 19,422 37,443 47,147
Other, net (22,379) (6,227) (40,475) (1,243)
----------- ----------- ----------- -----------
Net cash provided by operating activities (965) 48,763 229,548 359,933
----------- ----------- ----------- -----------
Cash flows provided by (used in) investing
activities:
Utility construction expenditures (74,969) (92,336) (200,205) (228,428)
Acquisition of businesses, net of cash
acquired -- -- (50) (716,031)
Proceeds from disposition of assets 238,515 892 254,147 28,452
Other, net 1,823 (30,962) (14,287) (73,580)
----------- ----------- ----------- -----------
Net cash used in investing activities 165,369 (122,406) 39,605 (989,587)
----------- ----------- ----------- -----------
Cash flows provided by (used in) financing
activities:
Issuance of long-term debt -- 544 -- 258,315
Retirement of long-term debt (12,379) (2,783) (171,110) (185,855)
Change in short-term debt (121,501) 81,482 69,287 65,132
Retirement of preferred shares (300) (601) (3,830) (1,852)
Proceeds from Corporate Premium Income Equity
Securities, net -- -- -- 334,650
Issuance of common shares 2,612 1,048 8,291 324,520
Acquisition of treasury shares (60) (346) (65,852) (108,987)
Cash dividends paid on common shares (32,725) (31,884) (98,729) (93,710)
Other, net 73 114 286 340
----------- ----------- ----------- -----------
Net cash provided by (used in) financing
activities (164,280) 47,574 (261,657) 592,553
----------- ----------- ----------- -----------
Net increase (decrease) in cash and cash
equivalents 124 (26,069) 7,496 (37,101)
Cash and cash equivalents at beginning of the
period 50,905 49,816 43,533 60,848
----------- ----------- ----------- -----------
Cash and cash equivalents at end of the period $ 51,029 $ 23,747 $ 51,029 $ 23,747
=========== =========== =========== ===========
*Net of effect from acquisitions of businesses.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Twelve Months
Ended September 30,
---------------------------------
(Dollars in thousands) 2000 1999
============= =============
Cash flows from operating activities:
<S> <C> <C>
Net income $ 187,985 $ 188,050
Adjustments to reconcile net income to net
cash:
Depreciation and amortization 336,119 293,594
Net changes in price risk management activities (20,268) --
Deferred federal and state income taxes, net (13,007) 928
Deferred investment tax credits, net (7,692) (7,626)
Gain on sale of Market Hub Partners (Pre-tax) (51,870) --
Other, net 30,731) 1,482
Change in certain assets and liabilities -*
Accounts receivable, net (46,872) 63,890
Other receivables (46,101) 163
Natural gas in storage (71,811) (6,059)
Accounts payable 104,204 (77,996)
Taxes accrued 14,460 (46,299)
Gas cost adjustment clause (60,625) 20,185
Accrued employment costs 12,333 (4,959)
Other accruals 26,836 50,516
Other, net (71,777) (8,438)
------------- -------------
Net cash provided by operating activities 322,645 467,431
------------- -------------
Cash flows provided by (used in) investing
activities:
Utility construction expenditures (313,040) (302,557)
Acquisition of businesses, net of cash
acquired (21,888) (716,031)
Proceeds from disposition of assets 255,470 30,597
Other, net (1,787) (63,087)
------------- -------------
Net cash used in investing activities (81,245) (1,051,078)
------------- -------------
Cash flows provided by (used in) financing
activities:
Issuance of long-term debt 11,221 258,817
Retirement of long-term debt (189,212) (202,282)
Change in short-term debt 173,133 112,576
Retirement of preferred shares (4,385) (2,409)
Proceeds from Corporate Premium Income Equity
Securities, net -- 334,650
Issuance of common shares 8,664 325,476
Acquisition of treasury shares (83,320) (130,461)
Cash dividends paid on common shares (130,618) (121,916)
Other, net 399 453
------------- -------------
Net cash provided by (used in) financing
activities (214,118) 574,904
------------- -------------
Net increase (decrease) in cash and
cash equivalents 27,282 (8,743)
Cash and cash equivalents at beginning of the
period 23,747 32,490
------------- -------------
Cash and cash equivalents at end of the period $ 51,029 $ 23,747
============= =============
*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 and
trading operations with the April 1999 acquisition of TPC Corporation, now
renamed EnergyUSA-TPC Corp. (TPC). NiSource's electric business is comprised of
a regulated electric utility that operates in northern Indiana. The electric
business also includes wholesale power 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."
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 $2.0 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, 3.04414 shares in new
holding company stock. Stock elections are subject to proration for those
elections made with respect to more than 30% of CEG's outstanding shares.
Approval of the NiSource and CEG shareholders was obtained on June 1 and June 2,
respectively. All actions needed from state utility regulatory commissions and
from FERC have been received. The Securities and Exchange Commission (SEC)
approved the merger under the Public Utility Holding Company Act on October 30,
2000. The merger is expected to be completed on November 1, 2000. NiSource will
register as a public utility holding company.
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 $1.6 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. 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.
The SEC in its order approving the merger with CEG required NiSource to
divest its water utilities within 3 years from the date of the merger. NiSource
will comply with the Order and is currently evaluating its options for the
disposition of the water utilities.
(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 Market
Hub Partners, L.P. (MHP), a company which operates salt dome storage facilities
for natural gas. In the fourth quarter of 1999 acquired the remaining interests
in MHP. On September 18, 2000, NiSource sold its indirect ownership in MHP to
Duke Energy Gas Transmission for $250 million in cash plus the assumption of
$150 million in debt. The consolidated financial statements and disclosures
include operating results of TPC from April 1, 1999 and the consolidated results
of MHP from December 1999 through September 18, 2000.
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.
The approximate weighted average remaining lives for major components of
electric, gas, and water utility plant are as follows:
<TABLE>
<CAPTION>
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, nine month and twelve month periods ended September
30, 2000 and 1999 were as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Electric 3.7% 3.7% 3.7% 3.7% 3.7% 3.7%
Gas 4.5% 4.5% 4.6% 4.5% 4.5% 4.5%
Water 2.3% 2.5% 2.2% 2.2% 2.4% 2.4%
</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 $707.4 million
and $722.8 million at September 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 $76.9
million and $125.7 million at September 30, 2000 and December 31, 1999,
respectively, is being amortized over a weighted average period of 27 years.
Goodwill was reduced by $56.8 million as a result of the sale of MHP. Other
intangible assets, approximating $12.6 million and $12.8 million at September
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 September 30, 2000 and December 31, 1999, was approximately
$14.4 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 September 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 realized and unrealized gains (losses), net of
income taxes, on available for sale securities (securities) and on foreign
currency translation adjustments (foreign currency).
The accumulated amounts for these components are as follows:
<TABLE>
<CAPTION>
October 1, January 1, July 1, October 1, January 1, July 1, September 30,
(Dollars in millions) 1998 1999 1999 1999 2000 2000 2000
------------- ------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Securities $ 2.5 $ 3.6 $ 5.6 $ 4.0 $ 6.1 $ 6.2 $ 6.4
Foreign currency $ (2.7) $ (2.5) $ (2.3) $ (2.1) $ (0.9) $ (0.6) $ (0.5)
</TABLE>
Statements of Cash Flows. Temporary cash investments with an original maturity
of three months or less are considered to be cash equivalents.
Cash paid during the periods reported for income taxes and interest was as
follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 59,671 $ 24,010 $158,649 $114,188 $160,453 $152,286
Interest, net of amounts capitalized $ 55,485 $ 40,437 $443,491 $113,117 $190,420 $147,659
</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) appealed the Generic Order to
the Indiana Court of Appeals. 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. On September 5, 2000, the Indiana Court of Appeals issued an
order approving a joint stipulation for dismissal, with prejudice, of the OUCC's
appeal of the Generic Order.
Gas Cost Adjustment Clause. All metered gas sales rates contain an adjustment
factor, which reflects the increases and decreases in the cost of purchased gas,
contracted gas storage and storage transportation charges. 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. Northern Indiana
made its annual filing on September 1, 2000 and the matter is scheduled for
hearing on December 14, 2000.
If the statutory requirement relating to the level of return 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 September 2000 and
December 1999, the estimated replacement cost of gas in storage (current and
non-current) at September 30, 2000 and December 31, 1999 exceeded the stated
LIFO cost by $138.2 million and $48.9 million, respectively. Inventory valued
using LIFO was $88.4 million and $23.0 million at September 30, 2000 and
December 31, 1999, respectively. Inventory valued using the weighted average
methodology was $102.6 million and $40.8 million at September 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 September
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>
Regulatory assets were comprised of the following items:
<TABLE>
<CAPTION>
September 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
<S> <C> <C>
Unamortized reacquisition premium on debt (see Note 16) $ 37,084 $ 39,719
Unamortized R. M. Schahfer Unit 17 and Unit 18 carrying
charges and deferred depreciation (see below) 54,948 58,111
Bailly scrubber carrying charges and deferred depreciation
(see below) 7,308 8,010
Deferral of SFAS No. 106 expense not recovered
(see Note 8) 71,169 75,527
FERC Order No. 636 transition costs 9,097 13,728
Regulatory income tax asset, net (see Note 6) 28,710 24,941
Other 17,255 18,651
------------- -------------
225,571 238,687
------------- -------------
Less: Current portion of regulatory assets 19,613 24,245
------------- -------------
$ 205,958 $ 214,442
============= =============
</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 $31.1 million and $33.3 million relating to affordable housing projects
at September 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.
On a pro forma basis, NiSource's consolidated results of operations for the nine
months and twelve months ended September 30, 1999, including BSG, would have
been:
<TABLE>
<CAPTION>
UNAUDITED
(Dollars in thousands) Nine Months Twelve Months
============= =============
<S> <C> <C>
Operating revenue $ 2,339,870 $ 3,244,045
Operating income $ 350,816 $ 490,045
Net income $ 128,049 $ 183,673
</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. 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. In the
fourth quarter of 1999, NiSource acquired the remaining interests in MHP. On
September 18, 2000, NiSource sold its ownership interests in MHP to Duke Energy
Gas Transmission for $250 million in cash plus the assumption of $150 million in
debt. This transaction resulted in a pre-tax gain of $51.9 million which is
reflected as a component of Other, net under Other Income (Deductions) in the
accompanying Consolidated Statements of Income. Results for periods presented
prior to the acquisition to TPC are not impacted significantly by pro forma
results of TPC applied to those periods.
(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 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. On September
1, 2000, the Trustee filed a separate adversary proceeding against NI Energy
Services, Inc. and Capital Markets, asserting that NI Energy Services, Inc. and
Capital Markets received a preference of $7.2 million within a year of the PCA
bankruptcy filing. NPM, NI Energy Services, Inc. and Capital Markets dispute any
liability to the Trustee and intend 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-eight sites. Initial sampling has been conducted at thirty-four
sites. Investigation activities have been completed at twenty-five sites and
remedial measures have been selected or implemented at twenty-one 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 solvent
insurance companies. Additionally, agreements have been reached with other
Indiana utilities relating to cost sharing and management of the investigation
and remediation of several former manufactured-gas plant sites at which Northern
Indiana and such utilities or their predecessors were operators or owners.
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. Both utilities are actively negotiating with historic insurance
companies to resolve environmental claims.
As of September 30, 2000, a reserve of approximately $23.5 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. The supreme Court has agreed to
hear appeals from the Court of Appeals Decision. Once rectified, the revised
standards could require additional reductions in sulfur dioxide, particulate
matter and NOx emissions from coal-fired boilers (including Northern Indiana's
generating stations) beyond measures discussed above. Final implementation
methods will be set by the EPA as well as state regulatory authorities. 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.
