THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING.
<PAGE>
<TABLE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended June 30, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
<CAPTION>
Commission Registrant; State of Incorporation; I. R. S. Employer
File Number Address; and Telephone Number Identification No.
<C> <S> <C>
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY 31-4154203
(An Ohio Corporation)
215 North Front Street, Columbus, Ohio 43215
Telephone (614) 464-7700
1-3570 INDIANA MICHIGAN POWER COMPANY 35-0410455
(An Indiana Corporation)
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue S.W., Canton, Ohio 44702
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet
the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in General
Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports required to
be filed by Sections 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
The number of shares outstanding of American Electric Power Company, Inc. Common Stock,
par value $6.50, at July 31, 1996 was 187,435,000.
/TABLE
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<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 1996
INDEX
<CAPTION>
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . A-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
Notes to Consolidated Financial Statements . . . . . . . . . A-5 - A-6
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-7 - A-9
AEP Generating Company:
Statements of Income and Statements of Retained Earnings . . B-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . B-2 - B-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . B-4
Notes to Financial Statements. . . . . . . . . . . . . . . . B-5
Management's Narrative Analysis of Results of Operations . . B-6 - B-7
Appalachian Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . C-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . C-2 - C-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . C-4
Notes to Consolidated Financial Statements . . . . . . . . . C-5 - C-6
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . C-7 - C-9
Columbus Southern Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . D-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4
Notes to Consolidated Financial Statements . . . . . . . . . D-5
Management's Narrative Analysis of Results of Operations . . D-6 - D-7
Indiana Michigan Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . E-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4
Notes to Consolidated Financial Statements . . . . . . . . . E-5
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . E-6 - E-8
Kentucky Power Company:
Statements of Income and Statements of Retained Earnings . . F-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4
Notes to Financial Statements. . . . . . . . . . . . . . . . F-5
Management's Narrative Analysis of Results of Operations . . F-6 - F-7
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 1996
INDEX
Page
Ohio Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . G-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
Notes to Consolidated Financial Statements . . . . . . . . G-5
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . G-6 - G-8
Part II. OTHER INFORMATION
Item 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1 - II-3
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3 - II-4
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4
SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-5
This combined Form 10-Q is separately filed by American Electric Power Company, Inc.,
AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company,
Indiana Michigan Power Company, Kentucky Power Company and Ohio 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.
</TABLE>
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<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except per-share amounts)
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . .$1,400,941 $1,305,342 $2,918,722 $2,721,511
OPERATING EXPENSES:
Fuel and Purchased Power . . . . . . 404,914 357,055 845,891 769,042
Other Operation. . . . . . . . . . . 300,723 289,865 604,431 551,817
Maintenance. . . . . . . . . . . . . 139,043 131,388 244,466 261,996
Depreciation and Amortization. . . . 149,414 147,243 298,528 294,420
Taxes Other Than Federal
Income Taxes. . . . . . . . . . . . 120,990 116,757 248,616 246,230
Federal Income Taxes . . . . . . . . 65,232 51,750 164,043 129,166
TOTAL OPERATING EXPENSES . . 1,180,316 1,094,058 2,405,975 2,252,671
OPERATING INCOME . . . . . . . . . . . 220,625 211,284 512,747 468,840
NONOPERATING INCOME (LOSS) . . . . . . 1,030 83 (97) 4,881
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS . . . . . . . . . 221,655 211,367 512,650 473,721
INTEREST CHARGES . . . . . . . . . . . 98,363 100,782 198,388 201,256
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES . . . . . . . . . . . 10,626 14,107 21,584 28,137
NET INCOME . . . . . . . . . . . . . .$ 112,666 $ 96,478 $ 292,678 $ 244,328
AVERAGE NUMBER OF SHARES OUTSTANDING . 187,104 185,671 186,913 185,494
EARNINGS PER SHARE . . . . . . . . . . $0.60 $0.52 $1.57 $1.32
CASH DIVIDENDS PAID PER SHARE. . . . . $0.60 $0.60 $1.20 $1.20
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . .$1,477,852 $1,362,170 $1,409,645 $1,325,581
NET INCOME . . . . . . . . . . . . . . 112,666 96,478 292,678 244,328
DEDUCTIONS:
Cash Dividends Declared. . . . . . . 112,205 111,352 224,188 222,495
Other. . . . . . . . . . . . . . . . 120 36 (58) 154
BALANCE AT END OF PERIOD . . . . . . .$1,478,193 $1,347,260 $1,478,193 $1,347,260
See Notes to Consolidated Financial Statements.
/TABLE
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<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . . $ 9,266,447 $ 9,238,843
Transmission . . . . . . . . . . . . . . . . . . . . . 3,341,340 3,316,664
Distribution . . . . . . . . . . . . . . . . . . . . . 4,274,741 4,184,251
General (including mining assets and nuclear fuel) . . 1,495,849 1,442,086
Construction Work in Progress. . . . . . . . . . . . . 304,473 314,118
Total Electric Utility Plant . . . . . . . . . 18,682,850 18,495,962
Accumulated Depreciation and Amortization. . . . . . . 7,338,529 7,111,123
NET ELECTRIC UTILITY PLANT . . . . . . . . . . 11,344,321 11,384,839
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . 857,200 825,781
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . 110,414 79,955
Accounts Receivable (net). . . . . . . . . . . . . . . 544,950 492,283
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 272,925 271,933
Materials and Supplies . . . . . . . . . . . . . . . . 249,437 251,051
Accrued Utility Revenues . . . . . . . . . . . . . . . 171,650 207,919
Prepayments and Other. . . . . . . . . . . . . . . . . 143,619 98,717
TOTAL CURRENT ASSETS . . . . . . . . . . . . . 1,492,995 1,401,858
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . 1,917,335 1,979,446
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . 245,711 310,377
TOTAL. . . . . . . . . . . . . . . . . . . . $15,857,562 $15,902,301
See Notes to Consolidated Financial Statements.
</TABLE>
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<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1996 1995
Shares Authorized . . . .300,000,000 300,000,000
Shares Issued . . . . . .196,434,992 195,634,992
(8,999,992 shares were held in treasury) . . . . . .$ 1,276,827 $ 1,271,627
Paid-in Capital. . . . . . . . . . . . . . . . . . . . 1,687,101 1,658,524
Retained Earnings. . . . . . . . . . . . . . . . . . . 1,478,193 1,409,645
Total Common Shareholders' Equity. . . . . . . 4,442,121 4,339,796
Cumulative Preferred Stocks of Subsidiaries:
Not Subject to Mandatory Redemption. . . . . . . . . 118,240 148,240
Subject to Mandatory Redemption. . . . . . . . . . . 515,082 515,085
Long-term Debt . . . . . . . . . . . . . . . . . . . . 4,766,759 4,920,329
TOTAL CAPITALIZATION . . . . . . . . . . . . . 9,842,202 9,923,450
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . 927,744 884,707
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year 55,824 144,597
Short-term Debt. . . . . . . . . . . . . . . . . . . . 526,471 365,125
Accounts Payable . . . . . . . . . . . . . . . . . . . 177,719 220,142
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 370,524 420,192
Interest Accrued . . . . . . . . . . . . . . . . . . . 81,018 80,848
Obligations Under Capital Leases . . . . . . . . . . . 97,597 89,692
Other. . . . . . . . . . . . . . . . . . . . . . . . . 284,709 304,466
TOTAL CURRENT LIABILITIES. . . . . . . . . . . 1,593,862 1,625,062
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . 2,631,704 2,656,651
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . 418,190 430,041
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . 245,236 249,875
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . 198,624 132,515
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . .$15,857,562 $15,902,301
See Notes to Consolidated Financial Statements.
