SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
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 31,1999, 125,056,430 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 sheets of NiSource
Inc. (an Indiana corporation) and subsidiaries as of September 30, 1999, and
December 31, 1998, and the related consolidated statements of income, common
shareholders' equity and cash flows for the three, nine and twelve month periods
ended September 30, 1999 and 1998. These consolidated financial statements are
the responsibility of the company's management. Our responsibility is to express
an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of NiSource
Inc. and subsidiaries as of September 30, 1999, and December 31, 1998, and the
results of their operations and their cash flows for the three, nine and twelve
month periods ended September 30, 1999 and 1998, in conformity with generally
accepted accounting principles.
/s/ Arthur Andersen LLP
Chicago, Illinois
November 9, 1999
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets
September 30, December 31,
Assets 1999 1998
========== ==========
<S> <C> <C>
(In thousands)
Property, Plant and Equipment:
Utility Plant, (including Construction Work in
Progress of $316,525 and $197,112, respectively)
Electric $ 4,217,811 $ 4,154,060
Gas 2,846,138 1,447,945
Water 725,256 663,355
Common 365,101 364,822
---------- ----------
8,154,306 6,630,182
Less -Accumulated depreciation and amortization 3,384,196 2,968,078
---------- ----------
Net Utility Plant 4,770,110 3,662,104
---------- ----------
Other property, at cost, net of accumulated depreciation 129,521 86,565
---------- ----------
Net Property, Plant and Equipment 4,899,631 3,748,669
---------- ----------
Investments:
Investments, at equity 253,002 111,340
Investments, at cost 53,083 41,609
Other investments 30,585 28,702
---------- ----------
Total Investments 336,670 181,651
---------- ----------
Current Assets:
Cash and cash equivalents 23,747 60,848
Accounts receivable, less reserve of $19,857 and
$8,984, respectively 326,735 261,971
Other receivables 36,646 31,780
Fuel adjustment clause 5,716 --
Gas cost adjustment clause 39,251 45,738
Materials and supplies, at average cost 65,859 62,818
Electric production fuel, at average cost 23,091 32,402
Natural gas in storage 119,117 69,640
Prepayments and other 38,114 41,670
---------- ----------
Total Current Assets 678,276 606,867
---------- ----------
Other Assets:
Regulatory assets 223,803 209,059
Intangible assets, net of accumulated amortization 121,665 65,039
Prepayments and other 247,216 175,218
---------- ----------
Total Other Assets 592,684 449,316
---------- ----------
$ 6,507,261 $ 4,986,503
========== ==========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets
September 30, December 31,
Capitalization and Liabilities 1999 1998
========== ==========
<S> <C> <C>
(In thousands)
Capitalization:
Common shareholders' equity
(See accompanying statement) $ 1,364,839 $ 1,149,708
Preferred stocks, excluding amounts due within
one year-
Series without mandatory redemption provisions 81,114 85,613
Series with mandatory redemption provisions 54,585 56,435
IWC Resources Corporation:
Series without mandatory redemption provisions 4,497 --
Company-obligated mandatorily redeemable
preferred securities of subsidiary trust holding
solely Company debentures 345,000 --
Long-term debt, excluding amounts due within one year 1,842,390 1,667,965
---------- ----------
Total Capitalization 3,692,425 2,959,721
---------- ----------
Current Liabilities:
Current portion of long-term debt 163,283 6,790
Short-term borrowings 575,475 411,040
Accounts payable 265,330 251,399
Dividends declared on common and preferred stocks 32,915 31,072
Customer deposits 27,614 22,199
Taxes accrued 16,750 44,939
Interest accrued 28,907 21,202
Fuel adjustment clause -- 6,279
Accrued employment costs 49,384 52,121
Other accruals 119,403 39,022
---------- ----------
Total Current Liabilities 1,279,061 886,063
---------- ----------
Other:
Deferred income taxes 979,984 667,167
Deferred investment tax credits, being amortized over
life of related property 96,909 98,177
Deferred credits 108,965 68,046
Customer advances and contributions in aid of construction 124,588 118,778
Accrued liability for postretirement benefits 156,387 143,870
Other noncurrent liabilities 68,942 44,681
---------- ----------
Total Other Liabilities 1,535,775 1,140,719
---------- ----------
Commitments and Contingencies
$ 6,507,261 $ 4,986,503
========== ==========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Income
(In thousands, except for per share amounts)
Three Months Nine Months
Ended September 30, Ended September 30,
--------------------- ---------------------
1999 1998 1999 1998
========== ========== ========== ==========
<S> <C> <C> <C> <C>
Operating Revenues:
Gas $ 265,393 $ 199,435 $ 1,127,925 $ 831,698
Electric 324,290 468,315 865,355 1,136,162
Water 29,894 24,374 74,794 62,940
Products and Services 68,415 55,668 192,156 148,744
---------- ---------- ---------- ----------
687,992 747,792 2,260,230 2,179,544
---------- ---------- ---------- ----------
Cost of Sales:
Gas costs 208,032 159,917 812,759 636,835
Fuel for electric generation 72,092 72,246 188,020 193,263
Power purchased 28,204 179,645 76,611 365,657
Products and Services 37,523 29,110 100,134 75,126
---------- ---------- ---------- ----------
345,851 440,918 1,177,524 1,270,881
---------- ---------- ---------- ----------
Operating Margin 342,141 306,874 1,082,706 908,663
---------- ---------- ---------- ----------
Operating Expenses and Taxes:
Operation 119,627 104,365 374,754 298,584
Maintenance 18,450 19,100 62,672 59,058
Depreciation and amortization 78,006 64,417 228,454 191,334
Taxes (except income) 24,572 22,044 77,806 66,582
---------- ---------- ---------- ----------
240,655 209,926 743,686 615,558
---------- ---------- ---------- ----------
Operating Income 101,486 96,948 339,020 293,105
---------- ---------- ---------- ----------
Other Income (Deductions):
Interest expense, net (42,376) (33,077) (119,378) (94,522)
Minority interests (5,415) 0 (13,539) 0
Dividend requirements on preferred stock (2,071) (2,122) (6,264) (6,417)
Other, net (9,888) 2,870 (2,022) 10,387
---------- ---------- ---------- ----------
(59,750) (32,329) (141,203) (90,552)
---------- ---------- ---------- ----------
Income Before Income Taxes 41,736 64,619 197,817 202,553
Income Taxes 13,781 21,492 70,359 69,259
---------- ---------- ---------- ----------
Net Income $ 27,955 $ 43,127 $ 127,458 $ 133,294
========== ========== ========== ==========
Average common shares outstanding - basic 125,031 119,495 124,218 121,833
Basic earnings per average common share $ 0.22 $ 0.36 $ 1.02 $ 1.09
========== ========== ========== ==========
Diluted earnings per average common share $ 0.22 $ 0.35 $ 1.02 $ 1.08
========== ========== ========== ==========
Dividends declared per common share $ 0.255 $ 0.240 $ 0.765 $ 0.720
========== ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statements of Income
(In thousands, except for per share amounts)
Twelve Months
Ended September 30,
-----------------------
1999 1998
========== ==========
<S> <C> <C>
Operating Revenues:
Gas $ 1,506,002 $ 1,260,510
Electric 1,155,793 1,447,286
Water 95,833 81,311
Products and Services 255,836 197,526
---------- ----------
3,013,464 2,986,633
---------- ----------
Cost of Sales:
Gas costs 1,100,962 965,243
Fuel for electric generation 245,406 253,786
Power purchased 123,244 433,867
Products and Services 129,398 98,735
---------- ----------
1,599,010 1,751,631
---------- ----------
Operating Margin 1,414,454 1,235,002
---------- ----------
Operating Expenses and Taxes:
Operation 475,764 398,489
Maintenance 78,244 79,428
Depreciation and amortization 293,594 253,667
Taxes (except income) 99,431 88,704
---------- ----------
947,033 820,288
---------- ----------
Operating Income 467,421 414,714
---------- ----------
Other Income (Deductions):
Interest expense, net (153,660) (125,887)
Minority interests (13,539) --
Dividend requirements on preferred stock (8,385) (8,588)
Other, net (1,825) 8,680
---------- ----------
(177,409) (125,795)
--------- ----------
Income Before Income Taxes 290,012 288,919
Income Taxes 101,962 99,719
---------- ----------
Net Income $ 188,050 $ 189,200
========== ==========
Average common shares outstanding - basic 122,578 122,645
Basic earnings per average common share $ 1.53 $ 1.54
========== ==========
Diluted earnings per average common share $ 1.52 $ 1.53
========== ==========
Dividends declared per common share $ 1.020 $ 0.960
========== ==========
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Statement Of Common Shareholders' Equity
Additional
(In thousands) Common Treasury Paid-in Retained
Three Months Ended Shares Shares Capital Earnings Other
======================== ========== ========== ========== ========== ==========
<S> <C> <C> <C> <C> <C>
Balance, July 1, 1998 $ 870,930 $ (456,018) $ 90,704 $ 698,633 $ (2,962)
Comprehensive Income:
Net income 43,127
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $621)
Realized (net of income
tax of $720)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (28,144)
Treasury shares acquired (84,520)
Issued:
Employee stock purchase plan 100 251
Long-term incentive plan 2,210 46
Amortization of
unearned compensation 591
Other (55)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1998 $ 870,930 $(538,228) $ 90,955 $ 713,561 $ (2,325)
========== ========== ========== ========== ==========
Balance, July 1, 1999 $ 870,930 $(455,640) $ 172,388 $ 779,102 $ (976)
Comprehensive Income:
Net income 27,955
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $1,068)
Realized (net of income tax
of $113)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (31,891)
Treasury shares acquired (346)
Issued:
Employee stock purchase plan 112 252
Long-term incentive plan 655 29 (39)
Amortization of
unearned compensation 877
Equity contract costs (302)
Other (177)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138)
========== ========== ========== ========== ==========
<CAPTION>
<PAGE>
Accumulated Shares
Other ------------------------
Three Months Ended Comprehensive Comprehensive Common Treasury
(continued) Income Total Income Shares Shares
======================== ========== ========== ========== ========== ==========
<CAPTION>
Balance, July 1, 1998 $ 2,602 $1,203,889 $ 147,784 $ (26,750)
Comprehensive Income:
Net income 43,127 43,127
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $621) (1,017) (1,017) (1,017)
Realized (net of income tax
of $720) (1,180) (1,180) (1,180)
Gain (loss) on foreign currency
translation:
Unrealized (766) (766) (766)
Realized 186 186 186
----------
Total Comprehensive Income $40,350
==========
Dividends:
Common shares (28,144)
Treasury shares acquired (84,520) (2,993)
Issued:
Employee stock purchase plan 351 13
Long-term incentive plan 2,256 123
Amortization of
unearned compensation 591
Other (55)
---------- ---------- ---------- ----------
Balance, September 30, 1998 $ (175) $1,134,718 $ 147,784 $ (29,607)
========== ========== ========== ==========
Balance, July 1, 1999 $ 3,323 $1,369,127 $ 147,784 $ (22,770)
Comprehensive Income:
Net income 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)
Treasury shares acquired (346) (16)
Issued:
Employee stock purchase plan 364 14
Long-term incentive plan 645 32
Amortization of
unearned compensation 877
Equity contract costs (302)
Other (177)
---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 1,910 $1,364,839 $ 147,784 $ (22,740)
========== ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Additional
(In thousands) Common Treasury Paid-in Retained
Nine Months Ended Shares Shares Capital Earnings Other
======================== ========== ========== ========== ========== ==========
<CAPTION>
Balance, January 1, 1998 $ 870,930 $(363,943) $ 89,768 $ 667,790 $ (2,624)
Comprehensive Income:
Net income 133,294
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $140)
Realized (net of income
of $1,340)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (86,781)
Treasury shares acquired (182,502) 2
Issued:
Employee stock purchase plan 251 608
Long-term incentive plan 7,966 575 (1,084)
Amortization of
unearned compensation 1,383
Other 2 (742)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1998 $ 870,930 $(538,228) $ 90,955 $ 713,561 $ (2,325)
========== ========== ========== ========== ==========
Balance January 1, 1999 $ 870,930 $(559,027) $ 94,181 $ 744,309 $ (1,815)
Comprehensive Income:
Net income 127,458
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $2,075)
Realized (net of income tax
of $274)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (95,624)
Treasury shares acquired (108,987)
Issued:
Employee stock purchase plan 339 845
Long-term incentive plan 3,853 188 (571)
Bay State Gas Acquisition 205,881 109,753
Other Acquisitions 2,722 939
Amortization of
unearned compensation 2,248
Equity contract costs (33,539)
Other (1,154)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138)
========== ========== ========== ========== ==========
Accumulated Shares
Other ------------------------
Nine Months Ended Comprehensive Comprehensive Common Treasury
(continued) Income Total Income Shares Shares
======================== ========== ========== ========== ========== ==========
Balance, January 1, 1998 $ 2,867 $1,264,788 $ 147,784 $(23,472)
Comprehensive Income:
Net income 133,294 133,294
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $140) 232 232 232
Realized (net of income tax
of $1,340) (2,196) (2,196) (2,196)
Gain (loss) on foreign currency
translation:
Unrealized (1,264) (1,264) (1,264)
Realized 186 186 186
----------
Total Comprehensive Income $ 130,252
==========
Dividends:
Common shares (86,781)
Treasury shares acquired (182,500) (6,620)
Issued:
Employee stock purchase plan 859 32
Long-term incentive plan 7,457 453
Amortization of
unearned compensation 1,383
Other (740)
---------- ---------- ---------- ----------
Balance, September 30, 1998 $ (175) $1,134,718 $ 147,784 $ (29,607)
========== ========== ========== ==========
Balance January 1, 1999 $ 1,130 $1,149,708 $ 147,784 $ (30,254)
Comprehensive Income:
Net income 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)
Treasury shares acquired (108,987) (3,899)
Issued:
Employee stock purchase plan 1,184 43
Long-term incentive plan 3,470 194
Bay State Gas Acquisition 315,634 11,042
Other Acquisitions 3,661 134
Amortization of
unearned compensation 2,248
Equity contract costs (33,539)
Other (1,154)
---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 1,910 $1,364,839 $ 147,784 $ (22,740)
========== ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
Additional
(In thousands) Common Treasury Paid-in Retained
Twelve Months Ended Shares Shares Capital Earnings Other
======================== ========== ========== ========== ========== ==========
<CAPTION>
Balance, October 1, 1997 $ 870,930 $(336,148) $ 89,663 $ 641,708 $ (3,210)
Comprehensive Income:
Net income 189,200
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $380)
Realized (net of income
tax of $1,340)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (116,605)
Treasury shares acquired (211,843) 1
Issued:
Employee stock purchase plan 315 714
Long-term incentive plan 9,448 575 (1,084)
Amortization of
unearned compensation 1,969
Other 2 (742)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1998 $ 870,930 $(538,228) $ 90,955 $ 713,561 $ (2,325)
========== ========== ========== ========== ==========
Balance October 1, 1998 $ 870,930 $(538,228) $ 90,955 $ 713,561 $ (2,325)
Comprehensive Income:
Net income 188,050
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $671)
Realized (net of income tax
of $274)
Gain (loss) on foreign
currency translation:
Unrealized
Realized
Total Comprehensive Income
Dividends:
Common shares (125,439)
Treasury shares acquired (130,461)
Issued:
Employee stock purchase plan 429 1,155
Long-term incentive plan 4,438 159 (571)
Bay State Gas Acquisition 205,881 109,753
Other Acquisitions 2,722 939
Amortization of
unearned compensation 2,758
Equity contract costs (33,539)
Other 2,945 (1,183)
---------- ---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 870,930 $(455,219) $ 172,367 $ 774,989 $ (138)
========== ========== ========== ========== ==========
Accumulated Shares
Other ------------------------
Twelve Months Ended Comprehensive Comprehensive Common Treasury
(continued) Income Total Income Shares Shares
======================== ========== ========== ========== ========== ==========
Balance, October 1, 1997 $ 3,762 $1,266,705 $ 147,784 $ (22,276)
Comprehensive Income:
Net income 189,200 189,200
Other comprehensive income,
net of tax:
Gain/loss on available
for sale securities:
Unrealized (net of income
tax of $380) 622 622 622
Realized (net of income
tax of $1,340) (2,195) (2,195) (2,195)
Gain (loss) on foreign
currency translation:
Unrealized (2,550) (2,550) (2,550)
Realized 186 186 186
----------
Total Comprehensive Income $ 185,263
==========
Dividends:
Common shares (116,605)
Treasury shares acquired (211,842) (7,920)
Issued:
Employee stock purchase plan 1,029 40
Long-term incentive plan 8,939 549
Amortization of
unearned compensation 1,969
Other (740)
---------- ---------- ---------- ----------
Balance, September 30, 1998 $ (175) $1,134,718 $ 147,784 $ (29,607)
========== ========== ========== ==========
Balance October 1, 1998 $ (175) $1,134,718 $ 147,784 $ (29,607)
Comprehensive Income:
Net income 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)
Treasury shares acquired (130,461) (4,589)
Issued:
Employee stock purchase plan 1,584 54
Long-term incentive plan 4,026 226
Bay State Gas Acquisition 315,634 11,042
Other Acquisitions 3,661 134
Amortization of
unearned compensation 2,758
Equity contract costs (33,539)
Other 1,762
---------- ---------- ---------- ----------
Balance, September 30, 1999 $ 1,910 $1,364,839 $ 147,784 $ (22,740)
========== ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
(In thousands)
Three Months Nine Months
Ended September 30, Ended September 30,
----------------------- -----------------------
1999 1998 1999 1998
========== ========== ========== ==========
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 27,955 $ 43,127 $ 127,458 $ 133,294
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 78,006 64,417 228,454 191,334
Deferred federal and state
income taxes, net 3,978 (6,991) (26,772) (49,641)
Deferred investment tax credits, net (1,921) (1,821) (5,728) (5,463)
Other, net 2,810 307 (215) (4,437)
Change in certain assets and liabilities -*
Accounts receivable, net (4,692) 31,696 124,753 39,726
Other receivables 56 (3,644) (4,866) 70,422
Natural gas in storage (38,759) (34,467) (8,462) (10,607)
Accounts payable 20,799 (6,067) (121,478) (23,697)
Taxes accrued (18,232) 2,571 (20,691) 15,048
Gas cost adjustment clause (39,860) (6,511) 32,587 56,655
Accrued employment costs 5,428 5,215 (11,011) (12,730)
Other accruals 19,422 (3,684) 47,147 (12,277)
Other, net (6,227) (13,902) (1,243) (10,995)
---------- ---------- ---------- ----------
Net cash provided by operating activities 48,763 70,246 359,933 376,632
---------- ---------- ---------- ----------
Cash flows from investing activities:
Utility construction expenditures (92,336) (56,395) (228,428) (176,196)
Acquisition of businesses,
net of cash acquired -- -- (716,031) --
Proceeds from disposition of assets 892 24 28,452 10,443
Other, net (30,962) (14,964) (73,580) (63,631)
---------- ---------- ---------- ----------
Net cash used in investing activities (122,406) (71,335) (989,587) (229,384)
---------- ---------- ---------- ----------
Cash flows from financing activities:
Issuance of long-term debt 544 40,503 258,315 46,878
Retirement of long-term debt (2,783) (41,631) (185,855) (79,204)
Change in short-term debt 81,482 109,341 65,132 149,574
Retirement of preferred shares (601) (600) (1,852) (1,856)
Proceeds from Corporate Premium
Income Equity Securities, net -- -- 334,650 --
Issuance of common shares 1,048 2,561 324,520 9,400
Acquisition of treasury shares (346) (84,520) (108,987) (182,500)
Cash dividends paid on common shares (31,884) (28,871) (93,710) (88,180)
Other, net 114 112 340 350
---------- ---------- ---------- ----------
Net cash provided by (used in)
financing activities 47,574 (3,105) 592,553 (145,538)
---------- ---------- ---------- ----------
Net increase (decrease) in cash and
cash equivalents (26,069) (4,194) (37,101) 1,710
Cash and cash equivalents at
beginning of the period 49,816 36,684 60,848 30,780
---------- ---------- ---------- ----------
Cash and cash equivalents at
end of the period $ 23,747 $ 32,490 $ 23,747 $ 32,490
========== ========== ========== ==========
*Net of effect from acquisitions of businesses.
The accompanying notes to consolidated financial statements are an integral
part of these statements.
