UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
or
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address and Telephone Number Identification No.
1-11377 CINERGY CORP. 31-1385023
(A Delaware Corporation)
139 East Fourth Street
Cincinnati, Ohio 45202
(513) 421-9500
1-1232 THE CINCINNATI GAS & ELECTRIC COMPANY 31-0240030
(An Ohio Corporation)
139 East Fourth Street
Cincinnati, Ohio 45202
(513) 421-9500
1-3543 PSI ENERGY, INC. 35-0594457
(An Indiana Corporation)
1000 East Main Street
Plainfield, Indiana 46168
(513) 421-9500
2-7793 THE UNION LIGHT, HEAT AND POWER COMPANY 31-0473080
(A Kentucky Corporation)
139 East Fourth Street
Cincinnati, Ohio 45202
(513) 421-9500
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes X No __
This combined Form 10-Q is separately filed by Cinergy Corp., The Cincinnati Gas & Electric Company, PSI Energy, Inc., and The Union Light, Heat and Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.
The Union Light, Heat and Power Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing its company specific information with the reduced disclosure format specified in General Instruction H(2) of Form 10-Q.
As of July 31, 2002, shares of common stock outstanding for each registrant were as listed:
Registrant Description Shares
---------- ----------- ------
Cinergy Corp. Par value $.01 per share 167,660,585
The Cincinnati Gas & Electric Company Par value $8.50 per share 89,663,086
PSI Energy, Inc. Without par value, stated value $.01 per
share 53,913,701
The Union Light, Heat and Power Company Par value $15.00 per share 585,333
TABLE OF CONTENTS
Item
Number
------
PART I FINANCIAL INFORMATION
1 Financial Statements
Cinergy Corp.
Consolidated Statements of Income
Consolidated Balance Sheets
Consolidated Statements of Changes in Common Stock Equity
Consolidated Statements of Cash Flows
The Cincinnati Gas & Electric Company
Consolidated Statements of Income and Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
PSI Energy, Inc.
Consolidated Statements of Income and Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
The Union Light, Heat and Power Company
Statements of Income
Balance Sheets
Statements of Cash Flows
Notes to Financial Statements
Cautionary Statements Regarding Forward-Looking Information
2 Management's Discussion and Analysis of Financial Condition and
Results of Operations
Introduction
Organization
Liquidity and Capital Resources
2002 Quarterly Results of Operations - Historical
2002 Year to Date Results of Operations - Historical
Results of Operations - Future
3 Quantitative and Qualitative Disclosures About Market Risk
PART II OTHER INFORMATION
1 Legal Proceedings
6 Exhibits and Reports on Form 8-K
Signatures
CINERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
Quarter Ended Year to Date
June 30 June 30
2002 2001 2002 2001
---- ---- ---- ----
(dollars in thousands, except per share amounts)
(unaudited)
Operating Revenues
Electric $1,340,370 $2,405,463 $2,623,794 $4,298,921
Gas 1,116,953 1,236,779 2,020,214 3,050,601
Other 22,700 22,096 39,778 40,118
------ ------ ------ ------
Total Operating Revenues 2,480,023 3,664,338 4,683,786 7,389,640
Operating Expenses
Fuel and purchased and exchanged power 758,673 1,877,861 1,486,220 3,242,515
Gas purchased 1,076,315 1,195,668 1,899,392 2,906,278
Operation and maintenance 342,341 267,065 607,792 516,555
Depreciation 100,947 92,203 200,431 180,767
Taxes other than income taxes 64,247 53,409 136,669 116,501
------ ------ ------- -------
Total Operating Expenses 2,342,523 3,486,206 4,330,504 6,962,616
Operating Income 137,500 178,132 353,282 427,024
Equity in Earnings (Losses) of Unconsolidated Subsidiaries (159) 2,072 4,708 833
Miscellaneous - Net (3,100) 13,173 (4,147) 8,479
Interest 61,243 68,067 122,871 131,617
Preferred Dividend Requirement of Subsidiary Trust 5,968 - 11,881 -
Income Before Taxes 67,030 125,310 219,091 304,719
Income Taxes 21,189 41,485 76,664 99,789
Preferred Dividend Requirements of Subsidiaries 858 858 1,716 1,716
--- --- ----- -----
Net Income $ 44,983 $ 82,967 $ 140,711 $ 203,214
========== ========== ========== ==========
Average Common Shares Outstanding 167,330 159,061 165,821 159,025
Earnings Per Common Share (Note 9)
Net Income $ 0.27 $ 0.51 $ 0.85 $ 1.27
Earnings Per Common Share - Assuming Dilution (Note 9)
Net Income $ 0.26 $ 0.51 $ 0.84 $ 1.26
Dividends Declared Per Common Share $ 0.45 $ 0.45 $ 0.90 $ 0.90
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
TOC
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Assets
Cash and cash equivalents $ 99,777 $ 111,067
Restricted deposits 9,180 8,055
Notes receivable (Note 5) 137,943 31,173
Accounts receivable less accumulated provision for doubtful accounts
of $17,405 at June 30, 2002, and $35,580 at December 31, 2001 (Note 5) 1,359,795 1,123,214
Materials, supplies, and fuel - at average cost 283,358 240,812
Energy risk management current assets (Note 1(c)) 375,131 449,397
Prepayments and other 111,150 110,311
------- -------
Total Current Assets 2,376,334 2,074,029
Property, Plant, and Equipment - at Cost
Utility plant in service 8,222,639 8,089,961
Construction work in progress 574,550 464,560
------- -------
Total Utility Plant 8,797,189 8,554,521
Non-regulated property, plant, and equipment 4,648,959 4,527,994
Accumulated depreciation 5,002,838 4,845,620
--------- ---------
Net Property, Plant, and Equipment 8,443,310 8,236,895
Other Assets
Regulatory assets 1,002,608 1,015,863
Investments in unconsolidated subsidiaries 348,455 339,059
Energy risk management non-current assets (Note 1(c)) 150,070 134,445
Other investments 173,345 164,155
Goodwill 54,539 53,587
Other intangible assets 21,269 22,250
Other 233,398 259,530
------- -------
Total Other Assets 1,983,684 1,988,889
Total Assets $12,803,328 $12,299,813
=========== ===========
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated
financial statements.
CINERGY CORP.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Liabilities
Accounts payable $ 1,335,430 $ 1,029,173
Accrued taxes 205,903 195,976
Accrued interest 64,775 56,216
Notes payable and other short-term obligations (Note 4) 1,091,257 1,155,786
Long-term debt due within one year (Note 3) 127,091 148,431
Energy risk management current liabilities (Note 1(c)) 310,136 429,794
Other 136,035 127,375
------- -------
Total Current Liabilities 3,270,627 3,142,751
Non-Current Liabilities
Long-term debt (Note 3) 3,611,340 3,596,730
Deferred income taxes 1,338,384 1,301,407
Unamortized investment tax credits 122,834 127,385
Accrued pension and other postretirement benefit costs 478,583 438,962
Energy risk management non-current liabilities (Note 1(c)) 129,137 135,619
Other 292,986 246,340
------- -------
Total Non-Current Liabilities 5,973,264 5,846,443
Total Liabilities 9,243,891 8,989,194
Preferred Trust Securities
Company obligated, mandatorily redeemable, preferred trust
securities
of subsidiary, holding solely debt securities of the company 307,251 306,327
Cumulative Preferred Stock of Subsidiaries
Not subject to mandatory redemption 62,829 62,833
Common Stock Equity (Note 2)
Common stock - $.01 par value; authorized shares - 600,000,000;
outstanding shares - 167,486,129 at June 30, 2002, and
159,402,839 at December 31, 2001 1,675 1,594
Paid-in capital 1,861,689 1,619,659
Retained earnings 1,330,780 1,337,135
Accumulated other comprehensive income (loss) (4,787) (16,929)
------ -------
Total Common Stock Equity 3,189,357 2,941,459
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholders' Equity $12,803,328 $12,299,813
=========== ===========
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated
financial statements.
TOC
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
Accumulated Total
Other Common
Common Paid-in Retained Comprehensive Stock
Stock Capital Earnings Income/(Loss) Equity
----- ------- -------- ------------- ------
(dollars in thousands)
(unaudited)
Quarter Ended June 30, 2002
Balance at April 1, 2002 $1,669 $1,839,338 $1,360,989 $(19,188) $3,182,808
Comprehensive income:
Net income 44,983 44,983
Other comprehensive income (loss), net of tax effect of
($7,772)
Foreign currency translation adjustment (Note 1(g)) 16,897 16,897
Unrealized gain (loss) on investment trusts (583) (583)
Cash flow hedges (Note 1(b)) (1,913) (1,913)
------
Total comprehensive income 59,384
Issuance of 660,033 shares of common stock - net 6 19,518 19,524
Dividends on common stock ($.45 per share) (75,200) (75,200)
Other 2,833 8 2,841
------ ----- ------ ------ -----
Ending balance at June 30, 2002 $1,675 $1,861,689 $1,330,780 $ (4,787) $3,189,357
====== ========== ========== ======== ==========
Quarter Ended June 30, 2001
Balance at April 1, 2001 $1,590 $1,619,366 $1,229,552 $(15,356) $2,835,152
Comprehensive income:
Net income 82,967 82,967
Other comprehensive income (loss), net of tax effect of $2,161
Foreign currency translation adjustment (3,401) (3,401)
Unrealized gain (loss) on investment trusts 540 540
Minimum pension liability adjustment (23) (23)
Cash flow hedges (Note 1(b)) 1,313 1,313
-----
Total comprehensive income 81,396
Issuance of 86,522 shares of common stock - net 1 2,865 2,866
Treasury shares purchased (7,824) (7,824)
Treasury shares reissued 5,622 5,622
Dividends on common stock ($.45 per share) (71,555) (71,555)
Other 3,429 (203) 3,226
----- ----- ---- ----- -----
Ending balance at June 30, 2001 $1,591 $1,623,458 $1,240,761 $(16,927) $2,848,883
====== ========== ========== ======== ==========
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(Continued)
Accumulated Total
Other Common
Common Paid-in Retained Comprehensive Stock
Stock Capital Earnings Income/(Loss) Equity
(dollars in thousands)
(unaudited)
Six Months Ended June 30, 2002
Balance at January 1, 2002 $1,594 $1,619,659 $1,337,135 $(16,929) $2,941,459
Comprehensive income:
Net income 140,711 140,711
Other comprehensive income (loss), net of tax effect of
($4,622)
Foreign currency translation adjustment (Note 1(g)) 15,313 15,313
Unrealized gain (loss) on investment trusts (1,634) (1,634)
Minimum pension liability adjustment 136 136
Cash flow hedges (Note 1(b)) (1,673) (1,673)
------
Total comprehensive income 152,853
Issuance of 8,083,290 shares of common stock - net 81 235,412 235,493
Dividends on common stock ($.90 per share) (147,082) (147,082)
Other 6,618 16 6,634
------ ----- -- ------ -----
Ending balance at June 30, 2002 $1,675 $1,861,689 $1,330,780 $ (4,787) $3,189,357
====== ========== ========== ======== ==========
Six Months Ended June 30, 2001
Balance at January 1, 2001 $1,590 $1,619,153 $1,179,113 $(10,895) $2,788,961
Comprehensive income:
Net income 203,214 203,214
Other comprehensive income (loss), net of tax effect of $1,344
Foreign currency translation adjustment (2,705) (2,705)
Unrealized gain (loss) on investment trusts (143) (143)
Cumulative effect of change in accounting principle (2,500) (2,500)
Minimum pension liability adjustment 68 68
Cash flow hedges (Note 1(b)) (752) (752)
- ----
Total comprehensive income 197,182
Issuance of 120,392 shares of common stock - net 1 3,691 3,692
Treasury shares purchased (10,015) (10,015)
Treasury shares reissued 6,000 6,000
Dividends on common stock ($.90 per share) (143,096) (143,096)
Other 4,629 1,530 6,159
------ ----- ----- ------ -----
Ending balance at June 30, 2001 $1,591 $1,623,458 $1,240,761 $(16,927) $2,848,883
====== ========== ========== ======== ==========
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated financial statements.
TOC
CINERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year to Date
June 30
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Operating Activities
Net income $ 140,711 $ 203,214
Items providing or (using) cash currently:
Depreciation 200,431 180,767
Change in net position of energy risk management activities (54,030) (50,245)
Deferred income taxes and investment tax credits - net 20,779 13,886
Equity in earnings of unconsolidated subsidiaries (4,708) (833)
Allowance for equity funds used during construction (7,167) (3,219)
Regulatory assets deferrals (43,403) (40,924)
Regulatory assets amortization 53,288 61,849
Accrued pension and other postretirement benefit costs 39,621 18,789
Changes in current assets and current liabilities:
Restricted deposits (1,125) (882)
Accounts and notes receivable (298,692) (234,953)
Materials, supplies, and fuel (46,196) (47,346)
Prepayments (6,240) (111,830)
Accounts payable 316,561 299,060
Accrued taxes and interest 18,486 (19,903)
Other items - net 59,854 (25,768)
------ -------
Net cash provided by (used in) operating activities 388,170 241,662
Financing Activities
Change in short-term debt (64,529) 524,479
Issuance of long-term debt 20,125 372,476
Redemption of long-term debt (33,423) (37,090)
Retirement of preferred stock of subsidiaries (2) -
Issuance of common stock 235,493 3,692
Dividends on common stock (147,082) (143,096)
-------- --------
Net cash provided by (used in) financing activities 10,582 720,461
Investing Activities
Construction expenditures (less allowance for equity funds used during
construction) (394,047) (376,917)
Acquisitions and other investments (15,995) (545,056)
------- --------
Net cash provided by (used in) investing activities (410,042) (921,973)
Net increase (decrease) in cash and cash equivalents (11,290) 40,150
Cash and cash equivalents at beginning of period 111,067 93,054
------- ------
Cash and cash equivalents at end of period $ 99,777 $ 133,204
Supplemental Disclosure of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized) $ 119,766 $ 130,570
Income taxes $ 32,083 $ 47,384
The accompanying notes as they relate to Cinergy Corp. are an integral part of these consolidated
financial statements.
TOC
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Quarter Ended Year to Date
June 30 June 30
2002 2001 2002 2001
---- ---- ---- ----
(dollars in thousands)
(unaudited)
Operating Revenues
Electric $ 866,450 $1,203,140 $1,502,336 $2,144,949
Gas 56,008 79,407 235,617 404,500
------ ------ ------- -------
Total Operating Revenues 922,458 1,282,547 1,737,953 2,549,449
Operating Expenses
Fuel and purchased and exchanged power 564,329 920,960 909,344 1,590,704
Gas purchased 24,471 51,555 132,439 289,846
Operation and maintenance 138,341 120,770 244,196 232,395
Depreciation 48,892 46,656 97,052 92,263
Taxes other than income taxes 45,719 44,597 99,205 91,968
------ ------ ------ ------
Total Operating Expenses 821,752 1,184,538 1,482,236 2,297,176
Operating Income 100,706 98,009 255,717 252,273
Miscellaneous - Net 3,566 672 (138) (1,732)
Interest 21,774 26,487 44,629 53,883
Income Before Taxes 82,498 72,194 210,950 196,658
Income Taxes 29,828 22,793 80,695 65,682
------ ------ ------ ------
Net Income $ 52,670 $ 49,401 $ 130,255 $ 130,976
Preferred Dividend Requirement 212 212 423 423
--- --- --- ---
Net Income Applicable to Common Stock $ 52,458 $ 49,189 $ 129,832 $ 130,553
========== ========== ========== ==========
Net Income $ 52,670 $ 49,401 $ 130,255 $ 130,976
Other Comprehensive Income (Loss), Net of Tax Effect (1,913) 1,255 (2,085) (2,660)
------ ----- ------ ------
Comprehensive Income $ 50,757 $ 50,656 $ 128,170 $ 128,316
========== ========== ========== ==========
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part of these
consolidated financial statements.
TOC
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Assets
Cash and cash equivalents $ 9,461 $ 9,074
Restricted deposits 4,304 3,540
Notes receivable from affiliated companies (Note 5) 75,414 -
Accounts receivable less accumulated provision for doubtful accounts
of $5,877 at June 30, 2002, and $25,874 at December 31, 2001 (Note 5) 522,965 332,970
Accounts receivable from affiliated companies 1,762 12,112
Materials, supplies, and fuel - at average cost 113,607 138,119
Energy risk management current assets (Note 1(c)) 40,240 44,360
Prepayments and other 15,358 13,087
------ ------
Total Current Assets 783,111 553,262
Property, Plant, and Equipment - at Cost
Utility plant in service
Electric 2,042,387 2,000,595
Gas 946,932 926,381
Common 242,595 253,978
------- -------
Total Utility Plant In Service 3,231,914 3,180,954
Construction work in progress 98,352 96,247
------ ------
Total Utility Plant 3,330,266 3,277,201
Non-regulated property, plant, and equipment 3,387,119 3,314,285
Accumulated depreciation 2,634,746 2,555,639
--------- ---------
Net Property, Plant, and Equipment 4,082,639 4,035,847
Other Assets
Regulatory assets 601,087 592,491
Energy risk management non-current assets (Note 1(c)) 49,593 48,982
Other investments 1,082 1,080
Other 113,441 128,082
------- -------
Total Other Assets 765,203 770,635
Total Assets $5,630,953 $5,359,744
========== ==========
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part
of these consolidated financial statements.
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Liabilities
Accounts payable $ 583,061 $ 352,450
Accounts payable to affiliated companies 44,215 30,419
Accrued taxes 137,467 116,616
Accrued interest 19,523 16,570
Notes payable and other short-term obligations (Note 4) 196,100 196,100
Notes payable to affiliated companies (Note 4) 379,749 444,801
Long-term debt due within one year 100,000 100,000
Energy risk management current liabilities (Note 1(c)) 16,863 23,341
Other 37,803 33,217
------ ------
Total Current Liabilities 1,514,781 1,313,514
Non-Current Liabilities
Long-term debt 1,105,497 1,105,333
Deferred income taxes 802,188 779,295
Unamortized investment tax credits 88,332 91,246
Accrued pension and other postretirement benefit costs 171,985 165,326
Energy risk management non-current liabilities (Note 1(c)) 32,131 41,773
Other 122,369 105,681
------- -------
Total Non-Current Liabilities 2,322,502 2,288,654
Total Liabilities 3,837,283 3,602,168
Cumulative Preferred Stock
Not subject to mandatory redemption 20,486 20,486
Common Stock Equity
Common stock - $8.50 par value; authorized shares -
120,000,000; outstanding shares - 89,663,086 at June 30,
2002, and December 31, 2001 762,136 762,136
Paid-in capital 571,926 571,926
Retained earnings 446,885 408,706
Accumulated other comprehensive income (loss) (7,763) (5,678)
------ ------
Total Common Stock Equity 1,773,184 1,737,090
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholder's Equity $5,630,953 $5,359,744
========== ==========
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral
part of these consolidated financial statements.
TOC
THE CINCINNATI GAS & ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year to Date
June 30
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Operating Activities
Net income $ 130,255 $ 130,976
Items providing or (using) cash currently:
Depreciation 97,052 92,263
Deferred income taxes and investment tax credits - net 21,393 3,170
Change in net position of energy risk management activities (5,840) (14,190)
Allowance for equity funds used during construction 480 (941)
Regulatory assets deferrals (28,195) (29,102)
Regulatory assets amortization 17,951 29,077
Accrued pension and other postretirement benefit costs 6,659 (205)
Changes in current assets and current liabilities:
Restricted deposits (764) (925)
Accounts and notes receivable (219,100) (167,878)
Materials, supplies, and fuel 24,512 (10,059)
Prepayments (4,318) (6,802)
Accounts payable 244,530 173,649
Accrued taxes and interest 23,804 (23,481)
Other items - net 6,255 (17,117)
----- -------
Net cash provided by (used in) operating activities 314,674 158,435
Financing Activities
Change in short-term debt, including net affiliate notes (65,629) 128,702
Dividends on preferred stock (349) (339)
Dividends on common stock (91,653) (143,086)
------- --------
Net cash provided by (used in) financing activities (157,631) (14,723)
Investing Activities
Construction expenditures (less allowance for equity funds used
during construction) (156,655) (151,363)
Other Investments (1) -
------- -------
Net cash provided by (used in) investing activities (156,656) (151,363)
Net increase (decrease) in cash and cash equivalents 387 (7,651)
Cash and cash equivalents at beginning of period 9,074 20,637
----- ------
Cash and cash equivalents at end of period $ 9,461 $ 12,986
========= =========
Supplemental Disclosure of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized) $ 40,504 $ 48,298
Income taxes $ 15,495 $ 28,753
The accompanying notes as they relate to The Cincinnati Gas & Electric Company are an integral part
of these consolidated financial statements.