</TABLE>
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<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . .$ 292,678 $ 244,328
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . 294,865 285,933
Deferred Federal Income Taxes. . . . . . . . . . . . . . . (9,048) 622
Deferred Investment Tax Credits. . . . . . . . . . . . . . (11,760) (11,903)
Amortization of Deferred Property Taxes. . . . . . . . . . 74,709 72,657
Amortization of Operating Expenses and
Carrying Charges (net). . . . . . . . . . . . . . . . . 18,183 35,448
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . (52,667) (21,648)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . 622 (39,309)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 36,269 12,185
Prepayments and Other Current Assets . . . . . . . . . . . (44,902) (51,879)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . (42,423) (86,474)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . (49,668) (97,782)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . 26,812 -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . 20,615 (8,534)
Net Cash Flows From Operating Activities . . . . . . . 554,285 333,644
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . (215,227) (280,956)
Proceeds from Sale of Property and Other . . . . . . . . . . 6,670 10,551
Net Cash Flows Used For Investing Activities . . . . . (208,557) (270,405)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . . 33,121 23,371
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 309,404 264,415
Change in Short-term Debt (net). . . . . . . . . . . . . . . 161,346 113,890
Retirement of Cumulative Preferred Stock . . . . . . . . . . (38,057) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . . (556,895) (176,088)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . (224,188) (222,495)
Net Cash Flows From (Used For) Financing Activities. . (315,269) 3,093
Net Increase in Cash and Cash Equivalents. . . . . . . . . . . 30,459 66,332
Cash and Cash Equivalents at Beginning of Period . . . . . . . 79,955 62,866
Cash and Cash Equivalents at End of Period . . . . . . . . . .$ 110,414 $ 129,198
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $191,603,000 and
$197,982,000 and for income taxes was $138,641,000 and $151,158,000
in 1996 and 1995, respectively. Noncash acquisitions under capital
leases were $83,502,000 and $49,813,000 in 1996 and 1995, respectively.
See Notes to Consolidated Financial Statements.
/TABLE
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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should
be read in conjunction with the 1995 Annual Report
as incorporated in and filed with the Form 10-K. Certain
prior-period amounts have been reclassified to conform with
current-period presentation.
2. FINANCING AND RELATED ACTIVITIES
During the first six months of 1996, subsidiaries issued
$310 million principal amount of long-term debt: two series of
first mortgage bonds totaling $200 million at 6-3/8% and 6.8%
due in 2001 and 2006, respectively; $40 million of junior
subordinated deferrable interest debentures at 8% due in 2026;
two 6.75% term loans totaling $20 million due 2001 and two term
loans totaling $50 million at 6.42% and 6.57% due in 1999 and
2000, respectively.
The proceeds were used during 1996 to redeem the
outstanding shares of two series of $100 par value cumulative
preferred stock: 75,000 shares at 9.5% and 300,000 shares at
7.08%; and to retire $551 million principal amount of long-term
debt: $492 million of first mortgage bonds with interest rates
ranging from 5% to 9-7/8% with due dates ranging from 1996 to
2022; $31 million of sinking fund debentures with interest
rates ranging from 5-1/8% to 7-7/8% with due dates ranging from
1996 to 1999; and $28 million of term loans with interest rates
ranging from 5.79% to 10.78% all at maturity.
The redemption of three series of first mortgage bonds in
1996, a 7-7/8% series and a 7-1/2% series both due in 2002 and
a 9-7/8% series due in 2020, reduced the restriction on
subsidiaries use of retained earnings for the payment of cash
dividends on their common stock from $230 million to $30
million.
3. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and in 1996 as required by the new open
access rule filed a new non-discriminatory open access
transmission tariff that is basically the same as the
previously filed open access transmission tariff. The open
access final rule also provides under certain conditions for
the recovery of stranded costs from a utility's departing
wholesale customers -- that is costs that were prudently
incurred to serve departing wholesale customers that would go
unrecovered if these customers use open access to move to
another supplier. The other final rule provides for the manner
in which the open access rule will be administered. Management
does not expect these final rules to adversely impact financial
condition.
The Company continues to be involved in certain other
matters discussed in the 1995 Annual Report.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
RESULTS OF OPERATIONS
Net income increased 17% or $16.2 million in the comparative
second quarter and 20% or $48.4 million in the comparative year-to-date period
primarily due to an increase in energy sales in both
periods as a result of growth in the number of customers, increased
customer usage mainly due to weather, and increased weather-related
wholesale sales to other utilities.
Income statement items which changed significantly were:
Increase (Decrease)
Second Quarter Year-To-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . $95.6 7 $197.2 7
Fuel and Purchased
Power Expense. . . . . . . . 47.9 13 76.8 10
Other Operation Expense. . . . 10.9 4 52.6 10
Maintenance Expense. . . . . . 7.7 6 (17.5) (7)
Federal Income Taxes . . . . . 13.5 26 34.9 27
Preferred Stock Dividend
Requirements of Subsidiaries. (3.5) (25) (6.6) (23)
Operating revenues increased in both periods as a result of
increased energy sales to retail and wholesale customers and an
increase in other service revenues. Retail energy sales increased
4% in the comparative second quarter period and 5% in the
comparative year-to-date period reflecting increased energy sales
in all major retail customer classes largely as a result of
increased usage due to the weather and growth in the number of
customers. Energy sales to wholesale customers were up 62% in the
second quarter of 1996 and 53% in the year-to-date period largely
as a result of weather. Higher transmission and other service
revenues from wholesale customers contributed to the increased
revenues in both comparative periods reflecting the increased
demand.
The increase in fuel and purchased power expense was mainly due
to the increase in energy demand. Also contributing to the rise in
fuel expense during both comparative periods was the increased use
of higher cost coal-fired generation due to a reduction in the
availability of low-cost nuclear generation resulting from a
refueling outage at a nuclear unit in the second quarter of 1996.
Other operation expense increased in the comparative second
quarter reflecting an increase in the cost of pollution control
emission allowances and increased rent expense. The increase in
rent expense resulted from a favorable determination by the Indiana
state tax department that resulted in the reversal in the second
quarter of 1995 of a provision for state taxes applicable to the
Rockport Plant Unit 2 operating lease. Also contributing to the
rise in other operation expense during the first six months of this
year were increased employee benefits expenses, rent and other
operating costs of the recently installed Gavin Plant scrubbers and
the amortization, commensurate with recovery in rates, of
previously deferred Gavin scrubber expenses.
Maintenance expense rose in the comparative second quarter
mainly due to a 1996 maintenance outage at both of the Gavin units.
In the year-to-date period, maintenance expense declined primarily
due to the reversal in March 1996 of a loss contingency recorded in
March 1995 for deferred Virginia retail incremental storm damage
expenses, reductions in the number of employees performing
maintenance on the Company's nuclear plant and lower payments for
contract labor at the nuclear plant.
The increase in both periods in federal income tax expense
attributable to operations was due to an increase in pre-tax
operating income and, in the comparative second quarter period, to
changes in certain book/tax differences accounted for on a flow-through basis
for ratemaking and financial reporting purposes.
Preferred stock dividend requirements of the subsidiaries
decreased in both comparative periods reflecting preferred stock
redemptions in November 1995 and the first half of 1996.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months were $300 million.
During the first six months of 1996 subsidiaries issued $310
million principal amount of long-term debt at interest rates
ranging from 6-3/8% to 8%; retired $551 million principal amount of
long-term debt with interest rates ranging from 5% to 10.78%;
redeemed 375,000 shares of $100 par value cumulative preferred
stock at 9.5% and 7.08% and increased short-term debt by $161
million.