The components of the net deferred income tax liability at September 30, 2000
and December 31, 1999, were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Deferred tax liabilities--
<S> <C> <C>
Accelerated depreciation and other property differences $ 1,070,909 $ 1,129,011
AFUDC-equity 27,867 31,274
Adjustment clauses 17,518 16,730
Other regulatory assets 26,024 27,616
Prepaid pension and other benefits 63,788 64,853
Reacquisition premium on debt 14,876 15,919
Deferred tax assets--
Deferred investment tax credits (34,850) (36,650)
Removal costs (181,118) (171,645)
Other postretirement/postemployment benefits (59,456) (58,645)
Other, net (35,013) (27,300)
------------- -------------
910,545 991,163
Less: Deferred income taxes related to current assets
and liabilities (21,377) (7,519)
------------- -------------
Deferred income taxes--noncurrent $ 931,922 $ 998,682
============= =============
</TABLE>
Deferred income taxes on price risk management assets and liabilities
are reflected net as a component of Other, net above.
Federal and state income taxes as set forth in the Consolidated Statements of
Income were comprised of the following:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Current income taxes -
Federal $ 46,880 $ 10,165 $132,273 $ 88,706 $135,466 $ 94,412
State 5,569 1,559 18,138 14,153 18,116 14,248
-------- -------- -------- -------- -------- --------
52,449 11,724 150,411 102,859 153,582 108,660
-------- -------- -------- -------- -------- --------
Deferred income taxes, net -
Federal 1,241 3,837 (29,246) (24,497) (12,626) 1,097
State 225 141 (2,643) (2,275) (382) (169)
-------- -------- -------- -------- -------- --------
1,466 3,978 (31,889) (26,772) (13,008) 928
-------- -------- -------- -------- -------- --------
Deferred investment tax
credits (1,910) (1,921) (5,730) (5,728) (7,693) (7,626)
-------- -------- -------- -------- -------- --------
Total income taxes $ 52,005 $ 13,781 $112,792 $ 70,359 $132,881 $101,962
======== ======== ======== ======== ======== ========
</TABLE>
A reconciliation of total income tax expense to an amount computed by applying
the statutory federal income tax rate to pre-tax income is as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Net income $ 52,000 $ 27,955 $155,029 $127,458 $187,985 $188,050
Add - Income taxes 52,005 13,781 112,792 70,359 132,881 101,962
Dividend requirements on
preferred stocks of subsidiaries 2,003 2,071 6,045 6,264 8,115 8,385
-------- -------- -------- -------- -------- --------
Income before preferred dividend
requirements of subsidiaries
and income taxes $106,008 $ 43,807 $273,866 $204,081 $328,981 $298,397
======== ======== ======== ======== ======== ========
Amount derived by multiplying
pre-tax income by the statutory rate $ 37,103 $ 15,332 $ 95,853 $ 71,428 $115,143 $104,439
Reconciling items multiplied by the
statutory rate:
Book depreciation over related tax
depreciation 918 969 2,753 2,906 3,781 3,904
Amortization of deferred investment
tax credits (1,910) (1,921) (5,730) (5,728) (7,693) (7,626)
State income taxes, net of federal
income tax benefit 3,845 1,154 9,147 6,924 11,393 9,092
Reversal of deferred taxes provided
at rates in excess of the current
federal income tax rate (920) (721) (2,758) (2,163) (6,052) (4,822)
Low-income housing credits (1,267) (1,128) (3,801) (3,384) (4,929) (4,344)
Nondeductible amounts related to
amortization of intangible assets
and plant acquisition adjustments 619 619 1,857 1,857 2,476 2,486
Basis and stock sale differences 8,392 -- 8,392 -- 8,392 --
Other, net 5,225 (523) 7,079 (1,481) 10,370 (1,167)
-------- -------- -------- -------- -------- --------
Total income taxes $ 52,005 $ 13,781 $112,792 $ 70,359 $132,881 $101,962
======== ======== ======== ======== ======== ========
</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.
The change in the benefit obligation for the years 1999 and 1998 was as follows:
<TABLE>
<CAPTION>
(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>
The change in the fair value of the plans' assets for the years 1999 and 1998
was as follows:
<TABLE>
<CAPTION>
(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
============= =============
</TABLE>
The plans' assets are invested primarily in common stocks, bonds and
notes.
The plans' funded status as of December 31, 1999 and 1998 is as follows:
<TABLE>
<CAPTION>
(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 $213.7 million at September 30, 2000 and are reported
under the captions "Prepayments and Other" in the Consolidated Balance Sheets.
The following items are the components of provisions for pensions for the three
month, nine month and twelve month periods ended September 30, 2000 and
September 30, 1999:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 5,228 $ 5,032 $ 15,683 $ 14,752 $ 20,742 $ 18,808
Interest costs 18,876 17,078 56,628 50,570 75,668 67,688
Expected return on plan assets (27,221) (23,147) (81,661) (68,546) (108,343) (92,711)
Amortization of transition obligation 1,471 1,477 4,415 4,372 6,212 6,000
Amortization of prior service costs 1,581 1,607 4,742 4,765 6,487 5,328
Amortization of (gain)/loss (720) -- (2,160) -- (2,160) --
-------- -------- -------- -------- -------- --------
$ (785) $ 2,047 $ (2,353) $ 5,913 $ 1,394 $ 5,113
======== ======== ======== ======== ======== ========
</TABLE>
Assumptions used in the valuation and determination of 2000 and 1999 pension
expense were as follows:
<TABLE>
<CAPTION>
2000 1999
============= =============
<S> <C> <C>
Discount rate 7.75% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Expected long-term rate of return on assets 9.00% 9.00%
</TABLE>
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, $1.7 million and $2.3
million were made to these plans for the three month, nine month and twelve
month periods ended September 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.
The following table sets forth the change in the plans' accumulated
postretirement benefit obligation (APBO) as of December 31, 1999 and 1998:
<TABLE>
<CAPTION>
(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>
The change in the fair value of the plan assets for the years 1999 and 1998 is
as follows:
<TABLE>
<CAPTION>
(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>
Following is the funded status for postretirement benefits as of December 31,
1999 and 1998:
<TABLE>
<CAPTION>
(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 $174.2 million at September 30, 2000.
Net periodic postretirement benefit costs, before consideration of the
rate-making discussed previously, for the three month, nine month and twelve
month periods ended September 30, 2000 and September 30, 1999, include the
following components:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 1,520 $ 1,623 $ 4,564 $ 4,271 $ 4,484 $ 5,358
Interest costs 4,980 4,728 14,939 14,103 15,053 17,677
Expected return on plan assets (580) (700) (1,739) (1,933) (67) (1,999)
Amortization of transition obligation 3,215 3,197 9,646 9,525 10,869 12,482
Amortization of prior service costs 85 86 257 258 278 355
Amortization of (gain) loss (1,412) (1,204) (4,238) (3,600) (6,194) (5,167)
-------- -------- -------- -------- -------- --------
$ 7,808 $ 7,730 $ 23,429 $ 22,624 $ 24,423 $ 28,706
======== ======== ======== ======== ======== ========
</TABLE>
Assumptions used in the determination of 2000 and 1999 net periodic
postretirement benefit costs were as follows:
<TABLE>
<CAPTION>
2000 1999
============= =============
<S> <C> <C>
Discount rate 7.75% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Assumed annual rate of increase in health care benefits 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 $3.9
million for the three month and nine month periods ended September 30, 2000. The
effect of a 1% decrease in the assumed health care cost trend rates for each
future year would decrease the APBO at January 1, 2000 by approximately $21.1
million, and decrease the aggregate of the service and interest cost components
of plan costs by approximately $1.0 million and $3.0 million for the three month
and nine month periods ended September 30, 2000. Amounts disclosed above could
be changed significantly in the future by changes in health care costs, work
force demographics, interest rates, or plan changes.
(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
September 30, December 31, September 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 September 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 September 30, 2000, there were no additional
issuances of the above preferred stocks. The foregoing preferred stocks are
redeemable in whole or in part at any time upon thirty days' notice at the
option of the issuer at the redemption prices shown.
(11) Preferred Stocks, Redemption Outside Control of Issuer:
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:
<TABLE>
<CAPTION>
September 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Northern Indiana Public Service Company:
Cumulative preferred stock -$100 par value -
8.85% series - 25,000 and 37,500 shares outstanding,
<S> <C> <C>
respectively $ 2,500 $ 3,750
7-3/4% series - 27,798 shares outstanding 2,780 2,780
8.35% series - 39,000 and 45,000 shares outstanding,
respectively 3,900 4,500
Cumulative preferred stock -no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
------------- -------------
$ 52,180 $ 54,030
============= =============
</TABLE>
The redemption prices at September 30, 2000, as well as sinking fund provisions,
for the cumulative preferred stocks subject to mandatory redemption
requirements, or whose redemption is outside the control of Northern Indiana,
were as follows:
<TABLE>
<CAPTION>
Sinking Fund or
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% $102.95, reduced periodically 3,000 shares on or before July 1; increasing to 6,000
shares beginning in 2004; noncumulative option
to double amount each year.
Cumulative preferred stock -no par value -
6.50% $100.00 on October 14, 2002 430,000 shares on October 14, 2002.
</TABLE>
Sinking fund requirements with respect to redeemable preferred stocks
outstanding at September 30, 2000 for each of the twelve month periods
subsequent to September 30, 2001, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30, (Dollars in thousands)
===============================================================
<S> <C>
2002 $ 1,828
2003 $ 44,828
2004 $ 878
2005 $ 878
</TABLE>
Sinking fund payments due within one year are reported under the
caption "Other" included in 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 September 30, 2000, Northern Indiana had approximately
$134.0 million of retained earnings (earned surplus) available for the payment
of dividends. Future dividends will depend upon adequate retained earnings,
adequate future earnings and the absence of adverse developments.
(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.
The net income, preferred dividends and shares used to compute basic and diluted
earnings per share is presented in the following table:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands, except share amounts)
Basic
Weighted Average Number of Common
<S> <C> <C> <C> <C> <C> <C>
Shares Outstanding 120,559,039 125,030,566 121,651,509 124,217,959 122,422,589 122,577,821
=========== =========== =========== =========== =========== ===========
Net Income to be Used to Compute Basic
Earnings per Share:
Net Income $ 52,000 $ 27,955 $ 155,029 $ 127,458 $ 187,985 $ 188,050
=========== =========== =========== =========== =========== ===========
Basic Earnings per Average Common
Share $ 0.43 $ 0.22 $ 1.27 $ 1.02 $ 1.53 $ 1.53
=========== =========== =========== =========== =========== ===========
Diluted
Weighted Average Number of Common
Shares Outstanding 120,559,039 125,030,566 121,651,509 124,217,959 122,422,589 122,577,821
Dilutive Shares 2,853,505 1,024,180 3,628,149 722,559 3,143,613 710,818
----------- ----------- ----------- ----------- ----------- -----------
Weighted Average Shares 123,412,544 126,054,746 125,279,658 124,940,518 125,566,202 123,288,639
=========== =========== =========== =========== =========== ===========
Net Income to be Used to Compute
Diluted Earnings per Share:
Net Income $ 52,000 $ 27,955 $ 155,029 $ 127,458 $ 187,985 $ 188,050
=========== =========== =========== =========== =========== ===========
Diluted Earnings per Average
Common Share $ 0.42 $ 0.22 $ 1.23 $ 1.02 $ 1.49 $ 1.52
=========== =========== =========== =========== =========== ===========
</TABLE>
(14) Common Shares: As of September 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 effective February 20, 1998.