TOC
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
Quarter Ended Year to Date
June 30 June 30
2002 2001 2002 2001
---- ---- ---- ----
(dollars in thousands)
(unaudited)
Operating Revenues
Electric $467,428 $1,189,518 $1,097,272 $ 2,114,126
Operating Expenses
Fuel and purchased and exchanged power 217,356 973,013 603,848 1,670,168
Operation and maintenance 142,549 105,278 257,628 196,140
Depreciation 38,380 37,202 76,128 73,995
Taxes other than income taxes 17,149 7,551 33,546 22,535
------ ----- ------ ------
Total Operating Expenses 415,434 1,123,044 971,150 1,962,838
Operating Income 51,994 66,474 126,122 151,288
Miscellaneous - Net 4,370 7,330 9,721 5,560
Interest 17,789 20,597 37,080 38,537
Income Before Taxes 38,575 53,207 98,763 118,311
Income Taxes 8,861 18,990 30,966 42,662
----- ------ ------ ------
Net Income $ 29,714 $ 34,217 $ 67,797 $ 75,649
Preferred Dividend Requirement 646 646 1,293 1,293
--- --- ----- -----
Net Income Applicable to Common Stock $ 29,068 $ 33,571 $ 66,504 $ 74,356
Net Income $ 29,714 $ 34,217 $ 67,797 $ 75,649
Other Comprehensive Income (Loss), Net of Tax Effect (471) 338 (968) (127)
---- --- ---- ----
Comprehensive Income $ 29,243 $ 34,555 $ 66,829 $ 75,522
======== ========== ========== ===========
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated financial
statements.
TOC
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Assets
Cash and cash equivalents $ 1,365 $ 1,587
Restricted deposits 521 519
Notes receivable from affiliated companies (Note 5) 59,036 444,801
Accounts receivable less accumulated provision for doubtful accounts of
$5,491 at June 30, 2002, and $6,773 at December 31, 2001 (Note 5) 176,270 336,994
Accounts receivable from affiliated companies 16,547 10,470
Materials, supplies, and fuel - at average cost 124,314 87,661
Energy risk management current assets (Note 1(c)) 25,844 28,201
Prepayments and other 42,748 41,041
------ ------
Total Current Assets 446,645 951,274
Property, Plant, and Equipment - at Cost
Utility plant in service 4,990,725 4,909,007
Construction work in progress 476,198 368,313
------- -------
Total Utility Plant 5,466,923 5,277,320
Accumulated depreciation 2,268,475 2,216,908
--------- ---------
Net Property, Plant, and Equipment 3,198,448 3,060,412
Other Assets
Regulatory assets 401,521 423,372
Energy risk management non-current assets (Note 1(c)) 30,789 30,164
Other investments 59,454 57,633
Other 29,132 47,927
------ ------
Total Other Assets 520,896 559,096
Total Assets $4,165,989 $4,570,782
========== ==========
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated
financial statements.
PSI ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Liabilities
Accounts payable $ 238,160 $ 312,707
Accounts payable to affiliated companies 35,614 27,370
Accrued taxes 136,853 102,317
Accrued interest 25,790 23,760
Notes payable and other short-term obligations (Note 4) 159,600 148,600
Notes payable to affiliated companies (Note 4) 44,268 422,263
Long-term debt due within one year (Note 3) 979 23,000
Energy risk management current liabilities (Note 1(c)) 14,376 23,185
Other 44,654 41,695
------ ------
Total Current Liabilities 700,294 1,124,897
Non-Current Liabilities
Long-term debt (Note 3) 1,324,247 1,325,089
Deferred income taxes 479,183 486,694
Unamortized investment tax credits 34,502 36,139
Accrued pension and other postretirement benefit costs 164,722 154,799
Energy risk management non-current liabilities (Note 1(c)) 33,182 41,773
Other 81,632 63,557
------ ------
Total Non-Current Liabilities 2,117,468 2,108,051
Total Liabilities 2,817,762 3,232,948
Cumulative Preferred Stock
Not subject to mandatory redemption 42,343 42,347
Common Stock Equity
Common stock - without par value; $.01 stated value; authorized
shares - 60,000,000; outstanding shares - 53,913,701 at June 30, 2002,
and December 31, 2001 539 539
Paid-in capital 416,414 416,414
Retained earnings 891,494 880,129
Accumulated other comprehensive income (loss) (2,563) (1,595)
------ ------
Total Common Stock Equity 1,305,884 1,295,487
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholder's Equity $4,165,989 $4,570,782
========== ==========
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated
financial statements.
TOC
PSI ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year to Date
June 30
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Operating Activities
Net income $ 67,797 $ 75,649
Items providing or (using) cash currently:
Depreciation 76,127 73,995
Deferred income taxes and investment tax credits - net (8,881) 11,735
Change in net position of energy risk management activities 603 (14,190)
Allowance for equity funds used during construction (7,647) (2,278)
Regulatory assets deferrals (15,208) (11,822)
Regulatory assets amortization 35,337 32,772
Accrued pension and other postretirement benefit costs 9,923 6,464
Changes in current assets and current liabilities:
Restricted deposits (2) (673)
Accounts and notes receivable 120,198 (256,287)
Materials, supplies, and fuel (36,653) (38,476)
Prepayments (4,589) (2,103)
Accounts payable (66,185) 270,514
Accrued taxes and interest 36,566 9,643
Other items - net (1,792) (19,894)
------ -------
Net cash provided by (used in) operating activities 205,594 135,049
Financing Activities
Change in short-term debt, including net affiliate notes 77,806 (229,562)
Issuance of long-term debt - 322,471
Redemption of long-term debt (23,000) (19,825)
Retirement of preferred stock (2) -
Dividends on preferred stock (1,293) (1,294)
Dividends on common stock (55,138) -
------- -------
Net cash provided by (used in) financing activities (1,627) 71,790
Investing Activities
Construction expenditures (less allowance for equity funds used
during construction) (201,852) (193,691)
Other investments (2,337) (4,859)
------ ------
Net cash provided by (used in) investing activities (204,189) (198,550)
Net increase (decrease) in cash and cash equivalents (222) 8,289
Cash and cash equivalents at beginning of period 1,587 1,311
----- -----
Cash and cash equivalents at end of period $ 1,365 $ 9,600
========== ==========
Supplemental Disclosure of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized) $ 43,131 $ 43,758
Income taxes $ 15,400 $ 20,261
The accompanying notes as they relate to PSI Energy, Inc. are an integral part of these consolidated
financial statements.
TOC
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF INCOME
Quarter Ended Year to Date
June 30 June 30
2002 2001 2002 2001
---- ---- ---- ----
(dollars in thousands)
(unaudited)
Operating Revenues
Electric $55,136 $62,260 $106,993 $116,862
Gas 11,016 13,608 46,220 72,770
------ ------ ------ ------
Total Operating Revenues 66,152 75,868 153,213 189,632
Operating Expenses
Electricity purchased from parent company for resale 37,808 34,523 74,646 71,367
Gas purchased 5,311 8,324 28,200 51,236
Operation and maintenance 13,928 8,954 23,380 18,201
Depreciation 4,512 4,239 8,732 8,404
Taxes other than income taxes 1,167 1,155 2,368 2,262
----- ----- ----- -----
Total Operating Expenses 62,726 57,195 137,326 151,470
Operating Income 3,426 18,673 15,887 38,162
Miscellaneous - Net 962 (144) (4,206) (613)
Interest 1,452 1,550 2,957 3,243
Income Before Taxes 2,936 16,979 8,724 34,306
Income Taxes 944 5,968 2,848 9,440
--- ----- ----- -----
Net Income $ 1,992 $11,011 $ 5,876 $ 24,866
======= ======= ======== ========
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of these
financial statements.
TOC
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
ASSETS June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Assets
Cash and cash equivalents $ 2,261 $ 4,099
Notes receivable from affiliate companies (Note 5) 15,728 -
Accounts receivable less accumulated provision for doubtful accounts of
$30 at June 30, 2002, and $1,196 at December 31, 2001 (Note 5) 344 16,785
Accounts receivable from affiliated companies 165 2,401
Materials, supplies, and fuel - at average cost 7,075 10,835
Prepayments and other 632 300
--- ---
Total Current Assets 26,205 34,420
Property, Plant, and Equipment - at Cost
Utility plant in service
Electric 253,846 248,223
Gas 202,590 197,301
Common 32,631 50,289
------ ------
Total Utility Plant In Service 489,067 495,813
Construction work in progress 13,914 11,004
------ ------
Total Utility Plant 502,981 506,817
Accumulated depreciation 183,834 178,567
------- -------
Net Property, Plant, and Equipment 319,147 328,250
Other Assets
Regulatory assets 4,379 7,838
Other investments 23 2
Other 16,334 6,580
------ -----
Total Other Assets 20,736 14,420
Total Assets $366,088 $377,090
======== ========
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part
of these financial statements.
THE UNION LIGHT, HEAT AND POWER COMPANY
BALANCE SHEETS
LIABILITIES AND SHAREHOLDER'S EQUITY
June 30 December 31
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Current Liabilities
Accounts payable $ 4,676 $ 7,960
Accounts payable to affiliated companies 23,239 16,156
Accrued taxes 9,191 7,051
Accrued interest 1,287 643
Notes payable to affiliated companies (Note 4) - 26,432
Other 5,901 5,322
----- -----
Total Current Liabilities 44,294 63,564
Non-Current Liabilities
Long-term debt 74,637 74,621
Deferred income taxes 28,328 28,323
Unamortized investment tax credits 3,273 3,411
Accrued pension and other postretirement benefit costs 14,246 13,198
Amounts due to customers - income taxes 7,148 7,148
Other 18,758 14,622
------ ------
Total Non-Current Liabilities 146,390 141,323
Total Liabilities 190,684 204,887
Common Stock Equity
Common stock - $15.00 par value; authorized shares - 1,000,000;
outstanding shares - 585,333 at June 30, 2002, and December 31, 2001 8,780 8,780
Paid-in capital 21,111 21,111
Retained earnings 145,521 142,320
Accumulated other comprehensive income (loss) (8) (8)
-- --
Total Common Stock Equity 175,404 172,203
Commitments and Contingencies (Note 7)
Total Liabilities and Shareholder's Equity $366,088 $377,090
======== ========
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral part of
these financial statements.
TOC
THE UNION LIGHT, HEAT AND POWER COMPANY
STATEMENTS OF CASH FLOWS
Year to Date
June 30
2002 2001
---- ----
(dollars in thousands)
(unaudited)
Operating Activities
Net income $ 5,876 $ 24,866
Items providing or (using) cash currently:
Depreciation 8,732 8,404
Deferred income taxes and investment tax credits - net (132) 2,671
Allowance for equity funds used during construction (259) (37)
Regulatory assets deferrals 4,435 (377)
Regulatory assets amortization (1,077) 68
Accrued pension and other postretirement benefit costs 1,048 44
Changes in current assets and current liabilities:
Accounts and notes receivable 14,063 21,274
Materials, supplies, and fuel 3,760 (964)
Prepayment (332) (326)
Accounts payable 3,799 (18,316)
Accrued taxes and interest 2,784 6,814
Other items - net 5,751 (10,779)
----- -------
Net cash provided by (used in) operating activities 48,448 33,342
Financing Activities
Change in short-term debt, including net affiliate notes (32,024) (15,838)
Dividends on common stock (2,675) (4,829)
------ ------
Net cash provided by (used in) financing activities (34,699) (20,667)
Investing Activities
Construction expenditures (less allowance for equity funds used
during construction) (15,567) (14,709)
Other investments (20) -
------ ------
Net cash provided by (used in) investing activities (15,587) (14,709)
Net increase (decrease) in cash and cash equivalents (1,838) (2,034)
Cash and cash equivalents at beginning of period 4,099 6,460
----- -----
Cash and cash equivalents at end of period $ 2,261 $ 4,426
======== ========
Supplemental Disclosure of Cash Flow Information
Cash paid during the period for:
Interest (net of amount capitalized) $ 2,170 $ 3,129
Income taxes $ 2,386 $ 3,939
The accompanying notes as they relate to The Union Light, Heat and Power Company are an integral
part of these financial statements.
TOCNOTES TO FINANCIAL STATEMENTS
In this reportCinergy (which includesCinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as "we," "our," or "us."
1. Summary of Significant Accounting Policies
(a) Presentation
Our Financial Statements reflect all adjustments (which include normal, recurring adjustments) necessary in the opinion of the registrants for a fair presentation of the interim results. These statements should be read in conjunction with the Financial Statements and the notes thereto included in the combined 2001 Form 10-K of the registrants. Certain amounts in the 2001 Financial Statements have been reclassified to conform to the 2002 presentation.
(b) Financial Derivatives
We use derivative financial instruments to manage:
- funding costs;
- exposure to fluctuations in interest rates; and
- exposure to foreign currency exchange rates.
We account for derivatives under Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (Statement 133), which requires all derivatives that are not exempted to be accounted for at fair value. Changes in the derivative’s fair value must be recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivatives that qualify as hedges can (a) offset related fair value changes on the hedged item in the income statement for fair value hedges; or (b) be recorded in other comprehensive income for cash flow hedges. To qualify for hedge accounting, financial instruments must be designated as a hedge (for example, an offset of foreign exchange or interest rate risks) at the inception of the contract and must be effective at reducing the risk associated with the hedged item. Accordingly, changes in the fair values or cash flows of instruments designated as hedges must be highly correlated with changes in the fair values or cash flows of the related hedged items.
From time to time, we may use foreign currency contracts (for example, a contract obligating one party to buy, and the other to sell, a specified quantity of a foreign currency for a fixed price at a future date) and currency swaps (for example, a contract whereby two parties exchange principal and interest cash flows denominated in different currencies) to hedge foreign currency denominated purchase and sale commitments (cash flow hedges) and certain of our net investments in foreign operations (net investment hedges) against currency exchange rate fluctuations. Reclassification of unrealized gains or losses on foreign currency cash flow hedges from other comprehensive income occurs when the underlying hedged item is recorded in income.
We also use interest rate swaps (an agreement by two parties to exchange fixed-interest rate cash flows for floating-interest rate cash flows). Effective with our adoption of Statement 133 in the first quarter of 2001, we began accounting for all derivatives (including interest rate swaps) using fair value accounting, and we assess the effectiveness of any swaps used in hedging activities. At June 30, 2002, the fair value, and ineffectiveness, of instruments that we have classified as cash flow hedges of variable-rate debt instruments was not material. Reclassification of unrealized gains or losses on cash flow hedges of variable-rate debt instruments from other comprehensive income occurs as interest is accrued on the debt instrument. See Note 1(d)(iii) below for further discussion of Statement 133.
(c) Energy Marketing and Trading
We market and trade electricity, natural gas, coal, and other energy-related products. We designate transactions as accrual or trading at the time they are originated. Contracts are classified as accrual only when we (a) have the intent and projected ability to fulfill substantially all obligations from company-owned assets, and (b) meet the requirements to consider the contract a normal purchase or sale under Statement 133 (if a derivative), or meet the requirements to consider the contract non-trading under Emerging Issues Task Force (EITF) 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities(EITF 98-10) (if not a derivative under Statement 133). Such classification is generally limited to the sale of generation to third parties when it is not required to meet native load requirements (end-use customers within our public utility companies’ franchise service territory). All other energy contracts (excluding electric, coal, and gas purchase contracts for use in serving our native load requirements) are classified as trading. Gas trading is comprised of transactions for which gas is physically delivered to a customer (physical gas trading), as well as transactions that are financial in nature for which delivery rarely occurs (financial gas trading). SinceCinergy owns no gas production and has limited transmission capabilities, all gas transactions (other than procurement and sale of gas to The Cincinnati Gas & Electric Company (CG&E) and The Union Light, Heat and Power Company (ULH&P) retail customers) are considered trading whether physical or financial.
We account for accrual transactions by recognizing revenues and costs when the underlying commodity is delivered and trading transactions using the fair value method of accounting. Under the fair value method of accounting, unrealized trading transactions are shown at fair value in our Balance Sheets asEnergy risk management assets andEnergy risk management liabilities. We reflect unrealized gains and losses, resulting from changes in fair value, on a net basis inOperating Revenues. For physical gas trading and for all power trading, we recognize both revenues and costs on a gross basis inOperating Revenues and inFuel and purchased and exchanged power andGas purchased, respectively, when transactions are settled. For financial gas trading, realized gains and losses are recorded on a net basis inOperating Revenueswhen transactions are settled. In June 2002, the EITF reached consensuses on two issues in EITF Issue 02-3Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3) related to disclosure of energy trading activities under EITF 98-10. The consensus requires significant changes in the revenue reporting policy effective with the beginning of the third quarter of 2002. See Note 1(d)(v) below for further discussion.
Although we intend to settle accrual contracts with company-owned assets, occasionally we settle these contracts with purchases on the open trading markets. The cost of these purchases could be in excess of the associated revenues. We recognize the gains or losses on these transactions as delivery occurs. Due to the infrequency of such settlements, both historical and projected, and the fact that physical settlement to the customer still occurs, we continue to apply the normal purchases and sales exemption to such physical contracts that constitute derivatives. Open market purchases may occur for the following reasons:
- generating station outages;
- least-cost alternative;
- native load requirements; and
- extreme weather.
We anticipate that some of the electricity obligations, even though considered trading contracts, will ultimately be settled using company-owned generation. The cost of this generation is usually below the market price at which the trading portfolio has been valued. The potential for earnings volatility from period to period is increased due to the risks associated with marketing and trading electricity, natural gas, and other energy-related products.
We value contracts in the trading portfolio using end-of-the-period market prices, utilizing the following factors (as applicable):
- closing exchange prices (that is, closing prices for standardized electricity and natural gas products traded on an organized exchange, such as the New York Mercantile Exchange);
- broker-dealer and over-the-counter price quotations; and
- model pricing (which considers time value and historical volatility factors of electricity and natural gas).
(d) Accounting Changes
(i) Business Combinations and Intangible Assets
In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141,Business Combinations (Statement 141), and No. 142,Goodwill and Other Intangible Assets (Statement 142). Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. With the adoption of Statement 142, goodwill and other intangibles with indefinite lives will no longer be subject to amortization. Statement 142 requires that goodwill be assessed for impairment upon adoption and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under prior accounting standards. This test must be applied at the “reporting unit” level, which is not permitted to be broader than the current business segments discussed in Note 8. Under Statement 142, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer’s intent to do so. We began applying Statement 141 in the third quarter of 2001 and Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill, which began in the first quarter of 2002, is not material to our financial position or results of operations. We have identified the reporting units forCinergy and finalized the initial transition impairment test. Based on the result of this test, the transition impact of applying Statement 142 is not material to our financial position or results of operations. We will continue to perform goodwill impairment tests annually, as required by Statement 142, or when circumstances indicate that the fair value of a reporting unit has declined significantly.
(ii) Asset Retirement Obligations
In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations(Statement 143). Statement 143 requires fair value recognition of legal obligations to retire long-lived assets at the time the obligations are incurred. The initial recognition of this liability will be accompanied by a corresponding increase in property, plant, and equipment. Subsequent to the initial recognition, the liability will be adjusted for any revisions to the expected cash flows of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time (recognized as an operation expense). Additional depreciation expense will be recorded prospectively for any property, plant, and equipment increases. We currently accrue costs of removal on many regulated, long-lived assets through depreciation expense, with a corresponding charge to accumulated depreciation, as allowed by each regulatory jurisdiction. For assets that we conclude have a retirement obligation under Statement 143, the accounting we currently use will be modified to comply with this standard. We will adopt Statement 143 in the first quarter of 2003. We have formed an implementation team and have begun to analyze the impact of this statement, but, at this time, we are unable to predict whether its implementation will be material to our financial position or results of operations.