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
(In thousands)
Twelve Months
Ended September 30,
-----------------------
1999 1998
========== ==========
<S> <C> <C>
Cash flows from operating activities:
Net income $ 188,050 $ 189,200
Adjustments to reconcile net income
to net cash:
Depreciation and amortization 293,594 253,667
Deferred federal and state
income taxes, net 928 (17,784)
Deferred investment tax credits, net (7,626) (7,372)
Other, net 1,482 (3,929)
Change in certain assets and liabilities -*
Accounts receivable, net 63,890 (20,602)
Other receivables 163 44,811
Natural gas in storage (6,059) (19)
Accounts payable (77,996) 12,716
Taxes accrued (46,299) (12,148)
Gas cost adjustment clause 20,185 27,155
Accrued employment costs (4,959) (1,954)
Other accruals 50,516 (14,112)
Other, net (8,438) 26,176
---------- ----------
Net cash provided by operating activities 467,431 475,805
---------- ----------
Cash flows from investing activities:
Utility construction expenditures (302,557) (234,623)
Acquisition of businesses,
net of cash acquired (716,031) --
Proceeds from disposition of assets 30,597 16,475
Other, net (63,087) (99,802)
---------- ----------
Net cash used in investing activities (1,051,078) (317,950)
---------- ----------
Cash flows from financing activities:
Issuance of long-term debt 258,817 254,179
Retirement of long-term debt (202,282) (285,392)
Change in short-term debt 112,576 196,725
Retirement of preferred shares (2,409) (2,411)
Proceeds from Corporate Premium
Income Equity Securities, net 334,650 --
Issuance of common shares 325,476 11,047
Acquisition of treasury shares (130,461) (211,837)
Cash dividends paid on common shares (121,916) (116,431)
Other, net 453 470
---------- ----------
Net cash provided by (used in)
financing activities 574,904 (153,650)
---------- ----------
Net increase (decrease) in cash and
cash equivalents (8,743) 4,205
Cash and cash equivalents at
beginning of the period 32,490 28,285
---------- ----------
Cash and cash equivalents at
end of the period $ 23,747 $ 32,490
========== ==========
*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 and water to the
public for residential, commercial and industrial uses. 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 operates primarily in Indiana and New England through wholly-owned
regulated subsidiaries, collectively called the "Utilities." 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."
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 services are provided through the
wholly-owned "Products and Services" subsidiaries. Products and Services
subsidiaries perform energy-related services and offer products in connection
with these services, which include installing, repairing and maintaining
underground gas pipelines and locating and marking utility lines.
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 June 7, 1999, NiSource made an offer to acquire Columbia Energy Group
(CEG) for $5.7 billion, or $68 per share of CEG common stock, in cash. CEG's
board rejected the offer, and on June 25, 1999, a tender offer was commenced for
all outstanding shares of CEG common stock at $68 per share in cash. CEG's board
of directors recommended that CEG shareholders reject the tender offer. On
October 17, NiSource increased the consideration to $6.1 billion, or $74 per
share, in cash and extended the offer until November 12, 1999. In response to
the increased offer, on October 24, 1999, CEG's board rejected the offer,
recommended that CEG shareholders not tender their shares and authorized its
management to explore strategic alternatives. CEG stated that it would initiate
discussions with third parties regarding possible transactions, including a
merger, reorganization, or the disposition of a material amount of assets. The
terms and conditions of NiSource's tender offer are set forth in the Offer to
Purchase dated June 25, 1999, as amended and supplemented, and the related
Letter of Transmittal. A commitment letter has been accepted under which certain
financial institutions have agreed, subject to specified conditions, to provide
$6.5 billion to finance the proposed acquisition of CEG. The tender offer is
subject to a number of uncertainties, and no assurance can be given as to
whether, or on what terms, CEG will be acquired. At September 30, 1999 and
October 31, 1999, approximately $8.4 million and $9.7 million, respectively, in
filing fees and professional services fees related to the CEG acquisition were
capitalized.
CEG, based in Herndon, Virginia, is one of the nation's leading energy
services companies, with 1998 revenues of $6.6 billion and assets of $7.0
billion. CEG's subsidiaries engage in all phases of the natural gas business,
including exploration and production, transmission, storage and distribution, as
well as commodities marketing, energy management, and propane sales. CEG sells
natural gas to about 2 million customers in Kentucky, Maryland, Ohio,
Pennsylvania, Virginia and Washington D.C. It owns 16,500 miles of interstate
gas pipelines that run from Louisiana to the Northeast.
(2) Summary of Significant Accounting Policies:
Basis of Presentation. The consolidated financial statements include the
accounts of NiSource and its majority-owned subsidiaries after the elimination
of significant intercompany accounts and transactions. Investments for which at
least a 20% interest is owned and certain joint ventures are accounted for under
the equity method. Investments with less than a 20% interest are accounted for
under the cost method. Certain reclassifications were made to conform the prior
years' financial statements to the current presentation.
On April 1, 1999, NiSource acquired the stock of TPC Corporation. As a
result of the acquisition, NiSource indirectly owns a 77.3% equity interest in
Market Hub Partners, L.P. (MHP), which stores natural gas in salt caverns.
However, NiSource does not control the operations of MHP based upon the
governance provisions in MHP's partnership agreement. Accordingly, NiSource
accounts for its interests in MHP using the equity method of accounting. The
consolidated financial statements and disclosures include operating results from
TPC from the date of acquisition through September 30, 1999. See Note 3 for
additional information on this acquisition.
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 through
September 30, 1999. See Note 3 for additional information on this acquisition.
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. Utility revenues are recorded based on estimated service
rendered, but are billed to customers monthly on a cycle basis. Electric and gas
marketing revenues are recognized as the related commodity is delivered to
customers. Effective January 1, 1999, revenues relating to electric and gas
trading operations are recorded based upon changes in the fair values 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 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 21 years
Transmission plant 27 years
Distribution plant 30 years
Other gas plant 21 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, 1999 and 1998 were as follows:
<PAGE>
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
---------- ---------- ---------- ---------- ---------- ----------
1999 1998 1999 1998 1999 1998
========== ========== ========== ========== ========== ==========
<S> <C> <C> <C> <C> <C> <C>
Electric 3.7% 3.8% 3.7% 3.7% 3.7% 3.6%
Gas 4.5% 5.1% 4.5% 5.1% 4.5% 5.1%
Water 2.5% 2.2% 2.2% 2.1% 2.4% 2.1%
</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 $721.1 million
and $185.4 million at September 30, 1999 and December 31, 1998, 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 $117.6
million and $61.9 million at September 30, 1999 and December 31, 1998,
respectively, is being amortized over a weighted average period of 28 years.
Other intangible assets, approximating $12.5 million and $7.7 million at
September 30, 1999 and December 31, 1998, 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, 1999 and December 31, 1998 was
approximately $8.5 million and $4.6 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, 1999, $100.0 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 NiSource upon completion. The cost of the main extensions and the
amount of any funds advanced for the cost of water mains installed are included
in customer advances for construction and are generally refundable to the
customer over a period of ten years. Advances not refunded within ten years are
permanently transferred to contributions in aid of construction.
Comprehensive Income. Comprehensive income is reported in the consolidated
statements of common shareholders' equity. The components of accumulated other
comprehensive income include unrealized gains (losses), net of income taxes, on
available for sale securities ("securities") and on foreign currency translation
adjustments ("foreign currency"). The accumulated amounts for these components
are as follows:
<TABLE>
<CAPTION>
October 1, January 1, July 1, October 1, January 1, July 1,
(In millions) 1997 1998 1998 1998 1999 1999
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Securities $ 4.0 $ 4.4 $ 4.7 $ 2.5 $ 3.6 $ 5.6
Foreign currency $ (.3) $ (1.6) $ (2.1) $ (2.6) $ (2.5) $ (2.3)
</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,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
<S> <C> <C> <C> <C> <C> <C>
Income taxes $ 24,010 $ 19,313 $ 114,188 $ 95,413 $ 146,488 $ 131,562
Interest, net of amounts capitalized $ 40,437 $ 27,351 $ 113,117 $ 83,537 $ 147,659 $ 117,184
</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. Under-recovery or over-recovery is recorded as a current asset or
current liability until such time as it is billed or refunded to its customers.
The fuel adjustment factor is subject to a quarterly hearing by the IURC and
remains in effect for a three-month period.
On August 18, 1999, the IURC issued a generic order which established new
guidelines for the recovery of purchased power costs through fuel adjustment
clauses. The IURC ruled that each utility had to establish a "benchmark" which
is the utility's highest on-system fuel cost per kilowatt-hour (kwh) during the
most recent annual period. The IURC stated that if the weekly average of a
utility's purchased power costs were less than the "benchmark," these costs per
kwh should be considered net energy costs which are presumed "fuel costs
included in purchased power." If the weekly average of a utility's purchased
power costs exceeded the "benchmark," the utility would need to submit
additional evidence demonstrating the reasonableness of these costs. The Office
of Utility Consumer Counselor has appealed the August 18 order to the Indiana
Court of Appeals.
Gas Cost Adjustment Clause. All metered gas sales rates contain an
adjustment factor, which reflects the increases and decreases in the cost of
purchased gas, contracted gas storage and storage transportation charges. Each
gas cost adjustment factor is subject to a monthly, quarterly or semi-annual
hearing by the state Commissions and remains in effect for a one-, three-, six
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 hearing and
IURC approval, and made effective on November 1 of each year. The demand
component will remain in effect for one year until a new demand component is
approved by the IURC. The commodity component of the adjustment factor will be
determined by monthly filings, which will become effective on the first day of
each calendar month, subject to refund. The monthly filings do not require IURC
approval but will be reviewed by the IURC during the annual hearing that will
take place regarding the demand component filing. If the statutory requirement
relating to the level of return for the Indiana 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 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 purchased under the LIFO method in September
1999 and December 1998, the estimated replacement cost of gas in storage
(current and non-current) at September 30, 1999 and December 31, 1998 exceeded
the stated LIFO cost by $67.6 million and $33.7 million, respectively. Inventory
valued using LIFO was $49.4 million and $50.8 million at September 30, 1999 and
December 31, 1998, respectively. Inventory valued using the weighted average
methodology was $69.7 million and $18.8 million at September 30, 1999 and
December 31, 1998, respectively.
Derivatives. A variety of commodity-based derivative financial instruments are
utilized to reduce (hedge) the price risk inherent in natural gas and electric
operations. The gains and losses on these derivative financial instruments are
deferred as assets or liabilities and are recognized in earnings concurrent with
the disposition of the underlying physical commodity. In certain circumstances,
a derivative financial instrument will serve to hedge the acquisition cost of
natural gas injected into storage. In this situation, the gain or loss on the
derivative financial instrument is deferred as part of the cost basis of gas in
storage and recognized upon the ultimate disposition of the gas. If a derivative
financial instrument contract is terminated early because it is probable that a
transaction or forecasted transaction will not occur, any gain or loss as of
such date is immediately recognized in earnings. If a derivative financial
instrument is terminated for other economic reasons, any gain or loss as of the
termination date is deferred and recorded when the associated transaction or
forecasted transaction affects earnings.
Accounting for Energy Trading Activities. Energy trading contracts are accounted
for in accordance with the Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities." Such contracts are recorded at fair value on the balance sheet,
with the changes in their fair values included in earnings, effective January 1,
1999.
The change in accounting effective January 1, 1999 was insignificant.
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," and SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities- Deferral of
the Effective Date of FASB Statement No. 133." Statement No. 133 standardizes
the accounting for derivative instruments, including certain derivative
instruments embedded in other contracts, by requiring that a company recognize
those items as assets or liabilities in the balance sheet and measure them at
fair value. The Statement generally provides for matching of the timing of gain
or loss recognition of derivative instruments designated as a hedge with the
recognition of changes in the fair value of the hedged asset or liability
through earnings. The Statement also provides that the effective portion of a
hedging instrument's gain or loss on a forecasted transaction be initially
reported in other comprehensive income and subsequently reclassified into
earnings when the hedged forecasted transaction affects earnings. Statement No.
137, which was issued in June 1999, deferred implementation of Statement No. 133
until January 1, 2001. The impact of adopting the accounting prescribed in
Statement No. 133 is currently being assessed.
Regulatory Assets. The Utilities' operations are subject to the regulation of
the Commissions and, in the case of certain subsidiaries, 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, 1999, and December 31, 1998, 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. Regulatory assets were comprised of the following items:
<TABLE>
<CAPTION>
September 30, December 31,
(In thousands) 1999 1998
========== ==========
<S> <C> <C>
Unamortized reacquisition premium
on debt (see Note 16) $ 40,598 $ 43,233
Unamortized R. M. Schahfer Unit 17
and Unit 18 carrying charges and
deferred depreciation (see below) 59,166 62,329
Bailly scrubber carrying charges and
deferred depreciation (see below) 8,243 8,945
Deferral of SFAS No. 106 expense not
recovered (see Note 8) 76,980 81,339
FERC Order No. 636 transition costs 15,504 22,093
Regulatory income tax asset, net
(see Note 6) 36,185 18,793
Other 13,148 4,936
---------- ----------
249,824 241,668
Less: Current portion of regulatory
assets 26,021 32,609
---------- ----------
$223,803 $209,059
========== ==========
</TABLE>
Carrying Charges and Deferred Depreciation. Upon completion of R. M. Schahfer
Units 17 and 18, carrying charges and deferred depreciation were capitalized in
accordance with orders of the IURC until the cost of each unit was allowed in
rates. Such carrying charges and deferred depreciation are being amortized over
the remaining life of each unit.
Northern Indiana has capitalized carrying charges and deferred depreciation
and certain operating expenses relating to its scrubber service agreement for
its Bailly Generating Station in accordance with an order of the IURC. The
accumulated balance of the deferred costs and related carrying charges is being
amortized over the remaining life of the scrubber service agreement.
Allowance for Funds Used During Construction. Allowance for funds used during
construction (AFUDC) is charged to construction work in progress during the
period of construction and represents the net cost of borrowed funds used for
construction purposes and a reasonable rate upon other (equity) funds. Under
established regulatory rate practices, after the construction project is placed
in service, the Utilities are permitted to include in the rates charged for
utility services (a) a fair return on and (b) depreciation of such AFUDC
included in plant in service.
AFUDC was calculated using a weighted average pre-tax rate as follows:
<TABLE>
<CAPTION>
September 30, September 30,
1999 1998
---------- ----------
<S> <C> <C>
Three months ended 8.73% 8.95%
Nine months ended 8.72% 8.74%
Twelve months ended 8.79% 8.89%
</TABLE>
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 $34.0 million relating to affordable housing projects at both September
30, 1999 and December 31, 1998.
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 Bay State Gas (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 6.9 million Corporate Premium Income Equity Securities (see Note 19). 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. BSG, one of the largest natural gas utilities in New
England, provides natural gas distribution to more than 300,000 customers in
Massachusetts and, through its wholly-owned subsidiary Northern Utilities, Inc.,
New Hampshire and Maine. The accompanying financial statements reflect a
preliminary allocation of the purchase price since the purchase price allocation
has not been finalized.
Assets acquired and liabilities assumed in the acquisition of BSG were
comprised of the following:
<TABLE>
<CAPTION>
(In thousands) Assets acquired:
<S> <C>
Utility plant, net of accumulated depreciation $ 1,081,874
Intangible assets 16,264
Other current assets 177,148
Other noncurrent assets 75,126
----------
1,350,412
Less liabilities assumed:
Long-term debt 244,337
Short-term debt 100,295
Other current liabilities 122,408
Deferred taxes 297,477
Other noncurrent liabilities 25,765
----------
790,282
----------
Net assets acquired $ 560,130
==========
</TABLE>
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:
UNAUDITED
(In thousands) Nine Months Twelve Months
=========== ===========
Operating revenue $ 2,339,870 $ 3,244,045
Operating income $ 350,816 $ 490,045
Net income $ 128,049 $ 183,673
Pro forma adjustments primarily reflect adjustments for the addition of the
plant acquisition adjustment and intangible assets, the issuance of the
applicable Corporate Premium Income Equity Securities and additional income
taxes, as if the acquisition had occurred on January 1, 1999 for the nine month
results and on October 1, 1998 for the twelve month results.
On April 1, 1999, NiSource acquired the stock of TPC Corporation, 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 has an
indirect equity investment in the amount of $126.0 million, representing a 77.3%
interest in MHP. The accompanying financial statements reflect a preliminary
allocation of the purchase price since the purchase price allocation has not
been finalized.
(4) NESI Energy Marketing Canada Ltd. Litigation: On October 31, 1996, NiSource
Energy Services Canada, Ltd. (NESI Canada) acquired 70% of the outstanding
shares of 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 have filed claims in the Canadian courts against
NiSource, Capital Markets, NI Energy Services, Inc. and NESI Canada alleging
certain misrepresentations relating to NEMC's financial condition and claiming
damages. In addition, certain creditors of NEMC have, through the Canadian
bankruptcy court, asserted fraudulent transfer and other claims against
NiSource, Capital Markets, NI Energy Services, Inc., NESI Canada and the
directors of NEMC. 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 would
not be material to the financial position or 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 public health and the environment. Such
environmental laws and regulation affect operations as they relate to impacts on
air, water and land.
Superfund. Because NiSource is a "potentially responsible party" (PRP) 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 cost of clean up of such sites. A program was
instituted to investigate former manufactured-gas plant sites where it is the
current or former owner, which investigation has identified forty-six such
sites. Initial sampling has been conducted at thirty sites. Investigation
activities have been completed at twenty-three sites and remedial measures have
been selected or implemented at fifteen 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 several insurance
companies, including $13.3 million in the third quarter, 1999. Additionally,
agreements have been reached with other Indiana utilities relating to cost
sharing and management of the investigation and remediation of several former
manufactured-gas plant sites at which Northern Indiana and such utilities or
their predecessors were operators or owners.
BSG and Northern Utilities, Inc. have rate recovery for environmental
response costs in Maine, Massachusetts and New Hampshire. The rate treatment
allows for the recovery of 100% of prudently incurred costs for investigation
and remediation over a 5-7 year period from date of payment. Recoveries from
third parties or insurance companies in Maine and Massachusetts are allocated
50% to rate payers and 50% to shareholders. In New Hampshire 100% of any
recoveries from third parties or insurance companies are returned to rate
payers.
As of September 30, 1999, a reserve of approximately $24 million has been
recorded to cover probable corrective actions. The ultimate liability in
connection with these sites will depend upon many factors, including the volume
of material contributed to the site, the number of other 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) imposed 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 most of
the steps necessary to meet the NOx limits.
The CAAA also contain other provisions that could lead to limitations on
emissions of hazardous air pollutants and other air pollutants (including NOx as
discussed below), which may require significant capital expenditures for control
of these emissions. Until specific rules have been issued that affect 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. On
May 25, 1999, the D.C. Circuit Court of Appeals issued an order staying the NOx
SIP call rule's September 30, 1999 deadline for the state submittals until
further order of the court. Any resulting NOx emission limitations 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 EPA's final
rule and any potential requirements that could result from the final rule 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 depend
upon the outcome of the current litigation and the ultimate control program
agreed to by the targeted states and the EPA. Northern Indiana is continuing its
programs to reduce NOx emissions and NiSource will continue to closely monitor
developments in this area.
The EPA issued final rules revising the National Ambient Air Quality
Standards for ozone and particulate matter in July 1997. On May 14, 1999, the
United States Court of Appeals for the D.C Circuit remanded the new rules for
both ozone and particulate matters to the EPA. Once rectified, the revised
standards could require additional reductions in sulfur dioxide, particulate
matter and NOx emissions from coal-fired boilers (including Northern Indiana's
generating stations) beyond measures discussed above. Final implementation
methods will be set by the EPA as well as state regulatory authorities. NiSource
believes that the costs relating to compliance with any new limits may be
substantial but are dependent upon the ultimate control program agreed to by the
targeted states and the EPA. NiSource will continue to closely monitor
developments in this area and anticipates the exact nature of the impact of the
new limits on its operations will not be known for some time.