Share Purchase Rights Plan. On February 17, 2000, the Board of Directors of
NiSource adopted a 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 September 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. The counterparty has
informed NiSource that approximately 5.6 million shares have 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 $1.2 million, $3.8 million
and $4.5 million for the three month, nine month and twelve month periods ended
September 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 September 30, 2000, the nominal amount and fair value of the
equity forward purchase contract was approximately $150 million and a loss of
$(14) 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 effect of 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). 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). The 1988 Plan, as amended and restated,
and the 1994 Plan, as amended and restated, were re-approved by shareholders on
April 14, 1999. The Plans permit the following types of grants, separately or in
combination: nonqualified stock options, incentive stock options, restricted
stock awards, stock appreciation rights and performance units. Under the Plans,
the exercise price of each option equals the market price of common stock on the
date of grant. Each option has a maximum term of ten years and vests one year
from the date of grant.
The 1988 Plan provided for the issuance of up to 5.0 million common
shares to key employees through April 1998. On January 29, 2000, the Board of
Directors of NiSource approved certain additional amendments to the 1994 Plan
and on June 1, 2000, the 1994 Plan, as amended and restated, was approved by
shareholders at the 2000 Annual Meeting of Shareholders of NiSource. The amended
and restated 1994 Plan provides for the issuance of up to 11 million shares
through April 2004, and permits contingent stock awards and dividend equivalents
payable on grants of options, stock appreciation rights (SARs), performance
units and contingent stock awards. At September 30, 2000, there were 6,006,336
shares reserved for future awards under the amended and restated 1994 Plan.
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
679,500 and 513,500 restricted shares outstanding at September 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 September
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 $0.9 million for the three month,
$3.5 million and $2.2 million for the nine month and $4.8 million and $2.8
million for the twelve month periods ended September 30, 2000 and 1999,
respectively.
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:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
(Dollars in thousands, except per share data)
Net Income:
<S> <C> <C> <C> <C> <C> <C>
As reported $ 52,000 $ 27,955 $155,029 $127,458 $187,985 $188,050
Pro forma $ 51,264 $ 27,564 $153,068 $126,260 $185,613 $186,448
Earnings Per Average Common Share:
Basic:
As reported $ 0.43 $ 0.22 $ 1.27 $ 1.02 $ 1.53 $ 1.53
Pro forma $ 0.42 $ 0.22 $ 1.25 $ 1.01 $ 1.51 $ 1.52
Diluted:
As reported $ 0.42 $ 0.22 $ 1.23 $ 1.02 $ 1.49 $ 1.52
Pro forma $ 0.41 $ 0.21 $ 1.22 $ 1.01 $ 1.48 $ 1.51
</TABLE>
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions used for
grants in 2000, 1999 and 1998:
<TABLE>
<CAPTION>
August January August August
2000 2000 1999 1998
======== ======== ======== ========
<S> <C> <C> <C> <C>
Interest Rate 6.6% 6.60% 5.87% 5.29%
Expected Dividend Yield $1.08 $1.08 $1.02 $0.96
Expected Life (in years) 5.8 5.4 5.25 5.4
Volatility 26.16% 28.98% 15.72% 13.09%
</TABLE>
Changes in outstanding shares under option for the three month, nine month and
twelve month periods ended September 30, 2000 and September 30, 1999 were as
follows:
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
---------------------------------------------
Weighted Weighted
Average Average
Option Option
Three Months Ended September 30, 2000 Price 1999 Price
================================ ========= ========= ========= =========
<S> <C> <C> <C> <C>
Balance, beginning of period 4,112,545 $ 20.03 3,243,206 $ 18.81
Granted 827,000 22.22 744,750 24.59
Exercised (124,540) 13.91 (29,000) 15.62
Canceled (19,500) 21.47 -- --
--------- ---------
Balance, end of period 4,795,505 $ 20.56 3,958,956 $ 19.92
========= =========
Shares exercisable 3,567,505 $ 20.42 3,214,206 $ 18.84
========= =========
Weighted average fair value
of options granted $ 4.61 $ 3.66
========= =========
</TABLE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
---------------------------------------------
Weighted Weighted
Average Average
Option Option
Nine Months Ended September 30, 2000 Price 1999 Price
=============================== ========= ========= ========= =========
<S> <C> <C> <C> <C>
Balance, beginning of period 3,950,456 $ 19.90 2,651,300 $ 19.61
Converted -- -- 740,780 15.03
Granted 1,235,000 20.97 744,750 24.60
Exercised (330,951) 13.80 (171,374) 14.03
Canceled (59,000) 23.02 (6,500) 29.22
--------- ---------
Balance, end of period 4,795,505 $ 20.56 3,958,956 $ 19.92
========= =========
Shares exercisable 3,567,505 $ 20.42 3,214,206 $ 18.84
========= =========
Weighted average fair value
of options granted $ 4.33 $ 3.66
========= =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
---------------------------------------------
Weighted Weighted
Average Average
Option Option
Twelve Months Ended September 30, 2000 Price 1999 Price
================================= ========= ========= ========= =========
<S> <C> <C> <C> <C>
Balance, beginning of period 3,958,956 $ 19.92 2,685,100 $ 19.56
Converted -- -- 740,780 15.03
Granted 1,235,000 20.97 744,750 24.59
Exercised (330,951) 13.80 (203,174) 14.14
Canceled (67,500) 23.63 (8,500) 29.22
--------- ---------
Balance, end of period 4,795,505 $ 20.56 3,958,956 $ 19.92
========= =========
Shares exercisable 3,567,505 $ 20.42 3,214,20 6 $ 18.84
========= =========
Weighted average fair value
of options granted $ 4.33 $ 3.66
========= =========
</TABLE>
The following table summarizes information about nonqualified stock options:
<TABLE>
<CAPTION>
Options Outstanding and Exercisable by Price Range as of September 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 September 30, 2000 Life Price September 30, 2000 Exercise Price
--------------- ------------------ ----------- -------- ------------------ --------------
<S> <C> <C> <C> <C> <C>
$ 8.53-$12.76 101,500 0.7 $10.95 101,500 $10.95
$12.77-$19.15 2,058,665 4.7 $16.52 1,653,665 $16.05
$19.16-$28.74 2,050,340 8.8 $22.62 1,227,340 $22.89
$28.75-$29.22 585,000 7.7 $29.22 585,000 $29.22
--------------- ------------------ ----------- -------- ------------------ --------------
4,795,505 6.7 $20.56 3,567,505 $20.42
</TABLE>
(16) Long-Term Debt:
<TABLE>
<CAPTION>
September 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 $ 170,670 $ 183,100
Pollution control notes and bonds-
Weighted average interest rate of 4.87% and
various maturities between October 1, 2003 and
April 1, 2019 237,000 237,000
Medium-term notes -
Weighted average interest rate of 7.18% and
various maturities between August 15, 2001
and September 1, 2031 1,147,025 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 7.43% and
various maturities between August 15, 2002
and December 1, 2018 29,822 196,704
Variable bank loans - interest rate of 7.63%, due
August 7, 2003 5,600 30,600
Unamortized premium and discount on
long-term debt, net (2,826) (3,112)
------------- -------------
Total long-term debt, excluding amounts due
within one year $ 1,737,291 $ 1,975,184
============= =============
</TABLE>
Sinking fund requirements and maturities of long-term debt outstanding at
September 30, 2000 for the twelve month periods subsequent to September 30,
2001, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30, (Dollars in thousands)
===============================================================
<S> <C>
2002 $ 125,221
2003 $ 183,359
2004 $ 123,798
2005 $ 115,841
</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 $217.7 million
Medium-Term Notes, Series E, with various maturities, for purposes of
refinancing certain first mortgage bonds and medium-term notes. As of September
30, 2000, $139.0 million of 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 $3.4 billion at September 30, 2000.
(17) Current Portion of Long-Term Debt:
At September 30, 2000 and December 31, 1999, the current portion of long-term
debt due within one year was as follows:
<TABLE>
<CAPTION>
September 30, September 30,
(Dollars in thousands) 2000 1999
============= =============
Medium-term notes--
<S> <C> <C>
Weighted average interest rate of 6.35% $ 42,851 $ 166,254
Notes payable--
Weighted average interest rate of 6.69% 18,569 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 $ 89,420 $ 173,721
============= =============
</TABLE>
(18) Short-Term Borrowings: NiSource and its subsidiaries may borrow under two
364-day $200 million revolving credit agreements that terminate on September 23,
2001. 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
September 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 $175.7 million with lenders at either the lender's
commercial prime or market lending rates. As of September 30, 2000, there were
$78.7 million of borrowings outstanding under these lines of credit with a
weighted average interest rate of 7.35%. 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 $424.5 million. As of September 30, 2000, there were $254.0 million
outstanding under these money market lines of credit with a weighted average
interest rate of 7.14%. 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 were unsecured debentures of Capital
Markets and ranked equally with all other unsecured and unsubordinated debt of
Capital Markets. On September 28, 2000, all $160 million PURS were redeemed by
NiSource at par.
At September 30, 2000 and December 31, 1999, short-term borrowings were as
follows:
<TABLE>
<CAPTION>
September 30, December 31,
(Dollars in thousands) 2000 1999
============= =============
Commercial paper--
Weighted average interest rate of 6.80%
<S> <C> <C>
at September 30, 2000 $ 413,500 $ 299,565
Notes payable--
Weighted average interest rate of 6.69%
at September 30, 2000 335,108 379,756
------------- -------------
Total short-term borrowings $ 748,608 $ 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 September 30,
2000, there were 6.9 million 5.9% Preferred Securities outstanding with Capital
Trust assets of $345 million.
(20) Operating Leases:
The following is a schedule, by years of future minimum rental payments,
excluding those to associated companies, required under operating leases that
have initial or remaining noncancelable lease terms in excess of one year as of
September 30, 2000:
<TABLE>
<CAPTION>
Twelve Months Ended September 30, (Dollars in thousands)
===============================================================
<S> <C>
2001 $ 34,873
2002 65,993
2003 31,081
2004 77,091
2005 24,301
Later years 200,117
-------
Total minimum payments required $ 433,456
=======
</TABLE>
The Consolidated Financial Statements include rental expense for all operating
leases as follows:
<TABLE>
<CAPTION>
September 30, September 30,
(Dollars in thousands) 2000 1999
============= =============
<S> <C> <C>
Three months ended $ 12,528 $ 12,332
Nine months ended $ 37,146 $ 36,530
Twelve months ended $ 50,893 $ 42,531
</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 $47.8 million and $36.6 million, at
September 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 September 30, 2000, NiSource
had futures contracts representing the hedge of natural gas sales in the
notional amount of 0.6 billion cubic feet (BCF) resulting in a deferred loss of
$1.0 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 $0.9 million,
$1.8 million and $0.5 million, $0.7 million, $2.1 million and $0.004 million and
$0.7 million, $2.1 million and $0.004 million for the three month, nine month
and twelve month periods ended September 30, 2000, respectively. The daily VaR
for the gas trading portfolio on an average, high and low basis was $1.6
million, $5.8 million and $0.5 million, $2.4 million, $8.1 million and $0.5
million and $2.2 million, $8.1 million and $0.4 million for the three month,
nine month and twelve month periods ended September 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
$479.6 million and $90.7 million at September 30, 2000 and December 31, 1999,
respectively, of which $447.2 million and $90.7 million were included in "Price
risk management assets" and $32.4 million and $0.0 million were included under
the caption "Prepayments and other" included in the Other Assets at September
30, 2000 and December 31, 1999, respectively. The accompanying Consolidated
Balance Sheet also reflects price risk management liabilities (including net
option premiums) of $498.2 million and $113.0 million of which $453.3 million
and $113.0 million were included in "Price risk management liabilities" and
$44.9 million and $0.0 million were included in "Other noncurrent liabilities"
at September 30, 2000 and December 31, 1999, respectively. Power trading results
are reflected on a net basis in the accompanying Consolidated Statements of
Income, consistent with the guidance in EITF Issue No. 98-10 with respect to the
use of written options and its settlement methodology with respect to physical
forward sales and purchase contracts.
