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.
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
Consolidated Balance Sheets
September 30, December 31,
Assets 1999 1998
========== ==========
(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.
Consolidated Balance Sheets
September 30, December 31,
Capitalization and Liabilities 1999 1998
========== ==========
(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.
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
========== ========== ========== ==========
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.
Consolidated Statements of Income
(In thousands, except for per share amounts)
Twelve Months
Ended September 30,
-----------------------
1999 1998
========== ==========
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.
Consolidated Statement Of Common Shareholders' Equity
Additional
(In thousands) Common Treasury Paid-in Retained
Three Months Ended Shares Shares Capital Earnings Other
======================== ========== ========== ========== ========== ==========
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)
========== ========== ========== ========== ==========
Accumulated Shares
Other ------------------------
Three Months Ended Comprehensive Comprehensive Common Treasury
(continued) Income Total Income Shares Shares
======================== ========== ========== ========== ========== ==========
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
======================== ========== ========== ========== ========== ==========
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
======================== ========== ========== ========== ========== ==========
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.
Consolidated Statements of Cash Flows
(In thousands)
Three Months Nine Months
Ended September 30, Ended September 30,
----------------------- -----------------------
1999 1998 1999 1998
========== ========== ========== ==========
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.
Consolidated Statements of Cash Flows
(In thousands)
Twelve Months
Ended September 30,
-----------------------
1999 1998
========== ==========
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.
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:
Electric:
- ---------
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
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:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
---------- ---------- ---------- ---------- ---------- ----------
1999 1998 1999 1998 1999 1998
========== ========== ========== ========== ========== ==========
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%
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:
October 1, January 1, July 1, October 1, January 1, July 1,
(In millions) 1997 1998 1998 1998 1999 1999
---------- ---------- ---------- ---------- ---------- ----------
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)
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:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
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
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:
September 30, December 31,
(In thousands) 1999 1998
========== ==========
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
========== ==========
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:
September 30, September 30,
1999 1998
---------- ----------
Three months ended 8.73% 8.95%
Nine months ended 8.72% 8.74%
Twelve months ended 8.79% 8.89%
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:
(In thousands) Assets acquired:
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
==========
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:
September 30, December 31,
1999 1998
========== ==========
(In thousands)
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
========== ==========
Federal and state income taxes as set forth in the consolidated statements
of income were comprised of the following:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
(In thousands)
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
======= ======= ======= ======= ======= =======
A reconciliation of total income tax expense to an amount computed by
applying the statutory federal income tax rate to pretax income is as follows:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
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
======= ======= ======= ======= ======= =======
(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:
1998 1997
======== ========
(In thousands)
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
======== ========
The change in the fair value of the plans' assets for the years 1998 and
1997 was as follows:
(In thousands) 1998 1997
======== ========
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
======== ========
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:
1998 1997
======== ========
(In thousands)
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
======== ========
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:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
------------ ------------ ------------ ------------ ------------ ------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
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
======= ======= ======= ======= ======= =======
Assumptions used in the valuation and determination of 1999 and 1998
pension expense were as follows:
1999 1998
-------- --------
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%
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:
1998 1997
======= =======
(In thousands)
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
======== ========
The change in the fair value of the plan assets for the years 1998 and 1997
was as follows:
1998 1997
======= =======
(In thousands)
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
======= =======
Following is the funded status for postretirement benefits as of December
31, 1998 and 1997:
1998 1997
======= =======
(In thousands)
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)
======== ========
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:
Three Months Nine Months Twelve Months
Ended September 30, Ended September 30, Ended September 30,
--------------------- --------------------- ---------------------
(In thousands) 1999 1998 1999 1998 1999 1998
======= ======= ======= ======= ======= =======
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
======= ======= ======= ======= ======= =======
Assumptions used in the determination of 1999 and 1998 net periodic
postretirement benefit costs were as follows:
1999 1998
===== =====
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%
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:
Redemption
Price at
September 30, December 31, September 30,
1999 1998 1999
=========== =========== ===========
(Dollars in thousands)
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
=========== ===========
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:
September 30, December 31,
1999 1998
=========== ===========
(Dollars in thousands)
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
=========== ===========
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:
Sinking Fund or
Series Redemption Price Per Share Mandatory Redemption Provisions
=========== ========================== ======================================
Cumulative preferred stock -$100 par value -
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.
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:
Twelve Months Ended September 30,
=================================
(In thousands)
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
========
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:
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)
- ------------------------------------------------------------------------------------------------------------------------------------
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
========== ========== ========== ========== ========== ==========
(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:
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)
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
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:
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Three Months Ended September 30, 1999 Price 1998 Price
================================ ======== ======= ======== =======
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
========= ========
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Nine Months Ended September 30, 1999 Price 1998 Price
============================ ======== ======= ======== =======
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
======== ========
NONQUALIFIED STOCK OPTIONS
--------------------------------------------------
Weighted Weighted
Average Average
Option Option
Twelve Months Ended September 30, 1999 Price 1998 Price
============================ ======== ======= ======== =======
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
======== ========
The following table summarizes information about non-qualified stock
options at September 30, 1999:
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
============= =============== =============== =============== ===============
$ 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
=============== =============
(16) Long-Term Debt:
September 30, December 31,
(Dollars in thousands) 1999 1998
========== ==========
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
=========== ===========
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:
Twelve Months Ended September 30,
=================================
(In thousands)
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
===========
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:
September 30, December 31,
1999 1998
======== ========
(In thousands)
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
======== ========
(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:
September 30, December 31,
1999 1998
======== ========
(In thousands)
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
======== ========
(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:
Twelve Months Ended September 30,
=================================
(In thousands)
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
=========
The consolidated financial statements include rental expense for all
operating leases as follows:
September 30, September 30,
1999 1998
======== ========
(In thousands)
Three months ended $12,332 $ 6,167
Nine months ended $36,530 $17,699
Twelve months ended $42,531 $19,886
(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:
September 30, 1999 December 31, 1998
Carrying/ Estimated Carrying/ Estimated
Notional Fair Notional Fair
Amount Value Amount Value
------------ ------------ ------------ ------------
(In thousands)
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
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."
Other
(In thousands) Gas Products
For the three months ended September 30, 1999 Gas Electric Water Marketing & Services Adjustments Total
- -----------------------------------------------------------------------------------------------------------------------------
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
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:
Three Months Nine Months Twelve Months
Ended September 30, Ended Septembe 30, Ended September 30,
------------------------ ------------------------ ------------------------
1999 1998 1999 1998 1999 1998
(In thousands) ======== ======== ======== ======== ======== ========
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
======== ======== ======== ======== ======== ========
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:
Variations from Prior Periods
-------------------------------------
September 30, 1999 Compared to September 30, 1998
------------------------------------------------------
Three Nine Twelve
(In thousands) Months Months Months
========== ========== ==========
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
========== ========== ==========
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."
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