In a letter dated September 15, 1999, the Attorney General of the State of
New York alleged that Northern Indiana violated the Clean Air Act by
constructing a major modification of one of its electric generating stations
without obtaining pre-construction permits required by the Prevention of
Significant Deterioration (PSD) program. The major modification allegedly took
place at the R.M. Schahfer Station when, "in approximately 1995-1997, Northern
Indiana upgraded the coal handling system at Unit 14 at the plant." While
Northern Indiana is investigating these 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, which
is a by-product 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 Indiana's and Massachusetts'
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 that 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 for 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 rules could be costly and could 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 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 AFUDC-equity and the cumulative net amount of other income tax
timing differences for which deferred taxes had not been provided in the past,
when regulators did not recognize such taxes as costs in the rate-making
process. Regulatory liabilities are primarily attributable to 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,
1999 and December 31, 1998 were as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
========== ==========
(In thousands)
<S> <C> <C>
Deferred tax liabilities--
Accelerated depreciation and other
property differences $1,095,319 $806,148
AFUDC-equity 34,652 33,029
Adjustment clauses 7,459 14,965
Other regulatory assets 28,147 29,739
Prepaid pension and other benefits 38,278 34,170
Reacquisition premium on debt 16,267 17,311
Deferred tax assets--
Deferred investment tax credits (37,642) (37,236)
Removal costs (168,745) (157,728)
Other postretirement/postemployment benefits (56,226) (51,754)
Other, net 5,830 (29,353)
---------- ----------
963,339 659,291
Less: Deferred income taxes related to current
assets and liabilities (16,645) (7,876)
---------- ----------
Deferred income taxes--noncurrent $979,984 $667,167
========== ==========
</TABLE>
Federal and state income taxes as set forth in the consolidated statements
of income were comprised of the following:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
(In thousands)
<S> <C> <C> <C> <C> <C> <C>
Current income taxes -
Federal $ 10,165 $ 26,063 $ 88,706 $107,974 $ 94,412 $106,568
State 1,559 4,241 14,153 16,389 14,248 18,307
------- ------- ------- ------- ------- -------
11,724 30,304 102,859 124,363 108,660 124,875
------- ------- ------- ------- ------- -------
Deferred income taxes, net -
Federal 3,837 (6,520) (24,497) (46,020) 1,097 (16,704)
State 141 (471) (2,275) (3,621) (169) (1,080)
------- ------- ------- ------- ------- -------
3,978 (6,991) (26,772) (49,641) 928 (17,784)
------- ------- ------- ------- ------- -------
Deferred investment tax
credits, net (1,921) (1,821) (5,728) (5,463) (7,626) (7,372)
------- ------- ------- ------- ------- -------
Total income taxes $ 13,781 $ 21,492 $ 70,359 $ 69,259 $101,962 $ 99,719
======= ======= ======= ======= ======= =======
</TABLE>
A reconciliation of total income tax expense to an amount computed by
applying the statutory federal income tax rate to pretax income is as follows:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
<S> <C> <C> <C> <C> <C> <C>
Net income $ 27,955 $ 43,127 $127,458 $133,294 $188,050 $189,200
Add-Income taxes 13,781 21,492 70,359 69,259 101,962 99,719
Dividend requirements on
preferred stocks 2,071 2,122 6,264 6,417 8,385 8,588
------- ------- ------- ------- ------- -------
Income before preferred dividend
requirements and income taxes $ 43,807 $ 66,741 $204,081 $208,970 $298,397 $297,507
======= ======= ======= ======= ======= =======
Amount derived by multiplying pre-tax
income by the statutory rate $ 15,332 $ 23,360 $ 71,428 $ 73,140 $104,439 $104,127
Reconciling items multiplied
by the statutory rate:
Book depreciation over
related tax depreciation 969 998 2,906 2,994 2,906 3,957
Amortization of deferred
investment tax credits (1,921) (1,821) (5,728) (5,463) (7,626) (7,372)
State income taxes, net of
federal income tax benefit 1,154 2,286 6,924 7,032 9,092 10,820
Reversal of deferred taxes provided
at rates in excess of the current
federal income tax rate (721) (1,271) (2,163) (3,813) (1,462) (3,807)
Low-income housing credits (1,128) (960) (3,384) (2,880) (4,344) (3,644)
Nondeductible amounts related to
amortization of intangible assets
and plant acquisition adjustments 619 629 1,857 1,887 2,486 2,401
Other, net (523) (1,729) (1,481) (3,638) (3,529) (6,763)
------- ------- ------- ------- ------- -------
Total income taxes $ 13,781 $ 21,492 $ 70,359 $ 69,259 $101,962 $ 99,719
======= ======= ======= ======= ======= =======
</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 1998 and 1997 was as follows:
<TABLE>
<CAPTION>
1998 1997
======== ========
(In thousands)
<S> <C> <C>
Benefit obligation at beginning of year (January 1,) $875,756 $743,634
Service cost 17,093 14,714
Interest cost 60,686 57,938
Plan amendments 14,655 25,096
Actuarial loss 38,773 73,768
Acquisition of IWCR -- 15,772
Benefits paid (57,924) (55,166)
-------- --------
Benefit obligation at end of the year (December 31,) $949,039 $875,756
======== ========
</TABLE>
The change in the fair value of the plans' assets for the years 1998 and
1997 was as follows:
<TABLE>
<CAPTION>
(In thousands) 1998 1997
======== ========
<S> <C> <C>
Fair value of plan assets at beginning of year (January 1,) $ 924,857 $ 790,978
Actual return on plan assets 85,254 126,695
Employer contributions 34,843 46,440
Acquisition of IWCR -- 15,910
Benefits paid (57,924) (55,166)
-------- --------
Plan assets at fair value at end of the year (December 31,) $ 987,030 $ 924,857
======== ========
</TABLE>
The plans' assets are invested primarily in common stocks, bonds and notes.
The plans' funded status as of December 31, 1998 and 1997 is as follows:
<TABLE>
<CAPTION>
1998 1997
======== ========
(In thousands)
<S> <C> <C>
Plan assets in excess of benefit obligation $ 37,991 $ 49,101
Unrecognized net actuarial loss (10,938) (46,959)
Unrecognized prior service cost 57,193 47,114
Unrecognized transition amount 26,813 32,107
-------- --------
Prepaid pension costs $111,059 $ 81,363
======== ========
</TABLE>
The benefit obligation is the present value of future pension benefit
payments and is based on a plan benefit formula that considers expected future
salary increases. A discount rate of 7.00% and rate of increase in compensation
levels of 4.5% were used to determine the benefit obligations at December 31,
1998 and 1997.
BSG had noncontributory defined benefit pension plans covering substantially
all of its employees. At the date of acquisition the benefit obligation was
$83.9 million, the fair value of plan assets was $91.5 million and prepaid
pension costs were $15.4 million. The benefit obligation is the present value of
future pension benefit payments and was based on a plan benefit formula which
considers expected future salary increases. A discount rate of 7.00% and rate of
increase in compensation levels of 4.5% were used to determine the benefit
obligations at the date of acquisition.
Prepaid pension costs were $155.0 million at September 30, 1999 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, 1999 and
September 30, 1998:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 5,032 $ 4,850 $ 14,752 $ 17,886 $ 18,808 $ 16,301
Interest costs 17,078 15,712 50,570 59,280 67,688 51,922
Expected return on plan assets (23,147) (19,619) (68,546) (78,125) (92,711) (68,412)
Amortization of transition obligation 1,477 1,262 4,372 4,928 6,000 3,685
Amortization of prior service costs 1,607 96 4,765 4,279 5,328 3,869
------- ------- ------- ------- ------- -------
$ 2,047 $ 2,301 $ 5,913 $ 8,248 $ 5,113 $ 7,365
======= ======= ======= ======= ======= =======
</TABLE>
Assumptions used in the valuation and determination of 1999 and 1998
pension expense were as follows:
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Discount rate 7.00% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Expected long-term rate of return on assets 9.00% 9.00%
</TABLE>
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 $0.1 million, $1.6 million and $2.2
million were made to these plans for the three-month, nine-month and
twelve-month periods ended September 30, 1999, 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: Certain health care and life insurance benefits for
certain retired employees are provided. 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, 1998 and 1997:
<TABLE>
<CAPTION>
1998 1997
======= =======
(In thousands)
<S> <C> <C>
Accumulated postretirement benefit obligation
at beginning of year (January 1,) $223,908 $200,790
Service cost 5,249 5,034
Interest cost 15,793 16,215
Plan amendments (283) 4,015
Actuarial (gain) loss 8,453 (10,242)
Acquisition of IWCR -- 18,505
Benefits paid (12,519) (10,409)
-------- --------
Accumulated postretirement benefit obligation
at end of the year (December 31,) $240,601 $223,908
======== ========
</TABLE>
The change in the fair value of the plan assets for the years 1998 and 1997
was as follows:
<TABLE>
<CAPTION>
1998 1997
======= =======
(In thousands)
<S> <C> <C>
Fair value of plan assets at beginning of year (January 1,) $ 2,400 $ --
Actual return of plan assets 1,103 --
Employer contributions 10,637 12,809
Participant contributions 1,282 --
Benefits paid (12,519) (10,409)
------- -------
Plan assets at fair value at end of the year (December 31,) $ 2,903 $ 2,400
======= =======
</TABLE>
Following is the funded status for postretirement benefits as of December
31, 1998 and 1997:
<TABLE>
<CAPTION>
1998 1997
======= =======
(In thousands)
<S> <C> <C>
Funded status $(237,698) $(221,508)
Unrecognized net actuarial gain (87,087) (99,117)
Unrecognized prior service cost 3,873 4,195
Unrecognized transition amount 164,436 176,464
------- -------
Accrued liability for postretirement benefits $(156,476) $(139,966)
======== ========
</TABLE>
In order to determine the APBO at December 31, 1998, a discount rate of 7%
and a pre-Medicare medical trend rate of 7% declining to a long-term rate of 5%
was used, and at December 31, 1997, a discount rate of 7% and a pre-Medicare
medical trend rate of 8% declining to a long-term rate of 5% was used. The
accrued liability for postretirement benefits was $162.2 million at September
30, 1999.
BSG has postretirement benefit plans covering certain employees. At the
date of acquisition the APBO was $25.3 million, the fair value of plan assets
was $26.2 million and prepaid postretirement costs were $13.3 million. A
discount rate of 7% and a pre-Medicare medical trend rate of 5%, which is the
ultimate trend rate, were used to determine the APBO.
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, 1999 and September 30, 1998 include the
following components:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
<S> <C> <C> <C> <C> <C> <C>
Service costs $ 1,623 $ 1,488 $ 4,271 $ 4,162 $ 5,358 $ 4,428
Interest costs 4,728 4,073 14,103 12,219 17,677 14,041
Expected return on plan assets (700) (50) (1,933) (150) (1,999) (150)
Amortization of transition obligation 3,197 2,929 9,525 8,788 12,482 11,642
Amortization of prior service cost 86 75 258 225 355 504
Amortization of (gain) loss (1,204) (1,394) (3,600) (4,180) (5,167) (6,988)
------- ------- ------- ------- ------- -------
$ 7,730 $ 7,121 $22,624 $ 21,064 $28,706 $ 23,477
======= ======= ======= ======= ======= =======
</TABLE>
Assumptions used in the determination of 1999 and 1998 net periodic
postretirement benefit costs were as follows:
<TABLE>
<CAPTION>
1999 1998
===== =====
<S> <C> <C>
Discount rate 7.00% 7.00%
Rate of increase in compensation levels 4.50% 4.50%
Assumed annual rate of increase in health care benefits 7.00% 8.00%
Assumed ultimate trend rate 5.00% 5.00%
</TABLE>
The effect of a 1% increase in the assumed health care cost trend rates for
each future year would increase the APBO at January 1, 1999 by approximately
$30.6 million, and increase the aggregate of the service and interest cost
components of plan costs by approximately $0.8 million and $2.3 million for the
three-month and nine-month periods ended September 30, 1999. The effect of a 1%
decrease in the assumed health care cost trend rates for each future year would
decrease the APBO at January 1, 1999 by approximately $23.9 million, and
decrease the aggregate of the service and interest cost components of plan costs
by approximately $0.6 million and $1.8 million for the three-month and
nine-month periods ended September 30, 1999. 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 shares are
designated Series A Junior Participating Preferred Shares and 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
outstanding)
Indianapolis Water Company (IWC) -
300,000 shares -Cumulative Preferred -$100 par value
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,
1999 1998 1999
=========== =========== ===========
(Dollars in thousands)
<S> <C> <C> <C>
Northern Indiana Public Service Company:
Cumulative preferred stock - $100 par value
- 4-1/4% series -209,035 and 209,051
shares outstanding, respectively $ 20,903 $ 20,905 $101.20
4-1/2% series - 79,996 shares outstanding 8,000 8,000 $100.00
4.22% series - 106,198 shares outstanding 10,620 10,620 $101.60
4.88% series - 100,000 shares outstanding 10,000 10,000 $102.00
7.44% series - 41,890 shares outstanding 4,189 4,189 $101.00
7.50% series - 34,842 shares outstanding 3,484 3,484 $101.00
Premium on preferred stock 254 254 N/A
Cumulative preferred stock - no par value
Adjustable rate (6.00% at September
30, 1999),
Series A (stated value $50 per share) 473,285
shares outstanding 23,664 23,664 $50.00
Indianapolis Water Company:
Cumulative preferred stock- $100 par value
4.00% to 5.00%, 44,966 shares outstanding 4,497 4,497 $100.00- $105.00
-----------
$ 85,611 $ 85,613
=========== ===========
</TABLE>
During the period October 1, 1997 to September 30, 1999 there were no
additional issuances of the above preferred stocks. The foregoing preferred
stocks are redeemable in whole or in part, at any time upon thirty days' notice
at the option of 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,
1999 1998
=========== ===========
(Dollars in thousands)
<S> <C> <C>
Northern Indiana Public Service Company:
Cumulative preferred stock -$100 par value -
8.85% series - 37,500 and 50,000
shares outstanding, respectively $ 3,750 $ 5,000
7-3/4% series - 33,352 shares outstanding 3,335 3,335
8.35% series - 45,000 and 51,000 shares
outstanding, respectively 4,500 5,100
Cumulative preferred stock -no par value -
6.50% series - 430,000 shares outstanding 43,000 43,000
----------- -----------
$ 54,585 $ 56,435
=========== ===========
</TABLE>
The redemption prices at September 30, 1999, as well as sinking fund
provisions for the cumulative preferred stocks subject to mandatory redemption
requirements, or whose redemption is outside the control of issuer, 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% $100.74, reduced periodically 12,500 shares on or before April 1.
7-3/4% $104.06, reduced periodically 2,777 shares on or before December 1;
noncumulative option to double amount each year.
8.35% $103.20, reduced periodically 3,000 shares on or before July 1;
increasing to 6,000 shares beginning in 2004;
noncumulative option to double amount each year.
Cumulative preferred stock -no par value -
6.50% $100.00 on October 14, 2002 430,000 shares on October 14, 2002.
</TABLE>
Sinking fund requirements with respect to redeemable preferred stocks for
the next five years and thereafter, not reflecting redemptions made after
September 30, 1999, were as follows:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
=================================
(In thousands)
<S> <C>
2000 $ 1,828
2001 1,828
2002 1,828
2003 44,828
2004 878
Thereafter 5,223
--------
Total preferred stocks,
redemption outside control of issuer $ 56,413
========
</TABLE>
Sinking fund payments due within one year are reported under the caption "Other
accruals" in the Consolidated Balance Sheets.
(12) Common Dividend: During the next few years, NiSource's ability to pay
dividends will depend 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 the
earned surplus or net profits of Northern Indiana. At September 30, 1999,
Northern Indiana had approximately $146.3 million of retained earnings (earned
surplus) available for the payment of dividends. Future dividends will depend
upon adequate retained earnings, adequate future earnings and the absence of
adverse developments.
(13) Earnings Per Share: Basic earnings per share were computed by dividing net
income, reduced for preferred dividends, by the average number of common shares
outstanding during the period. The diluted earnings per share calculation
assumes the conversion of nonqualified stock options into common shares.
The net income, preferred dividends and shares used to compute basic and
diluted earnings per share are presented in the following table:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ----------- ------------ ------------ ------------
1999 1998 1999 1998 1999 1998
(In thousands, except per share amounts)
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Net Income $ 27,955 $ 43,127 $ 127,458 $ 133,294 $ 188,050 $ 189,200
========== ========== ========== ========== ========== ==========
Basic
Weighted Average Number of Shares:
Average Common Shares Outstanding 125,031 119,495 124,218 121,833 122,578 122,645
========== ========== ========== ========== ========== ==========
Basic Earnings per Average Common Share $ 0.22 $ 0.36 $ 1.02 $ 1.09 $ 1.53 $ 1.54
========== ========== ========== ========== ========== ==========
Diluted
Weighted Average Number of Shares:
Average Common Shares Outstanding 125,031 119,495 124,218 121,833 122,578 122,645
Dilutive effect for Nonqualified
Stock Options and Forward Share
Purchase Contract 1,024 566 723 555 711 522
---------- ---------- ---------- ---------- ---------- ----------
Weighted Average Shares 126,055 120,061 124,941 122,388 123,289 123,167
========== ========== ========== ========== ========== ==========
Diluted Earnings per Average Common Share $ 0.22 $ 0.35 $ 1.02 $ 1.08 $ 1.52 $ 1.53
========== ========== ========== ========== ========== ==========
</TABLE>
(14) Common Shares: On April 8, 1998, shareholders approved an increase in the
number of authorized common shares, without par value, from 200,000,000 shares
to 400,000,000 shares. All references to numbers of common shares reported,
including per share amounts and stock option data, have been adjusted to reflect
the two-for-one stock split paid February 20, 1998.
Share Purchase Rights Plan. Each Right, when exercisable, would initially
entitle the holder to purchase from NiSource one two-hundredth of a share of
Series A Junior Participating Preferred Share, without par value, at a price of
$30 per one two-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, 1999,
approximately 55.3 million shares had been repurchased at an average price of
$16.95 per share.
Equity Forward Share Purchase Contracts. During the second quarter of 1999,
a forward purchase contract was entered into covering the purchase of up to 5%
of NiSource's outstanding common shares. At the end of each quarterly period
during the term of the forward purchase contract, NiSource has the option, but
not the obligation, to settle the forward purchase contract with respect to all
or a portion of the common shares held by the counterparty. As of September 30,
1999, the counterparty informed NiSource that approximately 5.6 million shares
had been purchased at a weighted average cost of $26.90 per share. NiSource has
the option to settle with the counterparty by means of physical or net share
settlement. On a quarterly basis, NiSource will pay the counterparty a fee based
on the amount paid for common shares purchased by the counterparty, and the
counterparty will remit 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 $279,000 for the
three, nine and twelve months ended September 30, 1999.
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, 1999 the fee/ nominal amount and fair value of the
equity forward purchase contract were approximately $150 million and $124
million, respectively.
(15) Long-Term Incentive Plans: There are two long-term incentive plans for key
management employees that were approved by shareholders on April 13, 1988 (1988
Plan) and April 13, 1994 (1994 Plan), each of which provides for the issuance of
up to 5.0 million common shares to key employees through April 1998 and April
2004, respectively. The 1988 Plan, as amended and restated, and the 1994 Plan,
as amended and restated, were re-approved by shareholders at the 1999 Annual
Meeting of Shareholders, held on April 14, 1999.
At September 30, 1999, there were 1.8 million shares reserved for future
awards under the 1994 Plan. The Plans permit the following types of grants,
separately or in combination: nonqualified stock options, incentive stock
options, restricted stock awards, stock appreciation rights and performance
units. No incentive stock options or performance units were outstanding at
September 30, 1999. Under the Plans, the exercise price of each option equals
the market price of 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.
In connection with the acquisition of BSG (see Note 3), all outstanding BSG
non-qualified stock options were replaced with NiSource non-qualified 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 non-qualified stock options under
the caption "converted."
Stock appreciation rights (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. There were no SARs outstanding at September 30, 1999.
Restricted stock awards are restricted as to transfer and are subject to
forfeiture for specific periods from the date of grant. Restrictions on shares
awarded in 1995 lapse five years from date of grant, and vesting varies from 0%
to 200% of the number awarded, subject to specific earnings per share and stock
appreciation goals. Restrictions on shares awarded in 1998 and 1999 lapse two
years from date of grant and vesting varies from 0% to 100% of the number
awarded, subject to specific performance goals. If a participant's employment is
terminated prior to vesting other than by reason of death, disability or
retirement, restricted shares are forfeited. There were 513,500 and 534,666
restricted shares outstanding at September 30, 1999 and December 31, 1998,
respectively.
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 April 14,
1999, 75,500 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 $0.9 million and $0.6 million for the three-month,
$2.2 million and $1.4 million for the nine-month and $2.8 million and $2.0
million for the twelve-month periods ended September 30, 1999 and September 30,
1998, respectively. Had compensation cost for non-qualified stock options been
determined consistent with SFAS No. 123 "Accounting for Stock-Based
Compensation," net income 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,
------------------------ ------------------------ ------------------------
1999 1998 1999 1998 1999 1998
====== ====== ====== ====== ===== ======
(Dollars in thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C>
Net Income:
As reported $ 27,955 $ 43,127 $ 127,458 $ 133,294 $188,050 $189,200
Pro forma $ 27,564 $ 42,839 $ 126,260 $ 132,580 $186,448 $188,273
Earnings Per Average
Common Share:
Basic:
As reported $ 0.22 $ 0.36 $ 1.02 $ 1.09 $ 1.53 $ 1.54
Pro forma $ 0.22 $ 0.35 $ 1.01 $ 1.08 $ 1.52 $ 1.53
Diluted:
As reported $ 0.22 $ 0.35 $ 1.02 $ 1.08 $ 1.52 $ 1.53
Pro forma $ 0.21 $ 0.35 $ 1.01 $ 1.08 $ 1.51 $ 1.52
</TABLE>
The fair value of each option granted as used to determine pro forma net
income is estimated as of the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions used for grants in
the three-month, nine-month and twelve-month periods ended September 30, 1999
and September 30, 1998: risk-free interest rate of 5.87% and 5.29%,
respectively; expected dividend yield per share of $1.02 and $0.96,
respectively; expected option term of 5.22 years and 5.4 years, respectively;
and expected volatilities of 15.72% and 13.09%, respectively.