NiSource has recorded as a component of electric revenues a realized
net profit/(loss) of $(0.1) million, $7.7 million and $7.9 million for the three
month, nine month and twelve month periods ended September 30, 2000 and $ 6.2
million, $7.0 million and $7.0 million for the three month, nine month and
twelve month periods ended September 30, 1999.
These net amounts reflect realized revenues and cost of sales related to
option contracts and physical forward sales and purchase contracts as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Power Trading Revenues $203,085 $121,461 $378,003 $178,339 $437,420 $178,339
Power Trading Cost of Sales $203,154 $115,264 $370,339 $171,294 $429,466 $171,294
</TABLE>
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. The amounts recorded as gas trading revenues and costs of goods sold
were as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
-------------------------- --------------------------- ---------------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
============ ============ ============ ============= ============ ============
<S> <C> <C> <C> <C> <C> <C>
Gas Trading Revenues $ 448,520 $ 98,457 $ 1,112,956 $ 189,007 $ 1,303,122 $ 189,007
Gas Trading Cost of Sales $ 449,810 $ 109,564 $ 1,108,881 $ 201,126 $ 1,295,953 $ 201,126
</TABLE>
NiSource has entered into forward interest rate swaps to hedge the
interest rate risk exposure associated with $1.6 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 notional amount terminate on
March 30, 2006, the interest rate swap on the $500 million notional amount
terminates on March 30, 2011 and the interest rate swap on the $500 million
amount terminates on March 30, 2031. 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.
The carrying values and estimated fair values of financial instruments were as
follows:
<TABLE>
<CAPTION>
September 30, 2000 December 31, 1999
------------------------ ------------------------
Carrying Estimated Carrying Estimated
(Dollars in thousands) Amount Fair Value Amount Fair Value
=========== =========== =========== ===========
<S> <C> <C> <C> <C>
Investments $ 52,462 $ 52,937 $ 49,064 $ 49,352
Long-term debt (including current portion) $ 1,826,711 $ 1,663,901 $ 2,148,905 $ 1,992,348
Preferred stock (including current portion) $ 137,638 $ 111,587 $ 141,469 $ 119,702
Company-obligated mandatorily redeemable
preferred securities of subsidiary trust
holding solely Company debentures $ 345,000 $ 331,200 $ 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.
The following table shows the basic steel industry percentage of gas revenue
(including transportation services) and electric revenue for 2000 and 1999:
<TABLE>
<CAPTION>
Twelve Months Twelve Months
Ended September 30, Ended September 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 September 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 $ 202,323 $ 295,295 $ 29,109 $ 471,628 $ 77,482 $ (70,291) $1,005,546
Other Net $ (909) $ (28) $ (3) $ 50,175 $ 4,142 $ 697 $ 54,074
Depreciation and Amortization $ 31,865 $ 40,403 $ 4,294 $ 2,601 $ 3,950 $ 987 $ 84,100
Income before Interest and Other
Charges and Income Taxes $ (21,704) $ 119,266 $ 11,292 $ 56,061 $ 4,031 $ (7,552) $ 161,394
Assets $2,478,656 $2,723,813 $714,993 $ 791,566 $ 591,001 $(215,862) $7,084,167
Capital Expenditures $ 25,594 $ 33,398 $ -- $ 262 $ 3,247 $ -- $ 62,501
Investment in Equity-Method Investees $ -- $ -- $ -- $ 7,786 $ 97,247 $ -- $ 105,033
</TABLE>
<TABLE>
<CAPTION>
For the three months ended September 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 $ 133,335 $ 325,044 $ 29,923 $ 179,322 $ 72,068 $ (51,700) $ 687,992
Other Net $ 911 $ 4,871 $ 771 $ 1,422 $ (16,853) $ (862) $ (9,740)
Depreciation and Amortization $ 29,203 $ 39,856 $ 3,872 $ 777 $ 3,626 $ 672 $ 78,006
Income before Interest and Other
Charges and Income Taxes $ (14,545) $ 121,396 $ 12,888 $ (2,595) $ (15,385) $ (10,013) $ 91,746
Assets $2,348,302 $2,704,192 $666,307 $ 314,642 $ 547,900 $ (74,082) $6,507,261
Capital Expenditures $ 44,737 $ 24,646 $ 22,953 $ 25 $ 4,444 $ -- $ 96,805
Investment in Equity-Method Investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
</TABLE>
<TABLE>
<CAPTION>
For the nine months ended September 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 $ 914,459 $ 811,388 $ 77,190 $1,168,669 $ 221,251 $(196,891) $2,996,066
Other Net $ 1,422 $ 48 $ 223 $ 50,830 $ 10,014 $ (2,676) $ 59,861
Depreciation and Amortization $ 96,684 $ 120,563 $ 12,827 $ 8,645 $ 11,860 $ 2,638 $ 253,217
Income before Interest and Other
Charges and Income Taxes $ 70,248 $ 292,776 $ 21,246 $ 74,470 $ 6,378 $ (29,682) $ 435,436
Assets $2,478,656 $2,723,813 $714,993 $ 791,566 $ 591,001 $(215,862) $7,084,167
Capital Expenditures $ 71,463 $ 91,132 $ 38,831 $ 12,797 $ 12,959 $ -- $ 227,182
Investment in Equity-Method Investees $ -- $ -- $ -- $ 7,786 $ 97,247 $ -- $ 105,033
</TABLE>
<TABLE>
<CAPTION>
For the nine months ended September 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 $ 711,954 $ 867,730 $ 74,882 $ 554,694 $ 202,827 $(151,857) $2,260,230
Other Net $ 2,149 $ (430) $ 1,234 $ 3,659 $ (15,261) $ (1,907) $ (10,556)
Depreciation and Amortization $ 85,324 $ 119,104 $ 10,886 $ 1,661 $ 9,547 $ 1,932 $ 228,454
Income before Interest and Other
Charges and Income Taxes $ 62,764 $ 283,916 $ 23,725 $ (1,041) $ (12,056) $ (19,910) $ 337,398
Assets $2,348,302 $2,704,192 $666,307 $ 314,642 $ 547,900 $ (74,082) $6,507,261
Capital Expenditures $ 98,488 $ 92,528 $ 39,779 $ 66 $ 18,519 $ -- $ 249,380
Investment in Equity-Method Investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
For the twelve months ended September 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 $1,278,072 $1,068,154 $100,808 $1,385,751 $ 301,950 $(253,984) $3,880,751
Other Net $ 3,436 $ 134 $ 972 $ 52,377 $ 5,144 $ (10,776) $ 51,287
Depreciation and Amortization $ 127,506 $ 160,436 $ 17,367 $ 10,121 $ 15,423 $ 5,314 $ 336,167
Income before Interest and Other
Charges and Income Taxes $ 127,090 $ 372,534 $ 26,661 $ 75,026 $ 4,400 $ (64,167) $ 541,544
Assets $2,478,656 $2,723,813 $714,993 $ 791,566 $ 591,001 $(215,862) $7,084,167
Capital Expenditures $ 101,034 $ 132,468 $ 63,075 $ 12,912 $ 11,891 $ -- $ 321,380
Investment in Equity-Method Investees $ -- $ -- $ -- $ 7,786 $ 97,247 $ -- $ 105,033
</TABLE>
<TABLE>
<CAPTION>
For the twelve months ended September 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 $ 915,020 $1,159,127 $ 95,951 $ 760,843 $ 270,089 $(187,566) $3,013,464
Other Net $ 3,849 $ (231) $ 1,371 $ 4,087 $ (16,150) $ (2,507) $ (9,581)
Depreciation and Amortization $ 104,479 $ 158,786 $ 13,859 $ 1,799 $ 12,438 $ 2,233 $ 293,594
Income before Interest and Other
Charges and Income Taxes $ 100,366 $ 366,464 $ 29,212 $ 323 $ (5,746) $ (23,845) $ 466,774
Assets $2,348,302 $2,704,192 $666,307 $ 314,642 $ 547,900 $ (74,082) $6,507,261
Capital Expenditures $ 117,621 $ 130,331 $ 56,974 $ 432 $ 27,265 $ -- $ 332,623
Investment in Equity-Method Investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
Gas Marketing and Storage, Other Net for the three months, nine months, and twelve months ended September 30, 2000 includes a
pre-tax gain of $51.9 million related to the sale of MHP.
</TABLE>
The following table reconciles total reportable segment income before interest
and other charges and income taxes to net income for three month, nine month and
twelve month periods ended September 30, 2000 and 1999:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(Dollars in thousands) 2000 1999 2000 1999 2000 1999
======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Total Segment profit (loss) $161,394 $ 91,746 $435,436 $337,398 $541,544 $466,774
Interest expense, net (50,161) (42,376) (146,304) (119,378) (193,543) (153,660)
Minority interests (5,225) (5,563) (15,266) (13,939) (19,020) (14,717)
Dividends requirements on
preferred stock of subsidiaries (2,003) (2,071) (6,045) (6,264) (8,115) (8,385)
-------- -------- -------- -------- -------- --------
Income before income taxes 104,005 41,736 267,821 197,817 320,866 290,012
Less: Income taxes 52,005 13,781 112,792 70,359 132,881 101,962
-------- -------- -------- -------- -------- --------
Net Income $ 52,000 $ 27,955 $155,029 $127,458 $187,985 $188,050
======== ======== ======== ======== ======== ========
</TABLE>
(26) Unaudited Pro Forma Financial Information. The following unaudited pro
forma information reflects the historical combined condensed consolidated
financial data of NiSource and Columbia after accounting for the merger as a
purchase business combination. Accordingly, you should read the following
information together with the historical consolidated financial statements of
NiSource and Columbia and all related notes. The unaudited pro forma combined
condensed consolidated balance sheet assumes the merger was completed as of
September 30, 2000. The unaudited pro forma combined condensed consolidated
statements of income from continuing operations assumes the merger was completed
at the beginning of the periods stated.
The information presented below is not necessarily indicative of the
results of operations that would have occurred had the merger actually been
completed at the beginning of the periods stated, or the actual financial
position that would have resulted had the merger actually been completed on
September 30, 2000. The information is also not necessarily indicative of the
future results of operations or financial position of New NiSource. In addition,
NiSource management has identified significant synergies and merger savings
which are not reflected in the pro forma combined condensed consolidated
financial data. NiSource expects to record a restructuring charge during the
fourth quarter of 2000 reflecting costs associated with a workforce reduction
and other merger-related costs. NiSource has not yet quantified the amount of
this charge.
The information below reflects completion of the merger using a holding
company structure, which involves the creation of a new holding company,
currently named New NiSource, and two separate but concurrent mergers. In this
merger, a wholly-owned subsidiary of New NiSource will merge into NiSource. In
the other merger, a second wholly-owned subsidiary of New NiSource will merge
into Columbia. NiSource and Columbia will be the surviving corporations in those
mergers and will be wholly-owned by New NiSource. Immediately after these
mergers, NiSource will merge into New NiSource. New NiSource will then change
its name to "NiSource Inc." and will serve as a holding company for Columbia and
its subsidiaries and the subsidiaries of NiSource.