(iii) Derivatives
During 1998, the FASB issued Statement 133. This standard was effective forCinergy beginning in 2001, and requires us to record derivative instruments, which are not exempt under certain provisions of Statement 133, as assets or liabilities, measured at fair value (i.e., mark-to-market). Our financial statements reflect the adoption of Statement 133 in the first quarter of 2001. Since many of our derivatives were previously required to use fair value accounting, the effects of implementation were not material.
Our adoption did not reflect the potential impact of applying fair value accounting to selected electricity options and capacity contracts. We had not historically accounted for these instruments at fair value because they were intended as either hedges of peak period exposure or sales contracts served with physical generation, neither of which were considered trading activities. At adoption, we classified these contracts as normal purchases or sales based on our interpretation of Statement 133 and in the absence of definitive guidance on such contracts. In June 2001, the FASB staff issued guidance on the application of the normal purchases and sales exemption to electricity contracts containing characteristics of options. While many of the criteria in this guidance are consistent with the existing guidance in Statement 133, some criteria were added. We adopted the new guidance in the third quarter of 2001, and the effects of implementation for these contracts were not material to our financial position or results of operations. We will continue to apply this guidance to any new electricity contracts that meet the definition of a derivative.
In December 2001, the FASB staff revised the current guidance to make the evaluation of whether electricity contracts qualify as normal purchases and sales more qualitative than quantitative. This new guidance uses several factors to distinguish between capacity contracts, which qualify for the normal purchases and sales exemption, and options, which do not. These factors include deal tenor, pricing structure, specification of the source of power, and various other factors. Based on a review of existing contracts, we do not believe this revised guidance, which is effective in the third quarter of 2002, will have a material impact on our financial position or results of operations upon adoption. However, given our activity in energy trading, it could increase volatility in future results.
In October 2001, the FASB staff released final guidance on the applicability of the normal purchases and sales exemption to contracts that contain a minimum quantity (a forward component) and flexibility to take additional quantity at a fixed price (an option component). While this guidance was issued primarily to address optionality in fuel supply contracts, it applies to all derivatives (subject to certain exceptions for capacity contracts in electricity discussed in the previous paragraphs). This guidance concludes that such contracts are not eligible for the normal purchases and sales exemption due to the existence of optionality in the contract. We adopted this guidance in the second quarter of 2002, consistent with the transition provisions.Cinergy has certain contracts that contain fixed-price optionality, primarily coal contracts, which we reviewed to determine the impact of this new guidance. Due to a lack of liquidity with respect to coal markets in our region, we determined that our coal contracts do not meet the net settlement criteria of Statement 133 and thus do not qualify as derivatives. Given these conclusions, the results of applying this new guidance were not material to our financial position or results of operations. However, any coal transactions that constitute trading activities will continue to be accounted for at fair value pursuant to EITF 98-10.
In May 2002, the FASB issued an exposure draft that would amend Statement 133 to incorporate certain implementation conclusions reached by the FASB staff. The proposed effective date would be the first quarter of 2003. We do not believe the amendment as currently drafted, will have a material effect on our financial position or results of operations.
(iv) Asset Impairment
In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144,Accounting for the Impairment of Long-Lived Assets (Statement 144). Statement 144 addresses accounting and reporting for the impairment or disposal of long-lived assets. Statement 144 was effective beginning with the first quarter of 2002. The impact of implementation on our financial position or results of operations was not material.
(v) Energy Trading
The EITF has been discussing several issues related to the accounting and disclosure of energy trading activities under EITF 98-10. In June 2002, the EITF reached consensuses on two issues in EITF 02-3. First, a consensus was reached that all realized and unrealized gains and losses on energy trading contracts should be shown net in the income statement, whether or not settled physically.Cinergy’s policy as disclosed in Note 1(c) has differed from this proposal in that while financial trading is presented net, physical trading (both gas and power) are presented gross. This consensus is effective for the third quarter of 2002, and will have a substantial impact on the revenues reported byCinergy,CG&E, and PSI Energy, Inc. (PSI). However,Income Before Taxes andNet Income will not be affected by this change. We estimate that year-to-date revenue would be reduced by approximately 60 percent, 40 percent, and 35 percent forCinergy,CG&E, and PSI, respectively.
Second, the EITF reached a consensus in EITF 02-3 that enhanced disclosure is warranted for energy trading activities, much of which we discuss in “Market Risk Sensitive Instruments and Positions” in “Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations”. These disclosure requirements are effective for year-end 2002.
Additionally, the EITF has formed a working group to discuss the recognition of inception gains (inception value of new contracts when entered into) on energy trading transactions. The EITF is discussing whether such gains should be recorded when the fair values deriving those gains are based on models. Given that no decisions have been reached, we cannot conclude on whether the impacts of this proposal will be material to our financial position or results of operations. However,Cinergy’s inception gains on previous transactions are disclosed in a table with the line entitled “Inception value of new contracts when entered” located in “Market Risk Sensitive Instruments and Positions” section in “Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations”. The Securities and Exchange Commission (SEC) has requested that the EITF resolve this issue by the end of 2002 so that the impact of the consensus may be included in the annual filings of calendar year-end companies.
(e) Operating Revenues
Our operating companies recordOperating revenues for electric and gas service when delivered to customers. Customers are billed throughout the month as both gas and electric meters are read. We recognize revenues for retail energy sales that have not yet been billed, but where gas or electricity has been consumed. This is termed “unbilled revenue” and is a widely recognized and accepted practice for utilities. In making our estimates of unbilled revenue we use complex systems that consider various factors, including weather, in our calculation of retail customer consumption at the end of each month. Given the use of these systems and the fact that customers are billed monthly, we believe it is unlikely that materially different results will occur in future periods when revenue is billed. The amount of unbilled revenues forCinergy,CG&E, and PSI were $132 million, $68 million (including $11 million forULH&P), and $64 million, respectively, through June 30, 2002.
(f) Related Party Transactions
To supplement its native load requirements for 2002,CG&E andPSI have agreed to purchase peaking power from Cinergy Capital & Trading, Inc., an indirect wholly-owned subsidiary ofCinergy Corp., pursuant to the terms of a wholesale market-based tariff. For the six months ended June 30, 2002, payments under these contracts totaled approximately $12 million forCG&E and $5 million forPSI.
(g) Foreign Currency
We translate the assets and liabilities of foreign subsidiaries, whose functional currency (generally, the local currency of the country in which the subsidiary is located) is not the United States (U.S.) dollar, using the appropriate exchange rate as of the end of the month. We translate income and expense items using the average exchange rate prevailing during the month the respective transaction occurs. We record translation gains and losses inAccumulated other comprehensive income (loss), which is a component of common stock equity.
2. Common Stock
In February 2002,Cinergy Corp. sold 6.5 million shares of its common stock with net proceeds of approximately $200 million. The net proceeds from the transaction were used to repay a portion of short-term debt ofCinergy Corp.
As discussed in the 2001 Form 10-K,Cinergy issues newCinergy Corp. common shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan.Cinergy has issued 1,583,290 shares under these plans in 2002.
As discussed in the 2001 Form 10-K, we have historically accounted for our stock-based compensation plans under Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees(APB 25). In July 2002,Cinergy announced that it will adopt Statement of Financial Accounting Standards No. 123,Accounting for Stock-Based Compensation(Statement 123) effective with the next grant cycle (January 2003), and will begin measuring the compensation cost of stock-based awards under the fair value method. The application of the fair value accounting model under Statement 123 applies only to stock-based compensation awards granted prospectively, beginning with those granted in the year of adoption. Existing awards will continue to follow the intrinsic value method prescribed by APB 25. The FASB met on August 7, 2002 to discuss possible revisions to this transition method. The pro-forma impact on net income, assuming application of the fair value accounting method of Statement 123 toall outstanding awards, is disclosed in our 2001 Form 10-K. This change will primarily impact the accounting for the Cinergy Corp. 1996 Long-Term Incentive Compensation Plan, Cinergy Corp. Stock Option Plan, and Cinergy Corp. Employee Stock Purchase and Savings Plan.Cinergyalso announced that it is implementing a policy that will prohibit executive officers and directors from selling stock acquired by exercising options until 90 days after they leave the company or board.
3. Long-term Debt
In January 2002,PSI retired $23 million principal amount of Medium-Term Notes, Series A, which had matured. The securities were not replaced by new issues of long-term debt.
In May 2002, an indirect, wholly-owned subsidiary of Cinergy Global Resources, Inc. entered into a senior term loan and a junior term loan, borrowing $13.1 million and $7.0 million, respectively. Each of the loans is amortizing, with the senior loan having a final maturity of March 15, 2019, and the junior loan having a final maturity of March 15, 2012. In July 2002, borrowings under the senior and junior loans were increased to $13.8 and $7.1 million, respectively. At that time, the annual interest rate on the senior loan was fixed at 6.97 percent and the junior loan was fixed at 6.35 percent. Previously, interest on the loans was at a variable rate.
4. Notes Payable and Other Short-term Obligations
In February 2002,Cinergy Corp. placed a $600 million, 364-day senior revolving credit facility. This facility replaces a $400 million, 364-day senior revolving credit facility that expired in February 2002; a $225 million, 364-day senior revolving credit facility that expired in March 2002; and, a $150 million, three-year senior revolving credit facility that expired in June 2002.
The following table summarizes our Notes payable and other short-term obligations, and Notes payable to affiliated companies.
June 30, 2002 December 31, 2001
------------- -----------------
Established Established
Lines Outstanding Lines Outstanding
----- ----------- ----- -----------
(in millions)
Cinergy Corp.
Revolving lines $ 1,000 $ 180 $1,175 $ 599
Uncommitted lines (1) 40 5 40 -
Commercial paper (2) 800 495 800 125
Operating companies
Revolving lines - - - -
Uncommitted lines (1) 75 77 75 66
Pollution control notes N/A 279 N/A 279
Non-regulated subsidiaries
Revolving lines 14 10 46 38
Short-term debt 45 45 49 49
Cinergy Total $ 1,091 $1,156
CG&E and subsidiaries
Revolving lines $ - $ - $ - $ -
Uncommitted lines (1) 15 - 15 -
Pollution control notes N/A 196 N/A 196
Money pool N/A 380 N/A 445
CG&E Total $ 576 $ 641
PSI
Revolving lines $ - $ - $ - $ -
Uncommitted lines (1) 60 77 60 66
Pollution control notes N/A 83 N/A 83
Money pool N/A 44 N/A 422
PSI Total $ 204 $ 571
(1)Outstanding amounts may be greater than established lines as uncommitted lenders
are, at times, willing to loan funds in excess of the established lines.
(2)The commercial paper program is supported by Cinergy Corp.'s revolving lines.
In our credit facilities,Cinergy Corp. has covenanted to maintain:
- a consolidated net worth of $2 billion; and
- a ratio of consolidated indebtedness to consolidated total capitalization not in excess of 65 percent.
A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of available credit and acceleration of the related indebtedness include:
- bankruptcy;
- defaults in the payment of other indebtedness; and
- judgments against the company that are not paid or insured.
The latter two events, however, are subject to dollar-based materiality thresholds.
5. Sales of Accounts Receivable
In February 2002,CG&E,PSI, andULH&P replaced their existing agreement to sell certain of their accounts receivable and related collections.Cinergy Corp. formed Cinergy Receivables Company, LLC (Cinergy Receivables) to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections ofCG&E,PSI, andULH&P.Cinergy Corp. does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying special-purpose entity. The sales of receivables are accounted for under Statement of Financial Accounting Standards No. 140,Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities (Statement 140).
The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25 percent of the total proceeds). The note is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid toCG&E,PSI, andULH&P.
This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under Statement 140 and is classified withinNotes receivable from affiliated companies in the accompanying Balance Sheets ofCG&E,PSI, andULH&P and is classified withinNotes receivable onCinergy Corp.‘s Balance Sheets. In addition,Cinergy Corp.‘s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held byCG&E,PSI, andULH&P. The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions in estimating fair value are credit losses and selection of discount rates. Because (a) the receivables generally turn in less than two months, (b) credit losses are reasonably predictable due to each company’s broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated basis of the subordinated notes are not materially different than their face value. Interest accrues toCG&E,PSI, andULH&P on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent.CinergyCorp. records income from Cinergy Receivables in a similar manner. We record an impairment charge against the carrying value of both the retained interests and purchased beneficial interest whenever we determine that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).
The key assumptions used in measuring the retained interests for sales since the inception of the new agreement are as follows:
CG&E and
Cinergy subsidiaries PSI ULH&P
------- ------------ --- -----
Anticipated credit loss rate 0.6% 0.6% 0.5% 1.0%
Discount rate on expected cash flows 5.0% 5.0% 5.0% 5.0%
Receivables turnover rate (1) 13.3% 13.7% 12.8% 14.3%
(1)Receivables at period end divided by annualized sales for period.
The hypothetical effect on the fair value of the retained interests assuming both a 10 percent and 20 percent unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history.
CG&E retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse toCG&E,PSI, andULH&P in the event of a loss. While no direct recourse toCG&E,PSI, andULH&P exists, these entities do risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid toCG&E approximates a market rate.
The following table shows the gross and net receivables sold, retained interest, and purchased beneficial interest as of June 30, 2002.
CG&E and
Cinergy subsidiaries PSI ULH&P
------- ------------ --- -----
(in millions)
Receivables sold as of period end $ 421 $ 241 $ 180 $ 36
Less: Retained Interest 134 75 59 10
--- -- -- --
Net receivables sold as of period end $ 287 $ 166 $ 121 $ 26
Purchased beneficial interest $ 8 $ - $ - $ -
A decline in the long-term senior unsecured credit ratings ofCG&E,PSI, orULH&P below investment grade could prevent Cinergy Receivables from borrowing additional funds from commercial paper conduits. This event would result in a termination of the sale program and discontinuance of future sales of receivables.
6. Energy Trading Credit Risk
Cinergy's extension of credit for energy marketing and trading is governed by a Corporate Credit Policy. Written guidelines document the management approval levels for credit limits, evaluation of creditworthiness and credit risk mitigation procedures. Exposures to credit risks are monitored daily by the Corporate Credit Risk function. As of June 30, 2002, approximately 97 percent of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or higher. Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities is generally greater than with other commodity trading.
In December 2001, Enron Corp. (Enron) filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of New York. We decreased our trading activities with Enron in the months prior to its bankruptcy filing. We intend to resolve any contract differences pursuant to the terms of those contracts, business practices, and the applicable provisions of the U.S. Bankruptcy Code, as approved by the court. While we cannot predict the court's resolution of these matters, we do not believe that any exposure relating to those contracts would have a material impact on our financial position or results of operations. While most of our contracts with Enron were considered trading and thus recorded at fair value, a few contracts were accounted for utilizing the normal exemption under Statement 133 (see Note 1(d)(iii)). These contracts were recognized at fair value when the contracts were terminated in the fourth quarter of 2001. Fair value for these contracts, and all terminated contracts with Enron, is governed by the provisions of each contract, but typically approximates fair value at contract termination. However, the effect of the loss of Enron's participation in the energy markets on long-term liquidity and price volatility, or on the creditworthiness of common counterparties cannot be determined.
We continually review and monitor our credit exposure to all counterparties and secondary counterparties. If appropriate, we may adjust our credit reserves to attempt to compensate for increased credit risk within the industry. Counterparty credit limits may be adjusted on a daily basis in response to changes in a counterparties' financial status or public debt ratings.
7. Commitments and Contingencies
(a) Guarantees
Cinergy Corp. has made separate guarantees to certain counterparties regarding performance of commitments by our consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. We are subject to a SEC order under the Public Utility Holding Company Act of 1935, as amended, which limits the amount we can have outstanding under guarantees at any one time to $2 billion. As of June 30, 2002, we had $551 million outstanding under the guarantees issued, of which approximately 75 percent represents guarantees of obligations reflected onCinergy's Consolidated Balance Sheets. These outstanding guarantees relate to subsidiary and joint venture indebtedness and performance commitments.
(b) Ozone Transport Rulemakings
In June 1997, the Ozone Transport Assessment Group, which consisted of 37 states, made a wide range of recommendations to the Environmental Protection Agency (EPA) to address the impact of ozone transport on serious non-attainment areas (geographic areas defined by the EPA as non-compliant with ozone standards) in the Northeast, Midwest, and South. Ozone transport refers to wind-blown movement of ozone and ozone-causing materials across city and state boundaries. In late 1997, the EPA published a proposed call for revisions to State Implementation Plans (SIP) for achieving emissions reductions to address air quality concerns. The EPA must approve all SIPs.
(i) NOX SIP Call
In October 1998, the EPA finalized its ozone transport rule, also known as the NOX SIP Call. It applied to 22 states in the Eastern half of the U.S., including the three states in which our electric utilities operate, and proposed a model NOX emission allowance-trading program. This rule recommended states reduce NOX emissions primarily from industrial and utility sources to a certain level by May 2003. The EPA gave the affected states until September 30, 1999, to incorporate NOX reductions and, at the discretion of the state, a NOX trading program into their SIPs. The EPA proposed to implement a federal plan to accomplish the equivalent NOX reductions by May 1, 2003, if states failed to revise their SIPs.
Ohio, Indiana, a number of other states, and various industry groups (some of which we are a member), filed legal challenges to the NOX SIP Call with the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals).
Following a number of rulings and appeals, in August 2000, the Court of Appeals extended the deadline for NOX reductions to May 31, 2004. The states and other groups sought review of the Court of Appeals ruling by the U.S. Supreme Court (Supreme Court). In March 2001, the Supreme Court decided not to grant that review.
In June 2001, the Court of Appeals remanded portions of the NOX SIP Call to the EPA for reconsideration of how growth was factored into the state NOX budgets. On May 1, 2002, the EPA published, in the Federal Register, a final rule reaffirming its growth factors and state NOX budgets, with additional explanation. The states of West Virginia and Illinois, along with various industry groups (some of which we are a member), have challenged the growth factors and state NOX budgets in an action filed in the Court of Appeals. It is unclear when the Court of Appeals will reach a decision on this case, or whether this decision will result in an increase or decrease in the size of the NOX reduction requirement, or a deferral of the May 31, 2004 compliance deadline.
The states of Indiana and Kentucky developed final NOX SIP rules in response to the NOX SIP Call, through cap and trade programs, in June and July of 2001, respectively. On November 8, 2001, the EPA approved Indiana's SIP rules which became effective December 10, 2001. On April 11, 2002, the EPA proposed direct final approval of Kentucky's rules and they became effective on June 10, 2002. The state of Ohio completed its NOX SIP rules in response to the NOX SIP Call on July 8, 2002, with an effective date of July 18, 2002, the EPA approval is expected later this year. Cinergy's current plans for compliance with the EPA's NOX SIP Call would also satisfy compliance with Indiana's and Kentucky's SIP rules and Ohio's proposed rules.
On September 25, 2000,Cinergy announced a plan for its subsidiaries,CG&E andPSI, to invest in pollution control equipment and other methods to reduce NOX emissions. The current estimate of additional expenditures for this investment is approximately $430 million (in nominal dollars) and includes the following:
- install selective catalytic reduction units (SCR) at several different generating stations;
- install other pollution control technologies, including new computer software, at all generating stations;
- make combustion improvements; and
- utilize market opportunities to buy and sell NOX allowances.
SCRs are the most proven technology currently available for reducing NOX emissions produced in coal-fired generating stations.
(ii) Section 126 Petitions
In February 1998, several northeast states filed petitions seeking the EPA's assistance in reducing ozone in the Eastern U.S. under Section 126 of the Clean Air Act (CAA). The EPA believes that Section 126 petitions allow a state to claim that sources in another state are contributing to its air quality problem and request that the EPA require the upwind sources to reduce their emissions.