Changes in outstanding shares under option and SARs for the three-month,
nine-month and twelve-month periods ended September 30, 1999 and September 30,
1998 were as follows:
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Three Months Ended September 30, 1999 Price 1998 Price
================================ ======== ======= ======== =======
<S> <C> <C> <C> <C>
Balance, beginning of period 3,243,206 $ 18.81 2,193,600 $ 16.76
Granted 744,750 24.59 607,000 29.22
Exercised 29,000 15.62 115,500 17.77
Canceled -- -- -- --
--------- --------
Balance, end of period 3,958,956 $ 19.92 2,685,100 $ 19.53
========= ========
Shares exercisable 3,214,206 $ 18.84 2,078,100 $ 12.68
========= ========
</TABLE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Nine Months Ended September 30, 1999 Price 1998 Price
============================ ======== ======= ======== =======
<S> <C> <C> <C> <C>
Balance, beginning of period 2,651,300 $ 19.61 2,535,400 $ 16.41
Converted 740,780 15.03 -- --
Granted 744,750 24.60 607,000 29.22
Exercised 171,374 14.03 437,100 14.66
Canceled 6,500 29.22 20,200 20.64
-------- --------
Balance, end of period 3,958,956 $ 19.92 2,685,100 $ 19.56
======== ========
Shares exercisable 3,214,206 $ 18.84 2,078,100 $ 12.68
======== ========
</TABLE>
<TABLE>
<CAPTION>
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Twelve Months Ended September 30, 1999 Price 1998 Price
============================ ======== ======= ======== =======
<S> <C> <C> <C> <C>
Balance, beginning of period 2,685,100 $ 19.56 2,633,400 $ 16.42
Converted 740,780 15.03 -- --
Granted 744,750 24.59 607,000 29.22
Exercised 203,174 14.14 530,100 14.98
Canceled 8,500 29.22 25,200 20.64
-------- --------
Balance, end of period 3,958,956 $ 19.92 2,685,100 $ 19.56
======== ========
Shares exercisable 3,214,206 $ 18.84 2,078,100 $ 12.68
======== ========
Weighted average fair value
of options granted $ 3.66 $ 4.28
======== ========
</TABLE>
The following table summarizes information about non-qualified stock
options at September 30, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------------- ------------------------
Number Weighted Average Number
Range of Outstanding at Remaining Weighted Average Exercisable at
Option Price September 30, 1999 Contractual Life Option Price September 30, 1999
============= =============== =============== =============== ===============
<S> <C> <C> <C> <C>
$ 8.53 to $12.31 154,500 1.6 years $ 10.46 154,500
$13.03 to $19.77 2,012,006 6.9 years 15.98 2,012,006
$20.64 to $29.22 1,792,450 9.1 years 25.14 1,047,700
- ------------------ --------------- --------------- ---------- -------------
$ 8.53 to $29.22 3,958,956 6.4 years $ 19.92 3,214,206
=============== =============
</TABLE>
(16) Long-Term Debt:
<TABLE>
<CAPTION>
September 30, December 31,
(Dollars in thousands) 1999 1998
========== ==========
<S> <C> <C>
First mortgage bonds -
Weighted average interest rate of 6.62% and various
maturities between May 1, 2001 and July 15, 2028 $ 186,100 $ 186,600
Pollution control notes and bonds-
Weighted average interest rate of 3.91% and various
maturities between October 1, 2003 and April 1, 2019 239,500 239,500
Medium-term notes -
Weighted average interest rate of 7.16% and various
maturities between July 6, 2000 and September 1, 2031 1,191,313 1,048,025
Subordinated Debentures -7.75%, 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 7.32% and various
maturities between March 5, 2001 and December 1, 2018 48,102 41,807
Variable bank loans - Weighted average interest rate of 5.86% and
various maturities between March 17, 2001 and August, 2003 30,600 5,600
Unamortized premium and discount on long-term debt, net (3,225) (3,567)
----------- -----------
Total long-term debt, excluding amounts due within one year $ 1,842,390 $ 1,667,965
=========== ===========
</TABLE>
The sinking fund requirements and maturities of long-term debt for the next five
years and thereafter were as follows as of September 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
=================================
(In thousands)
<S> <C>
2000 $ 163,283
2001 91,273
2002 93,689
2003 183,945
2004 124,561
Thereafter 1,348,922
-----------
Total long-term debt (including current portion) $ 2,005,673
===========
</TABLE>
Unamortized debt expense, premium and discount on long-term debt applicable
to outstanding bonds are being amortized over the lives of such bonds.
Reacquisition premiums are being deferred and amortized. These premiums are not
earning a return during the recovery period.
The first mortgage bonds constitute a direct first mortgage lien upon
certain utility property and franchises. Certain trust indentures require annual
sinking or improvement payments amounting to .50% of the maximum aggregate
amount outstanding. As permitted, this requirement has been satisfied by
substituting a portion of permanent additions to utility plant.
Northern Indiana is authorized to issue and sell up to $217,692,000
Medium-Term Notes, Series E, with various maturities, for purposes of
refinancing certain first mortgage bonds and medium-term notes. As of September
30, 1999, $139.0 million of these medium-term notes had been issued with various
interest rates and maturities. The proceeds from these issuances were used to
pay short-term debt incurred to redeem Northern Indiana's First Mortgage Bonds,
Series N, and to pay at maturity various issues of Medium-Term Notes, Series D.
In July 1998, $40.0 million of twenty-year medium-term notes were issued at
a rate of 5.05% with a maturity date of July 15, 2018, with the proceeds being
used to redeem 7-7/8% Bonds. In February 1999, $35.0 million of ten-year medium
term notes were issued at a rate of 5.99% with a maturity date of February 1,
2009 and $45.0 million of twenty-year medium term notes were issued at a rate of
6.61% with a maturity date of February 1, 2019. The majority of the proceeds
were used to reduce existing credit facilities and the remaining proceeds were
used for general corporate purposes.
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 $2.9 billion at September 30, 1999.
(17) Current Portion of Long-Term Debt: At September 30, 1999 and December 31,
1998, the current portion of long-term debt due within one year was as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
======== ========
(In thousands)
<S> <C> <C>
Medium-term notes--
Weighted average interest rate of 6.80% $156,137 $ --
Notes payable--
Weighted average interest rate of 7.94% 5,146 4,790
Sinking funds due within one year 2,000 2,000
-------- --------
Total current portion of long-term debt $163,283 $ 6,790
======== ========
</TABLE>
(18) Short-Term Borrowings: NiSource and its subsidiaries may borrow under two
five-year, $100 million revolving credit agreements that terminate on September
23, 2003 and two 364-day $100 million revolving credit agreements that terminate
on September 23, 2000. The 364-day agreements may be extended at expiration for
additional periods of 364 days. Under these agreements, funds are borrowed at a
floating rate of interest or, under certain circumstances, at a fixed rate of
interest for short-term periods. These agreements provide financing flexibility
and may be used to support the issuance of commercial paper. At September 30,
1999, there were no borrowings outstanding under these agreements.
In addition, various NiSource subsidiaries maintain lines of credit for up
to an aggregate of $199.9 million with lenders at either the lender's commercial
prime or market lending rates. As of September 30, 1999, there were $41.1
million of borrowings outstanding under these lines of credit with a weighted
average interest rate of 6.13%. As of December 31, 1998, there were $84.1
million of borrowings outstanding under these lines of credit.
NiSource and its subsidiaries maintain market lines of credit for up to
$396.2 million. As of September 30, 1999, there were $103.9 million outstanding
under these money market lines of credit with a weighted average interest rate
of 5.55%. At December 31, 1998, there were $127.3 million of borrowings
outstanding under these money market lines of credit.
In September 1999, Capital Markets issued $160 million Puttable Reset
Securities (PURS) in an underwritten public offering. The PURS are unsecured
debentures of Capital Markets and rank equally with all other unsecured and
unsubordinated debt of Capital Markets. The PURS are subject to a call option
under which the underwriters may purchase all of the outstanding PURS from the
holders on September 28, 2000. The net proceeds from the sale of the PURS and
the call option of $162.4 million were used to refinance short-term indebtedness
incurred in connection with the acquisition of BSG in February 1999. Until
September 28, 2000, the PURS will accrue interest at a rate based on LIBOR plus
1.25%. On September 28, 2000, if the underwriters do not exercise their call
option, Capital Markets will be obligated to repurchase all of the outstanding
PURS. If the underwriters purchase all of the outstanding PURS pursuant to their
call option, the interest rate will be reset to a fixed rate based on then
current market rates plus a fixed margin and the PURS will remain outstanding
until 2010.
At September 30, 1999 and December 31, 1998, short-term borrowings were as
follows:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
======== ========
(In thousands)
<S> <C> <C>
Commercial paper--
Weighted average interest rate of 5.56% at September 30, 1999 $261,400 $ 193,700
Notes payable--
Weighted average interest rate of 6.13% at September 30, 1999 314,075 217,340
-------- --------
Total short-term borrowings $575,475 $ 411,040
======== ========
</TABLE>
(19) Corporate Premium Income Equity Securities and Company-Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely
Company Debentures: In February 1999 an underwritten public offering of 6.9
million Corporate Premium Income Equity Securities (PIES) was completed. 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.
Each PIES consists of (i) a stock purchase contract to purchase, four years
from the date of issuance, for $50 a number of common shares and (ii) a
Preferred Security with a liquidation amount of $50 issued by a wholly-owned
subsidiary trust. Each Preferred Security is pledged as collateral, for the
benefit of NiSource, in support of the holder's obligation to purchase common
shares under the stock purchase contract.
The face value of the PIES is not recorded in the consolidated balance
sheets. A $22.2 million present value contract fee payable to the PIES holders
has been recorded as a liability and as reduction to paid-in capital. In
addition, paid-in capital has been reduced by $10.4 million for the issuance
costs of the PIES.
The Preferred Securities represent undivided beneficial interests in the
assets of NIPSCO Capital Trust I (Capital Trust). The sole assets of Capital
Trust are subordinated debentures (Debentures) of Capital Markets that bear
interest at a rate of 5.90% per annum, and certain rights under related
guarantees by Capital Markets.
The distributions paid on the Preferred Securities are presented under the
caption "minority interests" in the 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 the consolidated balance sheets. At September 30, 1999,
there were 6.9 million, 5.9% Preferred Securities outstanding with Capital Trust
assets of $345.0 million.
(20) Operating Leases: The following is a schedule, by year, of future minimum
rental payments, excluding those to associated companies, required under
operating leases that have initial or remaining noncancelable lease terms in
excess of one year as of September 30, 1999:
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
=================================
(In thousands)
<S> <C>
2000 $ 34,442
2001 34,051
2002 65,273
2003 30,417
2004 76,784
Later years 224,978
---------
Total minimum payments required $465,945
=========
</TABLE>
The consolidated financial statements include rental expense for all
operating leases as follows:
<TABLE>
<CAPTION>
September 30, September 30,
1999 1998
======== ========
(In thousands)
<S> <C> <C>
Three months ended $12,332 $ 6,167
Nine months ended $36,530 $17,699
Twelve months ended $42,531 $19,886
</TABLE>
(21) Commitments: NiSource expects that approximately $1.3 billion will be
expended for construction purposes for the period from January 1, 1999 to
December 31, 2003. 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 its Bailly Generating
Station. Services under this contract commenced on June 15, 1992 with annual
charges approximating $20.0 million. The agreement provides that, assuming
various performance standards are met by Pure Air, a termination payment would
be due if Northern Indiana terminated 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 estimated at $20.0 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 serve 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 including in the Operating Leases in Note 20.
Primary has advanced approximately $36.7 million and $31.8 million, at
September 30, 1999 and December 31, 1998, respectively, to the lessors of the
energy related projects discussed above. These net advances are included in
"Other Receivables" in the consolidated balance sheets and as a component of
operating activities in the consolidated statements of cash flows.
(22) Financial Instruments and Risk Management: A variety of commodity-based
derivative financial instruments are utilized to reduce the price risk inherent
in natural gas and electric operations, as well as for energy trading
activities. The use of these derivative financial instruments is governed by a
risk management policy, which includes as its objective that commodity-based
derivative financial instruments will be used primarily for hedging. The risk
management policy also governs energy trading activities and is generally
designed to allow for such activities within defined risk limits.
Natural Gas Commodity Risk Management. Commodity futures, options and swaps are
used to hedge the impact of natural gas price fluctuations related to business
activities, including price risk related to the physical location of the natural
gas (basis risk). As of September 30, 1999, open derivative financial
instruments represented hedges of natural gas sales of 43.1 billion cubic feet
(Bcf), and natural gas purchases and inventories of 42.0 Bcf. The net deferred
gains on these derivative financial instruments was $3.1 million at September
30, 1999.
Energy Trading Activities. Energy trading contracts, which include forwards,
futures, options and swaps are used in connection with energy trading activities
and may involve the physical delivery of energy. The net open positions for
these energy trading contracts were not significant as of September 30, 1999.
(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, 1999 December 31, 1998
Carrying/ Estimated Carrying/ Estimated
Notional Fair Notional Fair
Amount Value Amount Value
------------ ------------ ------------ ------------
(In thousands)
<S> <C> <C> <C> <C>
Investments $ 45,159 $ 44,617 $ 36,594 $ 36,028
Long-term debt (including current portion) $2,005,673 $1,901,235 $1,674,755 $1,769,934
Preferred stock (including current portion) $ 137,527 $ 125,405 $ 143,876 $ 140,420
Preferred securities $ 345,000 $ 295,838 N/A N/A
</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 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 substantial portion of their electric and gas industrial deliveries
are dependent upon the basic steel industry. Electric revenues from the basic
steel industry for the twelve months ended September 30, 1999 and 1998 were 16%
and 13%, respectively.
(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, Electric, Water and Gas
Marketing. The Gas 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 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 segment provides natural gas marketing 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 arrangement 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. 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 Note 2, "Summary of
Significant Accounting Policies."
<TABLE>
<CAPTION>
Other
(In thousands) Gas Products
For the three months ended September 30, 1999 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 133,335 $ 325,044 $ 29,923 $ 179,322 $ 83,108 $ (62,740) $ 687,992
Other, net $ 911 $ 332 $ 771 $ 1,422 $(12,377) $ (947) $ (9,888)
Depreciation and amortization $ 29,203 $ 39,856 $ 3,872 $ 777 $ 3,958 $ 340 $ 78,006
Segment profit (loss) $ (14,545) $ 116,857 $ 12,888 $ (2,595) $(10,847) $ (10,160) $ 91,598
Assets $2,478,428 $2,774,031 $ 666,307 $ 365,239 $ 447,270 $(224,014) $6,507,261
Capital Expenditures $ 44,737 $ 24,646 $ 22,953 $ 25 $ 4,444 $ -- $ 96,805
Investments in
equity-method investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
Other
(In thousands) Gas Products
For the three months ended September 30, 1998 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 80,953 $ 469,116 $ 24,403 $ 136,746 $ 67,958 $ (31,384) $ 747,792
Other, net $ 186 $ 181 $ 355 $ 417 $ 126 $ 1,605 $ 2,870
Depreciation and amortization $ 18,868 $ 39,438 $ 2,968 $ 77 $ 3,013 $ 53 $ 64,417
Segment profit (loss) $ (15,320) $ 108,107 $ 8,187 $ 1,555 $ (482) $ (2,229) $ 99,818
Assets $1,024,921 $2,739,708 $ 603,754 $ 74,548 $ 496,364 $(102,065) $4,837,230
Capital Expenditures $ 16,815 $ 35,879 $ 11,848 $ 0 $ 8,705 $ -- $ 73,247
Investments in
equity-method investees $ -- $ -- $ -- $ 6,572 $ 100,630 $ -- $ 107,202
Other
(In thousands) Gas Products
For the nine months ended September 30, 1999 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 711,954 $ 867,730 $ 74,882 $ 554,694 $ 235,769 $(184,799) $2,260,230
Other, net $ 2,149 $ 696 $ 1,234 $ 3,659 $ (7,514) $ (2,246) $ (2,022)
Depreciation and amortization $ 85,324 $ 119,104 $ 10,886 $ 1,661 $ 10,450 $ 1,029 $ 228,454
Segment profit $ 62,764 $ 276,108 $ 23,725 $ (1,041) $ (4,113) $ (20,445) $ 336,998
Assets $2,478,428 $2,774,031 $ 666,307 $ 365,239 $ 447,270 $(224,014) $6,507,261
Capital Expenditures $ 98,488 $ 92,528 $ 39,779 $ 66 $ 18,519 $ -- $ 249,380
Investments in
equity-method investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
Other
(In thousands) Gas Products
For the nine months ended September 30, 1998 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 434,032 $1,138,589 $ 63,029 $ 451,543 $ 187,056 $ (94,705) $2,179,544
Other, net $ 1,102 $ 354 $ 575 $ 1,588 $ 4,682 $ 2,086 $ 10,387
Depreciation and amortization $ 56,390 $ 117,162 $ 7,634 $ 193 $ 9,795 $ 160 $ 191,334
Segment profit $ 30,637 $ 258,885 $ 19,070 $ 3,688 $ (1,341) $ (7,447) $ 303,492
Assets $1,024,921 $2,739,708 $ 603,754 $ 74,548 $ 496,364 $(102,065) $4,837,230
Capital Expenditures $ 46,680 $ 92,631 $ 42,070 $ -- $ 18,649 $ -- $ 200,030
Investments in
equity-method investees $ -- $ -- $ -- $ 6,572 $ 100,630 $ -- $ 107,202
Other
(In thousands) Gas Products
For the twelve months ended September 30, 1999 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 915,020 $1,159,127 $ 95,951 $ 760,843 $ 311,782 $(229,259) $3,013,464
Other, net $ 3,849 $ 895 $ 1,371 $ 4,087 $ (8,402) $ (3,625) $ (1,825)
Depreciation and amortization $ 104,479 $ 158,786 $ 12,883 $ 1,799 $ 14,563 $ 1,084 $ 293,594
Segment profit $ 100,366 $ 358,655 $ 30,188 $ 323 $ 1,151 $ (25,087) $ 465,596
Assets $2,478,428 $2,774,031 $ 666,307 $ 365,239 $ 447,270 $(224,014) $6,507,261
Capital Expenditures $ 117,621 $ 130,331 $ 56,974 $ 432 $ 27,265 $ -- $ 332,623
Investments in
equity-method investees $ -- $ -- $ -- $ 91,837 $ 159,355 $ -- $ 251,192
Other
(In thousands) Gas Products
For the twelve months ended September 30, 1998 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues $ 696,604 $1,450,576 $ 81,430 $ 654,088 $ 247,293 $(143,358) $2,986,633
Other, net $ 1,385 $ 632 $ 1,167 $ 2,109 $ 1,016 $ 2,371 $ 8,680
Depreciation and amortization $ 74,621 $ 154,819 $ 11,368 $ 253 $ 11,915 $ 691 $ 253,667
Segment profit $ 75,598 $ 338,706 $ 23,761 $ 3,861 $ (3,612) $ (14,920) $ 423,394
Assets $1,024,921 $2,739,708 $ 603,754 $ 74,548 $ 496,364 $(102,065) $4,837,230
Capital Expenditures $ 65,557 $ 107,055 $ 54,599 $ 7 $ 30,002 $ -- $ 257,220
Investments in
equity-method investees $ -- $ -- $ -- $ 6,572 $ 100,630 $ -- $ 107,202
</TABLE>
The following table reconciles total reportable segment income before interest
and other charges and income taxes to net income for three, nine and twelve
months ended September 30,1999 and 1998:
<TABLE>
<CAPTION>
Three Months Nine Months Twelve Months
Ended September 30, Ended Septembe 30, Ended September 30,
------------------------ ------------------------ ------------------------
1999 1998 1999 1998 1999 1998
(In thousands) ======== ======== ======== ======== ======== ========
<S> <C> <C> <C> <C> <C> <C>
Total segment profit $ 91,598 $ 99,818 $ 336,998 $ 303,492 $465,596 $423,394
Interest expense, net (42,376) (33,077) (119,378) (94,522) (153,660) (125,887)
Minority interests (5,415) -- (13,539) -- (13,539) --
Dividends requirements on
preferred stock (2,071) (2,122) (6,264) (6,417) (8,385) (8,588)
-------- -------- -------- -------- -------- --------
Income before income taxes 41,736 64,619 197,817 202,553 290,012 288,919
Less: income taxes 13,781 21,492 70,359 69,259 101,962 99,719
-------- -------- -------- -------- --------- --------
Net income $27,955 $43,127 $127,458 $133,294 $188,050 $189,200
======== ======== ======== ======== ======== ========
</TABLE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Results of Operations
Holding Company
NiSource Inc., formerly NIPSCO Industries, Inc., is an energy and
utility-based holding company headquartered in Merrillville, Indiana that
provides natural gas, electricity and water to the public for residential,
commercial and industrial uses. 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. NiSource operates primarily in Indiana and New
England through wholly-owned regulated and unregulated subsidiaries.
Operating Revenues
Twelve months ended September 30, 1999. Total operating revenues for the
twelve months ended September 30, 1999 were $26.8 million higher than total
operating revenues for the twelve months ended September 30, 1998. Gas revenues
were $1.5 billion, which represented a $245.5 million increase from the
comparable period ended September 30, 1998. This increase was primarily due to
the inclusion of $197.9 million gas revenues from BSG, increased marketing
revenues as a result of the TPC acquisition and increased deliveries of gas
transported for others, partially offset by decreased gas sales to residential
and commercial customers as a result of warmer weather during the fourth quarter
of 1998, decreased purchased gas costs per dekatherm (dth), decreased gas
transition costs and decreased sales to industrial customers. Electric revenues
were $1.2 billion, which represented a $291.5 million decrease from electric
revenues for the comparable period ended September 30, 1998. This decrease was
mainly due to a decrease in wholesale electric marketing volumes, partially
offset by increased electric sales to residential and commercial customers due
to warmer weather during the third quarter of 1999 and increased costs per
kilowatt-hour (kwh). Water revenues were $95.8 million, which represented a
$14.5 million increase from water revenues for the comparable period ended
September 30, 1998. This increase was primarily due to increased water volumes
sold and to increased water rates for IWC that became effective on April 8, 1998
and April 8, 1999. Products and Services revenues were $255.8 million, which
represented a $58.3 million increase from Products and Services revenues for the
comparable period ended September 30, 1998. This increase reflects revenues from
a new energy related project which began commercial operations in August 1998,
increased pipeline construction activity and increased line locating and marking
activity.