The pro forma combined condensed consolidated financial data assume
that 30% of Columbia's shares are each exchanged for 3.04414 New NiSource common
shares, and 70% of Columbia's shares are exchanged for $70 in cash plus $2.60
stated amount of a SAILS. The total aggregated purchase price for the
transaction using this assumption is approximately $5.8 billion.
The merger is being accounted for by the purchase method. The purchase
price has been allocated to the assets acquired and liabilities assumed based
upon their estimated fair values. The accompanying allocation anticipates that
the fair market value of Columbia's regulated operations reasonably approximates
the underlying book values of these operations. As a result, the purchase price
paid in excess of the estimated fair value of non-regulated operations and the
book value, which is a proxy for fair value, of regulated operations has been
allocated to goodwill. Allocations included in the pro forma combined condensed
consolidated financial statements are based on analyses that are not yet
completed. Management continues to assess the strategic nature and fit of
certain assets and operations of the combined entity. Additionally, management
continues to assess financial exposure to litigation, environmental, regulatory
and other similar contingencies as part of the merger. Another ongoing
assessment includes the requirements to fulfill the combined company's human
resource needs. Accordingly, the final value of the purchase price and its
allocation may differ, perhaps significantly, from the amounts included in the
accompanying pro forma statements.
On October 30, 2000 NiSource received an order from the SEC approving
the merger. This order requires NiSource to dispose of its water operations
three years from the date of the merger. Management has not developed a formal
plan of disposition responsive to the order and, accordingly, has not reflected
the water operations as a discontinued operation or assets held for sale.
The pro forma financial statements and notes should be read in
conjunction with the historical consolidated financial statements and related
notes of NiSource and CEG. These statements were prepared in accordance with
rules and regulations established by the Securities and Exchange Commission and
are not necessarily reflective of the actual or future results of operations or
financial position of the combined company.
<PAGE>
<TABLE>
<CAPTION>
New NiSource Inc.
Unaudited Pro Forma Combined Condensed Consolidated Balance Sheet
as of September 30, 2000
Pro Forma
(Dollars in thousands) NiSource CEG Adjustments Consolidated
============= ============= ============= =============
Assets
Property, Plant and Equipment:
<S> <C> <C> <C> <C>
Net Utility Plant $ 4,773,669 $ 4,313,300 $ -- $ 9,086,969
Net Other Plant 127,841 628,500 219,573 G 975,914
------------- ------------- ------------- -------------
Total Property, Plant and Equipment 4,901,510 4,941,800 219,573 10,062,883
------------- ------------- ------------- -------------
Investments:
Investment in unconsolidated affiliates 165,484 305,600 (12,773) L 458,311
Other 34,345 171,700 (134,600) O 71,445
------------- ------------- ------------- -------------
Total Investments 199,829 477,300 (147,373) 529,756
------------- ------------- ------------- -------------
Current Assets:
Cash and cash equivalents 51,029 30,300 -- 81,329
Accounts receivable, less reserve 425,216 278,300 -- 703,516
Exchange gas -- 458,400 -- 458,400
Energy adjustment clauses 94,280 92,300 -- 186,580
Other inventories 90,273 14,600 -- 104,873
Natural gas in storage 190,928 236,500 -- 427,428
Price risk management assets 447,219 -- -- 447,219
Prepayments and other current assets 45,774 200,400 -- 246,174
------------- ------------- ------------- -------------
Total Current Assets 1,344,719 1,310,800 -- 2,655,519
------------- ------------- ------------- -------------
Other Assets
Regulatory assets 205,958 344,900 -- 550,858
Intangible assets, less accumulated provision
for amortization 75,183 3,300 3,539,347 A,O 3,617,830
Prepayments and other assets 356,968 22,400 48,050 J 427,418
------------- ------------- ------------- -------------
Total Other Assets 638,109 370,600 3,587,397 4,596,106
------------- ------------- ------------- -------------
$ 7,084,167 $ 7,100,500 $ 3,659,597 $ 17,844,264
============= ============= ============= =============
See Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New NiSource Inc.
Unaudited Pro Forma Combined Condensed Consolidated Balance Sheet
as of September 30, 2000
Pro Forma
(Dollars in thousands) NiSource CEG Adjustments Consolidated
============= ============= ============= =============
Capitalization and Liabilities
Capitalization:
<S> <C> <C> <C> <C>
Common stock - without par $ 870,930 $ -- $ (870,930)D $ --
Common stock, $.01 par value -- 800 (800)D --
Common stock, $.01 par value -- -- 1,938 E 1,938
Additional paid-in capital 172,649 1,617,000 498,048 D,E,L 2,287,697
Treasury shares (516,065) (249,100) 765,165 K --
Retained earnings 824,551 665,600 (665,600)D 824,551
------------- ------------- ------------- -------------
Common Shareholders' Equity 1,352,065 2,034,300 (272,179) 3,114,186
------------- ------------- ------------- -------------
Cumulative Preferred Stock 135,811 -- -- 135,811
Company-obligated preferred securities of
subsidiary trust holding solely Company
debentures 345,000 -- -- 345,000
SAILS -- -- 106,100 M 106,100
Long-term debt, less current portion 1,737,291 1,639,200 2,494,563 I,N 5,871,054
------------- ------------- ------------- -------------
Total Capitalization 3,570,167 3,673,500 2,328,484 9,572,151
------------- ------------- ------------- -------------
Current Liabilities:
Current portion of long-term debt 89,420 311,100 -- 400,520
Short term borrowings 748,608 -- 3,828,916 H 4,577,524
Short term borrowings -- 54,100 (2,628,916)I (2,574,816)
Accounts payable 368,020 238,700 -- 606,720
Dividends declared on common and preferred stocks 33,679 -- -- 33,679
Transportation and exchange gas -- 223,700 -- 223,700
Taxes accrued 26,478 144,500 -- 170,978
Interest accrued 27,425 75,600 -- 103,025
Price risk management liabilities 453,302 -- -- 453,302
Deferred revenue -- 436,000 -- 436,00
Other accruals 220,642 321,600 -- 542,242
------------- ------------- ------------- -------------
Total Current Liabilities 1,967,574 1,805,300 1,200,000 4,972,874
------------- ------------- ------------- -------------
Other:
Deferred income taxes 931,922 741,100 83,262 G 1,756,284
Deferred investment tax credits, being
amortized over life of related property 89,217 31,600 -- 120,817
Deferred credits 112,609 -- -- 112,609
Deferred revenue -- 512,200 -- 512,200
Customers advances and contributions in aid to
construction 157,475 21,900 -- 179,375
Accrued liability for postretirement benefits 169,305 116,700 -- 286,005
Other 85,898 198,200 47,851 J 331,949
------------- ------------- ------------- -------------
Total Other 1,546,426 1,621,700 131,113 3,299,239
------------- ------------- ------------- -------------
$ 7,084,167 $ 7,100,500 $ 3,659,597 $ 17,844,264
============= ============= ============= =============
See Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New NiSource Inc.
Unaudited Pro Forma Combined Condensed Statement of Income from Continuing Operations
For Nine Months Ended September 30, 2000
Pro Forma
(Dollars in thousands, except for per share amounts) NiSource CEG Adjustments Consolidated
============= ============= ============= =============
<S> <C> <C> <C> <C>
Operating Revenues $ 2,996,066 $ 1,828,300 $ -- $ 4,824,366
Cost of Sales 1,835,891 468,300 -- 2,304,191
------------- ------------- ------------- -------------
Operating Margin 1,160,175 1,360,000 -- 2,520,175
------------- ------------- ------------- -------------
Operating Expenses and Taxes (except income) :
Operation and maintenance 458,213 638,900 (7,500)P 1,089,613
Settlement of supply charges -- -- -- --
Depreciation, depletion and amortization 253,217 153,000 74,597 F 480,814
Taxes (except income) 73,170 141,300 -- 214,470
------------- ------------- ------------- -------------
784,600 933,200 67,097 1,784,897
------------- ------------- ------------- -------------
Operating Income 375,574 426,800 (67,097) 733,660
------------- ------------- ------------- -------------
Other Income (Deductions) 59,861Q 103,800Q -- 163,661
------------- ------------- ------------- -------------
435,436 530,600 (67,097) 898,939
------------- ------------- ------------- -------------
Interest and Other Charges:
Interest expense 146,304 139,200 230,789 B 516,293
Minority interest 15,266 -- -- 15,266
Dividend requirements on preferred stock of
subsidiaries 6,045 -- -- 6,045
------------- ------------- ------------- -------------
Total 167,615 139,200 230,789 537,604
------------- ------------- ------------- -------------
Income Before Income Taxes 267,821 391,400 (297,886) 361,335
------------- ------------- ------------- -------------
Income Taxes 112,792Q 145,600Q (87,793)C,F,P 170,599
------------- ------------- ------------- -------------
Net Income from continuing operations 155,029 245,800 (210,093) 190,736
============= ============= ============= =============
Average common shares outstanding - basic 121,652 80,163 -- 201,815
Common shares retired -- -- (80,163)D (80,163)
Common shares issued -- -- 54,351 E 54,351
Average number of common shares -- -- - 176,003
Diluted shares 3,628 767 (767)D 3,628
------------- ------------- ------------- -------------
Total Diluted Shares 125,280 80,930 -- 179,631
Basic earnings per average common share from
continuing operations $ 1.27 $ 3.06 -- $ 1.08
============= ============= ============= =============
Diluted earnings per average common share from
continuing operations $ 1.23 $ 3.03 -- $ 1.06
============= ============= ============= =============
Common shares outstanding at end of period (000) 121,320 79,530 -- 175,671
See Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New NiSource Inc.
Unaudited Pro Forma Combined Condensed Statement of Income from Continuing Operations
For Twelve Months Ended September 30, 2000
Pro Forma
(Dollars in thousands, except for per share amounts) NiSource CEG Adjustments Consolidated
============= ============= ============= =============
<S> <C> <C> <C> <C>
Operating Revenues $ 3,880,751 $ 2,620,000 $ -- $ 6,500,751
Cost of Sales 2,318,352 683,400 -- 3,001,752
------------- ------------- ------------- -------------
Operating Margin 1,562,399 1,936,600 -- 3,498,999
------------- ------------- ------------- -------------
Operating Expenses and Taxes (except income) :
Operation and maintenance 637,042 862,200 (7,500)P 1,491,742
Settlement of supply charges -- (1,900) -- (1,900)
Depreciation, depletion and amortization 336,167 181,600 99,462 F 617,229
Taxes (except income) 98,933 188,700 -- 287,633
------------- ------------- ------------- -------------
1,072,142 1,230,600 91,962 2,394,704
------------- ------------- ------------- -------------
Operating Income 490,257 706,000 (91,962) 1,104,295
------------- ------------- ------------- -------------
Other Income (Deductions) 51,287Q 118,500Q -- 169,787
------------- ------------- ------------- -------------
541,544 524,500 (91,962) 1,274,082
------------- ------------- ------------- -------------
Interest and Other Charges:
Interest expense 193,543 187,800 307,718 B 689,061
Minority interest 19,020 -- -- 19,020
Dividend requirements on preferred stock of
subsidiaries 8,115 -- -- 8,115
------------- ------------- ------------- -------------
Total 220,678 187,800 307,718 716,196
------------- ------------- ------------- -------------
Income Before Income Taxes 320,866 636,700 (399,680) 557,886
------------- ------------- ------------- -------------
Income Taxes 132,881Q 219,800Q (118,006)C,F,P 234,675
------------- ------------- ------------- -------------
Net Income from continuing operations 187,985 416,900 (281,674) 323,211
============= ============= ============= =============
Average common shares outstanding - basic 122,423 80,423 -- 202,846
Common shares retired -- -- (80,423)D (80,423)
Common shares issued -- -- 72,468 E 72,468
Average number of common shares -- -- - 194,891
Diluted shares 3,143 767 (767)D 3,143
------------- ------------- ------------- -------------
Total Diluted Shares 125,566 81,190 -- 198,034
Basic earnings per average common share from
continuing operations $ 1.53 $ 5.18 -- $ 1.65
============= ============= ============= =============
Diluted earnings per average common share from
continuing operations $ 1.49 $ 5.13 -- $ 1.63
============= ============= ============= =============
Common shares outstanding at end of period (000) 121,320 79,530 -- 193,788
See Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New NiSource Inc.