In December 1999, the EPA granted four Section 126 petitions relating to NOX emissions. This ruling affected all of our Ohio and Kentucky facilities, as well as some of our Indiana facilities, and requires us to reduce our NOX emissions to a certain level by May 2003. In May 2001, the Court of Appeals substantially upheld a challenge to the Section 126 requirements, and remanded portions of the rule to the EPA for reconsideration of how growth was factored into the emission limitations. On August 24, 2001, the Court of Appeals temporarily suspended the Section 126 compliance deadline, pending the EPA's reconsideration of growth factors. On May 1, 2002, the EPA issued a final rule extending the Section 126 rule compliance deadline to May 31, 2004, thus harmonizing the deadline with that for the NOX SIP Call.
(iii) State Ozone Plans
On November 15, 1999, the states of Indiana and Kentucky (along with Jefferson County, Kentucky) jointly filed an amendment to their attainment demonstration on how they intend to bring the Greater Louisville Area (including Floyd and Clark Counties in Indiana) into attainment with the one-hour ozone standard. The Greater Louisville Area has since attained the one-hour ozone standard, and on October 23, 2001, the EPA re-designated the area as being in attainment with that standard. Previous SIP amendments called for, among other things, statewide NOX reductions from utilities in Indiana, Kentucky, and surrounding states which are less stringent than the EPA's NOX SIP Call. Indiana and Kentucky committed to adopt utility NOX control rules by December 2000 that would require controls be installed by May 2003. However, Indiana halted the rulemaking for NOX controls at this level, but completed NOX SIP Call level reduction regulations. Kentucky has completed its rulemaking, and issued a final rule that changed the compliance deadline to mirror the NOX SIP Call of May 31, 2004. However, on March 18, 2002, Kentucky completed the withdrawal of this regulation in favor of its completed and more restrictive regulations in response to the NOX SIP Call.
See (e) below for a discussion of the tentative EPA Agreement, the implementation of which could affect our strategy for compliance with the final NOX SIP Call.
(c) New Source Review (NSR)
The CAA's NSR provisions require that a company obtain a pre-construction permit if it plans to build a new stationary source of pollution or make a major modification to an existing facility, unless the changes are exempt.
On September 15, 1999, November 3, 1999, and February 2, 2001, the Attorneys General of New York, Connecticut, and New Jersey, respectively, issued letters notifyingCinergy andCG&E of their intent to sue under the citizens' suit provisions of the CAA. These states alleged violations of the CAA by constructing and continuing to operate a major modification ofCG&E's W.C. Beckjord Generating Station (Beckjord Station) without obtaining the required NSR pre-construction permits.
On November 3, 1999, the EPA sued a number of holding companies and electric utilities, includingCinergy,CG&E, andPSI, in various U.S. District Courts (District Court). TheCinergy,CG&E, andPSI suit alleged violations of the CAA at two of our generating stations relating to NSR and New Source Performance Standards requirements. The suit sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station and atPSI's Cayuga Generating Station (Cayuga Station), and (2) civil penalties in amounts of up to $27,500 per day for each violation.
On March 1, 2000, the EPA filed an amended complaint againstCinergy,CG&E, andPSI. The amended complaint added alleged violations of the NSR requirements of the CAA at two of our generating stations contained in a notice of violation (NOV) filed by the EPA on November 3, 1999. It also added claims for relief of alleged violations of nonattainment NSR, Indiana and Ohio SIPs, and particulate matter emission limits (as discussed below in (d)).
The amended complaint sought (1) injunctive relief to require installation of pollution control technology on each of the generating units at Beckjord Station andPSI's Cayuga Station, Wabash River Generating Station, and Gallagher Generating Station, and such other measures as necessary, and (2) civil penalties in amounts of up to $27,500 per day for each violation.
On March 1, 2000, the EPA also filed an amended complaint in a separate lawsuit alleging violations of the CAA relating to NSR, Prevention of Significant Deterioration (PSD), and Ohio SIP requirements regarding various generating stations, including a generating station operated by the Columbus Southern Power Company (CSP) and jointly-owned by CSP, the Dayton Power and Light Company (DP&L), andCG&E. The EPA is seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. This suit is being defended by CSP. On April 4, 2001, the District Court in that case ruled that neither the Government nor the intervening plaintiff environmental groups could obtain civil penalties for any alleged violations that occurred more than five years prior to the filing of the complaint, but that both parties could seek injunctive relief for alleged violations that occurred more than five years before the filing of the complaint. Thus, if the plaintiffs prevail in their claims, any calculation for penalties will not start on the date of the alleged violations, unless those alleged violations occurred after November 3, 1994, but CSP would be forced to install the controls required under the CAA. Neither party appealed that decision.
On June 28, 2000, the EPA issued an NOV toCinergy,CG&E, andPSI for alleged violations of NSR, PSD, and SIP requirements atCG&E's Miami Fort Generating Station andPSI's Gibson Generating Station. In addition,Cinergy andCG&E have been informed by DP&L, the operator of J.M. Stuart Generating Station (Stuart Station), that on June 30, 2000, the EPA issued an NOV to DP&L for alleged violations of NSR, PSD, and SIP requirements at this station.CG&E owns 39 percent of the Stuart Station. The NOVs indicated the EPA may (1) issue an order requiring compliance with the requirements of the SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation.
On August 2, 2001, the states of New York, New Jersey, and Connecticut filed an Assented to Motion to Intervene in this litigation. Their motion was granted by the District Court on August 3, 2001. The states' proposed complaint is an exhibit to the motion to intervene.Cinergy,CG&E, andPSI are in the process of evaluating the states' complaint, but at this time, are unable to determine the effect, if any, this filing will have on the issues affecting us regarding NSR, as framed in the EPA's Amended Complaint.
On January 17, 2002, the Hoosier Environmental Council and the Ohio Environmental Council (Environmental Groups) filed an unopposed motion to intervene as plaintiffs in this litigation. The motion was granted by the District Court on March 19, 2002, and the complaint of the Environmental Groups' was filed on May 1, 2002.Cinergy,CG&E, andPSI are in the process of evaluating the Environmental Groups complaint, but, at this time, are unable to determine the effect, if any, this filing will have upon the issues affecting us regarding NSR, as framed in the EPA's Amended Complaint.
On July 18, 2002, the United States District Court for the Southern District of Indiana (Indiana District Court), issued an order on a motion for partial summary judgment in a similar case involving the Southern Indiana Gas and Electric Company (SIGECO). The narrow issue presented by SIGECO's motion was at what point does an owner or operator of facilities have to determine whether a pre-construction permit is required under the CAA. The court, relying in part upon a decision issued by the Environmental Appeals Board in a similar case involving the Tennessee Valley Authority, ruled that the owner or operator must review evidence of the projected post-project emissions increases to determine if the pre-construction permit is required, and may not rely upon evidence of actual post-project emissions. This court is the same court in whichCinergy's case is pending, so it could be expected that this order would influence a decision upon any similar motion filed byCinergy. No such motion is pending at this date. At this timeCinergy cannot predict the impact any such ruling might have on our financial position or results of operations.
On July 26, 2002, the Indiana District Court also issued an order on a motion for partial summary judgment in the SIGECO case. The issue presented by SIGECO's motion was whether the general federal five-year statute of limitations bars an action for civil penalties for allegedly unlawful construction projects that were completed more than five years prior to the filing of suit. The court held that an NSR preconstruction violation accrues on the first day of construction without a permit, and continues only through the end of construction. Accordingly, the government may not collect civil penalties for allegedly unlawful projects for which construction ended more than five years before the filing of an enforcement action.Cinergy is not aware that any notice of appeal has been filed regarding that order.Cinergy will file a similar motion if the parties fail to enter into a consent decree to settle all issues. At this timeCinergy cannot predict the impact on our financial position or results of operations, although the amount of penalties, if any, that could potentially be awarded by the Indiana District Court if the ruling is not reversed, would be significantly smaller than the amount claimed by the EPA in its Amended Complaint againstCinergy.
See (e) below for a discussion of the tentative EPA Agreement, which relates to matters discussed within this note.
(d) Beckjord Station NOV
On November 30, 1999, the EPA filed an NOV againstCinergy andCG&E, alleging that emissions of particulate matter at the Beckjord Station exceeded the allowable limit. The NOV indicated the EPA may (1) issue an administrative penalty order, or (2) file a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. The allegations contained in this NOV were incorporated within the March 1, 2000 amended complaint, as discussed in (c) above. On June 22, 2000, the EPA issued an NOV and a finding of violation (FOV) alleging additional particulate emission violations at Beckjord Station and offered us an opportunity to meet and discuss the allegations and corrective measures. The NOV/FOV indicated the EPA may issue an administrative compliance order, issue an administrative penalty order, or bring a civil or criminal action.
See (e) below for a discussion of the tentative EPA Agreement, which relates to matters discussed within this note.
(e) EPA Agreement
On December 21, 2000,Cinergy,CG&E, andPSI reached an agreement in principle with the EPA, the U.S. Department of Justice (Justice Department), three northeast states, and two environmental groups that could serve as the basis for a negotiated resolution of CAA claims and other related matters brought against coal-fired power plants owned and operated byCinergy's operating subsidiaries. The complete resolution of these issues is contingent upon establishing a final agreement with the EPA and other parties. If a final agreement is reached with these parties, it would resolve past claims of alleged NSR violations as well as the Beckjord NOVs/FOV discussed previously under (c) and (d).
In addition, the intent of the tentative agreement is that we would be allowed to continue on-going activities to maintain reliability and availability without subjecting the plants to future litigation regarding federal NSR permitting requirements.
In return for resolution of claims regarding past maintenance activities, as well as future operational certainty, we have tentatively agreed to:
- shut down or repower with natural gas, nine small coal-fired boilers at three power plants beginning in 2004;
- build four additional sulfur dioxide (SO2) scrubbers, the first of which must be operational by December 31, 2007;
- upgrade existing particulate control systems;
- phase in the operation of NOX reduction technology year-round starting in 2004;
- reduce our existing Title IV SO2 cap by 35 percent in 2013;
- pay a civil penalty of $8.5 million to the U.S. government; and
- implement $21.5 million in environmental mitigation projects, including retiring 50,000 tons of SO2 allowances by 2005.
The estimated cost for these capital expenditures is expected to be approximately $700 million. These capital expenditures are in addition to our previously announced commitment to install NOX controls as previously discussed in (b) above.
In reaching the tentative agreement, we did not admit any wrongdoing and remain free to continue our current maintenance practices, as well as implement future projects for improved reliability.
In January 2002, the Justice Department completed its review of NSR, after considering dismissal of the lawsuits, and decided to pursue the pending lawsuits, including the suit againstCinergy,CG&E, andPSI. We will continue to pursue a negotiated settlement of these lawsuits if that continues to be in the best interests of the company. At this time, it is not possible to predict whether a final agreement implementing the agreement in principle can be reached. If the settlement is not completed, we intend to defend against the allegations, discussed in (c) and (d) above, vigorously in court. In such an event, it is not possible to determine the likelihood that the plaintiffs would prevail on their claims or whether resolution of these matters would have a material effect on our financial position or results of operations.
(f) Manufactured Gas Plant (MGP) Sites
(i) General
Prior to the 1950s, gas was produced at MGP sites through a process that involved the heating of coal and/or oil. The gas produced from this process was sold for residential, commercial, and industrial uses.
(ii) PSI
Coal tar residues, related hydrocarbons, and various metals associated with MGP sites have been found at former MGP sites in Indiana, including at least 21 sites whichPSI or its predecessors previously owned.PSI acquired four of the sites from Northern Indiana Public Service Company (NIPSCO) in 1931. At the same time,PSI sold NIPSCO the sites located in Goshen and Warsaw, Indiana. In 1945,PSI sold 19 of these sites (including the four sites it acquired from NIPSCO) to the predecessor of the Indiana Gas Company, Inc. (IGC). IGC later sold the site located in Rochester, Indiana to NIPSCO.
IGC (in 1994) and NIPSCO (in 1995) both made claims againstPSI. The basis of these claims was thatPSI is a Potentially Responsible Party with respect to the 21 MGP sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA). The claims further asserted thatPSI was legally responsible for the costs of investigating and remediating the sites. In August 1997, NIPSCO filed suit againstPSI in federal court, claiming recovery (pursuant to CERCLA) of NIPSCO's past and future costs of investigating and remediating MGP-related contamination at the Goshen, Indiana MGP site.
In November 1998, NIPSCO, IGC, andPSI entered into a Site Participation and Cost Sharing Agreement (Agreement). This Agreement allocated CERCLA liability for past and future costs at seven MGP sites in Indiana among the three companies. As a result of the Agreement, NIPSCO's lawsuit againstPSI was dismissed. The parties have assigned lead responsibility for managing further investigation and remediation activities at each of the sites to one of the parties. Similar agreements were reached between IGC andPSI that allocate CERCLA liability at 14 MGP sites with which NIPSCO was not involved. These agreements concluded all CERCLA and similar claims between the three companies related to MGP sites. The parties continue to investigate and remediate the sites, as appropriate, under the agreements and applicable laws. The Indiana Department of Environmental Management (IDEM) oversees investigation and cleanup of some of the sites.
PSI notified its insurance carriers of the claims related to MGP sites raised by IGC, NIPSCO, and IDEM. In April 1998,PSI filed suit in Hendricks County Circuit Court in the State of Indiana against its general liability insurance carriers.PSI sought a declaratory judgment to obligate its insurance carriers to (1) defend MGP claims againstPSI, or (2) payPSI's costs of defense and compensatePSI for its costs of investigating, preventing, mitigating, and remediating damage to property and paying claims related to MGP sites. The lawsuit was moved to the Hendricks County Superior Court (Superior Court) in July 1998.PSI and its insurance carriers filed briefs on various issues for decision by the Superior Court in hearings held in November 2001. On February 1, 2002, the Superior Court issued rulings on motions for summary judgment. The Superior Court granted the motions of several insurance carriers that claimed there was insufficient evidence concerning the terms of their insurance policies. The insurance policies in question were between 1950-1958 and 1961-1964. The Superior Court entered a final judgment with respect to these "lost policies" on March 25, 2002. With respect to the remaining policies (between 1958-1961 and 1964-1984), the Superior Court denied all of the insurance carriers' motions. This included motions on the issues of Trigger of Coverage, Expected or Intended Damage, Late Notice, and Voluntary Payments. The Superior Court found triable issues of fact for the jury to decide as to the former two issues, and ruled inPSI's favor, as a matter of law, on the latter two issues. On February 15, 2002,PSI requested rulings on certain remaining summary judgment issues and a clarification of certain of the Superior Court's summary judgment rulings. That request was denied on April 1, 2002. On March 15, 2002, one of the insurance carriers filed a motion for partial summary judgment asserting a Lack of Justifiability. That motion was heard on April 26, 2002 and denied by the Superior Court on April 30, 2002.
On April 23, 2002,PSI filed a notice of appeal with the Indiana Court of Appeals with respect to the Superior Court's March 25, 2002 order granting final judgment with respect to certain "lost policies." On May 1, 2002, the Superior Court grantedPSI's request to stay the litigation, including the trial that had been rescheduled for June 17, 2002, to allow the parties to seek interlocutory review of certain rulings made by the Superior Court. On June 21, 2002, the Superior Court granted the motions ofPSI and the insurance carriers and certified four orders for interlocutory review by the Indiana Court of Appeals. Unlike the "lost policies" appeal that is an appeal of right, the appeal of these four certified orders is discretionary and the Indiana Court of Appeals can accept or reject any or all of the issues certified. At the present time,PSI cannot predict the outcome of this litigation, including the outcome of the appeals to the Indiana Court of Appeals.
PSI has accrued costs for the sites related to investigation, remediation, and groundwater monitoring to the extent such costs are probable and can be reasonably estimated.PSI does not believe it can provide an estimate of the reasonably possible total remediation costs for any site before a remedial investigation/feasibility study has been completed. To the extent remediation is necessary, the timing of the remediation activities impacts the cost of remediation. Therefore,PSI currently cannot determine the total costs that may be incurred in connection with remediation of all sites, to the extent that remediation is required. According to current information, these future costs at the 21 Indiana MGP sites are not material to our financial position or results of operations. Until investigation and remediation activities have been completed on these sites, we are unable to reasonably estimate the total costs and impact on our financial position or results of operations.
(iii) CG&E
CG&E and its utility subsidiaries are aware of potential sites where MGP activities have occurred at some time in the past. None of these sites is known to present a risk to the environment.CG&E and its utility subsidiaries have begun preliminary site assessments to obtain information about some of these MGP sites.
(g) Gas Customer Choice
In January 2000, Cinergy Investments, Inc. (Investments) sold Cinergy Resources, Inc. (Resources), a former subsidiary, to Licking Rural Electrification, Inc., doing business as The Energy Cooperative (Energy Cooperative). In February 2001,Cinergy,CG&E, and Resources were named as defendants in three class action lawsuits relating to Energy Cooperative's removal from the Ohio Gas Customer Choice program and the failure to deliver gas to customers. Subsequently, these class action suits were amended and consolidated into one suit.CG&E has been dismissed as a defendant in the consolidated suit. In March 2001,Cinergy,CG&E, and Investments were named as defendants in a lawsuit filed by both Energy Cooperative and Resources. This lawsuit concerns any obligations or liabilities Investments may have to Energy Cooperative following its sale of Resources. We intend to vigorously defend these lawsuits. At the present time,Cinergy cannot predict the outcome of these suits.
(h) PSI Fuel Adjustment Charge
As discussed in the 2001 Form 10-K,PSI defers fuel costs that are recoverable in future periods subject to Indiana Utility Regulatory Commission (IURC) approval under a fuel recovery mechanism. In June 2001, the IURC issued an order in aPSI fuel recovery proceeding, disallowing approximately $14 million of deferred costs. On June 26, 2001,PSI formally requested that the IURC reconsider its disallowance decision. In August 2001, the IURC indicated that it will reconsider its decision and PSI has continued the deferral of these costs.PSI believes it has strong legal and factual arguments in its favor and that recovery of these costs remains probable. However,PSI cannot definitively predict the ultimate outcome of this matter.
In June 2001,PSI filed a petition with the IURC requesting authority to recover $16 million in under-billed deferred fuel costs incurred from March 2001 through May 2001. The IURC approved recovery of these costs subject to refund pending the findings of an investigative sub-docket. The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under-billed deferred fuel costs. A hearing was held on July 30, 2002. We anticipate a decision in the fourth quarter of 2002.
(i) Employee Severance Programs
In March 2002, a Voluntary Early Retirement Program (VERP) offering was made to approximately 280 non-union employees. As a result of the 213 employees electing the VERP in the second quarter of 2002, Cinergy recorded expenses of approximately $34 million relating to benefits provided to the VERP participants.
In June 2002, a VERP was also offered to approximately 70 Utility Workers of America / Independent Utilities Union # 600 (IUU) employees. The cut-off date for accepting the plan was July 22, 2002. The costs of the IUU VERP, which will be determined based on the level of employee acceptance, will be recognized in the third quarter of 2002.
In the second quarter of 2002,Cinergy incurred approximately $13 million in additional expenses related to other employee severance programs.
8. Financial Information by Business Segment
As discussed in the 2001 Form 10-K, we conduct operations through our subsidiaries, and manage through the following three business units:
- Energy Merchant Business Unit (Energy Merchant);
- Regulated Businesses Business Unit (Regulated Businesses); and
- Power Technology and Infrastructure Services Business Unit (Power Technology).
The following section describes the activities of our business units as of June 30, 2002.
Energy Merchant manages wholesale generation and energy marketing and trading of energy commodities. Energy Merchant operates and maintains our regulated and non-regulated electric generating plants including some of our jointly-owned plants. Energy Merchant is also responsible for all of our international operations. In addition, Energy Merchant also conducts the following activities:
- energy risk management;
- financial restructuring services;
- proprietary arbitrage activities;
- customized energy solutions; and
- directs our renewable energy investing activities.
Regulated Businesses consists ofPSI's regulated, integrated utility operations, andCinergy's other regulated electric and gas transmission and distribution systems. Regulated Businesses plans, constructs, operates, and maintainsCinergy's transmission and distribution systems and delivers gas and electric energy to consumers. Regulated Businesses also earns revenues from wholesale customers primarily by transmitting electric power throughCinergy's transmission system.
Power Technology primarily manages the development, marketing, and sales of our non-regulated retail energy and energy-related businesses. This is accomplished through various subsidiaries and joint ventures. Power Technology also manages Cinergy Ventures, LLC (Ventures),Cinergy's venture capital subsidiary. Ventures invests in emerging energy technologies that can benefit futureCinergy business development activities.