Nine months ended September 30, 1999. Total operating revenues for the
nine months ended September 30, 1999 were $80.7 million higher than total
operating revenues for the nine months ended September 30, 1998, representing a
3.7% increase. Gas revenues were $1.1 billion, which represented a $296.2
million increase from the comparable period ended September 30, 1998. This
increase was primarily due to the inclusion of $197.9 million in gas revenues
from BSG, increased marketing revenues as a result of the TPC acquisition,
increased gas sales to residential and commercial customers, increased
deliveries of gas transported for others partially offset by decreased gas costs
per dth and decreased transition costs. Electric revenues were $865.4 million,
which represented a $270.8 million decrease from electric revenues from the
comparable period ended September 30, 1998. This decrease was mainly due to
decreased wholesale electric marketing volumes in the 1999 period, compared to
the 1998 period partially offset by increased sales to residential, commercial
and industrial customers and increased costs per kwh. Water revenues were $74.8
million, which represented a $11.8 million increase from water revenues for the
comparable period ended September 30, 1998. This increase was primarily due to
increased water volumes sold and to increased water rates for IWC that became
effective on April 8, 1998 and April 8, 1999. Products and Services revenues
were $192.2 million, which represented a $43.4 million increase from Products
and Services revenues for the comparable period ended September 30, 1998. This
increase reflects revenues from a new energy related project which began
commercial operations in August 1998, increased pipeline construction activity
and increased line locating and marking activity.
Three months ended September 30, 1999. Total operating revenues for the
three months ended September 30, 1999 were $59.8 million lower than total
operating revenues for the three months ended September 30, 1998, representing a
8.0% decrease. Gas revenues were $265.4 million, which represented a $65.9
million increase from gas revenues for the comparable period ended September 30,
1998. This increase was primarily due to the inclusion of $28.8 million of
operating revenues from BSG, increased marketing revenues primarily as a result
of the TPC acquisition, increased gas sales to residential and commercial
customers and increased gas costs per dth, partially offset by decreased sales
to industrial customers. Electric revenues were $324.3 million, which
represented a $144 million decrease from electric revenues for the comparable
period ended September 30, 1998. This decrease was mainly due to decreased
wholesale electric marketing volumes in the 1999 period, compared to the 1998
period, partially offset by increased sales to commercial and industrial
customers and increased costs per kwh. Water revenues were $29.9 million, which
represented a $5.5 million increase from water revenues for the comparable
period ended September 30, 1998. This increase was primarily due to increased
water volumes sold and to increased water rates for IWC that became effective on
April 8, 1999. Products and Services revenues were $68.4 million, which
represented a $12.7 million increase from Products and Services revenues for the
comparable period ended September 30, 1998. This increase reflects revenues from
a new energy related project which began commercial operations in August 1998,
increased pipeline construction activity and increased line locating and marking
activity.
The basic steel industry accounted for 16.44% of all natural gas delivered
(including volumes transported) and 24.60% of all electric sales during the
twelve months ended September 30, 1999.
The components of the variations of operating revenues for gas,
electric, water and Products and Services are shown in the following table:
<TABLE>
<CAPTION>
Variations from Prior Periods
-------------------------------------
September 30, 1999 Compared to September 30, 1998
------------------------------------------------------
Three Nine Twelve
(In thousands) Months Months Months
========== ========== ==========
<S> <C> <C> <C>
Gas Revenue
Pass through of net changes in
purchased gas costs, gas storage,
and storage transportation costs $ 8,853 $ (17,111) $ (46,126)
Gas transition costs (1,137) (3,238) (6,732)
Changes in sales levels (9,866) (323) (50,780)
Gas transported (252) 765 6,760
Bay State Gas Acquisition 28,804 197,938 197,938
Gas Wholesale Marketing 39,555 118,196 144,432
---------- ---------- ----------
Gas Revenue Change 65,957 296,227 245,492
---------- ---------- ----------
Electric Revenue -
Pass through of net changes
in fuel costs 12,128 9,312 9,078
Changes in sales levels 14,315 25,736 24,896
Wholesale electric (170,467) (305,854) (325,466)
---------- ---------- ----------
Electric Revenue Change (144,024) (270,806) (291,492)
---------- ---------- ----------
Water Revenue Change 5,520 11,854 14,521
---------- ---------- ----------
Products and Services Revenues -
Pipeline construction 2,631 8,244 10,589
Locate and marking 1,768 3,452 5,332
Other 8,348 31,716 42,388
---------- ---------- ----------
Products and Services Revenue Change 12,747 43,412 58,309
---------- ---------- ----------
Total Revenue Change $(59,800) $ 80,687 $ 26,830
========== ========== ==========
</TABLE>
Cost of Sales
Cost of sales consists of gas costs, costs of fuel for electric
generation, costs of power purchased and Products and Services cost of sales.
Gas Costs. Total gas costs for the twelve months ended September 30, 1999
increased $135.7 million over the twelve months ended September 30, 1998. This
increase reflects the inclusion of gas costs of $95.7 million for BSG and
increased gas marketing activities, partially offset by decreased purchased gas
costs per dth for the Energy Utilities. The gas costs for the nine months ended
September 30, 1999 increased by $175.9 million, from gas costs for the nine
months ended September 30, 1998. This increase reflects the inclusion of gas
costs of $95.7 million for BSG and increased gas marketing activities partially
offset by decreased purchased gas costs per dth for the Energy Utilities. The
gas costs for the three months ended September 30, 1999 increased by $48.1
million, from gas costs for the three months ended September 30, 1998. This
increase reflects the inclusion of gas costs of $7.5 million for BSG, increased
gas marketing activities and increased gas cost per dth for the Energy
Utilities.
Fuel and Purchased Power. The cost of fuel used for electric generation
decreased during the twelve months ended September 30, 1999 and the nine months
ended September 30, 1999 due to decreased fuel costs, partially offset by
increased electric generation. The cost of fuel for the three months ended
September 30, 1999 was relatively unchanged from the three months ended
September 30, 1998. Purchased power decreased by $310.6, $289 and $151.4 million
for the twelve, nine and three months ended September 30, 1999, respectively,
compared to the comparable periods ended September 30, 1998, primarily due to
decreased power purchased for wholesale electric marketing activity.
Cost of Sales: Products and Services. The cost of sales for the Products
and Services subsidiaries during the twelve, nine and three months ended
September 30, 1999 were $30.7, $25.0 and $8.4 million higher, respectively, than
in the comparable periods ended September 30, 1998. These increases reflected
the inclusion of cost of sales for other Products and Services subsidiaries
acquired in the BSG acquisition and increased activity at SM&P Utility
Resources, Inc. (SM&P) and Miller Pipeline Corporation (Miller), the line
locating and marking and pipeline construction subsidiaries.
Operating Margins
Twelve months ended September 30, 1999. Operating margins for the twelve
months ended September 30, 1999 were $1.4 billion, an increase of $179.5 million
from the twelve months ended September 30, 1998. Gas operating margin was $109.8
million higher than in the comparable period ended September 30, 1998. This
increase reflects the February 1999 acquisition of BSG in the amount of $103.4
million and increased deliveries of gas transported for others, partially offset
by decreased sales to residential and commercial customers, reflecting unusually
warm weather during the fourth quarter of 1998, and decreased sales to
industrial customers. Electric operating margin was $27.5 million higher than
the comparable period ended September 30, 1998. This increase occurred mainly
due to increased sales to residential and commercial customers and improved
margins on wholesale electric marketing transactions, partially offset by
decreased industrial sales. Water operating margin was $14.5 million higher than
in the comparable period ended September 30, 1998, due to increased volumes sold
and increased water rates for IWC that became effective on April 8, 1998 and
April 8, 1999. Products and Services operating margin was $27.6 million higher
than in the comparable period ended September 30, 1998, reflecting a new energy
related project, which began commercial operations in August 1998 and increased
pipeline construction activity.
Nine months ended September 30, 1999. Operating margins for the nine
months ended September 30, 1999 were $1.1 billion, an increase of $174 million
from the nine months ended September 30, 1998. Gas operating margin was $120.3
million higher than in the comparable period ended September 30, 1998. This
increase reflects the February 1999 acquisition of BSG in the amount of 102.4
million, increased gas sales to residential customers and commercial customers,
reflecting colder weather during the first quarter of 1999, and increased
deliveries of gas transported for others. Electric operating margin was $23.5
million higher than in the comparable period ended September 30, 1998. This
increase occurred mainly due to increased sales to residential and commercial
customers and improved margins on wholesale power marketing transactions. Water
operating margin was $11.8 million higher than in the comparable period ended
September 30, 1998, due to increased volumes sold and increased rates for IWC
became effective on April 8, 1998 and April 8, 1999. Products and Services
operating margin was $18.4 million higher than in the comparable period ended
September 30, 1998, reflecting a new energy related project, which began
commercial operations in August 1998 and increased pipeline construction
activity.
Three months ended September 30, 1999. Operating margins for the three
months ended September 30, 1999 were $342.1 million, an increase of $35.3
million from operating margins for the three months ended September 30, 1998.
Gas operating margin was $17.8 million higher than gas operating margins for the
comparable period ended September 30, 1998. This increase reflected the February
1999 acquisition of BSG in the amount of $21.4 million. Electric operating
margin was $7.6 million higher than the electric operating margin for the
comparable period ended September 30, 1998. This increase was mainly due to
increased sales to residential customers and improved margins on wholesale
electric marketing transactions. Water operating margin was $5.5 million higher
than water operating margins for the comparable period ended September 30, 1998,
due to increased water volumes sold and increased rates for IWC that became
effective on April 8, 1999. Products and Services operating margin was $4.3
million higher than Products and Services margins for the comparable period
ended September 30, 1998, reflecting a new energy related project which began
commercial operations in August 1998 and increased pipeline construction
activity.
Operating Expenses and Taxes
Operating expenses and taxes (except income) consists of operation
expenses, maintenance expenses, depreciation and amortization expenses and taxes
(except income).
Operation expenses. Operation expenses for the twelve months ended
September 30, 1999 were $77.3 million higher than operation expenses for the
comparable period ended September 30, 1998. This increase reflects the inclusion
of $79.1 million of operation expenses at BSG and subsidiaries and increased
operation expenses at Primary due to the operation of a new energy related
project and IWC Resources Corporation (IWCR) partially offset by a $13.0 million
insurance settlement related to manufactured gas plant site cleanup costs.
Operation expenses for the nine months ended September 30, 1999 were $76.1
million higher than operation expenses for the comparable period ended September
30, 1998. This increase reflects the inclusion of $79.1 million of operation
expenses at BSG and subsidiaries increased operation expenses at Primary and
IWCR partially offset by a $13.0 million insurance settlement related to
manufactured gas plant site cleanup costs. Operation expenses for the three
months ended September 30, 1999 were $15.3 million higher than operation
expenses for the comparable period ended September 30, 1998. This increase was
primarily due to the inclusion of $26.9 million of operating expenses at BSG and
Primary partially offset by the $13.0 million insurance settlement.
Maintenance expenses. Maintenance expenses for the twelve months ended
September 30, 1999, were $1.2 million lower than for the comparable period ended
September 30, 1998. Maintenance expenses were lower primarily as a result of
decreased electric production facility maintenance costs and decreased gas
distribution facilities maintenance costs, partially offset by the inclusion of
maintenance expenses for BSG. Maintenance expenses for the nine months ended
September 30, 1999, were $3.6 million higher than for the comparable period
ended September 30, 1998 primarily due to the inclusion of maintenance expenses
for BSG. Maintenance expenses for the three months ended September 30, 1999 were
relatively unchanged from the comparable period ended September 30, 1998.
Depreciation and amortization expenses. Depreciation and amortization
expenses for the twelve months, nine months and three months ended September 30,
1999 were $39.9, $37.1 and $13.6 million higher, respectively, than depreciation
and amortization expenses for the comparable periods ended September 30, 1998.
These higher expenses reflect the inclusion of depreciation and amortization
expenses of BSG and property additions.
Other Income (Deductions)
Interest charges for the twelve months, nine months and three months
ended September 30, 1999 were $27.8, $24.9 and $9.3 million higher,
respectively, than interest charges in the comparable periods ended September
30, 1998. These increases reflect the inclusion of interest charges of BSG and
increased short-term and long-term borrowings. Additionally, minority interests
reflects dividends paid on Preferred Securities in connection with the PIES
offering during the nine-month period ended September 30, 1999.
Other, net for the twelve, nine and three months ended September 30, 1999
were $10.5, $12.4 and $12.8 million lower, respectively, than Other, net in the
comparable periods ended September 30, 1998. These decreases primarily result
from a charge of $16.5 million in the third quarter of 1999 related to an equity
exploration and production investment, partially offset by higher net gains on
disposition of businesses and properties and power trading activities, which
began in early 1999.
Liquidity and Capital Resources
Generally, cash flow from operations has provided sufficient
liquidity to meet current operating requirements. But because the utility and
utility construction business is seasonal in nature, commercial paper is issued
for short-term financing. As of September 30, 1999 and December 31, 1998, $261.4
million and $193.7 million of commercial paper was outstanding, respectively.
The weighted average interest rate of commercial paper outstanding as of
September 30, 1999 was 5.56%.
NiSource and its subsidiaries may borrow under two five-year, $100
million revolving credit agreements that terminate on September 23, 2003 and two
364-day $100 million revolving credit agreements that terminate on September 23,
2000. The 364-day agreements may be extended at expiration for additional
periods of 364 days. Under these agreements, funds are borrowed at a floating
rate of interest or, under certain circumstances, at a fixed rate of interest
for short-term periods. These agreements provide financing flexibility and may
be used to support the issuance of commercial paper. At September 30, 1999,
there were no borrowings outstanding under these agreements.
In addition, various lines of credit are maintained. At September 30,
1999, there were no borrowings under the uncommitted finance facility. Lines of
credit for up to $199.9 million are held with lenders at either their commercial
prime or market lending rates. At September 30, 1999, there were $41.1 million
of borrowings outstanding under these lines of credit with a weighted average
interest rate of 6.13%. As of December 31, 1998, there were $84.1 million of
borrowings outstanding under these lines of credit.
NiSource and its subsidiaries maintain money market lines of credit for up
to $403.5 million. As of September 30, 1999, $103.9 million was outstanding
under these money market lines of credit with a weighted average interest rate
of 5.57%. At December 31, 1998, there were $127.3 million of borrowings
outstanding under these money market lines of credit.
$40.0 million in revenue bonds were issued in July 1998 and an aggregate of
$80.0 million in medium-term notes were issued in February 1999. The revenue
bonds, which were used to redeem previously existing revenue bonds, bear
interest at 5.95% per annum and mature on July 15, 2028. 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 6.9 million Corporate
Premium Income Equity Securities (PIES) was completed. The net proceeds of
approximately $334.7 million were primarily used to fund the cash paid in the
acquisition of BSG, and to repay short-term indebtedness.
In September 1999, Capital Markets issued $160 million Puttable Reset
Securities (PURS) in an underwritten public offering and the underwriters
acquired a call option to purchase the PURS on September 28, 2000. The net
proceeds from the sale of the PURS and the call option of $162.4 million were
used to refinance short-term indebtedness incurred in connection with the
acquisition of BSG in February 1999. See Note 18 "Short-Term Borrowings," to the
consolidated financial statements for a description of the PURS.
NiSource has made an offer to acquire CEG for $6.1 billion, or $74 per
share of CEG common stock, in cash. A commitment letter has been accepted under
which certain financial institutions have agreed, subject to specified
conditions, to provide $6.5 billion to finance the proposed acquisition of CEG.
No assurance can be given as to whether, or on what terms, NiSource will acquire
CEG.
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
See Note 22, "Financial Instruments and Risk Management," to the consolidated
financial statements for a discussion of commodity-based derivative financial
instruments and risk management.
There are two primary market risks, commodity price risk and interest rate
risk, to which NiSource is exposed.
Commodity price risk. Price risk management activities are designed to
address price fluctuations in electricity and natural gas commodity prices that
are sensitive to changes in supply and demand. These changes are actively
monitored and derivative financial and commodity instruments are used to reduce,
or hedge, exposure to price risks. Part of these price risks includes
differences in price based on geography. Geographic price differentials result
primarily from transportation costs and local supply and demand factors. To
hedge a portion of this exposure, basis swaps are used from time to time.
However, not all basis exposure is hedged.
A portion of customer sales contracts are based upon a fixed sales price
with varying volumes that ultimately depend on a customer's supply requirements.
Financial derivatives are used based on modeling techniques in order to
anticipate future supply requirements. Nonetheless, NiSource remains exposed to
price risk for the difference between a customer's actual supply requirements
and those requirements predicted by the models.
Currently, commodity price risk of the Energy Utilities business is
relatively limited, since current regulations allow the Energy Utilities to
recoup any prudently incurred 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.
Because derivative financial and commodity instruments are substantially
the same commodities that are bought and sold in the physical market, NiSource
believes that its price management activities do not require any special
correlation studies, other than monitoring the degree of convergence between the
derivative and cash markets.
The daily net commodity position consists of natural gas inventories,
commodity purchase and sales contracts and derivative financial and commodity
instruments. The fair market value of this portfolio is a summation of the fair
market values calculated for each commodity, whose net values are measured by
quotes from energy exchange markets and over-the-counter markets. Based upon the
fair market value of this portfolio as of September 30, 1999, if the electric
and natural gas market prices dropped by 10 percent, this change would reduce
NiSource's net income by approximately $1.3 million. Any such movements in
prices, however, are not indicative of actual results and are subject to change.
Interest rate risk. Long-term debt is utilized as a primary source of
capital. A significant portion of this long-term debt consists of medium-term
notes. In addition, longer term fixed-price debt instruments have been used that
in the past have been refinanced when interest rates decreased. To the extent
that such refinancing is economical, refinancing these fixed-price instruments
will continue.
Information about long-term debt is in Note 16 to the consolidated
financial statements, "Long-Term Debt." Information about the current market
valuation of long-term debt is in Note 23 to the consolidated financial
statements, "Fair Value of Financial Instruments." Information about the use of
derivatives and risk management policy is in Note 2 to the consolidated
financial statements, "Summary of Significant Accounting Policies- Derivatives."
Year 2000 Costs
Risks. Year 2000 issues address the ability of electronic processing
equipment to process date sensitive information and recognize the last two
digits of a date as occurring in or after the year 2000. Any failure in any
system may result in material operational and financial risks. Possible
scenarios include a system failure in a generating plant, an operating
disruption or delay in transmission or distribution, or an inability to
interconnect with the systems of other utilities. In addition, while NiSource
anticipates that mission-critical systems will be year 2000 compliant in a
timely fashion, it cannot guarantee the compliance of systems operated by other
companies upon which it depends. For example, the ability of an electric company
to provide electricity to its customers depends upon a regional electric
transmission grid, which connects the systems of neighboring utilities to
support the reliability of electric power within the region. If one company's
system is not year 2000 compliant, then a failure could affect the reliability
of all providers within the grid, including NiSource. Similarly, gas operations
depend on natural gas pipelines that are not owned or controlled by NiSource,
and any non-compliance by a company owning or controlling those pipelines may
affect NiSource's ability to provide gas to its customers. Failure to achieve
year 2000 readiness could have a material adverse affect on results of
operations, financial position and cash flows.
The program to address risks associated with the year 2000 is continuing.
The focus is on both information technology (IT) and non-IT systems, and
substantial progress has been made in preparing these systems for proper
functioning in the year 2000.
State of Readiness. The year 2000 program consists of four phases:
inventory (identifying systems potentially affected by the year 2000),
assessment (testing identified systems), remediation (correcting or replacing
non-compliant systems) and validation (evaluating testing remediated systems to
confirm compliance). Northern Indiana has completed the remediation and
validation phases for all its mission-critical systems. The year 2000 program
for BSG is expected to be completed in the fourth quarter of 1999. The IWC year
2000 program was completed in June 1999. NiSource has completed the inventory
and assessment phases for all of its non-IT mission-critical systems and has
completed remediation (including replacement) and validation for its non-IT
mission-critical systems. Substantially all mission-critical year 2000 efforts
were completed in June, 1999.
Because outside suppliers and vendors with similar year 2000 issues are
depended upon, the ability of those suppliers and vendors to provide it with an
uninterrupted supply of goods and services is being assessed. Critical vendors
and suppliers have been contacted in order to investigate their year 2000
efforts. In addition, electricity and gas industry groups such as the North
American Electric Reliability Council, the Electric Power Research Institute,
and the American Gas Association are being worked with to discuss and evaluate
the potential impact of year 2000 problems upon the electric grid systems and
pipeline networks that interconnect within each of those industries.
Costs. The total cost of the year 2000 program is estimated to be $28
million. These costs have been, and will continue to be, funded from operations.
Costs related to the maintenance or modification of existing systems are
expensed as incurred. Costs related to the acquisition of replacement systems
are capitalized. These costs are not anticipated to have a material impact on
results of operations.
Contingency Plans. NiSource currently is in the process of structuring its
contingency plans to address the possibility that any mission-critical system
upon which it depends, including those controlled by outside parties, will be
non-compliant. This includes identifying alternate suppliers and vendors,
conducting staff training and developing communication plans. In addition, the
ability to maintain or restore service in the event of a power failure or
operating disruption or delay is being evaluated, along with the limited ability
to mitigate the effects of a network failure by isolating its own network from
the non-compliant segments of the greater network. These contingency plans were
completed during the second quarter of 1999; however, the contingency plans will
be under review during the fourth quarter of 1999.