Unaudited Pro Forma Combined Condensed Statement of Income from Continuing Operations
For Twelve Months Ended September 30, 1999
Pro Forma
(Dollars in thousands, except for per share amounts) NiSource CEG Adjustments Consolidated
============= ============= ============= =============
<S> <C> <C> <C> <C>
Operating Revenues $ 3,144,576 $ 2,800,900 $ -- $ 5,945,476
Cost of Sales 1,651,051 892,900 -- 2,543,951
------------- ------------- ------------- -------------
Operating Margin 1,493,525 1,908,000 -- 3,401,525
------------- ------------- ------------- -------------
Operating Expenses and Taxes (except income) :
Operation and maintenance 617,016 838,600 -- O 1,455,616
Settlement of supply charges -- (31,700) -- (31,700)
Depreciation, depletion and amortization 311,404 202,700 99,462 F 13,566
Taxes (except income) 103,569 203,200 -- 306,769
------------- ------------- ------------- -------------
1,031,989 1,212,800 99,462 2,344,251
------------- ------------- ------------- -------------
Operating Income 461,536 695,200 (99,462) 1,057,274
------------- ------------- ------------- -------------
Other Income (Deductions) (18,030) 34,900 -- 16,870
------------- ------------- ------------- -------------
443,506 730,100 (99,462) 1,074,144
------------- ------------- ------------- -------------
Interest and Other Charges:
Interest expense 166,617 164,200 307,718 B 638,535
Minority interest 17,693 -- -- 17,693
Dividend requirements on preferred stock of
subsidiaries 8,334 -- -- 8,334
------------- ------------- ------------- -------------
Total 192,644 164,200 307,718 664,562
------------- ------------- ------------- -------------
Income Before Income Taxes 250,862 565,900 (407,180) 409,582
------------- ------------- ------------- -------------
Income Taxes 90,448 178,100 (120,850)C,F,P 147,698
------------- ------------- ------------- -------------
Net Income from continuing operations 160,414 387,800 (286,330) 261,884
============= ============= ============= =============
Average common shares outstanding - basic 124,343 82,210 -- 206,553
Common shares retired -- -- (80,163)D (82,210)
Common shares issued -- -- 72,468 E 72,468
Average number of common shares -- -- - 196,811
Diluted shares 996 499 (499)D 996
------------- ------------- ------------- -------------
Total Diluted Shares 125,339 82,709 -- 197,807
Basic earnings per average common share from
continuing operations $ 1.29 $ 4.71 -- $ 1.33
============= ============= ============= =============
Diluted earnings per average common share from
continuing operations $ 1.28 $ 4.68 -- $ 1.32
============= ============= ============= =============
Common shares outstanding at end of period (000) 124,139 81,305 -- 196,607
See Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Notes to Unaudited Pro Forma Combined Condensed Consolidated Financial Statement
<S> <C> <C>
A. To reflect the purchase price allocation to goodwill. The adjustments
include the step-up applied to Columbia common shares, estimated merger
costs NiSource will incur and costs relating to certain compensation
obligations, net of tax benefits.
Weighted average consideration to be paid for Columbia common shares $ 72.54
Columbia Common Shares (in thousands):
Outstanding at September 30, 2000 excluding shares held by NiSource 79,350
-----------------
Fair value of consideration $ 5,756,084
Less: Columbia's net equity at September 30, 2000 2,034,300
Less: Profit from sale of electric facility 86,300
NiSource ownership of Columbia shares 13,313
-----------------
Consideration in excess of Columbia book value $ 3,648,797
Reserves for contractual obligations 47,851
Value of nonqualified stock options cashed out 111,413
Estimated merger costs 50,000
Estimated tax benefits associated with non-qualified stock options
and contractual obligations (48,050)
------------------
Allocable purchase price $ 3,810,010
Less:
Step-up allocated to non-utility properties, net of deferred taxes (136,311)
Adjustment to CEG debt (134,353)
------------------
Amount allocated to goodwill $ 3,539,346
=================
The weighted average consideration of $72.54 assumes that holders of
30% of Columbia's shares will elect to receive 3.04414 of New NiSource
common shares and that the holders of 70% of the shares will receive
$70 in cash and $2.60 stated amount of SAILS. The accompanying
allocation anticipates that the fair market value of Columbia's
regulated operations reasonably approximates the underlying book value
of these operations. This allocation is based on analyses that are not
yet completed. Accordingly, the final value of the purchase price and
its allocation may differ, perhaps significantly, from the amounts
included in the accompanying pro forma statements.
B. To adjust historical interest expense to reflect the cost of the
increased indebtedness from completion of the merger. The pro forma
statements assume a weighted average 7.8% per annum interest rate on
the indebtedness incurred to complete the merger. A one-eighth percent
variance from the assumed rate increases or decreases pre-tax interest
expense by approximately $4.8 million on an annual basis.
C. To recognize the estimated pro forma income tax effect of additional
interest expense reflected in adjustment (B).
D. To eliminate Columbia and NiSource common shareholders' equity and
related common shares.
E. To reflect the issuance of 3.04414 shares of New NiSource common stock
for each converted share of Columbia common stock and the issuance of
one share of New NiSource common stock for each old NiSource common
share.
F. To adjust historical depreciation, depletion and amortization expense
for the preliminary purchase price allocation reflected in these pro
forma financial statements. The amount allocated to goodwill reflects
amortization on a straight-line basis over a 40-year period. The amount
allocated to net other plant reflects amortization on a straight-line
basis over a 20-year period. This adjustment also reflects the deferred
income tax impact of amortizing the amount allocated to net other
plant.
G. To reflect the allocation of purchase price to the exploration
production properties including $219.6 million to net other plant and
related deferred income taxes of $83.3 million.
H. To reflect the issuance of $3.8 billion of short-term acquisition debt.
I. To reflect the reclassification of acquisition debt from short-term
to long-term consistent with NiSource's intent and ability to refinance
such amounts.
J. To reflect a liability of $47.9 million related to contractual
obligations associated with employment agreements of Columbia including
related tax benefits. The adjustment also reflects the estimated tax
benefits associated with the cash out of Columbia stock options.
K. To reflect the cancellation of NiSource and Columbia treasury shares.
L. To eliminate NiSource investments in Columbia common shares at
September 30, 2000 and allocate to purchase price.
M. To reflect the fair value purchase price consideration of SAILS, units
consisting of zero coupon securities and forward equity contracts.
N. To reflect the fair value adjustment of CEG's long term debt
outstanding.
O. To reflect the sale of Columbia's electric facilities expected to be
completed in the fourth quarter 2000. The adjustment reduces
investments by $134.6 million and increases equity by $86.3 million.
Net proceeds of $220.9 million will be used to reduce debt.
P. To reflect the elimination of compensation expense of certain CEG
employees associated with additional amounts paid as a result of the
merger, along with the related income tax effect.
Q. Other Income (Deductions) from continuing operations for the nine month
and twelve month periods ended September 30, 2000 reflect pre-tax gains
of $51.9 million for NiSource in connection with its disposition of MHP
and $95.2 million for CEG in connection with the sale of Cove Point
LNG. Amounts included in Income Taxes related to these sales include
$25.8 million for the disposition of MHP and $36.2 million for the sale
of Cove Point LNG. Operating revenues, operating income and net income
from continuing operations reflected in the accompanying unaudited pro
forma combined condensed consolidated statements of income from
continuing operations for MHP and Cove Point LNG are not significant to
each company.
</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 and
trading operations with the April 1999 acquisition of TPC Corporation, now
renamed EnergyUSA-TPC Corp. (TPC). 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 remained relatively unchanged from the twelve months ended
September 30, 1999. For nine months ended September 30, 2000 net income
increased $27.6 million from the nine months ended September 30, 1999 to $155.0
million and increased $24.0 million from the three months ended September 30,
1999 to $52.0 million for the three months ended September 30, 2000. Results for
the three periods ended September 30 are not directly comparable year to year
due to the acquisition of BSG, TPC and MHP in 1999. Earnings for all 2000
periods reflect an after tax gain of $23.8 million from the sale of MHP.
NiSource established its New England presence when it acquired BSG in February
1999. The natural gas marketing and asset optimization units of TPC 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 $2.4 billion for the twelve months ended September 30, 2000 (after
elimination of intercompany transmission, marketing and storage revenue of
approximately $237.9 million), an increase of $915.8 million from the comparable
period ended September 30, 1999. This increase was primarily due to increased
gas revenues from BSG of $221.8 million reflecting a full twelve months of
results, increased gas marketing, storage and trading revenues of $601.7 as a
result of the TPC and MHP acquisitions in 1999, and increased gas costs of
$110.2 million partially offset by decreased sales to the residential and
commercial customers of the Energy Utilities located in northern Indiana as a
result of heating degree days 3% lower than 1999.
Gas revenues were $1.9 billion for the nine months ended September 30,
2000 (after elimination of intercompany transmission, marketing and storage
revenue of approximately $185.4 million), an increase of $768.3 million from the
comparable period ended September 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 nine months results from BSG in
the 2000 period and increased gas costs partially offset by decreased sales to
the residential and commercial customers of the Energy Utilities located in
northern Indiana as a result of heating degree days 6% lower than 1999.
Gas revenues were $606.9 million for the three months ended September
30, 2000 (after elimination of intercompany transmission, marketing and storage
revenue of approximately $66.5 million) an increase of $341.5 million from the
comparable period ended September 30, 1999. This increase is attributable to
increased gas marketing, storage and trading revenues, increased gas costs and
increased sales to residential and commercial customers of the Energy Utilities
as a result of heating degree days 48% higher than 1999.
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 54.9, 188.4 and 258.1
million dth for others during the three month, nine month and twelve month
periods ended September 30, 2000, respectively.
The basic steel industry accounted for 18% of natural gas delivered
(including volumes transported) during the nine months ended September 30, 2000.
The components of the changes in gas revenues are shown in the following table:
<TABLE>
<CAPTION>
---------------------------------------------
Ended September 30, 2000
---------------------------------------------
Three Nine 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 $ 41,532 $ 90,726 $ 110,232
Changes in sales levels 18,120 (15,968) (19,449)
Bay State Gas Acquisition -- 103,273 221,765
Gas transported 7,945 844 1,543
Gas marketing, storage and trading 273,899 589,446 601,678
------------ ------------ ------------
Gas Revenue Change $ 341,496 $ 768,321 $ 915,769
============ ============ ============
</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 $785.3 million (71%) to $1.9 billion for the twelve months ended
September 30, 2000 from the comparable period ended September 30, 1999, due to
the increased gas costs of $125.8 million for BSG reflecting a full twelve
months of operations, increased gas marketing and trading activities of $589.7
million as a result of the TPC acquisition 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 $3.52 per dth, excluding purchased gas
costs of BSG, as compared to $2.48 per dth for the comparable period ended
September 30, 1999.