Financial results by business unit are as indicated below. Certain amounts for the prior year have been restated to reflect segment restructuring which includes the consolidation of all of our international operations into Energy Merchant. This restructuring became effective January 1, 2002.
Financial results by business unit for the quarters ended June 30, 2002 and June 30, 2001:
Business Units
- --------------------------------------------------------------------------------
Cinergy Business Units
----------------------
Energy Regulated Power Reconciling
Merchant Businesses Technology Total Eliminations(1) Consolidated
-------- ---------- ---------- ----- --------------- ------------
(in thousands)
Quarter ended June 30, 2002
- ---------------------------
Operating revenues-
External customers $1,898,551(3) $571,022 $ 10,450 $2,480,023 $ - $2,480,023
Intersegment revenues 37,809 - - 37,809 (37,809) -
Segment profit (loss) (2)(4) 27,554 29,141 (11,712) 44,983 - 44,983
Quarter ended June 30, 2001
---------------------------
Operating revenues-
External customers $3,074,515(3) $579,239 $ 10,584 $3,664,338 $ - $3,664,338
Intersegment revenues 33,153 - - 33,153 (33,153) -
Segment profit (loss) (2) 30,252 55,954 (3,239) 82,967 - 82,967
(1) The Reconciling Eliminations category eliminates the intersegment revenues of Energy Merchant.
(2) Management utilizes segment profit (loss) to evaluate segment performance.
(3) The decrease in 2002 is primarily due to the decrease in volumes and average price realized on wholesale
commodity non-firm transactions.
(4) Includes recognition of approximately $66 million of pre-tax costs associated with employee severance programs and charges
related to the write-off of certain equipment and technology investments, as follows:
Energy Regulated Power
Merchant Businesses Technology Total
-------- ---------- ---------- -----
(in millions)
Employee severance programs $ (23) $ (24) $ - $ (47)
Equipment, technology, and other (11) (1) (7) (19)
-------- --------- --------- --------
$ (34) $ (25) $ (7) $ (66)
Financial results by business unit for the six months ended June 30, 2002 and June 30, 2001:
Business Units
- --------------------------------------------------------------------------------
Cinergy Business Units
----------------------
Energy Regulated Power Reconciling
Merchant Businesses Technology Total Eliminations(1) Consolidated
-------- ---------- ---------- ----- --------------- ------------
(in thousands)
Six months ended June 30, 2002
- ------------------------------
Operating revenues-
External customers $3,392,393(3) $1,273,184(4) $18,209 $4,683,786 $ - $4,683,786
Intersegment revenues 74,647 - - 74,647 (74,647) -
Segment profit (loss) (2)(5) 55,896 101,938 (17,123) 140,711 - 140,711
Six months ended June 30, 2001
------------------------------
Operating revenues-
External customers $5,959,898(3) $1,404,717(4) $25,025 $7,389,640 $ - $7,389,640
Intersegment revenues 68,726 - - 68,726 (68,726) -
Segment profit (loss) (2) 73,381 137,870 (8,037) 203,214 - 203,214
(1) The Reconciling Eliminations category eliminates the intersegment revenues of Energy Merchant.
(2) Management utilizes segment profit (loss) to evaluate segment performance.
(3) The decrease in 2002 is primarily due to the decrease in volumes and average price realized on wholesale commodity
non-firm transactions.
(4) The decrease in 2002 is primarily due to the decrease in price reflecting a substantial decrease in the wholesale gas commodity
cost, which is passed directly to the retail customer dollar-for-dollar under the state mandated gas cost recovery mechanism.
Additionally, a portion of the decrease is due to the reversal of the provision for revenue reduction associated with the ULH&P
electric rate filing settled in May 2001.
(5) Includes recognition of approximately $66 million of pre-tax costs associated with employee severance programs and charges
related to the write-off of certain equipment and technology investments, as follows:
Energy Regulated Power
Merchant Businesses Technology Total
-------- ---------- ---------- -----
(in millions)
Employee severance programs $ (23) $ (24) $ - $ (47)
Equipment, technology, and other (11) (1) (7) (19)
-------- --------- --------- --------
$ (34) $ (25) $ (7) $ (66)
Total segment assets at June 30, 2002 and December 31, 2001, were as follows:
Cinergy Business Units
----------------------
Energy Regulated Power All
Business Units Merchant Businesses Technology Total Other(1) Consolidated
- -------------- -------- ---------- ---------- ----- -------- ------------
(in thousands)
Total segment assets at June 30, 2002 $5,298,984 $7,215,024 $227,874 $12,741,882 $61,446 $12,803,328
Total segment assets at December 31, 2001 4,956,109 7,084,104 213,260 12,253,473 46,340 12,299,813
(1) The All Other category represents miscellaneous corporate items which are not allocated to business units for purposes of
segment performance measurement.
9. Earnings Per Common Share (EPS)
A reconciliation of EPS to EPS - assuming dilution is presented below for the quarters ended June 30, 2002 and June 30, 2001:
Income Shares EPS
------ ------ ---
(in thousands, except per share amounts)
Quarter ended
June 30, 2002
EPS:
Net Income $44,983 167,330 $0.27
Effect of dilutive securities:
Common stock options 1,116
Employee stock purchase and savings plan 11
Directors' compensation plans 155
Contingently issuable common stock 869
Stock purchase contracts 323
------------------
EPS - assuming dilution:
Net income plus assumed conversions $44,983 169,804 $0.26
- ----------------------------------------------------------------------------------
Quarter ended June 30, 2001
EPS:
Net Income $82,967 159,061 $0.51
Effect of dilutive securities:
Common stock options 1,157
Employee stock purchase and savings plan 1
Directors' compensation plans 139
Contingently issuable common stock 588
------------------
EPS - assuming dilution:
Net income plus assumed conversions $82,967 160,946 $0.51
Options to purchase shares of common stock are excluded from the calculation of EPS - assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period. For the quarters ended June 30, 2002 and 2001, approximately 1.5 million and 1.8 million shares, respectively, were excluded from the EPS - assuming dilution calculation.
Also excluded from the EPS - - assuming dilution calculation for the quarter ended June 30, 2002, are up to 10.5 million shares issuable pursuant to the stock purchase contract associated with the preferred trust securities issued byCinergy Corp. in December 2001. As discussed in the 2001 Form 10-K, the number of shares issued pursuant to the stock purchase contracts is contingent upon the market price ofCinergy Corp. stock in February 2005 and could range between 9.2 and 10.8 million shares.
A reconciliation of EPS to EPS - assuming dilution is presented below for the six months ended June 30, 2002 and June 30, 2001:
Income Shares EPS
------ ------ ---
(in thousands, except per share amounts)
Six months ended June 30, 2002
EPS:
Net Income $140,711 165,821 $0.85
Effect of dilutive securities:
Common stock options 1,028
Employee stock purchase and savings plan 6
Directors' compensation plans 155
Contingently issuable common stock 836
-------------------
EPS - assuming dilution:
Net income plus assumed conversions $140,711 167,846 $0.84
Six months ended June 30, 2001
EPS:
Net Income $203,214 159,025 $1.27
Effect of dilutive securities:
Common stock options 1,060
Directors' compensation plans 139
Contingently issuable common stock 563
-------------------
EPS - assuming dilution:
Net income plus assumed conversions $203,214 160,787 $1.26
Options to purchase shares of common stock are excluded from the calculation of EPS - assuming dilution when the exercise prices of these options are greater than the average market price of the common shares during the period. For the six months ended June 30, 2002 and 2001, approximately 1.9 million and 2.1 million shares, respectively, were excluded from the EPS - assuming dilution calculation.
Also excluded from the EPS - assuming dilution calculation for the six months ended June 30, 2002, are up to 10.8 million shares issuable pursuant to the stock purchase contract associated with the preferred trust securities issued byCinergy Corp. in December 2001. As discussed in the 2001 Form 10-K, the number of shares to be issued pursuant to the stock purchase contracts is contingent upon the market price ofCinergy Corp. stock in February 2005 and could range between 9.2 and 10.8 million shares.
10. Ohio Deregulation
As discussed in the 2001 Form 10-K, on July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill), beginning the transition to electric deregulation and customer choice for the State of Ohio. The Electric Restructuring Bill created a competitive electric retail service market effective January 1, 2001. The legislation provides for a market development period that began January 1, 2001, and ends no later than December 31, 2005.
On May 8, 2000,CG&E reached a stipulated agreement with the Public Utilities Commission of Ohio (PUCO) staff and various other interested parties with respect to its proposal to implement electric customer choice in Ohio effective January 1, 2001. On August 31, 2000, the PUCO approvedCG&E's stipulation agreement. Subsequently, two parties filed applications for rehearing with the PUCO. On October 18, 2000, the PUCO denied these applications. One of the parties appealed to the Ohio Supreme Court in the fourth quarter of 2000 andCG&E subsequently intervened in that case. On April 17, 2002, the Ohio Supreme Court affirmed the PUCO's stipulated agreement withCG&E with respect to implementing electric customer choice. The Ohio Supreme Court ruling leavesCG&E's transition plan entirely intact.
A Federal Energy Regulatory Commission order, that was effective April 2002, allowedCinergy to jointly dispatch the regulated generating assets ofPSI in conjunction with the deregulated generating assets ofCG&E. The order also authorizes the transfer of theCG&E generating assets to a non-regulated affiliate. However,Cinergy has determined that it can realize the benefits of the new joint dispatch agreement without transferringCG&E's generation. Therefore, whileCG&E will continue to pursue any remaining regulatory and other approvals already in process that are necessary for the transfer ofCG&E's generation,Cinergy does not plan to transferCG&E's generating assets to a non-regulated affiliate in the foreseeable future.
TOCCautionary Statements Regarding Forward-Looking Information
In this report we discuss various matters that may make management's corporate vision of the future clearer for you. This report outlines management's goals and projections for the future. These goals and projections are considered forward-looking statements and are based on management's beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as "anticipate", "believe", "intend", "estimate", "expect", "continue", "should", "could", "may", "plan", "project", "predict", "will", and similar expressions.
Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ are often presented with forward-looking statements. In addition, other factors could cause actual results to differ materially from those indicated in any forward-looking statement. These include:
- Factors affecting operations, such as:
- unusual weather conditions;
- catastrophic weather-related damage;
- unscheduled generation outages;
- unusual maintenance or repairs;
- unanticipated changes in fossil fuel costs, gas supply costs, or availability constraints;
- environmental incidents; and
- electric transmission or gas pipeline system constraints.
- Legislative and regulatory initiatives regarding deregulation of the industry or potential national deregulation legislation.
- The timing and extent of the entry of additional competition in electric or gas markets and the effects of continued industry consolidation through the pursuit of mergers, acquisitions, and strategic alliances.
- Regulatory factors such as changes in the policies or procedures that set rates; changes in our ability to recover capital expenditures for environmental compliance, purchased power costs and investments made under traditional regulation through rates; and changes to the frequency and timing of rate increases.
- Financial or regulatory accounting principles or policies imposed by governing bodies.
- Political, legal, and economic conditions and developments in the United States (U.S.) and the foreign countries in which we have a presence. This would include inflation rates and monetary fluctuations.
- Changing market conditions and other factors related to physical energy and financial trading activities. These would include price, basis, credit, liquidity, volatility, capacity, transmission, currency exchange rates, interest rates, and warranty risks.
- The performance of projects undertaken by our non-regulated businesses and the success of efforts to invest in and develop new opportunities.
- Availability of, or cost of, capital.
- Employee workforce factors, including changes in key executives, collective bargaining agreements with union employees, and work stoppages.
- Legal and regulatory delays and other obstacles associated with mergers, acquisitions, and investments in joint ventures.
- Costs and effects of legal and administrative proceedings, settlements, investigations, and claims. Examples can be found in Note 7 of the "Notes to Financial Statements" in "Part I. Financial Information."
- Changes in international, federal, state, or local legislative requirements, such as changes in tax laws, tax rates, and environmental laws and regulations.
Unless we otherwise have a duty to do so, the Securities and Exchange Commission's (SEC) rules do not require forward-looking statements to be revised or updated (whether as a result of changes in actual results, changes in assumptions, or other factors affecting the statements). Our forward-looking statements reflect our best beliefs as of the time they are made and may not be updated for subsequent developments.
TOCItem 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
In this reportCinergy (which includesCinergy Corp. and all of our regulated and non-regulated subsidiaries) is, at times, referred to in the first person as "we," "our," or "us."
The following discussion should be read in conjunction with the accompanying financial statements and related notes included elsewhere in this report and the 2001 Form 10-K. The results discussed below are not necessarily indicative of the results to be expected in any future periods.
Introduction
In Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), we explain our general operating environment, as well as our liquidity and capital resources and results of operations. Specifically, we discuss the following:
- factors affecting current and future operations;
- potential sources of cash for future capital expenditures;
- why revenues and expenses changed from period to period; and
- how the above items affect our overall financial condition.
TOCOrganization
Cinergy Corp., a Delaware corporation created in October 1994, owns all outstanding common stock of The Cincinnati Gas & Electric Company (CG&E) and PSI Energy, Inc. (PSI), both of which are public utility subsidiaries. As a result of this ownership, we are considered a utility holding company. Because we are a holding company with material utility subsidiaries operating in multiple states, we are registered with and are subject to regulation by the SEC under the Public Utility Holding Company Act of 1935, as amended (PUHCA). Our other principal subsidiaries are:
- Cinergy Wholesale Energy, Inc.;
- Cinergy Services, Inc. (Services);
- Cinergy Investments, Inc.;
- Cinergy Global Resources, Inc.; and
- Cinergy Technologies, Inc.
CG&E, an Ohio corporation, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its subsidiaries, in nearby areas of Kentucky and Indiana.CG&E's principal subsidiary, The Union Light, Heat and Power Company (ULH&P), is a Kentucky corporation that provides electric and gas service in northern Kentucky.CG&E's other subsidiaries are insignificant to its results of operations.
In 2001,CG&E began a transition to electric deregulation and customer choice. Currently, the competitive retail electric market in Ohio is in the development stage.CG&E is recovering its Public Utilities Commission of Ohio (PUCO) approved costs and retail electric rates are frozen during this market development period.
PSI, an Indiana corporation, is a vertically integrated and regulated electric utility that provides service in north central, central, and southern Indiana.
The majority of our operating revenues are derived from the sale of electricity and the sale and/or transportation of natural gas.
TOCLIQUIDITY AND CAPITAL RESOURCES
Environmental Issues
Ambient Air Standards
In 1997, the Environmental Protection Agency (EPA) revised the National Ambient Air Quality Standards (NAAQS) for ozone and fine particulate matter. Fine particulate matter refers to very small solid or liquid particles in the air. The EPA has estimated that it will take up to five years to collect sufficient ambient air monitoring data to determine fine particulate matter non-attainment areas. A fine particulate monitoring network was put in place during 1999 and 2000. Following identification of non-attainment areas, the states will identify the sources of particulate emissions and develop emission reduction plans. These plans may be state-specific or regional in scope. We currently cannot predict the exact amount and timing of required reductions.
On May 14, 1999, the U.S. Circuit Court of Appeals for the District of Columbia (Court of Appeals) ruled that the EPA's final rule establishing the new eight-hour ozone standard and the fine particulate matter standard constituted an invalid delegation of legislative authority, and also that the EPA had improperly failed to consider the beneficial health effects of ozone (shielding from UV-B radiation) when it established the NAAQS ozone standards. In June 1999, the EPA appealed the conclusion that its standards constituted an invalid delegation of legislative authority, but did not appeal the decision that it is required to consider the beneficial health effects of ozone when setting the NAAQS. On February 27, 2001, the U.S. Supreme Court (Supreme Court) reversed the Court of Appeals' ruling. However, the Supreme Court invalidated the EPA's implementation procedure for the portion of the case dealing with the eight-hour ozone standard.
Following the Supreme Court's ruling, the Court of Appeals reconsidered the validity of the eight-hour ozone standard and the fine particulate matter standard, as a number of issues that were raised by the parties were not addressed in its original opinion invalidating those standards. On March 26, 2002, the Court of Appeals ruled in the EPA's favor on all remaining issues. Nonetheless, before the standards can be implemented, the EPA must conduct rulemaking to: (1) assess the beneficial health effects of ozone in connection with the NAAQS ozone standards; and (2) develop an approach for implementing the ozone standard in accordance with the Supreme Court's opinion. At this time, the EPA predicts that emissions reductions will be required in the 2007-2019 timeframe, but we currently cannot predict the exact amount and timing of required reductions. See Note 7 of the "Notes to Financial Statements" in "Part I. Financial Information" for additional Environmental Issues and other matters that could effect our liquidity.
Capital Resources
We meet our current and future capital requirement needs through a combination of internally and externally generated funds, including the issuance of debt and/or equity securities.
Notes Payable and Other Short-term Obligations
Short-term Borrowings
At June 30, 2002,Cinergy Corp. had $319 million remaining unused and available capacity relating to its $1 billion revolving credit facilities. The revolving credit facilities are comprised of a $400 million, three-year senior revolving credit facility expiring in May 2004 and a $600 million, 364-day senior revolving credit facility expiring in February 2003. At June 30, 2002, certain of our non-regulated subsidiaries had $4 million of unused and available revolving credit lines.
In our credit facilities,Cinergy Corp. has covenanted to maintain:
- a consolidated net worth of $2 billion; and
- a ratio of consolidated indebtedness to consolidated total capitalization not to exceed 65 percent.
A breach of these covenants could result in the termination of the credit facilities and the acceleration of the related indebtedness. In addition to breaches of covenants, certain other events that could result in the termination of available credit and acceleration of the related indebtedness include:
- bankruptcy;
- defaults in the payment of other indebtedness; and
- judgments against the company that are not paid or insured.
The latter two events, however, are subject to dollar-based materiality thresholds.
As of June 30, 2002, our operating companies had regulatory authority to borrow up to a total of $1.27 billion in short-term debt ($671 million forCG&E and its subsidiaries, including $65 million forULH&P, and $600 million forPSI). As of June 30, 2002,CG&E and its subsidiaries had $292 million (including $65 million forULH&P) unused and available andPSI had $479 million unused and available under their respective regulatory authority.
Uncommitted Lines
In addition to revolving credit facilities,
Cinergy,
CG&E, and
PSI also maintain uncommitted lines of credit represented by written, enforceable agreements. However, the lenders under such agreements are not obligated to make advances and, therefore, we pay no fees for these lines of credit. The purpose of these agreements is to provide the framework (including conditions to lending and events of default) for making borrowings at an interest rate and for a term that would be determined at the time that the borrower requests an advance. At June 30, 2002,
Cinergy Corp. had an uncommitted line of $40 million, of which $35 million remained unused.
CG&E and
PSI have established uncommitted lines of $15 million and $60 million, respectively, of which $15 million for
CG&E remained unused and available.
PSI's uncommitted line was fully drawn at June 30, 2002.
Commercial Paper
Cinergy Corp. has a commercial paper program with a maximum outstanding principal amount of $800 million. This program is supported byCinergy Corp.'s $1 billion revolving credit facilities. The commercial paper program at theCinergy Corp. level, in part, supports the short-term borrowing needs ofCG&E andPSI. At June 30, 2002,Cinergy Corp. had $495 million in commercial paper outstanding.
Money Pool
Cinergy Corp., Services, and our operating companies participate in a money pool arrangement to better manage cash and working capital requirements. Under this arrangement, those companies with surplus short-term funds provide short-term loans to affiliates (other than
Cinergy Corp.) participating under this arrangement. This surplus cash may be from internal or external sources. The amounts outstanding under this money pool arrangement are shown as Notes receivable from affiliated companies or Notes payable to affiliated companies on the Balance Sheets of
CG&E,
PSI, and
ULH&P. Any money pool borrowings outstanding reduce the unused and available short-term debt regulatory authority of
CG&E,
PSI, and
ULH&P.