NEW FERC RULES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access transmission
and stranded cost recovery in the wholesale market. In the open
access final rule, all public utilities with transmission lines are
required to file non-discriminatory open access tariffs that offer
non-affiliated wholesale customers the same transmission service at
the same terms and costs as they provide to themselves and their
affiliates. The Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the
provisions of a proposed FERC rule and as required by the new open
access rule filed a new non-discriminatory open access transmission
tariff that is basically the same as the previously filed open
access transmission tariff. The open access final rule also
provides under certain conditions for the recovery of stranded
costs from a utility's departing wholesale customers -- that is
costs that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule provides
for the manner in which the open access rule will be administered.
Management does not expect these final rules to adversely impact
financial condition.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $55,313 $53,819 $112,797 $113,994
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 21,736 22,078 45,268 48,640
Rent - Rockport Plant Unit 2 . . . . . 17,071 15,474 34,148 32,619
Other Operation. . . . . . . . . . . . 2,962 3,005 6,111 5,677
Maintenance. . . . . . . . . . . . . . 3,883 3,458 7,376 6,341
Depreciation . . . . . . . . . . . . . 5,413 5,417 10,826 10,834
Taxes Other Than Federal Income Taxes. 907 299 1,882 1,278
Federal Income Taxes . . . . . . . . . 886 746 1,937 1,563
TOTAL OPERATING EXPENSES . . . 52,858 50,477 107,548 106,952
OPERATING INCOME . . . . . . . . . . . . 2,455 3,342 5,249 7,042
NONOPERATING INCOME. . . . . . . . . . . 834 992 1,624 1,821
INCOME BEFORE INTEREST CHARGES . . . . . 3,289 4,334 6,873 8,863
INTEREST CHARGES . . . . . . . . . . . . 1,058 2,400 2,144 4,810
NET INCOME . . . . . . . . . . . . . . . $ 2,231 $ 1,934 $ 4,729 $ 4,053
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $1,953 $4,387 $1,955 $4,268
NET INCOME . . . . . . . . . . . . . . . 2,231 1,934 4,729 4,053
CASH DIVIDENDS DECLARED. . . . . . . . . 2,000 2,000 4,500 4,000
BALANCE AT END OF PERIOD . . . . . . . . $2,184 $4,321 $2,184 $4,321
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . . $627,581 $627,298
General . . . . . . . . . . . . . . . . . . . . . . . . 2,910 2,919
Construction Work in Progress . . . . . . . . . . . . . 1,825 1,397
Total Electric Utility Plant. . . . . . . . . . 632,316 631,614
Accumulated Depreciation. . . . . . . . . . . . . . . . 228,273 218,055
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . 404,043 413,559
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . 72 22
Accounts Receivable . . . . . . . . . . . . . . . . . . 19,637 19,028
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . 20,914 19,008
Materials and Supplies. . . . . . . . . . . . . . . . . 4,745 4,820
Prepayments . . . . . . . . . . . . . . . . . . . . . . 521 673
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . 45,889 43,551
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . 5,967 6,076
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . 3,229 1,693
TOTAL . . . . . . . . . . . . . . . . . . . . $459,128 $464,879
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares . . . . . . $ 1,000 $ 1,000
Paid-in Capital . . . . . . . . . . . . . . . . . . . . 47,235 47,735
Retained Earnings . . . . . . . . . . . . . . . . . . . 2,184 1,955
Total Common Shareholder's Equity . . . . . . . 50,419 50,690
Long-term Debt. . . . . . . . . . . . . . . . . . . . . 89,546 89,538
TOTAL CAPITALIZATION. . . . . . . . . . . . . . 139,965 140,228
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . 1,814 1,830
CURRENT LIABILITIES:
Short-term Debt - Notes Payable . . . . . . . . . . . . 17,325 21,725
Accounts Payable. . . . . . . . . . . . . . . . . . . . 8,510 9,094
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . 6,384 2,997
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . 4,963 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . 2,631 4,508
TOTAL CURRENT LIABILITIES . . . . . . . . . . . 39,813 43,287
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . 147,257 150,043
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . 75,262 76,949
Amounts Due to Customers for Income Taxes . . . . . . . 35,870 36,517
Other . . . . . . . . . . . . . . . . . . . . . . . . . 242 201
TOTAL REGULATORY LIABILITIES. . . . . . . . . . 111,374 113,667
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . 18,905 15,824
TOTAL . . . . . . . . . . . . . . . . . . . . $459,128 $464,879
See Notes to Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 4,729 $ 4,053
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . 10,826 10,834
Deferred Federal Income Taxes. . . . . . . . . . . . . 2,434 3,006
Deferred Investment Tax Credits. . . . . . . . . . . . (1,687) (1,691)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . (2,786) (2,786)
Deferred Property Taxes. . . . . . . . . . . . . . . . (1,562) (1,533)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . (609) (842)
Fuel, Materials and Supplies . . . . . . . . . . . . . (1,831) (1,017)
Accounts Payable . . . . . . . . . . . . . . . . . . . (584) (3,157)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 3,387 789
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . - (1,527)
Other (net). . . . . . . . . . . . . . . . . . . . . . . (1,616) (2,067)
Net Cash Flows From Operating Activities . . . . . 10,701 4,062
INVESTING ACTIVITIES - Construction Expenditures . . . . . (1,251) (2,566)
FINANCING ACTIVITIES:
Capital Contributions Returned to Parent Company . . . . (500) -
Change in Short-term Debt (net). . . . . . . . . . . . . (4,400) 2,500
Dividends Paid . . . . . . . . . . . . . . . . . . . . . (4,500) (4,000)
Net Cash Flows Used For Financing Activities . . . (9,400) (1,500)
Net Increase (Decrease) in Cash and Cash Equivalents . . . 50 (4)
Cash and Cash Equivalents at Beginning of Period . . . . . 22 7
Cash and Cash Equivalents at End of Period . . . . . . . . $ 72 $ 3
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,035,000 and
$4,632,000 and for income taxes was $(764,000) and $(1,269,000) in 1996 and
1995, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
GENERAL
The accompanying unaudited financial statements should be read
in conjunction with the 1995 Annual Report as incorporated in and
filed with the Form 10-K. Certain prior-period amounts have been
reclassified to conform with current-period presentation.
<PAGE>
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
Operating revenues are derived from the sale of Rockport Plant
energy and capacity to two affiliated companies and one
unaffiliated utility pursuant to Federal Energy Regulatory
Commission (FERC) approved long-term unit power agreements. The
unit power agreements provide for recovery of costs including a
FERC approved rate of return on common equity and a return on other
capital net of temporary cash investments.
Net income increased $0.3 million or 15% in the comparative
second quarter and $0.7 million or 17% in the comparative year-to-date period
resulting from the recovery of interest expense through
the return on other capital component of the unit power bills
compared to 1995 when the unit power agreement mechanism prevented
the Company from recovering all interest costs in the unit power
bills.
Income statement items which changed significantly were as
follows:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $ 1.5 3 $(1.2) (1)
Fuel Expense . . . . . . . . (0.3) (2) (3.4) (7)
Rent Expense-Rockport Plant
Unit 2. . . . . . . . . . . 1.6 10 1.5 5
Other Operation Expense. . . 0.0 N.M. 0.4 8
Maintenance Expense. . . . . 0.4 12 1.0 16
Taxes Other Than Federal
Income Taxes . . . . . . . 0.6 203 0.6 47
Federal Income Taxes . . . . 0.1 19 0.4 24
Nonoperating Income. . . . . (0.2) (16) (0.2) (11)
Interest Charges . . . . . . (1.3) (56) (2.7) (55)
N.M. = Not Meaningful
The increase in operating revenues for the second quarter
reflects increased recoverable operating expenses, primarily rent
expense for Rockport Plant Unit 2, offset in part by a reduction in
the return on other capital due to a decrease in long-term debt
interest expense. The revenue decrease in the year-to-date period
resulted from the reduction in the return on other capital,
partially offset by an increase in recoverable operating expenses.