Gas costs increased $698.8 million (86%) to $1.5 billion for the nine
months ended September 30, 2000 from the comparable period ended September 30,
1999, mainly due to increased gas purchases of $574.3 million related to gas
marketing and trading activities as a result of the TPC acquisition in 1999,
increased gas cost of $66.3 million for BSG reflecting a full nine 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 $3.64 per dth, excluding purchased gas costs of BSG, as compared to $2.49
per dth for the comparable period ended September 30, 1999.
Gas costs increased $318.4 million (153%) to $526.4 million for the
three months ended September 30, 2000 from the comparable period ended September
30, 1999, mainly due to increased gas purchases of $285.8 million related to gas
marketing and trading activities as a result of the TPC acquisition 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 $5.11 per dth as compared to
$3.04 per dth for the comparable period ended September 30, 1999.
GAS OPERATING MARGIN
Gas operating margin for the twelve months ended September 30, 2000
increased $130.5 million to $535.5 million from the comparable period ended
September 30, 1999. This increase mainly reflects an increase of $95.0 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 the Indiana Energy Utilities residential and commercial customers
reflecting a warmer heating season during the period.
Gas operating margin increased $69.5 million to $384.7 million during
the nine months ended September 30, 2000 from the comparable period ended
September 30, 1999. This increase mainly reflects an increase of $36.2 million
of gas operating margin from BSG, reflecting a full nine months of operation,
and increased gas marketing, storage and trading activities, partially offset by
decreased deliveries to the Indiana Energy Utilities residential and commercial
customers reflecting the warmer heating season during the first quarter of 2000
from the comparable period ended September 30, 1999.
Gas operating margin increased $23.1 million to $80.4 million during
the three months ended September 30, 2000 from the comparable period ended
September 30, 1999. This increase reflects increased margin earned from higher
sales to residential and commercial customers of the Energy Utilities as a
result of increased heating days and an increase of $2.8 million of margin from
gas marketing and trading activities.
ELECTRIC REVENUES
Electric revenues were $1.1 billion for the twelve months ended
September 30, 2000 (after elimination of intercompany transactions of
approximately $2.6 million), a decrease of $90.0 million from the comparable
period ended September 30, 1999. Electric revenues decreased as a result of
reduced wholesale sales and power marketing transactions, reduced sales to
residential customers due to cooler weather in 2000 and lower fuel costs,
partially offset by increased industrial sales. Sales of electricity in
kilowatt-hours (kwh) decreased 14% from the comparable period ended September
30, 1999.
Electric revenues were $809.4 million for the nine months ended
September 30, 2000 (after elimination of intercompany transactions of
approximately $2.0 million), a decrease of $55.6 million from the comparable
period ended September 30, 1999. Electric revenues decreased as a result of
reduced wholesale sales and power marketing transactions and reduced sales to
residential customers due to cooler weather. Sales of electricity in kwh
decreased 8% from the comparable period ended September 30, 1999, as a result of
cooling degree days 23% lower than 1999.
Electric revenues were $294.7 million for the three months ended
September 30, 2000 (after elimination of intercompany transactions of
approximately $0.6 million), a decrease of $34.6 million from the comparable
period ended September 30, 1999. Electric revenues decreased as a result of
reduced wholesale sales and power marketing transactions and reduced residential
and industrial sales. Electric wholesale sales decreased 45% and sales to
residential customers decreased 4%, due to cooler weather and decreased
industrial customers. Sales of electricity in kwh decreased 8% from the
comparable period ended September 30, 1999, as a result of cooling degree days
24% lower than 1999.
The basic steel industry accounted for 33% of electric sales during the
twelve months ended September 30, 2000.
The components of the changes in electric revenues are shown in the following
table:
<TABLE>
<CAPTION>
---------------------------------------------
Ended September 30, 2000
---------------------------------------------
Three Nine Twelve
(Dollars in thousands) Months Months Months
============ ============ ============
Electric Revenue Changes
<S> <C> <C> <C>
Pass through of net changes in fuel costs $ (12,234) $ (17,774) $ (20,182)
Changes in sales levels (6,916) 1,345 13,359
Wholesale sales and power marketing (15,414) (39,131) (83,129)
------------ ------------ ------------
Electric Revenue Change $ (34,564) $ (55,560) $ (89,952)
============ ============ ============
</TABLE>
ELECTRIC COST OF SALES
Cost of fuel for electric generation decreased $5.5 million to $239.9
million for the twelve months ended September 30, 2000 from the comparable
period ended September 30, 1999. The decrease is primarily due to decreased
generation and fuel costs per kwh generated. The average cost per kwh generated
decreased 5% from the comparable period ended September 30, 1999, to 1.41 cents
per kwh, for the twelve months ended September 30, 2000.
Cost of fuel for electric generation decreased $9.2 million to $178.8
million for the nine months ended September 30, 2000 from the comparable period
ended September 30, 1999. The decrease is primarily due to decreased fuel costs
per kwh generated. The average cost per kwh generated decreased 6% from the
comparable period ended September 30, 1999, to 1.40 cents per kwh, for the nine
months ended September 30, 2000.
Cost of fuel for electric generation decreased $7.3 million to $64.8
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999. The decrease is primarily due to decreased generation
and fuel cost per kwh generated. The average cost per kwh generated decreased 3%
from the comparable period ended September 30, 1999, to 1.45 cents per kwh, for
the three months ended September 30, 2000.
POWER PURCHASED
Power purchased decreased $88.0 million to $26.2 million for the twelve
months ended September 30, 2000 from the comparable period ended September 30,
1999. The decrease is a result of decreased wholesale sales and power marketing
activities and decreased cost per kwh.
Power purchased decreased $45.5 million and $21.2 million to $22.2
million and $7.0 million, respectively, for the nine and three months ended
September 30, 2000 from the comparable periods ended September 30, 1999. The
decrease is a result of decreased cost per kwh and decreased wholesale sales and
power marketing activities.
ELECTRIC OPERATING MARGIN
Operating margin from electric sales increased $3.5 million to $799.3
million for the twelve months ended September 30, 2000 from the comparable
period ended September 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 a $1.8 million charge to
earnings due to a change in the regulatory mechanism for recovery of purchased
power costs in the second quarter 2000 and decreased residential sales due to
weather.
Operating margin from electric sales decreased $0.9 million to $608.4
million for the nine months ended September 30, 2000 from the comparable period
ended September 30, 1999. This decrease includes a $1.8 million charge to
earnings due to a change in the regulatory mechanism for recovery of purchased
power costs, lower sales to residential customers due to cooler weather this
summer and was mostly offset by improved margins on wholesale and power
marketing transactions and increased sales to commercial and industrial
customers.
Operating margin from electric sales decreased $6.1 million to $222.9
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999. This decrease is mainly due to lower sales to
residential customers due to cooling degree days 24% less than last year.
WATER REVENUE
Water revenues were $100.4 million for the twelve months ended
September 30, 2000 (after elimination of intercompany transactions of
approximately $0.3 million for the twelve months ended September 30, 2000), an
increase of $4.6 million from the comparable period ended September 30, 1999.
This increase is due to the increase in base rates for IWC and increased water
volumes sold.
Water revenues were $76.8 million for the nine months ended September
30, 2000 (after elimination of intercompany transactions of approximately $0.2
million for the nine months ended September 30, 2000), an increase of $2.0
million from the comparable period ended September 30, 1999. This increase was
primarily due to the increase in base rates for IWC.
Water revenues were $28.9 million for the three months ended September
30, 2000 (after elimination of intercompany transactions of approximately $0.1
million for the three months ended September 30, 2000), a decrease of $1.0
million from the comparable period ended September 30, 1999. This decrease was
due to decreased water volumes sold during the quarter.
The components of the changes in water revenues are shown in the following
table:
<TABLE>
<CAPTION>
---------------------------------------------
Ended September 30, 2000
---------------------------------------------
Three Nine Twelve
(Dollars in thousands) Months Months Months
============ ============ ============
Water Revenue Changes
<S> <C> <C> <C>
Rate increase $ -- $ 1,160 $ 5,351
Changes in sales levels (968) 868 (773)
------------ ------------ ------------
Water Revenue Change $ (968) $ 2,028 $ 4,578
============ ============ ============
</TABLE>
PRODUCTS AND SERVICES REVENUES
Products and Services revenues were $293.1 million for the twelve
months ended September 30, 2000 (after elimination of intercompany transactions
of approximately $13.3 million), an increase of $37.3 million from the
comparable period ended September 30, 1999. This increase reflects increased
line locating and marking activity, increased pipeline construction activity,
increased revenue from a cogeneration facility and the inclusion of revenue of
BSG's unregulated subsidiaries commencing in February 1999.
Products and Services revenues were $213.6 million for the nine months
ended September 30, 2000 (after elimination of intercompany transactions of
approximately $9.3 million), an increase of $21.4 million from the comparable
period ended September 30, 1999. This increase reflects increased line locating
and marking activity and increased pipeline construction activity offset by
lower revenue from other energy-related service companies.
Products and Services revenues were $75.1 million for the three months
ended September 30, 2000 (after elimination of intercompany transactions of
approximately $3.1 million), an increase of $6.6 million from the comparable
period ended September 30, 1999. This increase reflects increased line locating
and marking activity offset by decreased pipeline construction activity and
lower revenue from the other energy-related service companies.
The components of the changes in operating revenues at Products and Services are
shown in the following table:
<TABLE>
<CAPTION>
---------------------------------------------
Ended September 30, 2000
---------------------------------------------
Three Nine Twelve
(Dollars in thousands) Months Months Months
============ ============ ============
Products and Services Revenue Changes
<S> <C> <C> <C>
Pipeline construction $ (793) $ 4,532 $ 7,311
Locate and marking 6,142 18,474 20,438
Cogeneration project 265 3,334 2,750
Other 1,026 (4,927) 6,783
------------ ------------ ------------
Products and Services Revenue Change $ 6,640 $ 21,413 $ 37,282
============ ============ ============
</TABLE>
PRODUCTS AND SERVICES COST OF SALES
The cost of sales for Products and Services increased $36.5 million to
$165.9 million for the twelve months ended September 30, 2000 from the
comparable period ended September 30, 1999. This increase reflects the inclusion
of higher costs due to increased activity from 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 $23.2 million to
$123.3 million for the nine months ended September 30, 2000 from the comparable
period ended September 30, 1999 mainly due to the increase in the cost of sales
for line locating and marking activities and pipeline construction partially
offset by decreased project costs at the energy-related service subsidiaries.
The cost of sales for Products and Services increased $6.5 million to
$44.0 million for the three months ended September 30, 2000 from the comparable
period ended September 30, 1999 mainly due to the increase in the cost of sales
for line locating and marking activities 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 $0.8 million to $127.2
million for the twelve months ended September 30, 2000, reflecting increased
revenue from a cogeneration facility, increased pipeline construction activity
and the inclusion of the operating margin of certain subsidiaries acquired in
connection with the BSG acquisition, offset by decreased margin in line locating
and marking activity.
Products and Services operating margin decreased $1.8 million to $90.2
million for the nine months ended September 30, 2000, reflecting decreased
margin in line locating and marking activity and real estate sales partially
offset by increased margins from cogeneration activities.
Products and Services operating margin decreased $0.2 million to $31.1
million for the three months ended September 30, 2000, reflecting decreased
pipeline construction activity and real estate sales activity, offset by
increased margin in line locating and marking activity and margins from
cogeneration activities.
OPERATING EXPENSES AND TAXES (EXCEPT INCOME)
Operating expenses and taxes (except income) increased $124.3 million
to $1,072.1 million for the twelve months ended September 30, 2000 from the
comparable period ended September 30, 1999. Operating expenses and taxes (except
income) increased $40.2 million to $784.6 million for the nine months ended
September 30, 2000 from the comparable period ended September 30, 1999.