Capital Leases
Our operating companies are able to enter into capital leases subject to the authorization limitations of the applicable state utility commissions. New financing authority is subject to the approval of the respective commissions. On June 26, 2002,PSI received approval from the Indiana Utility Regulatory Commission (IURC) to enter into an additional $100 million of capital lease obligations for the period ending December 31, 2003. On May 22, 2002,ULH&P received approval from the Kentucky Public Service Commission (KPSC) to enter into up to an additional $25 million of capital lease obligations for the period ending December 31, 2004.
Long-term Debt
We are required to secure authority to issue long-term debt from the SEC under the PUHCA and the state utility commissions of Ohio, Kentucky, and Indiana. The SEC under the PUHCA regulates the issuance of long-term debt byCinergy Corp. The respective state utility commissions regulate the issuance of long-term debt by our operating companies. In June 2000, the SEC issued an order under the PUHCA authorizingCinergy Corp., over a five-year period expiring in June 2005, to increase its total capitalization based on a balance at December 31, 1999 (excluding retained earnings and accumulated other comprehensive income (loss)) by an additional $5 billion, through the issuance of any combination of equity and debt securities. This increased authorization is subject to certain conditions, including, among others, that common equity comprises at least 30 percent ofCinergy Corp.'s consolidated capital structure and thatCinergy Corp., under certain circumstances, maintains an investment grade rating on its senior debt obligations.
As of June 30, 2002,CG&E had $500 million remaining unused and available under its existing PUCO authority andULH&P had $75 million remaining unused and available under its KPSC authority. In June 2002,PSI received approval from the IURC authorizing the issuance of up to $500 million of long-term debt through the period ending December 31, 2003. As of June 30, 2002 all remained unused and available. In July 2002,CG&E filed a registration statement with the SEC to sell up to an additional $175 million in unsecured debt securities, first mortgage bonds, and preferred stock. The prospectus included in the registration statement also relates to an additional $525 million of unsecured debt securities, first mortgage bonds, and preferred stock that had been previously registered but remains unused. The registration statement has not been declared effective by the SEC. We may, at any time, seek to issue additional long-term debt, subject to regulatory approval.
Off-Balance Sheet Financing
As discussed in the 2001 Form 10-K,Cinergy uses special-purpose entities (SPE) to finance various projects. The Financial Accounting Standards Board (FASB) issued an exposure draft in July 2002 on a proposed interpretation of consolidation accounting standards that would significantly change the consolidation requirements for SPEs. We have reviewed the impact of this proposal and, if adopted in its current form, believe that it would require consolidation of all the SPEs discussed in the 2001 Form 10-K, except the accounts receivable sale facility discussed in Note 5 of the "Notes to Financial Statements" in "Part I. Financial Information." The accounts receivable sale facility involves transfers of financial assets to a qualifying SPE, which is exempted from consolidation by Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities and this proposal. This exposure draft proposes that SPEs not meeting the required criteria be consolidated at fair value, effective in the second quarter of 2003 forCinergy.
As discussed in the 2001 Form 10-K,Cinergy has an arrangement with an SPE that has contracted to buy five combustion turbines (turbines). In the second quarter of 2002,Cinergy exercised its option to purchase the contractual rights to two of the turbines and subsequently sold those rights to third parties.Cinergy recognized a loss of $6.9 million on these sales. The rights to the remaining turbines remain with the SPE.
Securities Ratings
As of June 30, 2002, the major credit ratings agencies rated our securities as follows:
Fitch Moody's(1) S&P(2)
Cinergy Corp.
Corporate Credit BBB+ Baa2 BBB+
Senior Unsecured Debt BBB+ Baa2 BBB
Commercial Paper F-2 P-2 A-2
Preferred Trust Securities BBB+ Baa2 BBB
CG&E
Senior Secured Debt A- A3 A-
Senior Unsecured Debt BBB+ Baa1 BBB
Junior Unsecured Debt BBB Baa2 BBB-
Preferred Stock BBB Baa3 BBB-
Commercial Paper F-2 P-2 Not Rated
PSI
Senior Secured Debt A- A3 A-
Senior Unsecured Debt BBB+ Baa1 BBB
Junior Unsecured Debt BBB Baa2 BBB-
Preferred Stock BBB Baa3 BBB-
Commercial Paper F-2 P-2 Not Rated
ULH&P
Senior Unsecured Debt Not Rated Baa1 BBB
(1) Moody's Investors Service (Moody's)
(2) Standard & Poor's Ratings Services (S&P)
The lowest investment grade credit rating for Fitch is BBB-, Moody's is Baa3,
and S&P is BBB-.
In April 2002, Moody's affirmed the credit ratings ofCinergy Corp. and its operating subsidiaries,CG&E andPSI. Moody's also removed Cinergy Corp. from review for possible downgrade, and assigned stable outlooks to the debt and preferred stock of Cinergy Corp. and all of its operating subsidiaries.
On June 19, 2002, S&P affirmedCinergy Corp.‘s corporate credit rating, the rating of the company’s commercial paper program, and the secured debt ratings ofCG&E andPSI, while lowering the credit ratings on other issuances. S&P removed all of theCinergy Corp.,CG&E,andPSI ratings from CreditWatch with negative implications and assigned a stable outlook.
On June 19, 2002, Fitch affirmed the credit ratings ofCinergy Corp. Fitch also changed the rating outlook on these securities from negative to stable and affirmed the ratings ofCG&E andPSI.
These securities ratings may be revised or withdrawn at any time, and each rating should be evaluated independently of any other rating.
Equity Securities
In February 2002,Cinergy issued 6,500,000 shares of common stock and received approximately $200 million in proceeds. As discussed in the 2001 Form 10-K, in November 2001,Cinergy chose to reinstitute the practice of issuing newCinergy Corp. common shares to satisfy obligations under its various employee stock plans and the Cinergy Corp. Direct Stock Purchase and Dividend Reinvestment Plan. See Note 2 of the “Notes to Financial Statements” in “Part I. Financial Information” for additional information on issued shares.
Guarantees
Cinergy Corp. has made separate guarantees to certain counterparties regarding performance of commitments by our consolidated subsidiaries, unconsolidated subsidiaries, and joint ventures. We are subject to a SEC order under the PUHCA, which limits the amount we can have outstanding under guarantees at any one time to $2 billion. As of June 30, 2002, we had $551 million outstanding under the guarantees issued, of which approximately 75 percent represents guarantees of obligations reflected onCinergy’sConsolidated Balance Sheets. These outstanding guarantees relate to subsidiary and joint venture indebtedness and performance commitments.
Collateral Requirements
Cinergyhas certain contracts in place, primarily with trading counterparties, that require the issuance of collateral in the event our debt ratings are downgraded below investment grade. Based upon our June 30, 2002 trading portfolio, if such an event were to occur,Cinergy would be required to issue up to approximately $65 million in collateral related to its gas and power trading operations in connection with a downgrade to anything below an investment grade rating.
TOC2002 QUARTERLY RESULTS OF OPERATIONS - HISTORICAL
Summary of Results
Electric and gas gross margins and net income forCinergy,CG&E, andPSI for the quarters ended June 30, 2002 and 2001 were as follows:
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Electric gross margin $ 581,697 $527,602 $ 302,121 $282,180 250,072 $216,505 $
Gas gross margin 40,638 41,111 31,537 27,852 - -
Net income 44,983 82,967 52,670 49,401 29,714 34,217
(1) The results of Cinergy also include amounts related to non-registrants.
Net income for the second quarter of 2002 was $45 million ($.26 per share on a diluted basis) as compared to $83 million ($.51 per share on a diluted basis) for the same period last year. Income before taxes for the period was $67 million compared to $125 million for the same period a year ago. Increased electric gross margins were offset by the recognition of approximately $66 million of costs associated with employee severance programs and charges related to the write-off of certain equipment and technology investments, as follows:
Pre-Tax Charges
---------------
CG&E and
Cinergy(1) subsidiaries PSI
---------- ------------ ---
(in millions)
Employee severance programs $ 47 $ 17 $ 22
Equipment, technology, and other 19 - 2
-- -
Total $ 66 $ 17 $ 24
(1)Includes amounts related to non-registrants.
Also contributing to the decrease in net income were increases in operating costs, property taxes, and depreciation.
Electric Operating Revenues
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 % Change 2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- -------- ---- ---- --------
(in millions)
Retail $ 667 $ 652 2 $ 341 $ 355 (4) $ 325 $ 297 9
Wholesale 596 1,676 (64) 494 838 (41) 133 884 (85)
Transportation 3 1 - 3 1 - - - -
Other 75 77 (3) 28 9 - 9 8 13
-- -- -- - - -
Total $1,341 $2,406 (44) $ 866 $1,203 (28) $ 467 $1,189 (61)
(1) The results of Cinergy also include amounts related to non-registrants.
Electric operating revenues forCinergy,CG&E, andPSIdecreased for the quarter ended June 30, 2002, as compared to 2001. Decreases in wholesale revenues are due to a reduction in the average price received per megawatt hour (MWh) of approximately 45 percent and a reduction in the amount of wholesale MWh delivered. The decrease in delivered MWh reflects reduced liquidity within the wholesale electric commodity market caused by the exit and reduced credit reliability of several trading counterparties. Additionally, the decrease inPSI’s wholesale revenues reflect the implementation of the new joint operating agreement effective April 2002 (see “Termination of Operating Agreement” in “Results of Operations-Future”). In connection with implementation of the new operating agreement, the majority of new wholesale sales transactions entered into during the second quarter of 2002 were originated on behalf ofCG&E.
Retail revenues decreased forCG&E due to a reduction in the average price realized per MWh. The reduction in average price realized is a result of decreases in certain rate adjustment riders.PSI’s retail revenue increased due to an increase in average price realized per MWh and an increase in the amount of MWh delivered. The increase in average price realized is due to the increase in rate adjustment riders associated with a demand-side management (DSM) program, purchased power tracker (Tracker), and fuel cost recovery. The cost of fuel forPSI’s retail customers is passed on dollar-for-dollar under the state mandated fuel cost recovery mechanism.
Gas Operating Revenues
Cinergy (1) CG&E and subsidiaries
----------- ---------------------
2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- --------
(in millions)
Retail $ 47 $ 69 (32) $ 47 $ 69 (32)
Wholesale 1,061 1,158 (8) - - -
Transportation 8 7 14 8 7 14
Other 1 3 (67) 2 4 (50)
- - - -
Total $1,117 $1,237 (10) $ 57 $ 80 (29)
(1) The results of Cinergy also include amounts related to non-registrants.
Gas operating revenues forCinergy decreased for the quarter ended June 30, 2002, as compared to 2001, mainly due to a lower price received per thousand cubic feet (mcf) sold by Cinergy Marketing & Trading, LP (Marketing & Trading). Wholesale natural gas commodity spot prices were 23 percent lower on average than the second quarter of 2001. This decrease was partially offset by an increase in the amount of mcf delivered to customers.
Cinergy's andCG&E's retail gas revenues decreased primarily due to lower price received per mcf delivered. The lower price reflects a substantial decrease in the wholesale gas commodity cost, which is passed directly to the retail customer dollar-for-dollar under the state mandated gas cost recovery mechanism. Partially offsetting this decrease was an increase in retail mcf sales of 6.1 percent compared to the same period last year.
Operating Expenses
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 % Change 2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- -------- ---- ---- --------
(in millions)
Fuel $ 212 $ 196 8 $ 96 $ 84 14 $ 111 $ 109 2
Purchased and
exchanged power 546 1,683 (68) 468 837 (44) 106 864 (88)
Gas purchased 1,076 1,195 (10) 25 52 (52) - - -
Operation and
maintenance 343 268 28 138 120 15 142 105 35
Depreciation 101 92 10 49 46 7 38 37 3
Taxes other than
income taxes 65 53 23 46 45 2 18 8 -
-- -- -- -- -- ---
Total $ 2,343 $3,487 (33) $ 822 $1,184 (31) $ 415 $1,123 (63)
(1) The results of Cinergy also include amounts related to non-registrants.
Fuel
Fuel primarily represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from the quarter ended June 30, 2001, to the quarter ended June 30, 2002:
Cinergy (1) CG&E PSI
----------- ---- ---
(in millions)
Fuel expense - June 30, 2001 $ 196 $ 84 $ 109
Increase (decrease) due to changes in:
Price of fuel 1 (5) 6
Deferred fuel cost (3) - (3)
MWh generation 5 6 (1)
Other (2) 13 11 -
-- -- --
Fuel expense - June 30, 2002 $ 212 $ 96 $ 111
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Includes third party coal marketing activity.
Purchased and Exchanged Power
Purchased and exchanged powerexpensedecreased forCinergy,CG&E, andPSI for the quarter ended June 30, 2002, as compared to 2001, due to a reduction in purchase price and MWh volumes purchased. These decreases reflect reduced liquidity within the wholesale electric commodity market caused by the exit and reduced credit reliability of several trading counterparties. As discussed above,CG&E’s andPSI’s purchased and exchanged power expense also reflects the effects of the implementation of the new joint operating agreement beginning in April 2002.
Gas Purchased
Gas purchased expense decreased forCinergy for the quarter ended June 30, 2002, as compared to 2001, primarily due to a decrease in the average cost per mcf of gas purchased by Marketing & Trading. Wholesale gas commodity spot prices were 23 percent lower on average than in the second quarter of 2001.CG&E’s gas purchased expense decreased primarily due to a decrease in the average cost purchased per mcf.CG&E’s wholesale commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism mandated by state law.
Operation and Maintenance
Operation and maintenance expense increased forCinergy,CG&E, andPSI for the quarter ended June 30, 2002, as compared to 2001, primarily due to the recognition of costs associated with employee severance programs (see “Summary of Results”). Also contributing to this increase were higher transmission costs and expenditures related to process improvement and performance measurement initiatives.Cinergy’s andPSI’s increase also reflects increased amortization of DSM expenditures. In addition,Cinergy’s variance also reflects increased operating costs of our non-regulated affiliates and the expensing of certain project costs.Cinergy’s andCG&E’s increases were partially offset by a decrease in production maintenance expenditures, reflecting a change in the timing ofCG&E’s planned system outages.
Depreciation
Depreciationexpense increased forCinergy,CG&E, andPSI for the quarter ended June 30, 2002, as compared to 2001, primarily attributable to the addition of depreciable plant, includingCinergy’s acquisitions of non-regulated peaking generation in 2001.
Taxes Other Than Income Taxes
Taxes other than income taxesincreased forCinergy,CG&E, andPSI for the quarter ended June 30, 2002, as compared to 2001. This increase is primarily attributable to increased property taxes.
Interest
Interest expense decreased $6.8 million forCinergy for the quarter ended June 30, 2002, as compared to 2001. This decrease was primarily the result of lower interest rates and a reduction in the average amount of outstanding short-term debt.
Income Taxes
Income tax expense decreased $20.3 million and $10.1 million forCinergy andPSI, respectively, for the quarter ended June 30, 2002, as compared to 2001, primarily due to the decrease in taxable income.CG&E’s income tax expense increased $7.0 million for the quarter ended June 30, 2002, as compared to 2001, primarily due to the increase in taxable income and tax changes, including state rate changes, due to deregulation.
Miscellaneous - - Net
Miscellaneous - net expense increased $16.3 million forCinergy for the quarter ended June 30, 2002, as compared to 2001, primarily reflecting the write-off of certain equipment and technology investments (see “Summary of Results”).
Preferred Dividend Requirement of Subsidiary Trust
Preferred dividend requirement of subsidiary trust was $6.0 million for the quarter ended June 30, 2002. This expense relates to quarterly payments to be made to holders ofCinergy’s preferred trust securities, which were issued in December 2001.
TOC2002 YEAR TO DATE RESULTS OF OPERATIONS - HISTORICAL
Summary of Results
Electric and gas gross margins and net income forCinergy,CG&E, andPSI for the six months ended June 30, 2002 and 2001 were as follows:
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 2002 2001 2002 2001
---- ---- ---- ---- ---- ----
(in thousands)
Electric gross margin $ 1,137,574 $1,056,406 $592,992 $554,245 $493,424 $443,958
Gas gross margin 120,822 144,323 103,178 114,654 - -
Net income 140,711 203,214 130,255 130,976 67,797 75,649
(1) The results of Cinergy also include amounts related to non-registrants.
Net income for the six months ended June 30, 2002 was $141 million ($.84 per share on a diluted basis) as compared to $203 million ($1.26 per share on a diluted basis) for the same period last year. Income before taxes for the period was $219 million compared to $305 million for the same period a year ago. Increased electric gross margins were offset by the recognition of approximately $66 million of costs associated with employee severance programs and charges related to the write-off of certain equipment and technology investments, as follows:
Pre-Tax Charges
---------------
CG&E and
Cinergy(1) subsidiaries PSI
---------- ------------ ---
(in millions)
Employee severance programs $ 47 $ 17 $ 22
Equipment, technology, and other 19 - 2
-- -
Total $ 66 $ 17 $ 24
(1)Includes amounts related to non-registrants.
In addition, contributing to the overall decrease in net income were increases in operating costs, property taxes and depreciation.
Electric Operating Revenues
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 % Change 2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- -------- ---- ---- --------
(in millions)
Retail $1,318 $1,280 3 $ 675 $ 694 (3) $ 643 $ 586 10
Wholesale 1,153 2,864 (60) 765 1,433 (47) 440 1,512 (71)
Transportation 5 1 - 5 1 - - - -
Other 148 154 (4) 57 17 - 14 16 (13)
--- --- -- -- -- --
Total $2,624 $4,299 (39) $1,502 $2,145 (30) $1,097 $2,114 (48)
(1) The results of Cinergy also include amounts related to non-registrants.
Electric operating revenues forCinergy,CG&E, andPSI decreased for the six months ended June 30, 2002, as compared to 2001. Decreases in wholesale revenues are due to a reduction in the average price received per MWh of approximately 45 percent and a reduction in the amount of wholesale MWh delivered. The decrease in delivered MWh is due to a reduced liquidity within the wholesale electric commodity market caused by the exit and reduced credit reliability of several trading counterparties. Additionally, the decrease inPSI's wholesale revenues reflect the implementation of the new joint operating agreement effective April 2002 (see "Termination of Operating Agreement" in "Results of Operations-Future"). In connection with implementation of the new operating agreement, the majority of new wholesale sales transactions entered into during the second quarter of 2002 were originated on behalf ofCG&E.
Retail revenues decreased forCG&E due to a reduction in the average price realized per MWh and a decrease in the amount of MWh delivered. The reduction in average price realized is a result of decreases in certain rate adjustment riders.PSI's retail revenues increased due to an increase in average price realized per MWh and an increase in the amount MWh delivered. The increase in average price realized is due to the increase in rate adjustment riders associated with a DSM management program, Tracker, and fuel cost recovery. The cost of fuel forPSI's retail customers is passed on dollar-for-dollar under the state mandated fuel cost recovery mechanism.
Gas Operating Revenues
Cinergy (1) CG&E and subsidiaries
----------- ---------------------
2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- --------
(in millions)
Retail $ 208 $ 376 (45) $ 208 $ 376 (45)
Wholesale 1,785 2,647 (33) - - -
Transportation 25 23 9 25 23 9
Other 2 5 (60) 3 6 (50)
- - - -
Total $2,020 $ 3,051 (34) $ 236 $ 405 (42)
(1) The results of Cinergy also include amounts related to non-registrants.
Gas operating revenues forCinergy decreased for the six months ended June 30, 2002, as compared to 2001 mainly due to a lower price received per mcf sold by Marketing & Trading. Wholesale natural gas commodity spot prices were 45 percent lower on average than the six months ended 2001. This decrease was partially offset by an increase in the amount of mcf delivered to customers.
Cinergy's andCG&E's retail gas revenues decreased primarily due to a lower price received per mcf delivered. The lower price reflects a substantial decrease in the wholesale gas commodity cost, which is passed directly to the retail customer dollar-for-dollar under the state mandated gas cost recovery mechanism.
Operating Expenses
Cinergy (1) CG&E and subsidiaries PSI
----------- --------------------- ---
2002 2001 % Change 2002 2001 % Change 2002 2001 % Change
---- ---- -------- ---- ---- -------- ---- ---- --------
(in millions)
Fuel $ 422 $ 396 7 189 $ 180 5 $221 $ 208 6
Purchased and
exchanged power 1,064 2,847 (63) 720 1,411 (49) 383 1,462 (74)
Gas purchased 1,899 2,906 (35) 133 290 (54) - - -
Operation and
maintenance 608 517 18 244 232 5 257 196 31
Depreciation 201 181 11 97 92 5 76 74 3
Taxes other than
income taxes 137 116 18 99 92 8 34 23 48
--- --- -- -- -- --
Total $4,331 $6,963 (38) $1,482 $2,297 (35) $971 $1,963 (51)
(1) The results of Cinergy also include amounts related to non-registrants.