The decline in fuel expense was attributable to a reduction in
generation as Rockport Plant Unit 2 was out-of-service for planned
general boiler inspection and repair during March and April 1996.
Rent expense for Rockport Plant Unit 2 increased in both
periods due to the effect of a favorable determination by the
Indiana state tax department that resulted in a May 1995 reversal
of a provision for Indiana gross income tax applicable to the
lease.
Other operation expense increased in the year-to-date period
mainly due to increased AEP Service Corporation billings for
managerial, engineering and other professional services; increased
employee benefits expense caused primarily by a reduction in COLI
death benefits; and the recording in 1996 of the expense of
destroyed railroad coal cars.
The increase in maintenance expense during the second quarter
and year-to-date periods resulted from the general boiler
inspection and repairs performed on Rockport Unit 2 in 1996.
Taxes other than federal income taxes increased for both
periods due to the effect of a favorable Indiana property tax
accrual adjustment recorded in the second quarter of 1995.
Federal income tax expense attributable to operations increased
primarily due to an increase in pre-tax operating income.
The decrease in nonoperating income for both periods reflects
a decline in interest income earned on temporary cash investments
as the amounts available for investment declined in 1996.
Interest charges declined in both periods primarily due to
refinancing of $90 million of long-term debt at lower variable
rates and the retirement of $20 million of long-term debt in the
third quarter of 1995.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $379,887 $339,957 $820,859 $747,473
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 91,907 72,082 181,503 171,975
Purchased Power. . . . . . . . . . . . 76,510 72,894 167,637 136,852
Other Operation. . . . . . . . . . . . 61,066 55,942 123,809 105,915
Maintenance. . . . . . . . . . . . . . 36,225 32,962 59,376 69,426
Depreciation and Amortization. . . . . 33,168 33,338 66,041 66,428
Taxes Other Than Federal Income Taxes. 29,014 27,613 60,316 59,342
Federal Income Taxes . . . . . . . . . 8,778 6,287 35,321 29,552
TOTAL OPERATING EXPENSES . . . 336,668 301,118 694,003 639,490
OPERATING INCOME . . . . . . . . . . . . 43,219 38,839 126,856 107,983
NONOPERATING INCOME (LOSS) . . . . . . . (21) (3,804) 576 (4,639)
INCOME BEFORE INTEREST CHARGES . . . . . 43,198 35,035 127,432 103,344
INTEREST CHARGES . . . . . . . . . . . . 27,092 26,549 55,702 52,921
NET INCOME . . . . . . . . . . . . . . . 16,106 8,486 71,730 50,423
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 4,100 4,097 8,201 8,201
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 12,006 $ 4,389 $ 63,529 $ 42,222
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $223,469 $217,485 $199,021 $206,361
NET INCOME . . . . . . . . . . . . . . . 16,106 8,486 71,730 50,423
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 27,075 26,709 54,150 53,418
Cumulative Preferred Stock . . . . . 3,917 3,919 7,834 7,838
Capital Stock Expense. . . . . . . . . 184 178 368 363
BALANCE AT END OF PERIOD . . . . . . . . $208,399 $195,165 $208,399 $195,165
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,863,422 $1,857,621
Transmission . . . . . . . . . . . . . . . . . . . . 1,045,165 1,041,415
Distribution . . . . . . . . . . . . . . . . . . . . 1,448,028 1,409,407
General. . . . . . . . . . . . . . . . . . . . . . . 182,296 169,602
Construction Work in Progress. . . . . . . . . . . . 74,856 80,391
Total Electric Utility Plant . . . . . . . . 4,613,767 4,558,436
Accumulated Depreciation and Amortization. . . . . . 1,741,060 1,694,746
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,872,707 2,863,690
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 30,111 31,523
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 15,310 8,664
Accounts Receivable (net). . . . . . . . . . . . . . 177,436 140,158
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 53,534 69,037
Materials and Supplies . . . . . . . . . . . . . . . 54,947 55,756
Accrued Utility Revenues . . . . . . . . . . . . . . 50,983 65,078
Prepayments. . . . . . . . . . . . . . . . . . . . . 19,371 8,579
TOTAL CURRENT ASSETS . . . . . . . . . . . . 371,581 347,272
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 430,754 435,352
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 55,159 57,541
TOTAL. . . . . . . . . . . . . . . . . . . $3,760,312 $3,735,378
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares. . . . . . . . . . $ 260,458 $ 260,458
Paid-in Capital. . . . . . . . . . . . . . . . . . . 550,419 525,051
Retained Earnings. . . . . . . . . . . . . . . . . . 208,399 199,021
Total Common Shareholder's Equity. . . . . . 1,019,276 984,530
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 55,000 55,000
Subject to Mandatory Redemption. . . . . . . . . . 190,082 190,085
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,299,447 1,278,433
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,563,805 2,508,048
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 94,768 102,178
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . - 7,251
Short-term Debt. . . . . . . . . . . . . . . . . . . 93,750 125,525
Accounts Payable . . . . . . . . . . . . . . . . . . 83,043 82,224
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 47,892 48,666
Customer Deposits. . . . . . . . . . . . . . . . . . 14,178 14,411
Interest Accrued . . . . . . . . . . . . . . . . . . 21,460 19,057
Revenue Refunds Accrued. . . . . . . . . . . . . . . 26,812 -
Other. . . . . . . . . . . . . . . . . . . . . . . . 59,575 75,303
TOTAL CURRENT LIABILITIES. . . . . . . . . . 346,710 372,437
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 656,494 656,006
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 86,892 89,682
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 11,643 7,027
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . . . . . $3,760,312 $3,735,378
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 71,730 $ 50,423
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . 66,694 67,262
Deferred Federal Income Taxes. . . . . . . . . . . . . . . 2,030 (3,365)
Deferred Investment Tax Credits. . . . . . . . . . . . . . (2,409) (2,430)
Storm Damage Expense Amortization (Deferrals). . . . . . . (2,003) 11,548
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . (37,278) (2,793)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . 16,312 (16,826)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 14,095 9,383
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . (10,792) (11,076)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . 819 (16,172)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . 26,812 -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . (9,135) 11,214
Net Cash Flows From Operating Activities . . . . . . . 136,875 97,168
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . (74,210) (101,704)
Proceeds from Sale of Property . . . . . . . . . . . . . . . 1,079 7,050
Net Cash Flows Used For Investing Activities . . . . . (73,131) (94,654)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . . 25,000 15,000
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 200,825 128,785
Change in Short-term Debt (net). . . . . . . . . . . . . . . (31,775) (10,350)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . (189,164) (74,950)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . (54,150) (53,418)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . (7,834) (7,837)
Net Cash Flows Used For Financing Activities . . . . . (57,098) (2,770)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . 6,646 (256)
Cash and Cash Equivalents at Beginning of Period . . . . . . . 8,664 5,297
Cash and Cash Equivalents at End of Period . . . . . . . . . . $ 15,310 $ 5,041
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $51,719,000 and $51,472,000 and
for income taxes was $29,226,000 and $32,665,000 in 1996 and 1995, respectively.
Noncash acquisitions under capital leases were $5,584,000 and $8,827,000 in 1996
and 1995, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1995 Annual
Report as incorporated in and filed with the Form 10-K.