ALL STATEMENTS REGARDING YEAR 2000 MATTERS CONTAINED IN THIS REPORT ARE
"YEAR 2000 READINESS DISCLOSURES" WITHIN THE MEANING OF THE YEAR 2000
INFORMATION AND READINESS DISCLOSURE ACT.
Competition and Regulatory Changes
The regulatory frameworks applicable to the Energy Utilities, at both the
state and federal levels, are undergoing fundamental change. These changes have
impacted and will continue to have an impact on operations, structure and
profitability. At the same time, competition within the electric and gas
industries will create opportunities to compete for new customers and revenues.
Management has taken steps to become more competitive and profitable in this
changing environment, including 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 customer
choice for new products and services, acquiring companies which increase our
scale and establishing subsidiaries that provide gas and develop new
energy-related products for residential, commercial and industrial customers.
The Electric Industry. At the Federal level, FERC issued Order No. 888-A in
1996 which required all public utilities owning, controlling or operating
transmission lines to file non-discriminatory open-access tariffs and offer
wholesale electricity suppliers and marketers the same transmission service they
provide themselves. In 1997, FERC approved Northern Indiana's open-access
transmission tariff. Although wholesale customers currently represent a small
portion of Northern Indiana's electricity sales, it intends to continue its
efforts to retain and add wholesale customers by offering competitive rates and
also intends to expand the customer base for which it provides transmission
services.
At the state level, it was announced in 1997 that if a consensus could be
reached regarding electric utility restructuring legislation, a restructuring
bill during the 1999 session of the Indiana General Assembly would be supported.
During 1998, discussions were held with the other investor-owned utilities in
Indiana regarding the technical and economic aspects of possible legislation
leading to greater customer choice. A consensus was not reached. Therefore, no
legislation was supported regarding electric restructuring during the 1999
session of the Indiana General Assembly. During 1999, discussions will continue
with all segments of the Indiana electric industry in an attempt to reach a
consensus on electric restructuring legislation for introduction during the 2000
session of the Indiana General Assembly.
The Gas Industry. At the Federal level, gas industry deregulation began in
the mid-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 Indiana Utility Regulatory Commission (IURC)
approved in 1997 Northern Indiana's Alternative Regulatory Plan (ARP) which
implemented new rates and services that included, among other things, unbundling
of services for additional customer classes (primarily residential and
commercial users), negotiated services and prices, a gas cost incentive
mechanism, and a price protection program. The gas cost incentive mechanism
allows Northern Indiana to share any cost savings or cost increases with its
customers based upon a comparison of Northern Indiana's actual gas supply
portfolio cost to a market-based benchmark price. Phase I of Northern Indiana's
Customer Choice Pilot Program ended on March 31, 1999. This pilot program
offered a limit of 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.
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
Information about the impact of anticipated accounting standards that have
not yet been adopted upon accounting policy can be found in Note 2, "Summary of
Significant Accounting Policies- Impact of Accounting Standards" to the
consolidated financial statements.
Forward Looking Statements
This report contains forward looking statements within the meaning of the
securities laws. Forward looking statements include terms such as "may," "will,"
"expect," "believe," "plan" and other similar terms. 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, year 2000 issues, the economic
climate, regional, commercial, industrial and residential growth in the service
territories served by NiSource's subsidiaries, customers' usage patterns and
preferences, the speed and degree to which competition enters the utility
industry, the timing and extent of changes in commodity prices, changing
conditions in the capital and equity markets and other uncertainties, all of
which are difficult to predict, and many of which are beyond NiSource's control.
Item 3. Quantitative and Qualitative Disclosures About Market Risk.
For a discussion of primary market risks and risk management policy, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations- Market Risk Sensitive Instruments and Positions." <PAGE>
PART II.
OTHER INFORMATION
Item 1. Legal Proceedings.
NiSource and its subsidiaries are parties to various pending proceedings,
including suits and claims against them for personal injury, death and property
damage. Such proceedings and suits, and the amounts involved, are routine
litigation and proceedings for the kinds of businesses conducted by NiSource and
its subsidiaries, except as described under Note 4 (NESI Energy Marketing Canada
Ltd. 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- Letter Agreement dated October 25, 1999 between Mr. Roger
A. Young and NiSource Inc.
Exhibit 10.2- Letter Agreement Dated April 9, 1999 between Mr. Joseph L.
Turner, Jr. and NiSource Inc.
Exhibit 10.3- Equity Forward Purchase Transaction dated November 9, 1999
between Scotia Capital (USA) Inc.and NiSource Inc.
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 August 31, 1999. All events were
reported under Item 5, Other Events. A report on Form 8-K was
filed September 28, 1999. All events were reported under Item
5, Other Events. A report on Form 8-K was filed September 30,
1999. All events were reported under Item 5, Other Events.
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
NiSource Inc.
(Registrant)
/s/ STEPHEN P. ADIK
----------------------------------------------
Stephen P. Adik
Senior Executive Vice President, Chief
Financial Officer,
Treasurer and Chief Accounting Officer
Date: November 10, 1999
Exhibit 10.1
[NiSource logo]
Gary L. Neale
Chairman, President, and
Chief Executive Officer
801 E. 86th Avenue
Merrillville, IN 46410-6272
(219) 647.6004
October 25, 1999
Mr. Roger A. Young
Chairman of the Board
Bay State Gas Company
300 Friberg Parkway
Westborough, MA 01581-5039
Re: Consulting Agreement
Dear Roger:
This letter will confirm our agreement as to your status, responsibilities and
compensation relating to your positions with NiSource Inc. and its wholly-owned
subsidiary, Bay State Gas Company, following your retirement as a Bay State Gas
Company employee on November 12, 1999 and extending through the date of the
annual meeting of NiSource's shareholders in 2002.
During that period you will continue to serve as a non-employed member of the
Board of Directors and non-executive Chairman of the Board of Bay State Gas
Company and as a member of the Board of Directors of NiSource Inc. In addition
you will serve on such other Boards, including that of the Institute of Gas
Technology, as you and I shall agree from time to time. You also will
periodically brief me and the CEO of Bay State Gas Company on merger and
acquisition activity in the Northeast, and participate as requested in strategy
sessions and meetings with potential partners and targets. You will continue to
participate as an invitee to Bay State Gas Company officer group meetings and as
requested from time to time in visits to legislators and regulators.
In addition to compensation received as a non-employed director of NiSource,
your compensation for all of these services will be at the annual rate of
$24,000 to be paid by Bay State Gas Company in substantially equal monthly
installments, and you will be reimbursed for expenses incurred on our behalf.
This compensation will be in lieu of payments usually received by directors of
Bay State Gas Company. You will perform these services as an independent
contractor and not as an employee of NiSource Inc. or any of its subsidiaries.
You will be responsible for all taxes due as a result of receipt of compensation
under this agreement.
This agreement may be terminated early by you at any time and by NiSource on 30
days notice in the event of your death or disability or if such termination is
determined to be in the best interests of NiSource by a vote of its Board of
Directors.
Please signify your agreement by signing and returning a copy of this letter to
me.
Sincerely,
/s/ Gary L. Neale
Gary L. Neale
Chairman of the Board, President
and Chief Executive Officer
AGREED:
/s/ Roger A. Young
Roger A. Young
Exhibit 10.2
CONSULTING AGREEMENT
This Consulting Agreement ("Agreement") is entered into this 9th day of
April, 1999 among NIPSCO Industries, Inc. ("NI"), an Indiana corporation,
Primary Energy, Inc. ("Company"), an Indiana corporation and a wholly-owned
subsidiary of NI, and Joseph L. Turner, Jr. ("Consultant").
WHEREAS, NI and Company wish to enter into a consulting relationship with
Consultant; and
WHEREAS, Consultant desires to enter into a consulting relationship
with NI and Company upon the terms and conditions hereinafter contained;
NOW, THEREFORE, in consideration of the covenants and agreements herein
set forth, and of the mutual benefits accruing to NI, Company and Consultant
from the consulting relationship to be established among the parties by the
terms of this Agreement, NI, Company and Consultant agree as follows:
1. Consulting Relationship.
Company hereby retains Consultant, and Consultant hereby agrees to be
retained by Company, as an independent consultant, and not as an employee.
2. Term.
The Term of this Agreement shall begin on November 21, 2001 and shall
continue until November 20, 2003. In no event shall this Agreement be renewed or
extend beyond November 20, 2003 without the express written consent of the
parties hereto. Notwithstanding the preceding two sentences:
(a) Mutual Agreement. This Agreement may be terminated at
any time by mutual agreement of the parties hereto.
(b) Breach or Injurious Conduct. NI or Company may terminate
this Agreement at any time without notice if (i) Consultant materially
breaches any provision of this Agreement or (ii) Consultant engages in
conduct which, in the judgment of the Chief Executive Officer and the
Vice President, Human Resources of NI, is deemed to be injurious to NI
or Company.
(c) Death or Inability to Perform due to Injury or Illness.
This Agreement shall terminate as of the date of Consultant's death, or
Consultant's Inability to Perform Due to Injury or Illness. Inability
to Perform Due to Injury or Illness shall be defined as Consultant's
absence from work due to injury or illness for 15 days during any 12
month period in the Term.
(d) Failure to Meet Performance Standard. This Agreement shall
terminate as of December 31 of any calendar year ending in the Term in
which Company's Revenue does not exceed Company's Revenue for the prior
calendar year by at least two and one-half percent (2.5%). Revenue
shall mean pre-tax operating income of Company for the applicable
calendar year as defined in Company's Incentive Plan existing on the
date hereof.
(e) Relinquishment of Duties. This Agreement may, by express
written agreement of the parties hereto, be terminated upon the
relinquishment of all of Consultant's duties hereunder to Consultant's
successor identified pursuant to subsection 3(d).
(f) Change in Control. This Agreement shall terminate upon the
effective date of a Change in Control as defined in Section 6.
3. Consulting Services.
Consultant agrees that during the Term of this Agreement:
(a) He will devote his best efforts to his position as an
independent consultant for Company and will perform such
duties and execute the policies of Company as determined by
the Chief Executive Officer and the Vice President, Human
Resources of NI; provided that said duties and policies will
not be inconsistent with the nature of the duties performed by
Consultant during his active service with Company as an
officer and employee thereof immediately prior to the
commencement of the Term;
(b) Consultant shall exercise a reasonable degree of skill and
care in performing the services referred to in paragraph (a)
above;
(c) Consultant shall be available to render services to Company
under this Agreement for a minimum of 223 business days during
any 12-month period commencing on the date of this Agreement
or any anniversary thereof. Consultant shall not be obligated
to render in excess of 223 days of service during any such
12-month period, nor shall Consultant be obligated to render
services on any holiday recognized by Company. Consultant
shall be entitled to elect 25 business days during any such
12-month period for which he shall not be obligated to render
any services under this Agreement; and
(d) Consultant shall retain the title of President of Company
until such time as he identifies a successor to act as
President of Company. At such time Consultant shall relinquish
the title of President of Company and shall retain such title
as is mutually agreed upon among Consultant, NI and Company.
4. Compensation.
(a) On November 21, 2001, Consultant shall receive a start bonus,
payable in cash, in the amount of $30,000, from Company.
(b) On November 21, 2001, Consultant shall receive a grant of
restricted stock of NI, in similar amount and with similar
restrictions as the grant of NI restricted stock made to
Consultant during calendar year 2000 while he was an active
employee of Company.
(c) Company agrees to pay Consultant consulting fees for his
services performed under this Agreement at the rate of
$19,500.00 per month, increased by five percent (5%) effective
on each February 1 occurring during the Term of the Agreement;
provided that the Agreement is not otherwise terminated under
Section 2.
(d) Consultant shall be entitled to reimbursement for expenses
authorized in writing by Company and incurred by Consultant in
the performance of his duties under this Agreement.
(e) Consultant shall receive Short-Term Incentive Payments during
the Term of the Agreement payable in cash and stock, similar
to those earned by Consultant while he was an active employee
of Company during the last full calendar year immediately
preceding the commencement of the Term of the Agreement.
(f) Consultant shall receive Long-Term Incentive Payments during
the Term of the Agreement in the form of nonqualified stock
options ("NQOs") to purchase shares of common stock of NI,
payable on such terms and in such amounts as determined by the
Chief Executive Officer or the Vice President, Human Resources
of NI. In making such determination, the Chief Executive
Officer and the Vice President, Human Resources of NI shall
consider the size and features of NQOs granted to Consultant
during the last full calendar year immediately preceding the
commencement of the Term of the Agreement and the Consultant's
compensation relative to executives serving in similar
positions in the industry.
(g) The amount of Consultant's Short-Term and Long-Term Incentive
Payments shall be based on Consultant's progress in
identifying a successor as President of Company, and Company's
progress in developing projects outside the Northwest Indiana
region. The Chief Executive Officer and the Vice President,
Human Resources of NI, in their discretion, shall determine
whether such progress has been made in each area, and shall
base the terms and amounts of such Short-Term and Long-Term
Incentive Payments on such determination.
(h) Consultant shall not be entitled to participate in or receive
benefits under any NI or Company programs maintained for
employees, including, without limitation, life, medical and
disability benefits, pension, profit sharing, savings or other
retirement plans or other fringe benefits. However, Consultant
shall receive all vested benefits which he accrued prior to
his termination of active employment with Company immediately
prior to the commencement of the Term under all employee
benefit plans of NI and Company, pursuant to the terms of each
respective plan, and to participate in such plans as are
available to retired employees of NI and Company.
5. Other Conditions.
Company shall, at its expense, provide Consultant with appropriate and
sufficient space in order to allow Consultant to perform his duties hereunder.
Consultant shall have no authority over any employee or officer of Company,
except as may be necessary in the routine performance of his duties hereunder,
nor shall NI or Company be required in any manner to implement any plans or
suggestions Consultant may provide.
6. Change in Control.
A "Change in Control" shall be deemed to take place on the occurrence
of any of the following events:
(1) The acquisition by an entity, person or group (including all
Affiliates or Associates of such entity, person or group) of
beneficial ownership, as that term is defined in Rule 13d-3
under the Securities Exchange Act of 1934, of capital stock of
NI entitled to exercise more than 30% of the outstanding
voting power of all capital stock of NI entitled to vote in
elections of directors ("Voting Power");
(2) The effective time of (i) a merger or consolidation of NI with
one or more other corporations as a result of which the
holders of the outstanding Voting Power of NI immediately
prior to such merger or consolidation (other than the
surviving or resulting corporation or any Affiliate or
Associate thereof) hold less than 50% of the Voting Power of
the surviving or resulting corporation, or (ii) a transfer of
30% of the Voting Power, or a Substantial Portion of the
Property, of NI other than to an entity of which NI owns at
least 50% of the Voting Power. Substantial Portion of the
Property of NI shall mean 50% of the aggregate book value of
the assets of NI and its Affiliates and Associates as set
forth on the most recent balance sheet of NI, prepared on a
consolidated basis, by its regularly employed, independent,
certified public accountants;
(3) The election to the Board of Directors of NI of candidates who
were not recommended for election by the Board of Directors of
NI in office immediately prior to the election, if such
candidates constitute a majority of those elected in that
particular election; or
(4) The sale by NI of a majority of the capital stock of Company
to a third party in which NI holds less than 50% of the
Voting Power.
Notwithstanding the foregoing, a Change in Control shall not be deemed to take
place by virtue of any transaction in which Consultant is a participant in a
group effecting an acquisition of NI or Company and, after such acquisition,
Consultant holds an equity interest in the entity that has acquired NI or
Company.
In the event of a Change in Control, Consultant shall receive a lump
sum cash payment equal to the present value of an amount comprised of (i) all
consulting fees, as provided in Section 3 and (ii) fifty percent (50%) of the
Short-Term Incentive Payments, that would otherwise be payable under Section 3
during the remainder of the Term of the Agreement. No Long-Term Incentive
Payments shall be included in the determination of such lump sum cash payment
payable in the event of a Change in Control. In determining present value for
purposes of this Change in Control calculation, the Moody's Average Corporate
Bond Index Rate shall be used.
7. Title to Certain Tangible Property.
All tangible materials (whether original or duplicates) including, but
not in any way limited to, equipment purchase agreements, file or data base
materials in whatever form, books, manuals, sales literature, equipment price
lists, training materials, client record cards, client files, correspondence,
documents, contracts, orders, messages, memoranda, notes, agreements, invoices,
receipts, lists, software listings or printouts, specifications, models,
computer programs, and records of any kind in the possession or control of
Consultant which in any way relate or pertain to NI's business or Company's
business, including the business of the subsidiaries or affiliates of NI or
Company, whether furnished to Consultant by NI or Company or prepared, compiled
or acquired by Consultant during his consulting relationship with Company, shall
be the sole property of Company or NI. At any time upon request of Company or
NI, and in any event promptly upon termination of this Agreement, Consultant
shall deliver all such materials to Company or NI. NI and Company shall be under
no obligation to pay to Consultant any sums of money then due Consultant or
becoming due thereafter until Consultant has complied with the provisions of
this section.
8. Title to Certain Intangible Property.
Consultant shall immediately disclose and assign to Company all his
right, title and interest in any inventions, models, processes, patents,
copyrights and improvements thereon relating to services or processes or
products of NI and Company that he conceives or acquires during any consulting
relationship with NI or Company or that he may conceive or acquire during a
period of one year after termination of this Agreement.
9. Acknowledgment of Necessity of Special Covenants Contained in Sections 10,
11, and 12.
In the course of Consultant's consulting services hereunder, Consultant
will acquire valuable trade secrets, proprietary data and other confidential
information, with respect to Company's and NI's business. The parties hereto
agree that such trade secrets, proprietary data and other confidential
information include but are not limited to the following: the inventions,
models, processes, patents, copyrights, and improvements thereon described in
Section 8, NI's and Company's business and financial methods and practices,
pricing and selling techniques, file or data base materials, price lists,
software listings or printouts, computer programs, lists of NI's and Company's
customers, customer record cards, customer files, credit and financial data of
NI's and Company's suppliers and present and prospective customers, and
particular business requirements of NI's and Company's present and prospective
customers, as well as similar information relating to the subsidiaries and
affiliates of NI and Company. In addition, Consultant, on behalf of Company, may
develop a personal acquaintance with customers and prospective customers of NI
and Company, its subsidiaries and affiliates. As a consequence thereof, the
parties hereto acknowledge that Consultant will occupy a position of trust and
confidence with respect to NI's and Company's affairs, products and services.
In view of the foregoing and in consideration of the remuneration to be
paid to Consultant, Consultant acknowledges that it is reasonable and necessary
for the protection of the goodwill and business of NI and Company that
Consultant make the covenants contained in Sections 10, 11, and 12 regarding the
conduct of Consultant during and subsequent to Consultant's rendering of
services to Company, and that NI or Company will suffer irreparable injury if
Consultant engages in conduct prohibited thereby. Consultant represents that his
experience and abilities are such that observance of the aforementioned
covenants will not cause Consultant any undue hardship or unreasonably interfere
with Consultant's ability to earn a livelihood.
The covenants contained in Sections 10, 11, and 12 shall each be
construed as a separate agreement independent of any other provisions of this
Agreement, and the existence of any claim or cause of action of Consultant
against NI or Company, whether predicated on this Agreement or otherwise, shall
not constitute a defense to the enforcement by NI or Company of any of those
covenants.
10. Trade Secrets and Confidential Information.
Consultant, during the term of the Agreement or at any time thereafter,
will not, without the express written consent of NI or Company, directly or
indirectly communicate or divulge to, or use for his own benefit or for the
benefit of any other person, firm, association or corporation, any of NI's or
Company's trade secrets or trade secrets of either NI's or Company's
subsidiaries or affiliates, proprietary data or other confidential information
including, by way of illustration, the information described in Section 8, which
trade secrets, proprietary data and other confidential information were
communicated to or otherwise learned or acquired by Consultant in the course of
the consulting relationship covered by this Agreement, except that Consultant
may disclose such matters to the extent that disclosure is required (a) in the
course of the consulting relationship with Company or (b) by a court or other
governmental agency of competent jurisdiction. As long as such matters remain
trade secrets, proprietary data or other confidential information, Consultant
will not use such trade secrets, proprietary data or other confidential
information in any way or in any capacity other than as a consultant of Company
and to further the NI's or Company's interests.
11. NI and Company Customers.
For a period of two years following the termination of this Agreement
for any reason whatsoever (or if this period shall be unenforceable by law, then
for such period as shall be enforceable), Consultant will not contact (with a
view towards selling any product or service competitive with any product or
service sold or immediately proposed to be sold by NI, Company, or any
subsidiary or affiliate of NI or Company at the time of termination of this
Agreement) any person, firm, association or corporation (a) to which NI, Company
or any subsidiary or affiliate of NI or Company sold any product or service, (b)
which Consultant solicited, contacted or otherwise dealt with on behalf of NI or
Company or any subsidiary or affiliate of NI or Company, or (c) which Consultant
was otherwise aware was a customer of NI or Company or any subsidiary or
affiliate of NI or Company, during the twelve month period preceding the
termination of this Agreement. Consultant will not directly or indirectly make
any such contact, either for his own benefit or for the benefit of any other
person, firm, association, or corporation, and Consultant will not in any manner
assist any person, firm, association, or corporation to make any such contact.