Fuel
Fuel primarily represents the cost of coal, natural gas, and oil that is used to generate electricity. The following table details the changes to fuel expense from the six months ended June 30, 2001, to the six months ended June 30, 2002:
Cinergy(1) CG&E PSI
---------- ---- ---
(in millions)
Fuel expense - June 30, 2001 $396 $180 $208
Increase (decrease) due to changes in:
Price of fuel (5) (12) 7
Deferred fuel cost 10 - 10
MWh generation (3) 1 (4)
Other (2) 24 20 -
-- -- --
Fuel expense - June 30, 2002 $422 $189 $221
(1) The results of Cinergy also include amounts related to non-registrants.
(2) Includes third party coal marketing activity.
Purchased and Exchanged Power
Purchased and exchanged powerexpense decreased forCinergy,CG&E, andPSI for the six months ended June 30, 2002, as compared to 2001, due to a reduction in the purchase price and MWh volumes purchased. These decreases reflect reduced liquidity within the wholesale electric commodity market caused by the exit and reduced credit reliability of several trading counterparties. As discussed above,CG&E’s and PSI’s purchased and exchanged power expense also reflects the effects of the implementation of the new joint operating agreement beginning in April 2002.
Gas Purchased
Gas purchased expense decreased forCinergy for the six months ended June 30, 2002, as compared to 2001, primarily due to the average cost per mcf of gas purchased by Marketing & Trading. Wholesale gas commodity spot purchases were 45 percent lower on average than the six months ended 2001.CG&E’s gas purchased expense decreased primarily due to a decrease in the average cost purchased per mcf.CG&E’s wholesale commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism mandated by state law.
Operation and Maintenance
Operation and maintenance expense increased forCinergy,CG&E, andPSI for the six months ended June 30, 2002, as compared to 2001, primarily due to the recognition of costs associated with employee severance programs (see “Summary of Results”). Also contributing to this increase were higher transmission costs and expenditures related to process improvement and performance measurement initiatives.Cinergy’s andPSI’s increase also reflects increased amortization of DSM expenditures. In addition,Cinergy’s variance also reflects increased operating costs of our non-regulated affiliates and the expensing of certain project costs.
Depreciation
Depreciation expense increased forCinergy,CG&E,andPSI for the six months ended June 30, 2002, as compared to 2001, primarily attributable to the addition of depreciable plant, includingCinergy’s acquisitions of non-regulated peaking generation in 2001.
Taxes Other Than Income Taxes
Taxes other than income taxes increased forCinergy,CG&E,andPSI for the six months ended June 30, 2002, as compared to 2001. This increase is primarily attributable to increased property taxes.
Interest
Interest expense decreased $8.7 million forCinergyfor the six months ended June 30, 2002, as compared to 2001. This decrease was primarily the result of lower interest rates, and a reduction in the average amount of outstanding short-term debt.
Income Taxes
Income taxexpense decreased $23.1 million and $11.7 million forCinergyandPSI, respectively,for the six months ended June 30, 2002, as compared to 2001. This decrease was primarily due to the decrease in taxable income.CG&E’s income tax expense increased $15.0 million for the six months ended June 30, 2002, as compared to 2001. This increase primarily reflects an increase in taxable income and tax changes, including state rate changes, due to deregulation.
Miscellaneous - - Net
Miscellaneous - net expense increased $12.6 million forCinergy for the six months ended June 30, 2002, as compared to 2001, primarily reflecting the write-off of certain equipment and technology investments (see “Summary of Results”).
Preferred Dividend Requirement of Subsidiary Trust
Preferred dividend requirement of subsidiary trust was $11.9 million for the six months ended June 30, 2002. This expense relates to quarterly payments to be made to holders ofCinergy’s preferred trust securities, which were issued in December 2001.
ULH&P
The Results of Operations discussion forULH&P is presented only for the six months ended June 30, 2002, in accordance with General Instruction H(2)(a) of Form 10-Q.
Electric and gas margins and net income forULH&P for the six months ended June 30, 2002 and 2001, were as follows:
ULH&P
-----
2002 2001
---- ----
(in thousands)
Electric gross margin $32,347 $45,495
Gas gross margin 18,020 21,534
Net income 5,876 24,866
Electric Gross Margin
Electric operating revenues decreased $9.9 million for the six months ended June 30, 2002, as compared to 2001, primarily due to recognition of revenues in 2001 which were previously deferred subject to refund in connection with a 2000 retail rate filing with the KPSC. A settlement was reached in May 2001, allowingULH&P to retain these revenues.Electricity purchased from parent company for resale increased $3.3 million for the six months ended June 30, 2002, as compared to 2001, due to a new wholesale power contract withCG&E that became effective in January 2002. This five-year agreement is a negotiated fixed-rate contract that replaced the previous cost of service based contract that expired on December 31, 2001.
Gas Gross Margin
Gas operating revenues decreased $26.6 million for the six months ended June 30, 2002, as compared to 2001. This decrease is primarily due to lower price received per mcf. The lower price reflects a substantial decrease in the wholesale gas commodity cost.Gas purchased expenses decreased $23 million for the six months ended June 30, 2002, as compared to 2001, due to lower prices paid per mcf. The wholesale gas commodity cost is passed directly to the retail customer dollar-for-dollar under the gas cost recovery mechanism that is mandated under state law.
Operation and Maintenance
Operation and maintenance expense increased $5.2 million for the six months ended June 30, 2002, as compared to 2001, due primarily to higher transmission costs associated with the new wholesale power contract withCG&E that became effective in January 2002.
Income Taxes
Income tax expense decreased $6.6 million for the six months ended June 30, 2002, as compared to 2001, primarily due to a reduction in taxable income.
Miscellaneous - - net
Miscellaneous - net expense increased $3.6 million for the six months ended June 30, 2002, as compared to 2001, primarily due to the expensing of previously deferred costs, that were denied recovery in the final order onULH&P’s gas rate case.
TOCRESULTS OF OPERATIONS - FUTURE
Electric Industry
Wholesale Market Developments
Federal Energy Regulatory Commission (FERC) Notice of Proposed Rulemaking (NOPR)
In July 2002, the FERC issued a NOPR on “Remedying Undue Discrimination through Open Access Transmission Service and Standard Electricity Market Design”, that proposed significant changes designed to create genuine wholesale competition, efficient transmission systems, the right pricing signals for investment in transmission, generation facilities and demand reduction, and more customer options. Market monitoring and market power mitigation proposals are also critical parts of the proposals for standardized power market rules. Among other things, the FERC proposes to amend its regulations under the Federal Power Act to modify the proforma open access transmission tariff established under the FERC’s Order No. 888 to remedy remaining undue discrimination in the provision of interstate transmission services and in other industry practices, and to assure just and reasonable rates within and among regional power markets. FERC proposes to require all public utilities with open access transmission tariffs to file modifications to their tariffs to reflect non-discriminatory, standardized transmission services and standardized wholesale electric market design. Comments to the NOPR are due to the FERC no later than 75 days after issuance of the NOPR. FERC proposes a phased compliance process. By July 31, 2003, all public utilities that own, operate or control interstate transmission facilities must file revised open access transmission tariffs to become effective September 30, 2004, that reflect the inclusion of bundled retail customers as eligible customers. By December 1, 2003, all public utilities that own, control or operate interstate transmission facilities must file revised open access transmission tariffs, to become effective no later than September 30, 2004, or such other time as directed by the FERC, that reflect all of the remaining revisions and requirements of the Final Rule in the proceeding.Cinergyis currently evaluating this ruling and at this time cannot determine the impact to either our financial position or results of operations.
Retail Market Developments
Ohio
As discussed in the 2001 Form 10-K, on July 6, 1999, Ohio Governor Robert Taft signed Amended Substitute Senate Bill No. 3 (Electric Restructuring Bill), beginning the transition to electric deregulation and customer choice for the State of Ohio. The Electric Restructuring Bill created a competitive electric retail service market effective January 1, 2001. The legislation provides for a market development period that began January 1, 2001, and ends no later than December 31, 2005.
On May 8, 2000,CG&E reached a stipulated agreement with the PUCO staff and various other interested parties with respect to its proposal to implement electric customer choice in Ohio effective January 1, 2001. On August 31, 2000, the PUCO approvedCG&E’sstipulation agreement. Subsequently, two parties filed applications for rehearing with the PUCO. On October 18, 2000, the PUCO denied these applications. One of the parties appealed to the Ohio Supreme Court in the fourth quarter of 2000 andCG&E subsequently intervened in that case. On April 17, 2002, the Ohio Supreme Court affirmed the PUCO’s stipulated agreement withCG&E with respect to implementing electric customer choice. The Ohio Supreme Court ruling leavesCG&E’s transition plan entirely intact.
A FERC order, that was effective April 2002, allowedCinergy to jointly dispatch the regulated generating assets ofPSI in conjunction with the deregulated generating assets ofCG&E. The order also authorizes the transfer of theCG&E generating assets to a non-regulated affiliate. However,Cinergy has determined that it can realize the benefits of the new joint dispatch agreement without transferringCG&E’s generation. Therefore, whileCG&E will continue to pursue any remaining regulatory and other approvals already in process that are necessary for the transfer ofCG&E’s generation,Cinergy does not plan to transferCG&E’s generating assets to a non-regulated affiliate in the foreseeable future. For further discussion of the joint dispatch agreement, see “Termination of Operating Agreement.”
Demand-side Actions
In July 2002, we experienced record peak loads of 11,133 megawatts (MW), 5,265 MW,and 6,088 MW for Cinergy,CG&E, andPSI, respectively.Cinergy andCG&Esubsequently set new record peak loads of 11,305 MW and 5,311 MW, respectively, in August 2002. We met customer demands with our own supply and planned purchases from other regional electric suppliers.
Midwest Independent Transmission System Operator, Inc. (Midwest ISO)
As part of the effort to create a competitive wholesale power marketplace, the FERC approved the formation of the Midwest ISO during 1998. In that same year,Cinergy agreed to join the Midwest ISO in preparation for meeting anticipated changes in the FERC regulations and future deregulation requirements. The Midwest ISO was established as a non-profit organization to maintain functional control over the combined transmission systems of its members.
On December 15, 2001, the Midwest ISO initiated startup of its operations with the provision of a variety of support or stand-alone services to its transmission owning members. The Midwest ISO achieved full startup, including implementation of tariff administration, on February 1, 2002. Although the Midwest ISO continues to develop, modify, and enhance its various operating practices, it has assumed functional control of the transmission systems of its member companies, including theCinergy utilities. The impact of this transfer was not material to our financial position or results of operations.
In July 2002, the FERC issued a NOPR that proposed significant changes to the electricity wholesale market. These changes could materially impact the Midwest ISO and Cinergy, however, at this time, we are unable to determine the impacts. See "FERC NOPR" for further discussion.
Finally, in its July 17, 2002 open meeting and subsequent orders, FERC reaffirmed its expectation that the Midwest ISO and the PJM Interconnection, LLC (PJM) implement a common wholesale market between them by October 1, 2004. FERC also imposed more immediate deadlines upon the Midwest ISO, PJM, and various other parties to establish certain protocols, including the elimination of pancaked rates between the Midwest ISO and PJM, necessary to establish a “virtual” single regional transmission organization among the Midwest ISO and PJM companies.Cinergy is currently evaluating these orders, and at this time cannot determine their impact upon either our financial position or results of operations.
Federal Update
Energy Bill
President George W. Bush (President Bush), in conjunction with the work of an inter-agency energy task force headed by Vice President Richard Cheney, developed a number of recommendations to address the energy security needs of America. The U.S. House of Representatives (House) passed its version of energy security legislation, H.R. 4 last summer and the U.S. Senate (Senate) passed its version, S. 517, on April 25, 2002. The bill is now in a joint House/Senate Conference Committee that is scheduled for completion before Congress recesses in mid-October.
Both House and Senate versions of the energy bill include tax provisions for favorable gas distribution line depreciation changes, tax incentives for combined heat and power facilities and for other non-traditional fuel sources such as biomass.
The Senate bill includes an electricity provision that calls for repeal of the PUHCA with consumer protection provisions and increased oversight by the FERC over mergers. The Senate bill also includes a Renewable Portfolio Standard, mandating that utilities purchase an increasing percent of power from renewable sources.
At this time, it is not possible to predict whether energy legislation will pass by the end of this session of Congress or what provisions affectingCinergy will be included. Because of this, it is not possible at this time to determine the impact of the pending legislation on our operations or financial position.
Significant Rate Developments
Purchased Power Tracker
As discussed in the 2001 Form 10-K, in May 1999,PSIfiled a petition with the IURC seeking approval of a Tracker. This request was designed to provide for the recovery of costs related to purchases of power necessary to meet native load requirements to the extent such costs are not sought through the existing fuel adjustment clause.
A hearing was held before the IURC in February 2001, to determine whether it was appropriate forPSIto continue the Tracker for future periods. In April 2001, a favorable order was received extending the Tracker process for two years, through the summer of 2002.PSI is authorized to seek recovery of 90 percent of its purchased power expenses through the Tracker (net of the displaced energy portion recovered through the fuel recovery process and net of the mitigation credit portions), with the remaining 10 percent deferred for subsequent recovery inPSI’snext general rate case.
In June 2001,PSI filed a petition with the IURC seeking approval of the recovery of its summer 2001 purchased power costs through the Tracker. In October 2001,PSI filed an amended petition with the IURC, seeking approval of the costs associated with additional power purchases made during July and August 2001. In February 2002, the IURC issued an order approving the recovery of $15.3 million ofPSI’s summer 2001 purchase power costs via the Tracker. The remaining $1.7 million was deferred for subsequent recovery inPSI’snext general rate case. In March 2002,PSI filed a petition with the IURC seeking approval to extend the Tracker process beyond the summer of 2002 and seek recovery of power purchases made year-round (rather than just in the summer months) as needed to maintain adequate reserves. A hearing is scheduled for the fourth quarter of 2002.
In June 2002,PSI filed a petition with the IURC seeking approval of the recovery through the Tracker of its actual summer 2002 purchased power costs. A hearing is scheduled for the first quarter of 2003.
Termination of Operating Agreement
As discussed in the 2001 Form 10-K,CG&E,PSI, and Services filed a notice of termination of the operating agreement with the FERC in October 2000. In December 2000, the FERC ruled that the companies have the contractual right to terminate the agreement and established a termination effective date in May 2001 and also set a hearing date in May 2001 on the issue of the reasonableness of termination.
Certain parties appealed the FERC’s decision to establish a termination date. In March 2001, the IURC initiated an investigation proceeding into the termination of the operating agreement. In May 2001, the parties to the FERC proceeding reached a settlement agreement resolving the termination issues and certain compensation and damage issues. The settlement agreement was approved by the FERC in June 2001 and delayed the termination of the existing operating agreement until a new successor agreement was approved by the FERC.
In August 2001, the parties to both the IURC proceeding and the previous FERC proceeding entered into two complementary settlement agreements. Both the IURC and FERC agreements were conditioned upon FERC acceptance of the proposed successor agreements. The IURC settlement agreement was approved by the IURC in September 2001.Cinergy filed the successor agreements with the FERC in October 2001 and in March 2002, the FERC approved the successor agreements. The successor agreements allowCinergy to jointly dispatch the regulated generating assets ofPSI in conjunction with the deregulated generating assets ofCG&E at market based pricing. The successor agreements were implemented effective in April 2002.
PSI Fuel Adjustment Charge
As discussed in the 2001 Form 10-K,PSI defers fuel costs that are recoverable in future periods subject to IURC approval under a fuel recovery mechanism. In June 2001, the IURC issued an order in aPSI fuel recovery proceeding, disallowing approximately $14 million of deferred costs. On June 26, 2001,PSI formally requested that the IURC reconsider its disallowance decision. In August 2001, the IURC indicated that it will reconsider its decision andPSI has continued the deferral of these costs.PSIbelieves ithas strong legal and factual arguments in its favor and that recovery of these costs remains probable. However,PSI cannot definitively predict the ultimate outcome of this matter.
In June 2001,PSI filed a petition with the IURC requesting authority to recover $16 million in under-billed deferred fuel costs incurred from March 2001 through May 2001. The IURC approved recovery of these costs subject to refund pending the findings of an investigative sub-docket. The sub-docket was opened to investigate the reasonableness of, and underlying reasons for, the under-billed deferred fuel costs. A hearing was held on July 30, 2002. We anticipate a decision in the fourth quarter of 2002.
Construction Work in Progress (CWIP) Ratemaking Treatment for Nitrogen Oxide (NOX) Equipment
During the third quarter of 2001,PSI filed an application with the IURC requesting CWIP ratemaking treatment for costs related to NOX equipment currently being installed at certainPSI generation facilities. CWIP ratemaking treatment allows for the recovery of carrying costs on the equipment during the construction period.PSI filed its case-in-chief testimony in January 2002. In July 2002, the IURC approved the application allowingPSIto commence CWIP ratemaking treatment for its NOX equipment investments made through December 31, 2001. Initially this rate adjustment will result in approximately a one percent increase in customer rates. Under the IURC’s CWIP rules,PSImay update its CWIP tracker at six-month intervals. The IURC’s July order also authorizedPSI to defer, for subsequent recovery, post-in-service depreciation and to continue the accrual for allowance for funds used during construction.
Transfer of Generating Assets to PSI
In December 2001,PSI filed a petition with the IURC requesting approval, under Indiana’s Power Plant Construction Act, to acquire the Butler County, Ohio and Henry County, Indiana peaking plants from their current owner, a subsidiary of Cinergy Capital & Trading, Inc., to address its need for increased generating capacity. The IURC has scheduled a hearing for September 2002.PSI is unable to predict the outcome of this request. This proposed transfer is also contingent upon receipt of approval from the FERC and the SEC under PUHCA.
2002 Purchased Power Costs
In May 2002, the IURC approved a settlement agreement betweenPSI, the IURC staff, and the Indiana Office of Utility Consumer Counselor effective June 1, 2002 through December 31, 2002. This agreement allowsPSI to purchase the output of the Henry County and Butler County generating plants through December 31, 2002. The parties also agreed to not challenge the recovery of costs for the purchase of power from these plants throughPSI’s Tracker. The order also provides for cost recovery through the fuel cost recovery mechanism.
Gas Industry
ULH&P Gas Rate Case
On May 4, 2001,ULH&P filed a retail gas rate case with the KPSC seeking to increase base rates for natural gas distribution services by $7.3 million annually, or 8.4 percent overall. In addition to an increase in base rates,ULH&P requested recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with a capital cost of approximately $112 million over the next ten years. A hearing on this matter was held in November 2001 and an order was issued on January 31, 2002. In the order, the KPSC authorized a base rate increase of $2.7 million or 2.8 percent overall, to be effective on January 31, 2002. In addition, the KPSC authorizedULH&P to implement the tracking mechanism to recover the costs of the accelerated gas main replacement program for an initial period of three years, with the possibility of renewal for the full ten years. Per the terms of the order, the tracker will be set annually. The first filing was made on March 27, 2002 and is expected to become effective September 1, 2002. The Kentucky Attorney General has appealed the KPSC’s approval of the tracking mechanism to the Franklin Circuit Court. At the present time,ULH&P cannot predict the outcome of this litigation.
CG&E Gas Rate Case
On July 31, 2001,CG&E filed a retail gas rate case with the PUCO seeking to increase base rates for natural gas distribution services by approximately $26 million or 5 percent overall. Simultaneously,CG&Erequested recovery through a tracking mechanism of the costs of an accelerated gas main replacement program with a capital cost of approximately $716 million over the next ten years.CG&E entered into a settlement agreement with most of the parties to the case, resolving most of the issues, andCG&E filed the settlement agreement with the PUCO on April 17, 2002. The settlement agreement provides for a base rate increase of $15.1 million or 3.3 percent and also provides for implementation of the tracking mechanism, subject to rate caps, through the date ofCG&E’s next base rate case.CG&E agreed, as part of the settlement agreement, not to file a new gas base rate case prior to January 1, 2004, absent certain exceptional circumstances. On May 30, 2002, the PUCO issued an order approving the settlement.