Operating expenses and taxes (except income) increased $14.9 million to $256.0
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999.
The operation and maintenance expenses of the Energy Utilities
increased $42.7 million to $431.0 million for the twelve months ended September
30, 2000 from the comparable period ended September 30, 1999. The increase was
due to an increase of $34.3 million of operation expenses from BSG reflecting a
full twelve months of expenses, a favorable $13.0 million insurance settlement
in the 1999 period related to manufactured gas plants site cleanup costs,
increased employee related costs of $2.2 million, partially offset by decreased
customer related costs of $2.8 million, decreased expenses for electric
production facilities of $1.6 million and other operating costs. The unregulated
gas marketing, gas storage and trading operation expenses increased $8.7 million
to $19.2 million for the twelve months ended September 30, 2000 primarily due to
the inclusion of an additional $15.5 million of TPC operation costs offset by
decreases in other operating costs. Operation expenses at the Water Utilities
increased $2.8 million to $49.6 million for the twelve months ended September
30, 2000 from the comparable period ended September 30, 1999. Operation expenses
for Products and Services increased $4.9 million to $115.0 million for the
twelve months ended September 30, 2000 from the comparable period ended
September 30, 1999 reflecting increased operating expenses in line locating and
marking operations and pipeline construction operations.
Operation expenses for the twelve months ended September 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 $8.5 million to $317.6 million for the nine months ended September 30,
2000 from the comparable period ended September 30, 1999. This increase was
primarily due to increased operation expenses from BSG of $12.4 million
reflecting a full nine months expenses, the $13.0 million insurance settlement
in September 1999 related to manufactured gas plants site cleanup costs,
partially offset by decreased employee related costs of $7.4 million, decreased
sales and marketing costs of $1.3 million, decreased customer related costs of
$1.4 million and various other operation costs. The unregulated gas marketing,
gas storage and trading operation expenses increased $6.3 million to $15.6
million for the nine month ended September 30, 2000 from the comparable period
ended September 30, 1999 primarily due to the inclusion of a full nine months of
TPC operation costs. Operation and maintenance expenses at the Water Utilities
increased $1.3 million to $36.9 million for the nine months ended September 30,
2000 from the comparable period ended September 30, 1999. Operation and
maintenance expenses for Products and Services increased $1.5 million to $84.6
million for the nine month ended September 30, 2000 from the comparable period
ended September 30, 1999 reflecting increased operating expenses in line
locating and marking operations and pipeline construction operations.
The operation and maintenance expenses of the Energy Utilities
increased $7.0 million to $99.2 million for the three months ended September 30,
2000 from the comparable period ended September 30, 1999. This increase was
primarily due to the $13.0 million insurance settlement in September 1999
related to manufactured gas plants site cleanup costs, partially offset by
decreased employee related costs of $1.8 million and other decreased operation
costs. The unregulated gas marketing, gas storage and trading operation expenses
increased $1.1 million to $5.1 million for the three month ended September 30,
2000 from the comparable period ended September 30, 1999 primarily due to the
inclusion of a full three months of TPC operation costs. Operation and
maintenance expenses at the Water Utilities decreased $0.6 million to $11.6
million for the three months ended September 30, 2000 from the comparable period
ended September 30, 1999. Operation and maintenance expenses for Products and
Services increased $1.5 million to $28.2 million for the three month ended
September 30, 2000 from the comparable period ended September 30, 1999
reflecting increased operating expenses in line locating and marking operations.
Depreciation and amortization expenses increased $42.6 million to
$336.2 million for the twelve months ended September 30, 2000 from the
comparable period ended September 30, 1999, primarily resulting from increased
depreciation and amortization expense from BSG of $19.3 million reflecting a
full twelve months of expenses, increased depreciation and amortization from TPC
and MHP of $9.9 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 $24.8 million to
$253.2 million for the nine months ended September 30, 2000 from the comparable
periods ended September 30, 1999, primarily resulting from increased
depreciation and amortization expense from BSG of $8.8 million and from TPC and
MHP of $8.1 million reflecting a full nine months of expenses and increased
depreciation expense at the Energy and Water Utilities due to plant additions.
Depreciation and amortization expenses increased $6.1 million to $84.1
million for the three months ended September 30, 2000 from the comparable
periods ended September 30, 1999, primarily resulting from increased
depreciation and amortization expense from TPC and MHP of $1.9 million,
increased depreciation and amortization expense from BSG of $1.8 million and
increased depreciation expense at the Energy and Water Utilities due to plant
additions.
Taxes (except income) decreased $0.5 million to $98.9 million for the
twelve months ended September 30, 2000, from the comparable period ended
September 30, 1999 primarily as the result of decreased property tax expense at
Northern Indiana offset by the inclusion of a full twelve months expenses from
BSG.
Taxes (except income) decreased $4.6 million and $0.2 million to $73.2
million and $24.4 million for the nine months and three months ended September
30, 2000, respectively, from the comparable period ended September 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 $39.9 million to $193.5 million for the
twelve months ended September 30, 2000 from the comparable period ended
September 30,1999. This increase reflects the inclusion of a full twelve months
of interest expense from BSG of $9.6 million and MHP of $18.8 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 $26.9 million to $146.3 million for the
nine months ended September 30, 2000 from the comparable periods ended September
30,1999. This increase reflects the inclusion of nine months of interest charges
for BSG and MHP, interest on the September 1999 issuance of $160 million in PURS
and increased interest expense on higher short-term borrowings.
Interest expense, net increased $7.8 million to $50.1 million for the
three months ended September 30, 2000 from the comparable periods ended
September 30,1999. This increase reflects the interest on the September 1999
issuance of $160 million in PURS and increased interest expense on higher
short-term borrowings.
MINORITY INTERESTS
Minority interest increased $4.3 million and $1.3 million and decreased
$0.3 million for the twelve months, nine months and three months ended September
30, 2000, respectively, from the comparable periods ended September 30, 1999.
The increases for the twelve month and nine month periods reflect the inclusion
of dividends paid on Company-obligated mandatorily redeemable Preferred
Securities issued in February 1999.
OTHER, NET
Other, net changed $59.8 million to a gain of $51.3 million for the
twelve months ended September 30, 2000 from the comparable period ended
September 30, 1999, primarily reflecting the pre-tax gain of $51.9 million on
the sale of MHP and a non-recurring pre-tax charge of $16.5 million in the 1999
period related to the carrying value of oil and gas properties, partially offset
by the abandonment of certain businesses and facilities that were not consistent
with its strategic direction in the fourth quarter of 1999.
Other, net increased $69.3 million to $59.9 million for the nine months
ended September 30, 2000 from the comparable period ended September 30, 1999.
This increase reflects the gain on the sale of MHP and a non-recurring pre-tax
charge of $16.5 million in the 1999 period related to the carrying value of oil
and gas properties.
Other, net increased $68.3 million to $54.1 million for the three
months ended September 30, 2000 from the comparable period ended September 30,
1999. This increase reflects the gain on the sale of MHP and a non-recurring
pre-tax charge of $16.5 million in the 1999 period related to the carrying value
of oil and gas properties.
INCOME TAXES
Income taxes increase by $30.9 million, $42.4 million and $38.2 million
for the twelve months, nine months and three months ended September 30, 2000,
respectively. In each case, the increase is primarily a result of increased
pre-tax book income, certain basis differences associated with the sale of MHP
and income tax return adjustments associated with the tax return filing.
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 September 30, 2000 and December 31, 1999, $413.5
million and $299.6 million of commercial paper was outstanding, respectively.
The weighted average interest rate on commercial paper outstanding as of
September 30, 2000 was 6.72%.
NiSource and its subsidiaries may borrow under two 364-day $200 million
revolving credit agreements that terminate on September 23, 2001. 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 September 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 $175.7 million with lenders at either the lender's
commercial prime or market lending rates. As of September 30, 2000, there were
$78.7 million of borrowings outstanding under these lines of credit with a
weighted average interest rate of 7.35%. 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 $424.5 million. As of September 30, 2000, there were $254.0 million
outstanding under these money market lines of credit at a weighted average
interest rate of 7.14%. 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 PURS in an underwritten public offering. The PURS were unsecured
debentures of Capital Markets and ranked equally with all other unsecured and
unsubordinated debt of Capital Markets. 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. On
September 28, 2000, all $160 million PURS were redeemed by NiSource at par. 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 $2.0 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, 3.04414 in new holding
company stock. Stock elections are subject to proration for those elections made
with respect to more than 30% of CEG's outstanding shares. Approval of the
NiSource and CEG shareholders was obtained on June 1 and June 2, respectively.
All actions needed from state utility regulatory commissions and from FERC have
been received. The Securities and Exchange Commission (SEC) approved the merger
under the Public Utility Holding Company Act on October 30, 2000. The merger is
expected to be completed on November 1, 2000.
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 $1.6 billion of its
anticipated refinancing of such debt.
NiSource expects to record a restructuring charge during the fourth
quarter of 2000 reflecting costs associated with a workforce reduction and other
merger-related costs. NiSource has not yet quantified the amount of this charge.
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 finding, among other
things, that the type of investigation requested by CAC could only be conducted
by the IURC itself. Northern Indiana has been meeting with the interested
parties in this proceeding. As of October 30, 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 $0.9 million, $1.8 million and $0.5 million, $0.7 million, $2.1
million and $0.004 million and $0.7 million, $2.1 million and $0.004 million for
the three month, nine month and twelve month periods ended September 30, 2000,
respectively. The daily VaR for the gas trading portfolio on an average, high
and low basis was $1.6 million, $5.8 million and $0.5 million, $2.4 million,
$8.1 million and $0.5 million and $2.2 million, $8.1 million and $0.4 million
for the three month, nine month and twelve month periods ended September 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 September 30, 2000 and December 31, 1999,
the combined borrowings outstanding under these facilities totaled $749 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 $2.0 million and $1.3
million for the three months, $5.4 million and $3.7 million for the nine months
and $6.6 million and $4.7 million for the twelve months ending September 30,
2000 and September 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. On October 16, 2000, NiSource filed with the FERC
indicating that it is committed to joining a RTO and that it would likely join
the Alliance 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.
<PAGE>
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."
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.
None
Item 5. Other Information.
None
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 10.1 Puttable Reset Securities (PURS) Purchase Agreement by and
among NiSource Capital Markets, Inc., NiSource Inc., Goldman, Sachs and
Company, and Barclays Bank plc dated September 13, 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 September 1, 2000. All events were
reported under Item 5, Other Events. A report on Form 8-K was filed
September 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 and Chief Financial Officer
and Treasurer
Date: October 31, 2000
<PAGE>
EXHIBIT-23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report included in this Form 10-Q, into NiSource Inc.'s (formerly known
as NIPSCO Industries, Inc.) previously filed Form S-8 Registration Statement No.
33-30619; Form S-8 Registration Statement No. 33-30621; Form S-8 Registration
Statement No. 333-08263; Form S-8 Registration Statement No. 333-19981; Form S-8
Registration Statement No. 333-19983; Form S-8 Registration Statement No.
333-19985; Form S-3 Registration Statement No. 333-26847; Form S-8 Registration
Statement No. 333-59151; Form S-8 Registration Statement No. 333-59153; Form S-3
Registration Statement No. 333-69279; Form S-8 Registration Statement No.
333-72367; Form S-8 Registration Statement No. 333-72401; Form S-3 Registration
Statement No. 333-76645, Form S-3 Registration Statement No. 333-76909, and Form
S-4 Registration Statement Nos. 333-33896 and 333-33896-01.
/s/ Arthur Andersen LLP
Chicago, Illinois
October 30, 2000