12. Restrictive Covenants.
Consultant shall not, during the term of this Agreement and for two
years thereafter (or if this period shall be unenforceable by law, then for such
period as shall be enforceable), be associated, directly or indirectly, as
employee, proprietor, stockholder, partner, agent, representative, officer, or
otherwise, with the operation of any business that is competitive with any
business of NI or Company or their respective affiliates or subsidiaries
throughout the United States, except that Consultant's ownership (or that of his
spouse and children) of publicly traded securities of any such business
representing less than 1% of such securities outstanding shall not be considered
a violation of this section. For purposes of the preceding sentence, Consultant
shall be considered as the "stockholder" of any equity securities owned by his
spouse and all relatives and children residing in Consultant's principal
residence. Notwithstanding the foregoing, Consultant may participate in the
affairs of any governmental, educational or other charitable institution, may
engage in professional speaking and writing activities and may serve as a member
of the board of directors of publicly held corporations so long as the Chief
Executive Officer or Vice President, Human Resources of NI, in good faith, does
not determine that such activities unreasonably interfere with the business of
NI or Company or diminish Consultant's duties and obligations to NI or Company,
and Consultant shall be entitled to retain all fees, royalties and other
compensation derived form such activities in addition to the compensation and
other benefits otherwise payable to him.
13. Relief.
In the event of a breach or a threatened or intended breach of this
Agreement by any party hereto, the other parties shall be entitled, in addition
to remedies otherwise available to such parties at law or in equity, to the
following particular forms of relief:
(a) In the event Consultant breaches Section 10, 11, or 12, NI
and Company shall be entitled to injunctions, both preliminary and
permanent, enjoining such breach or threatened or intended breach, and
Consultant hereby consents to the issuance thereof forthwith in any
court of competent jurisdiction.
(b) In the event any party shall enforce any part of this
Agreement through legal proceedings, the other parties agree to pay to
such prevailing party any costs and attorney's fees reasonably incurred
by him or it in connection therewith.
The taking of any action by any party or the forbearance of any party
to take any action shall not constitute a waiver by such party of any of its
rights to remedies or relief under this Agreement or under law or equity.
14. The Complete Agreement.
This Agreement represents the complete Agreement among NI, Company and
Consultant concerning the subject matter hereof and supersedes all prior
agreements or understandings, written or oral. No attempted modification or
waiver of any of the provisions hereof shall be binding on any party unless in
writing and signed by Consultant, NI and Company. This Agreement may, by mutual
written agreement of the parties hereto, be modified upon a material change in
Consultant's duties hereunder or the relinquishment of a material portion of his
duties to a successor.
15. Notices.
Notices required under this Agreement shall be in writing and sent by
registered mail, return receipt requested, to the following addresses or to such
other address as the party being notified may have previously furnished to the
other party by written notice:
If to NI: NIPSCO Industries, Inc.
801 E. 86th Avenue
Merrillville, IN 46410
Attention: Vice President, Human Resources
If to Company: Primary Energy, Inc.
801 E. 86th Avenue
Merrillville, IN 46410
If to Consultant: Joseph L. Turner, Jr.
117 West Hickory Avenue
Hinsdale, Illinois 60521-3345
<PAGE>
16. Assignability.
This Agreement may not be assigned by any party without the prior
written consent of the other parties, except that no consent is necessary for NI
to assign this Agreement to a corporation succeeding to substantially all the
assets or business of NI whether by merger, consolidation, acquisition or
otherwise, or for Company to assign this Agreement to a corporation succeeding
to substantially all of the assets or business of Company whether by merger,
consolidation, acquisition or otherwise. This Agreement shall be binding upon
Consultant, his heirs and permitted assigns, NI, its successors and permitted
assigns, and Company, its successors and permitted assigns.
17. Severability.
Each of the sections contained in this Agreement shall be enforceable
independently of every other section in this Agreement, and the invalidity or
nonenforceability of any section shall not invalidate or render nonenforceable
any other section contained herein. If any section or provision in a section is
found invalid or unenforceable, it is the intent of the parties that a court of
competent jurisdiction shall reform the section or provisions to produce its
nearest enforceable economic equivalent.
18. Applicable Law.
It is the intention of the parties hereto that all questions with
respect to the construction and performance of this Agreement and the rights and
liabilities of the parties hereto shall be determined in accordance with the
laws of the State of Indiana. The parties hereto submit to the jurisdiction of
the courts of Indiana in respect of any matter or thing arising out of this
Agreement or pursuant thereto.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as
of the day and the year first above written.
NIPSCO Industries, Inc.
By: /s/ Gary L. Neale
Title: Chairman, President and
Chief Executive Officer
Primary Energy, Inc.
By: /s/ Mark D. Wyckoff
Title: Assistant Secretary
By: /s/ Joseph L. Turner, Jr.
Joseph L. Turner, Jr.,
Consultant
::ODMA\PCDOCS\CHI_DOCS2\268546\2 18Mar99 15:51:23
Exhibit 10.3
[GRAPHIC OMITTED]
Scotia Capital (USA) Inc.
One Liberty Plaza, 165 Broadway, 26th Floor, New York, New York 10006
November 9, 1999
NiSource Inc.
5265 Hohman Avenue
Hammond, Indiana 46320-1775
Attention: Mr. Stephen P. Adik
Senior Executive Vice-President
Chief Financial Officer & Treasurer
Dear Sirs:
Re: Equity Forward Purchase Transaction
The purpose of this facsimile is to set forth the amended and restated
terms and conditions of the Transaction entered into between Scotia Capital
(USA) Inc. (formerly Scotia Capital Markets (USA) Inc.) ("Party A") and NiSource
Inc. ("Party B") on the Trade Date specified below (the "Transaction"). This
facsimile constitutes a "Confirmation" as referred to in the ISDA Master
Agreement specified below and amends, restates and replaces the Confirmation,
dated May 21, 1999, entered into between Party A and Party B.
This Confirmation is subject to and incorporates the definitions
contained in the 1991 ISDA Definitions, as supplemented by the 1998 Supplement
(the "1991 ISDA Definitions"), and the 1996 ISDA Equity Derivatives Definitions
(the "Equity Definitions") (each as published by the International Swaps and
Derivatives Association, Inc. ("ISDA")) (collectively, the "ISDA Definitions").
In the event of any inconsistency between the ISDA Definitions and this
Confirmation, this Confirmation will govern. This Confirmation supplements,
forms part of, and is subject to, the ISDA Master Agreement, dated May May 21,
1999, as amended and supplemented from time to time (the "ISDA Agreement"),
between Party A and Party B. All provisions contained in the ISDA Agreement
govern this Confirmation except as expressly modified below.
1. The terms of the particular Transaction to which this Confirmation relates
are as follows:
I. General Terms:
Trade Date: May 21, 1999
Effective Date: May 21, 1999
Termination Date: May 20, 2003, subject to postponement pursuant to the
Optional Extension provision set out below.
Extension Date: The earlier of November 21, 2003 and the date on which the
restriction cited by Party B in its extension notice, given pursuant to the
Optional Extension provision set out below, ceases to apply to Party B
Extension Term: The period commencing on but excluding the Termination Date
to but including the Extension Date
Optional Termination Date: Any Floating Rate
Reset Date selected by Party B in
accordance with the Notice provision
of the Settlement Terms set out
below.
Forward Purchase Seller: Party A
Forward Purchase Buyer: Party B
Exchange: New York Stock Exchange
Shares: NiSource Inc. common shares (Exchange designation "NI"), CUSIP No.
65473P105, quoted in USD on the Exchange.
Accumulation Period: The period commencing on and including the Effective
Date to and including the date by which Party A, or any U.S. subsidiary of The
Bank of Nova Scotia acquiring Shares in respect of this Transaction (the "Hedge
Subsidiary"), has, by means of one or more purchase transactions effected on the
Exchange through such period, accumulated such quantity of Shares as shall have
an Aggregate Notional approximately equal to USD 150,000,000, (the date on which
such accumulation is achieved being the "Accumulation Period End Date"). For
purposes hereof, "Aggregate Notional" means the product of the Initial Price and
the Number of Shares, as these terms are defined below.
Party A shall provide to Party B, on
or before the second Local Business
Day following the Accumulation
Period End Date, written notice
setting out the purchase
transactions effected by Party A or
the Hedge Subsidiary and Party A's
calculation of the Initial Price.
Initial Price: The price, in USD, per Share calculated as a weighted
average of the respective purchase prices per Share, including commissions which
shall not exceed USD 0.04 per Share, each in USD, of all Share purchase
transactions effected by Party A or the Hedge Subsidiary on the Exchange during
the Accumulation Period, which weighted average shall be determined by
multiplying each purchase price by the number of Shares to which such purchase
price is applicable, aggregating the products thereof and dividing such sum by
the total number of purchased Shares. The quotient thereof shall be the Initial
Price (per Share).
Disposition Period: In the context of Net Share
Settlement of this Transaction, the
period commencing on and including
the Optional Termination Date, the
Commencement Date or the Termination
Date (as applicable) to and
including the Final Settlement Date.
For purposes hereof, "Final
Settlement Date" means the earlier
of (1) the settlement date of the
last trade by which Party A, or the
Hedge Subsidiary, has effected, on
the Exchange, the sale of the
Relevant Share Number, (2) 90th
calendar day following the
commencement date of the Disposition
Period, or (3) the date on which the
Daily Settlement Amount (as defined
in the Net Share Settlement
provision) is an amount less than or
equal to zero and, if less than
zero, the absolute value thereof is
less than the closing price of the
Shares as reported by the Exchange
in respect of such Final Trading
Date (a "Zero Settlement Amount").
"Final Trading Date" means the day
on which any Share sale transaction
effected on the Exchange pursuant to
the Net Share Settlement provision
would settle on the Final Settlement
Date. "Relevant Share Number" means
the Number of Shares or, in the
context of any partial settlement to
be effected on any Optional
Termination Date, the number of
Shares specified or deemed specified
by Party B in its termination notice
given pursuant to the Notice
provision set out below.
Number of Shares: The aggregate number of
Shares yielded pursuant to Party A's
or the Hedge Subsidiary's purchase
program as referenced in
"Accumulation Period" above, less
the aggregate number of Shares
previously delivered by Party A or
the Hedge Subsidiary to Party B
pursuant to all partial settlements
(as contemplated by the Settlement
Terms) effected prior to the
relevant date of determination.
Business Days: London and New York
II. Floating Amounts payable by Party B
Floating Amount Payer: Party B
Notional Amount: same as Aggregate Notional
Payment Dates: The first Business Day
immediately following the
Accumulation Period End Date and,
thereafter, the first day of each of
the months of May, August, November
and February during the Term hereof
and, if applicable, during the
Extension Term, the Optional
Termination Date, the Termination
Date and, if applicable, the
Extension Date, subject to
adjustment in accordance with the
Modified Following Business Day
Convention.
Floating Rate Option: For all Calculation Periods following the
Accumulation Period, USD-LIBOR-BBA
Designated Maturity: 3-months
Reset Dates: In respect of each
Calculation Period following the
Accumulation Period, the first day
of each Calculation Period subject
to adjustment in accordance with the
Modified Following Business Day
Convention.
Spread: Plus 53.5 basis points (0.535%).
Day Count Fraction: Actual/360
Floating Rate for first Calculation Period following the Accumulation
Period (the "Initial Period"): USD-LIBOR-BBA quoted as of 11:00 a.m., London
time (the "Determination Time") on the day which is two London Banking Days
prior to the first day of the Initial Period (the "Determination Date") but for
a Designated Maturity equal to the actual number of days in such Initial Period
plus Spread. If there is no rate quoted on the Determination Date in respect of
such Designated Maturity and the Accumulation Period is greater than 30 days,
the Floating Rate for the Initial Period shall be the rate determined by linear
interpolation of USD-LIBOR-BBA quoted as of the Determination Time on such date
for a Designated Maturity of one-month and of USD-LIBOR-BBA quoted on such date
for a Designated Maturity of three-months, plus Spread. If there is no rate
quoted as of the Determination Time on the Determination Date in respect of a
Designated Maturity equal to the number of days in the Initial Period and the
Accumulation Period is less than 30 days, the Floating Rate for the Initial
Period shall be the rate determined by linear interpolation of the Overnight
Rate and of USD-LIBOR-BBA quoted as of the Determination Time on the
Determination Date for a Designated Maturity of three-months, plus Spread. For
purposes hereof, "Overnight Rate" means the average rate at which overnight
deposits in United States Dollars are offered by four major banks in the London
interbank market, as selected by Party A, as of the Determination Time on the
Determination Date.
Floating Amount in respect of Accumulation Period: Notwithstanding the
foregoing, the Floating Amount payable by Party B in respect of the Accumulation
Period shall be determined as follows:
For each day of the Accumulation
Period, the Calculation Agent shall
determine an amount (the
"Calculation Amount") in accordance
with the following formula:
[Calculation Amounti!1 + (Number of
Purchased Sharesi x WAPi)] x (1 +
Accumulation Period Floating Ratei /
360)
where, "Calculation Amounti!1" means
the Calculation Amount determined in
respect of the day preceding the
relevant day of determination,
"Number of Purchased Sharesi" means
the number of Shares purchased by
Party A or the Hedge Subsidiary on
the relevant date of determination;
"WAPi" means the weighted average of
the respective purchase prices per
Share, including commissions which
shall not exceed USD 0.04 per Share,
each in USD, of all Share purchase
transactions effected by Party A or
the Hedge Subsidiary on the relevant
date of determination, which
weighted average shall be determined
by multiplying each purchase price
by the number of Shares to which
such purchase price is applicable,
aggregating the products thereof and
dividing such sum by the total
number of purchased Shares; and
"Accumulation Period Floating Ratei"
means the Overnight Rate (as defined
above) in effect on the relevant
date of determination, as if such
date were a Reset Date, plus Spread.
The amount payable by Party B to
Party A in respect of the
Accumulation Period shall be the
Calculation Amount determined in
respect of the Accumulation Period
End Date minus an amount equal to
the product of the Initial Price
multiplied by the Number of Shares.
Such amount shall be paid by Party B
to Party A on the second Business
Day following the Accumulation
Period End Date.
III. Settlement Terms
Settlement: This Transaction may be settled, in whole or in part, on any
Optional Termination Date, and, in the event of a partial settlement, the
unsettled portion shall remain, during the Term hereof, a Transaction for
purposes of the ISDA Agreement Otherwise, this Transaction shall terminate, and
each party's obligations in respect thereof shall be settled, on the Termination
Date. Settlement shall be effected in accordance with the settlement mechanism
selected by Party B in its settlement notice given in accordance with the Notice
provision set out below. All partial settlements shall, however, be effected
only in integral multiples of 500,000 Shares.
Physical Settlement: Where Physical Settlement is applicable, on the
Optional Termination Date or Termination Date Party A shall deliver to Party B
Shares equal in number to the Number of Shares or, in the context of any partial
settlement to be effected on any Optional Termination Date, the number of Shares
specified or deemed specified by Party B in its settlement notice given pursuant
to the Notice provision set out below (such number being, in either case, the
"Relevant Share Number") and Party B shall pay to Party A an amount, in USD,
equal to the product of the Initial Price multiplied by the Relevant Share
Number (the "Settlement Price"). Any delivery made pursuant to this provision
shall be on a delivery versus payment basis and the due date of such delivery
shall be subject to adjustment in accordance with Section 6.2 of the Equity
Definitions in the event of the occurrence of a Settlement Disruption Event.
Net Share Settlement: Where Net Share
Settlement is elected or otherwise
applies, on the Optional Termination
Date, the Commencement Date or
Termination Date (as applicable),
Party A shall commence selling
Shares on the Exchange and shall,
for each day in the Disposition
Period, determine an amount in USD
(the "Daily Settlement Amount") in
accordance with the following
formulae:
SA0 = Initial Price x Relevant Share Number
SAi = SAi!1 x (1 + ONi!1 / 360) ! Number of Settled Sharesi x VWAPi
where "Number of Settled Sharesi"
means the number of Shares held by
Party A or the Hedge Subsidiary as a
hedge of this Transaction the sale
of which is settled by Party A or
the Hedge Subsidiary on the relevant
day of determination, "VWAPi" means
the modified volume-weighted average
per-Share price as determined by
means of the Bloomberg service on
the relevant day for trades in
Shares effected on the third
Exchange Business Day prior to such
day and adjusted by Party A to (i)
include commissions which shall not
exceed USD 0.04 per Share; (ii)
exclude the first trade in the
Shares effected on the Exchange on
the relevant day; and (iii) exclude
all trades in the Shares effected on
the Exchange within 60 minutes of
the close of trading on the Exchange
on such day, "SA0" means the Daily
Settlement Amount determined in
respect of the first day of the
relevant Disposition Period, "SAi"
means the Daily Settlement Amount
determined in respect of the
relevant day, "SAi!1" means the
Daily Settlement Amount determined
in respect of the immediately
preceding day, and "ONi!1" means the
Overnight Rate in effect as of the
day immediately preceding the
relevant day.
The Daily Settlement Amount
determined in respect of the Final
Settlement Date shall be the Final
Settlement Amount. For purposes of
giving effect to the foregoing,
"Number of Settled Sharesi" and
"VWAPi" shall be deemed to be zero
on any day in the Disposition Period
which is not an Exchange Business
Day.
If the Final Settlement Amount is a
Zero Settlement Amount, Party A or
the Hedge Subsidiary shall deliver
to Party B (1) the portion of the
Relevant Share Number remaining
after the Zero Settlement Amount is
reached (the "Unsold Shares"), and
(2) the absolute value of the Final
Settlement Amount, in USD, on or
before the Net Share Settlement
Date. If the Final Settlement Amount
is positive, Party A shall determine
a number of Shares in accordance
with the following formula:
Final Settlement Amount / Closing Price
where "Closing Price" is the closing
price of the Shares as reported by
the Exchange on the Final Settlement
Date. Party B shall deliver to Party
A Shares equal in number to the
number of Shares yielded by the
foregoing formula on or before the
Net Share Settlement Date. If within
ten Business Days after the Final
Settlement Date, Party A sells all
or a portion of the Shares (if any)
delivered to Party A by Party B
pursuant to this Net Share
Settlement provision (such Shares
being the "Settlement Shares") and
the net proceeds received by Party A
upon the sale of such Settlement
Shares is less than the Final
Settlement Amount (or if less than
all of such Settlement Shares are
resold, the applicable pro rata
portion of such Settlement Amount),
shall pay in USD or additional
Shares such difference (the
"Make-whole Amount") to Party A
within one Business Day following
the date on which Party A's notice
to Party B of the Make-whole Amount
becomes effective in accordance with
Section 12 of the ISDA Agreement. In
the event Party B elects to pay the
Make-whole Amount in additional
Shares, Party B shall deliver to
Party A the number of whole Shares
(the "Make-whole Shares") equal to
(i) the Make-whole Amount divided by
(ii) the closing price of the Shares
as reported by the Exchange on the
Exchange Business Day immediately
prior to delivery of such Shares. If
within ten Business Days after the
delivery of Make-whole Shares to
Party A, Party A sells all or any
portion of such Shares and the net
proceeds received by Party A are
less than the Make-whole Amount (or
if less than all the Make-whole
Shares are resold, the applicable
pro rata portion of the Make-whole
Amount), the provisions set forth
above with respect to payment in USD
or Shares based on the Settlement
Amount, including the make-whole
requirements, shall apply.
Net Share
Settlement Date: The second Clearance System
Business Day following the Final
Settlement Date, subject to
adjustment in accordance with
Section 6.2 of the Equity
Definitions in the event of the
occurrence of a Settlement
Disruption Event.
Notice: In the event Party B intends to effect a settlement in respect of
any Optional Termination Date, Party B shall provide Party A with prior written
notice of its intention to exercise its rights to so settle this Transaction and
such notice must become effective in accordance with Section 12 of the ISDA
Agreement on or before the 3rd day preceding the Optional Termination Date in
respect of which Party B intends to effect settlement. If Party B's notice
becomes effective after such 3rd day, Party B shall be deemed to have elected to
effect a settlement in respect of the next following Optional Termination Date;
provided, however, that no such notice may be given (i) on any day during the
Accumulation Period; or (ii) following the occurrence of an Event of Default,
Potential Event of Default or Termination Event (as such terms are defined in
the ISDA Agreement) or following the designation of an Early Termination Date in
respect of this Transaction in accordance with Section 6 of the ISDA Agreement.
Party B shall indicate in such notice whether settlement will be effected by way
of Physical Settlement or Net Share Settlement. In the context of any partial
settlement, Party B shall specify the number of Shares in respect of which
settlement will be effected. If such notice does not specify the manner of
settlement, Physical Settlement shall apply and, if such notice does not specify
the number of Shares in respect of which settlement will be effected, Party B
shall be deemed to have elected to effect settlement in respect of the full
Number of Shares then in effect. In the context of the Termination Date, if
Party B wishes to effect settlement by way of Net Share Settlement, Party B
shall so notify Party A and such notice must become effective in accordance with
Section 12 of the ISDA Agreement on or before the 3rd day prior to the
Termination Date, failing which Party B - shall be deemed to have elected to
utilize Physical Settlement.