2. RATE MATTERS
Virginia
On May 24, 1996 the Virginia State Corporation Commission
(Virginia SCC) issued a final order and concluded that the
Company was not entitled to a rate increase. The Company had
requested a base rate increase of $15.7 million annually in
September 1994 which included, among other things, recovery
over three years of $23.9 million of incremental storm damages
expenses deferred in 1994. The Virginia SCC had authorized the
Company to collect the rate increase subject to refund
beginning in November 1994. The Order also concluded that the
Company had recovered $11.9 million of the 1994 deferred
incremental storm damage expenses through existing rates. In
accordance with the Order, the net deferred storm damage
expenses will be amortized commensurate with recovery over a
five-year period effective July 1, 1996. Therefore, the
Company wrote off $11.9 million of deferred storm damages which
were not recoverable and reversed $6.9 million of previously
amortized storm damage. As of June 30, 1996 the revenue refund
liability of $26.8 million, including interest of $1.7 million,
had been provided for and the refund is to be completed by
September 3, 1996.
3. FINANCING ACTIVITIES
In February 1996 the Company redeemed $16 million of first
mortgage bonds with interest rates ranging from 8.75% to 9-7/8%
due 2020 through 2022. In March 1996 the Company issued $100
million of 6-3/8% Series First Mortgage Bonds due in 2001 and
$100 million of 6.80% Series First Mortgage Bonds due in 2006.
The proceeds were used to reduce outstanding short-term debt
and in April and May 1996 to redeem $165 million of first
mortgage bonds with interest rates ranging from 7-1/2% to 9-7/8% due 1998
through 2022. The April redemption of these
first mortgage bonds removed the restriction on the use of
retained earnings for common stock dividends.
In June 1996, the Company received a $25 million cash
capital contribution from its parent which was credited to
paid-in capital.
4. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and as required by the new open access rule
filed a new non-discriminatory open access transmission tariff
that is basically the same as the previously filed open access
transmission tariff. The open access final rule also provides
under certain conditions for the recovery of stranded costs
from a utility's departing wholesale customers -- that is costs
that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule
provides for the manner in which the open access rule will be
administered. Management does not expect these final rules to
adversely impact financial condition.
The Company continues to be involved in certain other
matters discussed in its 1995 Annual Report.
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
RESULTS OF OPERATIONS
Net income increased $7.6 million or 90% in the comparative
second quarter and $21.3 million or 42% in the comparative year-to-date period
as a result of increased demand for energy by
residential and wholesale customers and an increase in nonoperating
income due to the effect of a loss in 1995 resulting from the sale
of coal-mining assets owned by the Company.
Income statement lines which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $39.9 12 $73.4 10
Fuel Expense . . . . . . . . 19.8 28 9.5 6
Purchased Power Expense. . . 3.6 5 30.8 22
Other Operation Expense. . . 5.1 9 17.9 17
Maintenance Expense. . . . . 3.3 10 (10.1) (14)
Taxes Other Than Federal
Income Taxes . . . . . . . 1.4 5 1.0 2
Federal Income Taxes . . . . 2.5 40 5.8 20
Nonoperating Income (Loss) . 3.8 N.M. 5.2 N.M.
N.M. = Not Meaningful
Substantial increases in wholesale and retail energy sales
resulted in the increases in revenues for the quarter and year-to-date period.
Wholesale energy sales increased 98% in the quarter
and 84% in the year-to-date period primarily due to increased
energy sales to unaffiliated utilities by the AEP System Power Pool
(Power Pool) resulting from unseasonable weather in 1996 and
increased amounts of energy supplied to the Power Pool to meet the
weather related load requirements of other Power Pool members.
Residential and commercial sales increased 9% and 5%, respectively,
in the second quarter and 12% and 6%, respectively, in the year-to-date period.
The sales increases were due to growth in the number
of customers and customer usage due mainly to unseasonable weather
in 1996.
The increase in fuel and purchased power expenses reflected the
rise in energy demand which resulted in increased generation and
additional energy purchases from the Power Pool to meet the
increase in demand.
Other operation expense increased in the comparative quarter
and year-to-date periods primarily due to the expensing of $3.9
million of previously deferred research costs, an increase in
employee benefit costs and the expensing of $2.8 million of
previously capitalized software costs as a result of a final rate
order from the Virginia State Corporation Commission (Virginia
SCC).
Maintenance expense increased for the quarter largely due to
an increase in engineering and other professional services billed
by the AEP Service Corporation. In the year-to-date period, the
reversal in March 1996 of a $7.9 million loss provision for
deferred Virginia retail incremental storm damage expenses recorded
in March 1995 accounted for the decrease in maintenance expense.
The provision was reversed as a result of a Virginia SCC Hearing
Examiner's Report which was not the same as the final order.
Taxes other than federal income taxes increased primarily due
to the West Virginia business and occupation (B&O) tax. Prior to
June 1995 the B&O tax was computed on the basis of generation;
subsequently the tax was based on generating capacity. In 1995 the
Company's generation was at a reduced level.
The increase in federal income tax expense was primarily due
to an increase in pre-tax operating income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months of 1996 were $80 million.
In March 1996, the Company issued $100 million of 6-3/8% Series
First Mortgage Bonds due in 2001 and $100 million of 6.80% Series
First Mortgage Bonds due in 2006. The proceeds were used to reduce
outstanding short-term debt and in April and May 1996 to redeem
$165 million of first mortgage bonds with interest rates ranging
from 7-1/2% to 9-7/8% due 1998 through 2022. The redemption of
these first mortgage bonds eliminated the restriction on the use of
retained earnings for common stock dividends.
In June 1996, the Company received a $25 million cash capital
contribution from its parent which was credited to paid-in-capital.
NEW FERC RULES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access transmission
and stranded cost recovery in the wholesale market. In the open
access final rule, all public utilities with transmission lines are
required to file non-discriminatory open access tariffs that offer
non-affiliated wholesale customers the same transmission service at
the same terms and costs as they provide to themselves and their
affiliates. The Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the
provisions of a proposed FERC rule and as required by the new open
access rule filed a new non-discriminatory open access transmission
tariff that is basically the same as the previously filed open
access transmission tariff. The open access final rule also
provides under certain conditions for the recovery of stranded
costs from a utility's departing wholesale customers -- that is
costs that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule provides
for the manner in which the open access rule will be administered.