Gas Prices
As discussed in the 2001 Form 10-K, in July 2001,CG&E filed an application with the PUCO requesting pre-approval of its gas procurement-hedging program. This request was subsequently denied. However, in denyingCG&E’s request for pre-approval of a hedging program, the PUCO order provided clarification that prudently incurred hedging costs are a valid component ofCG&E’s gas purchasing strategy. As a result,CG&E hedged approximately 50 percent of its winter 2001/2002 base load requirements and is currently recovering the hedging program costs through its gas cost recovery mechanism.
Market Risk Sensitive Instruments and Positions
The transactions associated with the Energy Merchant Business Unit (Energy Merchant) energy marketing and trading activities give rise to various risks, including market risk. Market risk represents the potential risk of loss from adverse changes in market price of electricity or other energy commodities. As Energy Merchant continues to develop its energy marketing and trading business (and due to its substantial investment in generation assets), its exposure to movements in the price of electricity and other energy commodities may become greater. As a result, we may be subject to increased future earnings volatility.
The changes in fair value of the energy risk management assets and liabilities for the quarter ended June 30, 2002, are presented in the table below:
Change in Fair Value
June 30, 2002
(in millions)
Year to Date
June 30
-------
Fair value of contracts outstanding at beginning of period: $ 18
Inception value of new contracts when entered (1) 5
Changes in fair value attributable to changes in
valuation techniques and assumptions (2) -
Other changes in fair value (3) 35
Option premiums paid/(received) 24
Contract reclassifications (4) 14
Contracts realized or otherwise settled (5) (10)
---
Fair value of contracts outstanding at end of period $ 86
======
(1) Represents fair value, recognized in income, attributable to long-term,
structured contracts, primarily in power, which is recorded on the date a
deal is signed. These contracts are primarily with end-use customers or
municipalities that seek to limit their risk to power price volatility.
While caps and floors often exist in such contracts, the amount of power
supplied can vary from hour to hour to mirror the customers load
volatility. The Emerging Issues Task Force (EITF) has proposed that such
gains no longer be recognized at inception unless certain criteria are met.
See "Accounting Changes" for additional information.
(2) Represents changes in fair value caused by changes in assumptions used in
calculating fair value or changes in modeling techniques.
(3) Represents changes in fair value, recognized in income, primarily
attributable to fluctuations in price. This amount includes both realized
and unrealized gains on energy trading contracts.
(4) Represents reclassifications of the settlement value of contracts that have
been terminated as a result of counterparty non-performance to non-current
other liabilities. These contracts no longer have price risk and are
therefore not considered energy trading contracts.
(5) Represents settlements of transactions during the period. For contracts
originated in a prior period, some portion of the settlement value includes
gains or losses recognized in prior periods but not realized until the
current period. Such gains or losses are reflected in the beginning balance
in this table.
The following table presents the expected maturity of theEnergy risk management assets andEnergy risk management liabilities as of June 30, 2002:
Fair Value of Contracts at June 30, 2002
----------------------------------------
Maturing
--------
Within Total
Source of Fair Value(1) 12 months 12-36 months 36-60 months Thereafter Fair Value
----------------------- --------- ------------------------- ---------- ----------
(in millions)
Prices actively quoted $ 37 $ (6) $ - $ - $ 31
Prices based on models
and other valuation methods 28 12 9 6 55
-- -- - - --
Total $ 65 $ 6 $ 9 $ 6 $ 86
====== ======= ====== ======= ======
(1) Active quotes are considered to be available for two years for standard electricity transactions
and three years for standard gas transactions. Non-standard transactions are classified based
on the extent, if any, of modeling used in determining fair value.
Concentrations of Credit Risk
Credit risk is the exposure to economic loss that would occur as a result of nonperformance by counterparties, pursuant to the terms of their contractual obligations. Specific components of credit risk include counterparty default risk, collateral risk, concentration risk, and settlement risk.
Energy Trading Credit Risk
Cinergy’s extension of credit for energy marketing and trading is governed by a Corporate Credit Policy. Written guidelines document the management approval levels for credit limits, evaluation of creditworthiness and credit risk mitigation procedures. Exposures to credit risks are monitored daily by the Corporate Credit Risk function. As of June 30, 2002, approximately 97 percent of the credit exposure related to energy trading and marketing activity was with counterparties rated Investment Grade or higher. Energy commodity prices can be extremely volatile and the market can, at times, lack liquidity. Because of these issues, credit risk for energy commodities is generally greater than with other commodity trading.
In December 2001, Enron Corp. (Enron) filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the Southern District of New York. We decreased our trading activities with Enron in the months prior to its bankruptcy filing. We intend to resolve any contract differences pursuant to the terms of those contracts, business practices, and the applicable provisions of the U.S. Bankruptcy Code, as approved by the court. While we cannot predict the court’s resolution of these matters, we do not believe that any exposure relating to those contracts would have a material impact on our financial position or results of operations. While most of our contracts with Enron were considered trading and thus recorded at fair value, a few contracts were accounted for utilizing the normal exemption under Statement of Financial Accounting Standard No. 133,Accounting for Derivative Instruments and HedgingActivity, (Statement 133) (see Note 1(d)(iii) of the “Notes to Financial Statements” in “Item 1. Financial Information”). These contracts were recognized at fair value when the contracts were terminated in the fourth quarter of 2001. Fair value for these contracts, and all terminated contracts with Enron, is governed by the provisions of each contract, but typically approximates fair value at contract termination. However, the effect of the loss of Enron’s participation in the energy markets on long-term liquidity and price volatility, or on the creditworthiness of common counterparties cannot be determined.
We continually review and monitor our credit exposure to all counterparties and secondary counterparties. If appropriate, we may adjust our credit reserves to attempt to compensate for increased credit risk within the industry. Counterparty credit limits may be adjusted on a daily basis in response to changes in a counterparties’ financial status or public debt ratings.
Accounting Changes
Business Combinations and Intangible Assets
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 141,Business Combinations (Statement 141), and No. 142,Goodwill and Other Intangible Assets (Statement 142). Statement 141 requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method. With the adoption of Statement 142, goodwill and other intangibles with indefinite lives will no longer be subject to amortization. Statement 142 requires that goodwill be assessed for impairment upon adoption and at least annually thereafter by applying a fair-value-based test, as opposed to the undiscounted cash flow test applied under prior accounting standards. This test must be applied at the “reporting unit” level, which is not permitted to be broader than the current business segments discussed in Note 8 of the “Notes to Financial Statements” in “Item 1. Financial Information”. Under Statement 142, an acquired intangible asset should be separately recognized if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented, or exchanged, regardless of the acquirer’s intent to do so. We began applying Statement 141 in the third quarter of 2001 and Statement 142 in the first quarter of 2002. The discontinuance of amortization of goodwill, which began in the first quarter of 2002, is not material to our financial position or results of operations. We have identified the reporting units forCinergy and finalized the initial transition impairment test. Based on the result of this test, the transition impact of applying Statement 142 is not material to our financial position or results of operations. We will continue to perform goodwill impairment tests annually, as required by Statement 142, or when circumstances indicate that the fair value of a reporting unit has declined significantly.
Asset Retirement Obligations
In July 2001, the FASB issued Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations(Statement 143). Statement 143 requires fair value recognition of legal obligations to retire long-lived assets at the time the obligations are incurred. The initial recognition of this liability will be accompanied by a corresponding increase in property, plant, and equipment. Subsequent to the initial recognition, the liability will be adjusted for any revisions to the expected cash flows of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time (recognized as an operation expense). Additional depreciation expense will be recorded prospectively for any property, plant, and equipment increases. We currently accrue costs of removal on many regulated, long-lived assets through depreciation expense, with a corresponding charge to accumulated depreciation, as allowed by each regulatory jurisdiction. For assets that we conclude have a retirement obligation under Statement 143, the accounting we currently use will be modified to comply with this standard. We will adopt Statement 143 in the first quarter of 2003. We have formed an implementation team and have begun to analyze the impact of this statement, but, at this time, we are unable to predict whether its implementation will be material to our financial position or results of operations.
Derivatives
During 1998, the FASB issued Statement 133. This standard was effective forCinergy beginning in 2001, and requires us to record derivative instruments, which are not exempt under certain provisions of Statement 133, as assets or liabilities, measured at fair value (i.e., mark-to-market). Our financial statements reflect the adoption of Statement 133 in the first quarter of 2001. Since many of our derivatives were previously required to use fair value accounting, the effects of implementation were not material.
Our adoption did not reflect the potential impact of applying fair value accounting to selected electricity options and capacity contracts. We had not historically accounted for these instruments at fair value because they were intended as either hedges of peak period exposure or sales contracts served with physical generation, neither of which were considered trading activities. At adoption, we classified these contracts as normal purchases or sales based on our interpretation of Statement 133 and in the absence of definitive guidance on such contracts. In June 2001, the FASB staff issued guidance on the application of the normal purchases and sales exemption to electricity contracts containing characteristics of options. While many of the criteria in this guidance are consistent with the existing guidance in Statement 133, some criteria were added. We adopted the new guidance in the third quarter of 2001, and the effects of implementation for these contracts were not material to our financial position or results of operations. We will continue to apply this guidance to any new electricity contracts that meet the definition of a derivative.
In December 2001, the FASB staff revised the current guidance to make the evaluation of whether electricity contracts qualify as normal purchases and sales more qualitative than quantitative. This new guidance uses several factors to distinguish between capacity contracts, which qualify for the normal purchases and sales exemption, and options, which do not. These factors include deal tenor, pricing structure, specification of the source of power, and various other factors. Based on a review of existing contracts, we do not believe this revised guidance, which is effective in the third quarter of 2002, will have a material impact on our financial position or results of operations upon adoption. However, given our activity in energy trading, it could increase volatility in future results.
In October 2001, the FASB staff released final guidance on the applicability of the normal purchases and sales exemption to contracts that contain a minimum quantity (a forward component) and flexibility to take additional quantity at a fixed price (an option component). While this guidance was issued primarily to address optionality in fuel supply contracts, it applies to all derivatives (subject to certain exceptions for capacity contracts in electricity discussed in the previous paragraphs). This guidance concludes that such contracts are not eligible for the normal purchases and sales exemption due to the existence of optionality in the contract. We adopted this guidance in the second quarter of 2002, consistent with the transition provisions.Cinergy has certain contracts that contain fixed-price optionality, primarily coal contracts, which we reviewed to determine the impact of this new guidance. Due to a lack of liquidity with respect to coal markets in our region, we determined that our coal contracts do not meet the net settlement criteria of Statement 133 and thus do not qualify as derivatives. Given these conclusions, the results of applying this new guidance were not material to our financial position or results of operations. However, any coal transactions that constitute trading activities will continue to be accounted for at fair value pursuant to EITF 98-10,Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10).
In May 2002, the FASB issued an exposure draft that would amend Statement 133 to incorporate certain implementation conclusions reached by the FASB staff. The proposed effective date would be the first quarter of 2003. We do not believe the amendment as currently drafted, will have a material effect on our financial position or results of operations.
Asset Impairment
In August 2001, the FASB issued Statement of Financial Accounting Standards No. 144,Accounting for the Impairment of Long-Lived Assets (Statement 144). Statement 144 addresses accounting and reporting for the impairment or disposal of long-lived assets. Statement 144 was effective beginning with the first quarter of 2002. The impact of implementation on our financial position or results of operations was not material.
Energy Trading
The EITF has been discussing several issues related to the accounting and disclosure of energy trading activities under EITF 98-10. In June 2002, the EITF reached consensuses on two issues in EITF Issue 02-3Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3). First, a consensus was reached that all realized and unrealized gains and losses on energy trading contracts should be shown net in the income statement, whether or not settled physically.Cinergy’s policy as disclosed in Note 1(c) in the “Notes to Financial Statements” in “Item 1. Financial Information” has differed from this proposal in that while financial trading is presented net, physical trading (both gas and power) are presented gross. This consensus is effective for the third quarter of 2002, and will have a substantial impact on the revenues reported byCinergy,CG&E, andPSI. However,Income Before Taxes andNet Income will not be affected by this change. We estimate that year-to-date revenue would be reduced by approximately 60 percent, 40 percent, and 35 percent forCinergy,CG&E, and PSI, respectively.
Second, the EITF reached a consensus in EITF 02-3 that enhanced disclosure is warranted for energy trading activities, much of which we already provided in "Market Risk Sensitive Instruments and Positions". These disclosure requirements are effective for year-end 2002.
Additionally, the EITF has formed a working group to discuss the recognition of inception gains (inception value of new contracts when entered into) on energy trading transactions. The EITF is discussing whether such gains should be recorded when the fair values deriving those gains are based on models. Given that no decisions have been reached, we cannot conclude on whether the impacts of this proposal would be material to our financial position or results of operations. However,Cinergy’s inception gains on previous transactions are disclosed in a table with the line entitled “Inception value of new contracts when entered” located in “Market Risk Sensitive Instruments and Positions”. The SEC has requested that the EITF resolve this issue by the end of 2002 so that the impact of the consensus may be included in the annual filings of calendar year-end companies.
Other
As indicated above, in June 2002, the EITF reached consensus on certain issues in EITF 02-3. Effective with the quarter ending September 30, 2002, all companies will be required to adopt net reporting of energy trading activities as opposed to the previously accepted gross basis.
As a result of recent disclosures by a number of companies related to their participation in simultaneous buy-sell transactions, we completed a review of our trading activity for the fiscal years 2000 and 2001 and for the six months ended June 30, 2002. Specifically, we examined all trades to determine if there was both a valid business purpose and a transfer of risk (e.g., credit or performance). While we confirmed all trades were executed for valid business purposes, a very small number of trades were identified that did not involve a transfer of risk. These trades were immaterial as they represented less than three-tenths of one percent of revenues for the entire period reviewed and less than one percent of revenues for any reported period. These trades had no effect on reported net income.
Effective with the adoption of EITF 02-3, trading revenues and expenses will be presented on a net basis.
Other Matters
Employee Severance Programs
In March 2002, a Voluntary Early Retirement Program (VERP) offering was made to approximately 280 non-union employees. As a result of the 213 employees electing the VERP in the second quarter of 2002,Cinergy recorded expenses of approximately $34 million relating to benefits provided to the VERP participants.
In June 2002, a VERP was also offered to approximately 70 Utility Workers of America / Independent Utilities Union # 600 (IUU) employees. The cut-off date for accepting the plan was July 22, 2002. The costs of the IUU VERP, which will be determined based on the level of employee acceptance, will be recognized in the third quarter of 2002.
In the second quarter of 2002, Cinergy incurred approximately $13 million in additional expenses related to other employee severance programs.
Collective Bargaining Agreements
As discussed in the 2001 Form 10-K, the collective bargaining agreements of the IUU and the International Brotherhood of Electrical Workers # 1393 (IBEW) expired on April 1, 2002 and April 30, 2002, respectively. With regards to the contracts, the parties have negotiated new three-year agreements that will run through March 31, 2005 and April 30, 2005 for the IUU and IBEW, respectively.
Federal Tax Law Changes
In March 2002, President Bush signed into law the Job Creation and Worker Assistance Act of 2002, also known as the Economic Stimulus Package. The primary provision of benefit toCinergy will be the allowance of additional first-year depreciation deduction for tax purposes, equal to 30 percent of the adjusted basis of qualified property. This provision applies to qualifying additions after September 11, 2001. WhileCinergy is currently analyzing the impacts of this provision, we do not believe it will have a material impact on our financial position or results of operations.
Indiana Tax Law Changes
In June 2002, the Indiana Legislature passed a bill, which was signed by the Governor, containing new tax law provisions in Indiana that apply to both utility and non-utility companies with operations in the state. After review of the new provisions, we do not believe that the total impact of these changes will materially impactCinergy orPSI.
Changes in Independent Public Accountants
On April 30, 2002, and as amended on May 15, 2002,Cinergy filed a Current Report on Form 8-K announcing that its board of directors approved the selection of Deloitte & Touche LLP as its independent public accountants for the fiscal year 2002, replacing Arthur Andersen LLP. The decision to change independent public accountants was not the result of any disagreements with Arthur Andersen LLP on matters of accounting principles or practices, financial statement disclosure or auditing scope and procedure. The transition to Deloitte & Touche LLP began in May 2002.
TOCITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information is provided in, and incorporated by reference from, the "Market Risk Sensitive Instruments and Positions" section in "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" in "Part I. Financial Information".
TOCPART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
CITY OF NEWPORT, KENTUCKY
On January 29, 2002,ULH&P instituted litigation proceedings in the Campbell County Circuit Court in the Commonwealth of Kentucky against the City of Newport, Kentucky, City of Newport doing business as (d/b/a/) the Newport Water Works and also known as (a/k/a) City of Newport Water Department and the Kentucky Risk Management Association. The complaint states that on or about October 5, 2000, a water main owned and under the control of the City of Newport and/or the City of Newport d/b/a/ Newport Water Works and a/k/a/ City of Newport Water Department located in and underground at the Newport Shopping Center on Monmouth Street, Newport, Campbell County, Kentucky ruptured. The abrasive action of the pressurized stream of water combined with the sand, gravel, and dirt flowing directly on the surface of the natural gas main, caused a hole that breached the adjacent natural gas main ofULH&P.ULH&Phas incurred total damages in excess of $3.5 million.
In February 2002, a third party complaint was filed by the City of Newport against the owners of the shopping center, Newport Company, Newport Associates, American Diversified Developments, Inc., and Newport Associates Limited Partnership. Subsequently,ULH&P filed a Second Amended Complaint naming the additional parties.
TOCITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) The documents listed below are being filed on behalf ofCinergy Corp.,CG&E,PSI, andULH&P and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:
Previously Filed
Exhibit Designation Registrant Nature of Exhibit as Exhibit to:
------------------- ---------- ----------------- --------------
3(ii)(a) Cinergy Corp. Amended By-Laws of Cinergy Corp. Cinergy Corp. March
effective as of May 2, 2002. 31, 2002, Form 10-Q
10-yy Cinergy Corp. Amendment to the Amended and Restated Cinergy Corp. March
Separation and Retirement Agreement and 31, 2002, Form 10-Q
Waiver and Release of Liability, between
Cinergy Corp. and Larry E. Thomas.
10-zz Cinergy Corp. Second Amendment to the Amended and
Restated Separation and Retirement
Agreement and Waiver and Release of
Liability, between Cinergy Corp. and
Larry E. Thomas.
(b) The following reports on Form 8-K were filed during the quarter or prior to the filing of the Form 10-Q for the quarter ended June 30, 2002.
Date of Report Registrant Item Filed
-------------- ---------- ----------
April 30, 2002 Cinergy Corp., CG&E, PSI, and Item 4. Changes in Registrant's
ULH&P Certifying Accountant
May 15, 2002 Cinergy Corp., CG&E, PSI, and Item 4. Changes in Registrant's
ULH&P Certifying Accountant
TOCSIGNATURES
Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, although Cinergy Corp., The Cincinnati Gas & Electric Company (CG&E), PSI Energy, Inc. (PSI), and The Union Light, Heat and Power Company (ULH&P) believe that the disclosures are adequate to make the information presented not misleading. In the opinion of Cinergy Corp., CG&E, PSI, and ULH&P, these statements reflect all adjustments (which include normal, recurring adjustments) necessary to reflect the results of operations for the respective periods. The unaudited statements are subject to such adjustments as the annual audit by independent public accountants may disclose to be necessary.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed by an officer and the chief accounting officer on their behalf by the undersigned thereunto duly authorized.
CINERGY CORP.
THE CINCINNATI GAS & ELECTRIC COMPANY
PSI ENERGY, INC.
THE UNION LIGHT, HEAT AND POWER COMPANY
---------------------------------------
Registrants
Date: August 13, 2002 /s/ Bernard F. Roberts
------------------
Bernard F. Roberts
Duly Authorized Officer
and
Chief Accounting Officer
TOC