Inability to Sell/Purchase Shares: If, in the context of Net Share
Settlement, any cash settlement election, or any other provision hereof which,
in order to give effect thereto, requires Party A to sell Shares (other than to
Party B), Party A is unable to effect a sale by any reasonably economic, viable
or practicable means, including a private transaction, of the requisite number
of Shares on or before the Final Trading Date for purposes of determining the
Final Settlement Amount for any reason including, without limitation, because
such Shares have a prospectus delivery requirement and Party B is unable to
provide Party A with a current prospectus, then, Party B shall be deemed to have
elected Physical Settlement with respect to the unsold portion of such requisite
number of Shares, and Party B shall, within one Business Day of the date it is
advised by Party A that a sale of all such Shares was not effected, repurchase
the unsold Shares for USD in an amount per Share that, when combined with all
amounts received by Party A for all effected sales of Shares, results in Party A
receiving an amount equal to the amount Party would have received had Physical
Settlement been elected. If, in the context of Physical Settlement or the
application of the Registration of Shares provision or any other provision of
this Confirmation which, in order to give effect thereto, requires delivery of
Shares to Party B by Party A, Party B is unable, due to the application of
applicable law, at the relevant time to take delivery of such Shares, a
Termination Event shall be deemed to have occurred for purposes of the ISDA
Agreement and in respect of which (i) Party B shall be the Affected Party, (ii)
this Transaction shall be the only Affected Transaction, (iii) and the payment
measure shall be Loss (as such terms are defined in the ISDA Agreement).
Good Delivery: Any party required to deliver Shares hereunder shall
transfer good title to such Shares, and such Shares shall be freely transferable
(together with any prospectus required by applicable law) and free and clear of
any liens, charges, claims and encumbrances. Delivery shall be effected by
book-entry transfer of the Shares to an account with The Depository Trust
Company (the "Clearance System") in the name of the recipient as is designated
by the recipient.
Dividends: An amount equal to each cash
dividend the record date of which
precedes the Termination Date, or,
if applicable, the Extension Date or
any further deferral thereof and
which is received by Party A or the
Hedge Subsidiary in respect of
Shares held by Party A or the Hedge
Subsidiary to hedge this Transaction
shall be paid to Party B on or
before the second Business Day
immediately following the date of
receipt of such cash dividend by
Party A or the Hedge Subsidiary.
IV Optional Extension
In the event that, due to operation of any state or federal securities
law then in effect in the United States of America and which is
applicable to Party B, as of the Termination Date, Party B believes, in
good faith and in reliance upon a written, reasoned legal opinion of
its external legal counsel, that it is restricted from purchasing
Shares from Party A in an amount equal to the Number of Shares, Party B
shall so notify Party A on or before 1:00 p.m. (New York time) on the
Termination Date and shall specify the basis of the prohibition. If
requested by Party A, Party B shall also provide to Party A a copy of
the legal opinion upon which Party B is relying within three Business
Days of the date on which Party A's request becomes effective in
accordance with Section 12 of the ISDA Agreement. In such event, the
Termination Date of this Transaction shall be the Extension Date and
settlement of each party's respective obligations (as provided for
herein) shall be deferred to such date.
In the event that as of the Extension Date, Party B believes, in good
faith and in reliance upon a written, reasoned legal opinion of its
external counsel (a copy of which shall be provided to Party A upon
Party A's request) that it remains restricted from purchasing the
requisite number of Shares it shall so notify Party A and Party A may,
at its option, grant a further postponement of the Termination Date to
a mutually agreed upon settlement date or elect to terminate this
Transaction. If Party A elects to terminate this Transaction, Party A
shall so notify Party B and Party B shall, on or before the first
Business Day following the date on which Party A's termination notice
becomes effective (the "Termination Election Date"), elect to effect
settlement either by way of cash settlement or Net Share Settlement
(failing which Party B shall be deemed to have elected cash
settlement).
Where Party A elects to terminate this Transaction and Party B has
elected cash settlement, on the first Exchange Business Day following
the Termination Election Date (the "Commencement Date"), Party A or the
Hedge Subsidiary shall commence selling the Shares comprising its, or
the Hedge Subsidiary's, hedge of this Transaction and shall determine
the Final Settlement Amount as defined in the Net Share Settlement
provision above except that the Final Trading Date shall be the earlier
of (1) the date on which Party A, or the Hedge Subsidiary, has effected
transactions on the Exchange by which it has completed the sale of the
Relevant Share Number, or (2) the 90th calendar day following the
Commencement Date. If the Final Settlement Amount determined in respect
of the Final Settlement Date is negative, Party A shall pay to Party B
the absolute value of such amount on the Final Settlement Date. If such
amount is positive, Party B shall pay to Party A such amount on the
first Business Day following the date on which Party A's notice to
Party B that such Final Settlement Amount is owing by Party B becomes
effective in accordance with Section 12 of the ISDA Agreement.
Where Party A elects to terminate and Party B has elected Net Share
Settlement, the terms of the Net Share Settlement provision set out
above shall apply; provided, however, that if (i) the Final Settlement
Amount is a Zero Settlement Amount, (ii) there remains Unsold Shares,
and (iii) Party B remains at such time, subject to the purchase
restrictions contemplated above, Party B shall be deemed to have
elected cash settlement in which case Party A shall continue selling
the Unsold Shares (if any) and the preceding paragraph of this Section
shall apply.
V Decline in Share Price
In the event that on any Exchange Business Day during the Term of this
Transaction (other than the Accumulation Period) the closing price per
Share as quoted by the Exchange on such day is USD 12.00 or less, Party
A may upon notice to Party B, given in accordance with Section 12 of
the ISDA Agreement, and provided an Event of Default or Termination
Event has not occurred with respect to Party A or is then continuing
(and which, in the context of a Termination Event, renders this
Transaction an Affected Transaction) and provided an Early Termination
Date has not been designated in respect of this Transaction, elect to
terminate this Transaction in its entirety. Party B shall, on or before
the first Business Day following the date on which Party A's
termination notice becomes effective, notify Party A of the manner in
which this Transaction shall be settled which, for purposes hereof, may
include cash-settlement as provided for in the Optional Extension
provision set out above (and, failing such notification, Party B shall
be deemed to have elected cash settlement). If Party B elects cash
settlement as provided for in such Optional Extension provision or Net
Share Settlement, for purposes of giving effect to such provisions, the
commencement of the Disposition Period shall be the first Exchange
Business Day following the date on which Party B's election notice
became effective (the "Settlement Election Date"). If Party B elects
Physical Settlement, settlement shall be effected on the third Business
Day following the Settlement Election Date in accordance with, and
subject to, the Physical Settlement provision set out above.
If, in the context of (i) a cash-settlement election, the Final
Settlement Date (as provided for in the Optional Extension provision),
(ii) in the context of a Physical Settlement election, the Settlement
Election Date, or (iii) in the context of a Net Share Settlement
election, the Net Share Settlement Date (each such date being a
"Trigger Date"), is not an Optional Termination Date, then, in addition
to any other amount then payable by Party B, Party B shall also pay to
Party A, on such date, the Break Funding Amount. For purposes, hereof,
"Break Funding Amount" means an amount equal to the present value
(discounted at the Discount Rate defined below and determined by the
Calculation Agent in a commercially reasonable manner) of the product
of (1) the difference between the Floating Rate Option applicable to
the then current Calculation Period and the Discount Rate, (2) the
Number of Shares, (3) the Initial Price, and (4) a fraction the
numerator of which is the number of days in the period commencing on
and including the relevant Trigger Date, to but excluding the next
Optional Termination Date and the denominator of which is 360.
"Discount Rate" means the appropriate interpolated USD-LIBOR-BBA rate
determined by the Calculation Agent as of the Final Settlement Date.
VI Adjustments
For purposes of Article 9 of the Equity Definitions, any reference to the term
"Share Swap Transaction" shall be deemed to mean "Forward Purchase Transaction";
provided, however, that "Potential Adjustment Event" shall exclude the
declaration or payment of any cash dividends in respect of the Shares.
Method of Adjustment: Calculation Agent Adjustment
Calculation Agent: Party A
VII. Extraordinary Events
Consequences of Merger Events:
(a) Share-for-Share: Alternative Obligation
(b) Share-for-Other: Cancellation and Payment
(c) Share-for-Combined: Alternative Obligation
Nationalization: Cancellation and Payment
VIII. Regulatory Event
If during the Term of this Transaction, Party B effects any action, including
any action with respect to its capital structure, the result of which is that
Party A, or the Hedge Subsidiary, then owns more of any class of outstanding
voting shares of Party B than is permitted by the Bank Holding Company Act of
1956, as amended, or other federal legislation (the "Regulatory Limit"), then,
Party B shall be deemed to have elected to partially settle this Transaction and
the extent to which the Number of Shares exceeds the Regulatory Limit shall be
the Relevant Share Number for purposes of the Settlement Terms set out above.
For purposes of giving effect to the foregoing, the date on which such partial
settlement shall be effected shall be the first Business Day following the date
on which Party A's notice to Party B that Party A is then in breach of the
Regulatory Limit becomes effective in accordance with Section 12 of the ISDA
Agreement. If on such date Party B believes in good faith that it is restricted
from purchasing Shares from Party A or the Hedge Subsidiary, Party B shall so
notify Party A and, in such event, Party A shall be deemed to have elected to
effect such partial settlement by way of cash-settlement as provided for in the
Optional Extension provision set out above and, for purposes of giving effect
thereto, the reference therein to "Number of Shares" shall be deemed a reference
to Relevant Share Number and "Commencement Date" shall be deemed to the first
Exchange Business Day following the date on which Party A's notice to Party B of
Party A's breach of the Regulatory Limit becomes effective as aforesaid. If the
Final Settlement Date (as provided for in the Optional Extension provision) is
not an Optional Termination Date, then, in addition to any other amount then
payable by Party B, Party B shall also pay to Party A, on such date, the Break
Funding Amount. For purposes, hereof, "Break Funding Amount" means an amount
equal to the present value (discounted at the Discount Rate defined below and
determined by the Calculation Agent in a commercially reasonable manner) of the
product of (1) the difference between the Floating Rate Option applicable to the
then current Calculation Period and the Discount Rate, (2) the Relevant Share
Number, (3) the Initial Price, and (4) a fraction the numerator of which is the
number of days in the period commencing on and including the Final Settlement
Date to but excluding the next Optional Termination Date and the denominator of
which is 360. "Discount Rate" means the appropriate interpolated USD-LIBOR-BBA
rate determined by the Calculation Agent as of the Final Settlement Date.
IX. Registration of Shares.
Notwithstanding any other provision hereof (including, without limitation, any
election of Net Share Settlement by Party B under "Notice" above, but excluding
any election by Party B of Net Share Settlement or cash settlement under
"Optional Extension" or "Decline in Share Price" above), Physical Settlement
shall apply unless the following conditions have been satisfied: (i) on the
Optional Termination Date or Termination Date, as the case may be, a
registration statement (a "Registration Statement") naming as selling
shareholders Party A and the Hedge Subsidiary and covering the public resale of
all Shares held by Party A or the Hedge Subsidiary to hedge this Transaction and
all Shares deliverable by Party B to Party A pursuant to the Net Share
Settlement provisions hereof (collectively, the "Registrable Shares") shall have
been filed with, and declared effective by, the Securities and Exchange
Commission under the Securities Act of 1933 (the "Securities Act"), and no stop
order shall be in effect with respect to such Registration Statement; (ii) a
printed prospectus relating to the Registrable Shares (including any prospectus
supplement thereto and amendments thereof, a "Prospectus") shall have been
delivered to Party A and the Hedge Subsidiary in such quantities as Party A
shall have requested no later than the Optional Termination Date or Termination
Date; (iii) the Registration Statement and the Prospectus shall be in form and
substance reasonably satisfactory to Party A; (iv) no later than the Exchange
Business Day before the Optional Termination Date or Termination Date, Party A
and Party B shall have entered into an agreement (a "Transfer Agreement") in
connection with the public resale of the Registrable Shares by Party A and the
Hedge Subsidiary substantially similar to underwriting agreements customary for
underwritten offerings of equity securities, in form and substance satisfactory
to Party A, providing for (without limitation): indemnification of, and
continuation in connection with the liability of, Party A and the Hedge
Subsidiary, the delivery of customary opinions of counsel and accountants
"comfort letters", the continuous effectiveness of the Registration Statement
until the fortieth day after the Optional Termination Date or Termination Date,
or if earlier, such time as all Registrable Shares have been resold pursuant
thereto and all expenses in connection with such resale, including all
registration costs and all fees and expenses of counsel for each of Party A and
Party B, have been paid by Party B; (v) Party A and the Hedge Subsidiary shall
have been afforded a reasonable opportunity to conduct a due diligence
investigation with respect to Party B customary in scope for underwritten
offerings of equity securities, and acceptance of the results of such
investigation by Party A and the Hedge Subsidiary cannot be unreasonably
withheld; (vi) all conditions to the obligations of each party under the
Transfer Agreement shall have been satisfied or waived no later than the
Optional Termination Date or Termination Date, and (vii) the representations and
warranties of Party B set forth herein and in the Transfer Agreement shall be
true and correct on the date of delivery of Registrable Shares to purchasers of
such Shares as though made at such time, and Party B shall have performed all
its obligations set forth herein and in such Transfer Agreement to be performed
by such time.
If, in the context of the Optional Extension provision or Decline in Share Price
provision, Party B has elected to cash-settle the Transaction or in the event
Party B has elected Net Share Settlement and Party B is required to deliver
Shares to Party A and any condition specified in items (i) - (vii) of the
previous paragraph shall not have been satisfied in the manner and at the times
specified therein, Party A may determine to (a) have some or all Registrable
Shares sold in one or more transactions exempt from the registration
requirements of the Securities Act, (b) extend this Transaction in order to give
Party B more time to satisfy such conditions, or (c) elect Physical Settlement.
If Party A chooses the action set forth in clause (a) above, Party B shall pay
all costs of such sales by Party A, including, without limitation, any
applicable sales or purchase taxes, transfer taxes and commissions. If Party A
chooses the action set forth in clause (b) above, the Calculation Agent will in
its reasonable discretion adjust the terms hereof to take into account any
additional costs to Party A and the Hedge Subsidiary of such extension. For the
purposes of this paragraph, references in items (i) - (vii) of the previous
paragraph to "the Optional Termination Date or Termination Date" shall be deemed
to be references to the Termination Election Date or the Settlement Election
Date, as the case may be.
2. Fee
Party B will, on or before November 12, 1999, pay to Party A a fee in the amount
of USD 175,000 and the payment thereof by Party B shall be a condition precedent
to Party A's obligations hereunder.
3. Additional Representations.
Each party will be deemed to represent to the other on the date of this
Confirmation that, with respect to this Transaction (1) It is entering into this
Transaction for its own account and not with a view to transfer, resale or
distribution, (2) it is an "accredited investor" within the meaning of Rule
501(a) of Regulation D under the Securities Act and has such knowledge and
experience in financial and business matters that it is capable of evaluating
the merits and risks of this Transaction, and (3) it understands and
acknowledges that this Transaction may involve the purchase or sale of a
"security" as defined in the Securities Act and the securities laws of certain
states, and that any such security has not been registered under the Securities
Act or the securities laws of any state and, therefore, may not be sold,
pledged, hypothecated, transferred or otherwise disposed of unless such security
is registered under the Securities Act and any applicable state securities law,
or an exemption from registration is available.
4. Additional Party B Representation
Party B represents to Party A that it is entering into this Transaction
in connection with its Share repurchase program which has been approved by its
board of directors and publicly announced, solely for the purposes stated in
such board resolution and public disclosure.
5. Additional Agreement
Each party agrees that it will comply, in connection with this
Transaction and all related or contemporaneous sales and purchases of Shares,
with the applicable provisions of the Securities Act, the Securities Exchange
Act of 1934 (the "Exchange Act"), and the rules and regulations thereunder,
including, without limitation, Rules 10b-5 under the Exchange Act, provided that
each party shall be entitled to rely conclusively on any information
communicated by the other party concerning such other party's market activities.
Party A represents to Party B and agrees that, in effecting the purchase
transactions referred to opposite "Accumulation Period", above, Party A shall
make bids for and purchases of the Shares only in accordance with the price,
volume, timing, and method of bidding and purchasing constraints set forth in
Rule 10b-18 under the Exchange Act, as if Party A were the issuer of the Shares
and wished to avail itself of the protections afforded by that rule.
6. Miscellaneous
Transfer: Party A may without the consent of Party B assign and delegate
its rights and obligations hereunder, in whole or in part, to any U.S.
subsidiary of The Bank of Nova Scotia effective upon delivery to Party B of a
guarantee by The Bank of Nova Scotia; provided that, at the time of such
proposed assignment (i) no Termination Event, Event of Default or Potential
Event of Default as defined in this Agreement shall have occurred and be
continuing with respect to Party A, (ii) no Early Termination Date shall have
been designated or shall have occurred, (iii) Party B will not, as a result of
such transfer, be required to pay to the transferee on the next succeeding
Scheduled Payment Date (as defined in the ISDA Agreement) an amount in respect
of an Indemnifiable Tax under Section 2(d)(i)(4) of the ISDA Agreement (except
in respect of interest under Section 2(e)) greater than the amount in respect of
which Party B would have been required to pay to Party A in the absence of such
assignment, (iv) the assignee will not, as a result of such transfer, be
required to withhold or deduct on account of a Tax under Section 2(d)(i) of the
ISDA Agreement (except in respect of interest under 2(e)) on the next succeeding
Scheduled Payment Date an amount in excess of that which Party A would have been
required to so withhold or deduct on the next succeeding Payment Date in the
absence of such assignment unless the assignee would be required to make
additional payment pursuant to Section 2(d)(4) of the ISDA Agreement
corresponding to such excess, and (v) an Event of Default or Termination Event
will not occur as a result of such assignment. With respect to the results
described in Clauses (iii) and (iv) above, Party A will cause the assignee to
make, and Party B will make, such reasonable Payer Tax Representations and Payee
Tax Representations as may be reasonably requested by the other party in order
to permit such other party to determine that such result will not occur after
such transfer. Party A will cause any assignee to deliver opinions of counsel in
the form and substance reasonably satisfactory to Party B and to cause such
assignee to enter into any legally required assumption or other similar
agreement, in each case at the expense of Party A. Any assignment permitted by
the foregoing sentences will not constitute an event or condition described in
Sections 5(a)(viii) and 5(b)(iv) of the ISDA Agreement.
Wire Instructions: Party A: The Bank of Nova Scotia, New York Agency One
Liberty Plaza, 165 Broadway, 26th Floor New York, New York SWIFT Code: NOSCUS33
ABA# 0260-02532 Account No.: 6027-36 Attention: IBD Derivative Products
Party B:
(please provide)
7. Offices
(a) The Office of Party A for this Transaction is New York; and
(b) The Office of Party B for this Transaction is Hammond,
Indiana.
<PAGE>
Please confirm that the foregoing correctly sets forth the terms of
our agreement by executing the copy of this Confirmation enclosed for that
purpose and returning it to us or by sending to us a letter or facsimile
substantially similar to this letter, which letter or facsimile sets forth the
material terms of the Transaction to which this Confirmation relates and
indicates agreement to those terms.
Yours truly,
SCOTIA CAPITAL (USA) INC.
By:____________________________
<PAGE>
Name:
Title:
Confirmed as of the date first above written:
NiSOURCE INC.
By:__________________________________
Name: Stephen P. Adik
Title: Senior Executive Vice President,
Chief Financial Officer and
Treasurer
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 and Form S-3 Registration Statement No. 333-76909.
/s/ Arthur Andersen LLP
Chicago, Illinois
November 10, 1999
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from the
financial statements of NiSource Inc. for three months ended September 30, 1999,
and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JUL-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 4,770,110
<OTHER-PROPERTY-AND-INVEST> 466,191
<TOTAL-CURRENT-ASSETS> 678,276
<TOTAL-DEFERRED-CHARGES> 247,216
<OTHER-ASSETS> 345,468
<TOTAL-ASSETS> 6,507,261
<COMMON> 415,711
<CAPITAL-SURPLUS-PAID-IN> 172,229
<RETAINED-EARNINGS> 776,899
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,364,839
54,585
81,114
<LONG-TERM-DEBT-NET> 484,100
<SHORT-TERM-NOTES> 314,075
<LONG-TERM-NOTES-PAYABLE> 1,358,290
<COMMERCIAL-PAPER-OBLIGATIONS> 261,400
<LONG-TERM-DEBT-CURRENT-PORT> 163,283
1,828
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<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,423,747
<TOT-CAPITALIZATION-AND-LIAB> 6,507,261
<GROSS-OPERATING-REVENUE> 687,992
<INCOME-TAX-EXPENSE> 13,781
<OTHER-OPERATING-EXPENSES> 586,506
<TOTAL-OPERATING-EXPENSES> 586,506
<OPERATING-INCOME-LOSS> 101,486
<OTHER-INCOME-NET> (9,888)
<INCOME-BEFORE-INTEREST-EXPEN> 91,598
<TOTAL-INTEREST-EXPENSE> (49,862)
<NET-INCOME> 27,955
0
<EARNINGS-AVAILABLE-FOR-COMM> 27,955
<COMMON-STOCK-DIVIDENDS> 28,330
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 48,763
<EPS-BASIC> 0.22
<EPS-DILUTED> 0.22
</TABLE>