Management does not expect these final rules to adversely impact
financial condition.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $269,023 $246,165 $540,063 $503,170
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 45,169 36,748 92,675 88,054
Purchased Power. . . . . . . . . . . . 39,971 41,180 83,440 73,099
Other Operation. . . . . . . . . . . . 46,844 44,541 91,008 89,603
Maintenance. . . . . . . . . . . . . . 17,409 18,586 31,332 33,989
Depreciation . . . . . . . . . . . . . 21,966 21,307 43,757 42,454
Amortization of Zimmer
Plant Phase-in Costs . . . . . . . . 7,965 7,472 16,413 15,523
Taxes Other Than Federal Income Taxes. 28,088 27,161 56,195 54,192
Federal Income Taxes . . . . . . . . . 14,438 9,991 29,644 22,640
TOTAL OPERATING EXPENSES . . . 221,850 206,986 444,464 419,554
OPERATING INCOME . . . . . . . . . . . . 47,173 39,179 95,599 83,616
NONOPERATING INCOME (LOSS) . . . . . . . 385 1,073 (2,520) 2,439
INCOME BEFORE INTEREST CHARGES . . . . . 47,558 40,252 93,079 86,055
INTEREST CHARGES . . . . . . . . . . . . 20,062 19,702 40,457 39,980
NET INCOME . . . . . . . . . . . . . . . 27,496 20,550 52,622 46,075
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,374 3,203 3,044 6,406
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 26,122 $ 17,347 $ 49,578 $ 39,669
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $78,984 $51,288 $74,320 $46,976
NET INCOME . . . . . . . . . . . . . . . 27,496 20,550 52,622 46,075
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 18,969 17,975 37,938 35,950
Cumulative Preferred Stock . . . . . 1,422 3,203 2,844 6,406
Capital Stock Expense. . . . . . . . . 70 35 141 70
BALANCE AT END OF PERIOD . . . . . . . . $86,019 $50,625 $86,019 $50,625
The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,489,791 $1,481,309
Transmission . . . . . . . . . . . . . . . . . . . . 320,010 314,413
Distribution . . . . . . . . . . . . . . . . . . . . 864,380 843,228
General. . . . . . . . . . . . . . . . . . . . . . . 124,518 117,185
Construction Work in Progress. . . . . . . . . . . . 56,825 64,073
Total Electric Utility Plant . . . . . . . . 2,855,524 2,820,208
Accumulated Depreciation . . . . . . . . . . . . . . 987,842 953,170
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,867,682 1,867,038
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 25,133 25,950
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 9,371 10,577
Accounts Receivable (net). . . . . . . . . . . . . . 64,667 65,853
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 21,387 24,316
Materials and Supplies . . . . . . . . . . . . . . . 23,973 23,519
Accrued Utility Revenues . . . . . . . . . . . . . . 41,088 40,389
Prepayments and Other. . . . . . . . . . . . . . . . 42,956 32,116
TOTAL CURRENT ASSETS . . . . . . . . . . . . 203,442 196,770
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 418,834 438,005
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 34,368 66,363
TOTAL. . . . . . . . . . . . . . . . . . . $2,549,459 $2,594,126
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares. . . . . . . . . . $ 41,026 $ 41,026
Paid-in Capital. . . . . . . . . . . . . . . . . . . 574,568 574,427
Retained Earnings. . . . . . . . . . . . . . . . . . 86,019 74,320
Total Common Shareholder's Equity. . . . . . 701,613 689,773
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 75,000 75,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 896,953 990,796
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,673,566 1,755,569
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 34,342 34,571
CURRENT LIABILITIES:
Preferred Stock Due Within One Year. . . . . . . . . - 7,500
Long-term Debt Due Within One Year . . . . . . . . . 30,000 -
Short-term Debt. . . . . . . . . . . . . . . . . . . 98,550 34,325
Accounts Payable . . . . . . . . . . . . . . . . . . 43,220 52,029
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 90,900 120,093
Interest Accrued . . . . . . . . . . . . . . . . . . 16,339 17,016
Other. . . . . . . . . . . . . . . . . . . . . . . . 24,542 30,955
TOTAL CURRENT LIABILITIES. . . . . . . . . . 303,551 261,918
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 457,038 464,413
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 59,186 61,010
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 21,776 16,645
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . $2,549,459 $2,594,126
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 52,622 $ 46,075
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 43,571 42,264
Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,789) (2,804)
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,824) (1,834)
Amortization of Deferred Property Taxes. . . . . . . . . 30,446 28,872
Amortization of Zimmer Plant Operating Expenses and
Carrying Charges . . . . . . . . . . . . . . . . . . . 15,211 13,180
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 1,186 4,541
Fuel, Materials and Supplies . . . . . . . . . . . . . . 2,475 2,383
Accrued Utility Revenues . . . . . . . . . . . . . . . . (699) (3,665)
Prepayments and Other Current Assets . . . . . . . . . . (10,840) (11,443)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (8,809) (6,366)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (29,193) (47,403)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,732) (2,235)
Net Cash Flows From Operating Activities . . . . . . 87,625 61,565
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (38,642) (47,067)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,301 2,262
Net Cash Flows Used For Investing Activities . . . . (36,341) (44,805)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . 64,225 72,175
Retirement of Cumulative Preferred Stock . . . . . . . . . (7,500) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (68,255) (50,000)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (37,938) (35,950)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,022) (6,406)
Net Cash Flows Used For Financing Activities . . . . (52,490) (20,181)
Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (1,206) (3,421)
Cash and Cash Equivalents at Beginning of Period . . . . . . 10,577 14,065
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 9,371 $ 10,644
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $39,244,000 and $38,666,000
and for income taxes was $18,674,000 and $32,312,000 in 1996 and 1995, respectively.
Noncash acquisitions under capital leases were $6,941,000 and $5,416,000 in 1996
and 1995, respectively.
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1995 Annual
Report as incorporated in and filed with the Form 10-K.
2. FINANCING ACTIVITIES
On June 12, 1996, the Company redeemed the entire $50
million outstanding principal amount of its 9.625% Series First
Mortgage Bonds Due 2021 at the regular redemption price of
107.22%.
The Company redeemed on August 1, 1996 the entire $30
million outstanding principal amount of the 9.31% Series First
Mortgage Bonds Due 2001 at the regular redemption price of
102.66%. Therefore at June 30, 1996 this debt is classified
as a current liability.
3. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and as required by the new open access rule
filed a new non-discriminatory open access transmission tariff
that is basically the same as the previously filed open access
transmission tariff. The open access final rule also provides
under certain conditions for the recovery of stranded costs
from a utility's departing wholesale customers -- that is costs
that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule
provides for the manner in which the open access rule will be
administered. Management does not expect these final rules to
adversely impact financial condition.
The Company continues to be involved in certain other
matters discussed in its 1995 Annual Report.
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
Net income increased 34% in the second quarter and 14% on a
year-to-date basis mainly due to increased energy sales. In the
year-to-date period, the effect of the sales increase was partly
offset by decreased nonoperating income due to provisions recorded
in the first quarter for certain demand side management programs
and for environmental remediation costs.
Income statement lines which changed significantly were as
follows:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $22.9 9 $36.9 7
Fuel Expense. . . . . . . . 8.4 23 4.6 5
Purchased Power Expense . . (1.2) (3) 10.3 14
Other Operation Expense . . 2.3 5 1.4 2
Maintenance Expense . . . . (1.2) (6) (2.7) (8)
Amortization of Zimmer
Plant Phase-in Costs . . . 0.5 7 0.9 6
Federal Income Taxes. . . . 4.4 45 7.0 31
Nonoperating Income (Loss). (0.7) (64) (5.0) N.M.
N.M. = Not Meaningful
The operating revenues increased in both comparative periods
due to increased energy sales to both retail and wholesale
customers. Energy sales to retail customers increased due mainly
to unseasonable weather in 1996 and growth in the number of
residential and commercial customers. Energy sales to wholesale
customers doubled in both periods primarily due to an increase in
sales made by the AEP System Power Pool (Power Pool) to
unaffiliated utilities largely as a result of the unseasonable
weather.
The increase in fuel expense was due to increased generation
resulting from the additional sales and an increased availability
of generating capacity. In 1996 all generating units were in-service while in
the second quarter of 1995 several Conesville
Plant units and the Picway Plant were out of service for scheduled
repairs to the boiler facilities. Purchased power expense
increased significantly in the year-to-date period due to increased
energy purchases from the Power Pool to supply the increased energy
demands of retail and wholesale customers.
The increase in other operation expense was mostly due to
certain demand side management program expenses and rents for new
customer service center equipment.
Maintenance expense decreased due to a staffing reduction at
the Company's power plants in the fourth quarter of 1995 as part of
an AEP restructuring program to functionally realign operations and
a reduction in plant maintenance work. Last year's maintenance
expense included expenditures associated with the outages at the
Conesville and Picway plants.
The amortization of Zimmer Plant phase-in costs increased due
to the increase in sales. In accordance with a 1994 rate order the
Company is collecting deferred Zimmer Plant costs under a phase-in
plan through a temporary rate surcharge. The amount of recovery
and related amortization is a function of retail sales volume.
The increase in federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating
income.
Nonoperating income declined in the year-to-date period due to
after tax provisions of $2.2 million for certain demand side
management program costs and $0.9 million for the clean-up of
underground fuel storage tanks at one of the Company's facilities.
Also contributing to the year-to-date decline in nonoperating
income and the primary cause of the decline in the comparative
quarter was a decrease in the return on unrecovered Zimmer Plant
deferrals due to the declining balance of unamortized phase-in plan
deferrals.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $323,494 $307,820 $653,377 $634,997
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 56,532 56,863 116,555 119,617
Purchased Power. . . . . . . . . . . . 34,653 25,782 69,316 53,411
Other Operation. . . . . . . . . . . . 78,686 74,003 157,496 147,636
Maintenance. . . . . . . . . . . . . . 30,107 32,102 56,549 64,574
Depreciation and Amortization. . . . . 35,086 34,652 69,978 69,083
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals. . . . . . . 3,911 3,911 7,822 7,822
Taxes Other Than Federal Income Taxes. 18,440 16,233 38,361 35,833
Federal Income Taxes . . . . . . . . . 15,649 12,888 33,852 29,324
TOTAL OPERATING EXPENSES . . . 273,064 256,434 549,929 527,300
OPERATING INCOME . . . . . . . . . . . . 50,430 51,386 103,448 107,697
NONOPERATING INCOME (LOSS) . . . . . . . 272 550 (365) 651
INCOME BEFORE INTEREST CHARGES . . . . . 50,702 51,936 103,083 108,348
INTEREST CHARGES . . . . . . . . . . . . 17,195 18,156 33,809 36,180
NET INCOME . . . . . . . . . . . . . . . 33,507 33,780 69,274 72,168
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 2,910 2,914 5,858 5,812
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 30,597 $ 30,866 $ 63,416 $ 66,356
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $239,799 $224,385 $235,107 $216,658
NET INCOME . . . . . . . . . . . . . . . 33,507 33,780 69,274 72,168
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 28,127 27,713 56,254 55,426
Cumulative Preferred Stock . . . . . 2,359 2,890 5,249 5,780
Capital Stock Expense. . . . . . . . . 551 57 609 115
BALANCE AT END OF PERIOD . . . . . . . . $242,269 $227,505 $242,269 $227,505
The common stock of the Company is wholly owned
by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,516,995 $2,507,667
Transmission . . . . . . . . . . . . . . . . . . . . 873,515 867,541
Distribution . . . . . . . . . . . . . . . . . . . . 683,154 666,810
General (including nuclear fuel) . . . . . . . . . . 210,781 186,959
Construction Work in Progress. . . . . . . . . . . . 71,630 90,587
Total Electric Utility Plant . . . . . . . . 4,356,075 4,319,564
Accumulated Depreciation and Amortization. . . . . . 1,802,986 1,751,965
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,553,089 2,567,599
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 453,260 433,619
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 164,683 150,994
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 6,236 13,723
Accounts Receivable. . . . . . . . . . . . . . . . . 125,051 115,765
Allowance for Uncollectible Accounts . . . . . . . . (448) (334)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 30,316 29,093
Materials and Supplies . . . . . . . . . . . . . . . 74,234 72,861
Accrued Utility Revenues . . . . . . . . . . . . . . 32,534 43,937
Prepayments. . . . . . . . . . . . . . . . . . . . . 13,404 10,191
TOTAL CURRENT ASSETS . . . . . . . . . . . . 281,327 285,236
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 436,689 458,525
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 35,798 32,364
TOTAL. . . . . . . . . . . . . . . . . . . $3,924,846 $3,928,337
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584
Paid-in Capital. . . . . . . . . . . . . . . . . . . 731,157 731,102
Retained Earnings. . . . . . . . . . . . . . . . . . 242,269 235,107
Total Common Shareholder's Equity. . . . . . 1,030,010 1,022,793
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 22,000 52,000
Subject to Mandatory Redemption. . . . . . . . . . 135,000 135,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,037,512 1,034,048
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,224,522 2,243,841
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 285,797 269,392
Other. . . . . . . . . . . . . . . . . . . . . . . . 195,142 184,103
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 480,939 453,495
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . - 6,053
Short-term Debt. . . . . . . . . . . . . . . . . . . 86,725 89,975
Accounts Payable . . . . . . . . . . . . . . . . . . 51,027 60,706
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 74,182 71,696
Interest Accrued . . . . . . . . . . . . . . . . . . 16,090 16,158
Obligations Under Capital Leases . . . . . . . . . . 37,197 31,776
Other. . . . . . . . . . . . . . . . . . . . . . . . 66,430 74,463
TOTAL CURRENT LIABILITIES. . . . . . . . . . 331,651 350,827
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 599,210 612,147
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 151,239 155,202
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 97,979 99,832
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 39,306 12,993
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . $3,924,846 $3,928,337
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 69,274 $ 72,168
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 73,820 73,979
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals. . . . . . . . . . . . . . . . 7,822 7,822
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net). . . . . . . . . . . . (4,850) 14,446
Deferred Federal Income Taxes. . . . . . . . . . . . . . (7,712) (12,973)
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,963) (3,993)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (9,172) 6,082
Fuel, Materials and Supplies . . . . . . . . . . . . . . (2,596) 44
Accrued Utility Revenues . . . . . . . . . . . . . . . . 11,403 (2,620)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (9,679) (28,072)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,486 (7,933)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 5,306 (26,222)
Net Cash Flows From Operating Activities . . . . . . 132,139 92,728
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (37,128) (51,710)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 853 964
Net Cash Flows Used For Investing Activities . . . . (36,275) (50,746)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 38,579 96,819
Change in Short-term Debt (net). . . . . . . . . . . . . . (3,250) 18,650
Retirement of Cumulative Preferred Stock . . . . . . . . . (30,555) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (46,091) (50,736)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (56,254) (55,426)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (5,780) (5,780)
Net Cash Flows From (Used For) Financing Activities. (103,351) 3,527
Net Increase (Decrease) in Cash and Cash Equivalents. . . . (7,487) 45,509
Cash and Cash Equivalents at Beginning of Period . . . . . . 13,723 9,907
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 6,236 $ 55,416
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $32,516,000 and $36,542,000
and for income taxes was $44,183,000 and $50,575,000 in 1996 and 1995, respectively.
Noncash acquisitions under capital leases were $42,290,000 and $9,254,000 in 1996
and 1995, respectively. In connection with the early termination of a western coal
land sublease the Company will receive cash payments from the lessee of $30.8
million over a ten year period which has been recorded at a net present value of
$22.8 million.
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should be
read in conjunction with the 1995 Annual Report
as incorporated in and filed with the Form 10-K. Certain
prior-period amounts have been reclassified to conform with
current-period presentation.
2. FINANCING ACTIVITIES
In the first six months of 1996, the Company issued $40
million of 8% Junior Subordinated Deferrable Interest
Debentures and retired $6 million of Sinking Fund Debentures,
$40 million of 9.50% First Mortgage Bonds and 300,000 shares
of 7.08% Cumulative Preferred Stock, par value $100.
3. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and as required by the new open access rule
filed a new non-discriminatory open access transmission tariff
that is basically the same as the previously filed open access
transmission tariff. The open access final rule also provides
for the recovery of stranded costs under certain conditions
from a utility's departing wholesale customers -- that is costs
that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule
provides for the manner in which the open access rule will be
administered. Management does not expect these final rules to
adversely impact financial condition.
The Company continues to be involved in certain matters
discussed in its 1995 Annual Report.
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
RESULTS OF OPERATIONS
Net income decreased 1% or $0.3 million for the quarter and 4%
or $2.9 million for the year-to-date comparative period, as
increased revenues were more than offset by increased operating
expenses.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . $15.7 5 $18.4 3
Purchased Power Expense . 8.9 34 15.9 30
Other Operation Expense . 4.7 6 9.9 7
Maintenance Expense . . . (2.0) (6) (8.0) (12)
Taxes Other Than
Federal Income Taxes . . 2.2 14 2.5 7
Federal Income Taxes. . . 2.8 21 4.5 15
Interest Charges. . . . . (1.0) (5) (2.4) (7)
Operating revenues increased primarily due to increased retail
sales in both periods. Weather-sensitive residential customers'
demand for electricity rose by 6% in the quarter and 4% in the
year-to-date period reflecting unseasonable spring weather and
colder winter weather. Also, contributing to the increase in
retail sales was a 12% quarterly and 10% year-to-date increase in
industrial sales primarily resulting from the addition of a major
new customer.
Although wholesale revenue changes had little effect on
operating revenues, there were large fluctuations within the two
major components of wholesale revenues. Wholesale sales to
affiliates declined reflecting lower deliveries to the AEP System
Power Pool (Power Pool) primarily due to a reduction in the
availability of nuclear generation as a result of a refueling
outage in the second quarter at one unit of the Company's two unit
Cook Nuclear Plant. Sales to the Company's non-affiliated
municipal and cooperative wholesale customers and sales by the
Power Pool to unaffiliated utilities allocated to the Company
increased mainly due to the unseasonable spring and colder winter
weather largely offsetting the decline in sales to the Power Pool.
Purchased power expense increased significantly primarily due
to increased purchases from the Power Pool, to replace the
unavailable nuclear generating capacity and to support the
Company's allocated share of Power Pool wholesale transactions with
unaffiliated utilities; increased purchases from unaffiliated
utilities for pass-through sales to other unaffiliated companies;
and increased purchases under an agreement with the Ohio Valley
Electric Corporation, an affiliated company which is not a member
of the Power Pool.
The increase in other operation expense reflects an increased
cost of pollution control emission allowances, increased rent
expense, reduced transmission investment equalization credits from
affiliates and increased engineering and other professional
services billed from AEP Service Corporation. The increase in rent
expense resulted from a favorable determination by the Indiana
state tax department that resulted in the reversal in the second
quarter of 1995 of a provision for state taxes applicable to the
Rockport Plant Unit 2 operating lease. Transmission equalization
credits decreased due to an increase in the Company's peak demand
relative to the peak demands of the other Power Pool members.
Under the AEP transmission equalization agreement the costs of
ownership of certain transmission facilities are shared by the
Power Pool members based on their relative peak demands.
Maintenance expense decreased in both periods as a result of
reductions in the number of employees performing maintenance on the
Company's nuclear plant and lower payments for contract labor.
The increase in taxes other than federal income taxes in both
periods was the result of a favorable accrual adjustment for
Indiana real and personal property taxes recorded in 1995.
Federal income taxes attributable to operations increased in
both periods due to changes in certain book/tax timing differences
accounted for on a flow-through basis for ratemaking and financial
reporting purposes and an increase in pre-tax operating income.
In both periods interest charges decreased primarily due to the
refinancing of certain fixed rate long-term debt at lower variable
and fixed rates during the third quarter of 1995.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the year-to-date period were $80 million. During the first six
months of 1996 short-term debt outstanding declined by $3.3
million.
During the first half of 1996 the Company redeemed 300,000
shares of 7.08% Cumulative Preferred Stock, par value $100, at
$101.85, $40 million of 9.50% First Mortgage Bonds due 2021 and
$6,053,000 of Sinking Fund Debentures. The Company also issued $40
million of 8% Junior Subordinated Debentures due 2026.
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access transmission
and stranded cost recovery in the wholesale market. In the open
access final rule, all public utilities with transmission lines are
required to file non-discriminatory open access tariffs that offer
non-affiliated wholesale customers the same transmission service at
the same terms and costs as they provide to themselves and their
affiliates. The Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the
provisions of a proposed FERC rule and as required by the new open
access rule filed a new non-discriminatory open access transmission
tariff that is basically the same as the previously filed open
access transmission tariff. The open access final rule also
provides for the recovery under certain conditions of stranded
costs from a utility's departing wholesale customers -- that is
costs that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule provides
for the manner in which the open access rule will be administered.
Management does not expect these final rules to adversely impact
financial condition.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $78,730 $72,699 $167,319 $158,001
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 20,110 18,375 41,790 39,736
Purchased Power. . . . . . . . . . . . . 22,102 20,337 44,621 42,627
Other Operation. . . . . . . . . . . . . 11,974 11,988 24,330 22,281
Maintenance. . . . . . . . . . . . . . . 7,634 6,508 15,354 13,659
Depreciation and Amortization. . . . . . 6,267 6,087 12,521 12,119
Taxes Other Than Federal Income Taxes. . 1,744 1,526 4,118 4,020
Federal Income Tax Expense (Credit). . . 598 (684) 3,126 1,354
TOTAL OPERATING EXPENSES. . . . . 70,429 64,137 145,860 135,796
OPERATING INCOME . . . . . . . . . . . . . 8,301 8,562 21,459 22,205
NONOPERATING LOSS. . . . . . . . . . . . . (95) (32) (429) (100)
INCOME BEFORE INTEREST CHARGES . . . . . . 8,206 8,530 21,030 22,105
INTEREST CHARGES . . . . . . . . . . . . . 5,837 5,983 11,905 11,743
NET INCOME . . . . . . . . . . . . . . . . $ 2,369 $ 2,547 $ 9,125 $ 10,362
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $92,071 $91,258 $91,381 $89,173
NET INCOME . . . . . . . . . . . . . . . . 2,369 2,547 9,125 10,362
CASH DIVIDENDS DECLARED. . . . . . . . . . 6,066 5,730 12,132 11,460
BALANCE AT END OF PERIOD . . . . . . . . . $88,374 $88,075 $88,374 $88,075
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $230,829 $230,054
Transmission . . . . . . . . . . . . . . . . . . . . 263,172 261,619
Distribution . . . . . . . . . . . . . . . . . . . . 316,060 313,783
General. . . . . . . . . . . . . . . . . . . . . . . 60,973 59,611
Construction Work in Progress. . . . . . . . . . . . 24,667 14,590
Total Electric Utility Plant . . . . . . . . 895,701 879,657
Accumulated Depreciation and Amortization. . . . . . 279,631 270,590
NET ELECTRIC UTILITY PLANT . . . . . . . . . 616,070 609,067
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 6,411 6,438
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 2,847 1,031
Accounts Receivable. . . . . . . . . . . . . . . . . 30,002 30,172
Allowance for Uncollectible Accounts . . . . . . . . (149) (259)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 8,747 3,526
Materials and Supplies . . . . . . . . . . . . . . . 12,389 12,481
Accrued Utility Revenues . . . . . . . . . . . . . . 6,253 13,500
Prepayments. . . . . . . . . . . . . . . . . . . . . 2,263 1,701
TOTAL CURRENT ASSETS . . . . . . . . . . . . 62,352 62,152
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 82,946 82,388
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 9,395 12,153
TOTAL. . . . . . . . . . . . . . . . . . . $777,174 $772,198
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450
Paid-in Capital. . . . . . . . . . . . . . . . . . . 88,750 78,750
Retained Earnings. . . . . . . . . . . . . . . . . . 88,374 91,381
Total Common Shareholder's Equity. . . . . . 227,574 220,581
First Mortgage Bonds . . . . . . . . . . . . . . . . 179,252 224,235
Notes Payable. . . . . . . . . . . . . . . . . . . . 50,000 -
Subordinated Debentures. . . . . . . . . . . . . . . 38,874 38,854
TOTAL CAPITALIZATION . . . . . . . . . . . . 495,700 483,670
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 16,640 15,031
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . - 29,436
Short-term Debt. . . . . . . . . . . . . . . . . . . 57,025 27,050
Accounts Payable . . . . . . . . . . . . . . . . . . 16,675 21,766
Customer Deposits. . . . . . . . . . . . . . . . . . 3,520 3,704
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 6,175 7,972
Interest Accrued . . . . . . . . . . . . . . . . . . 5,483 5,853
Other. . . . . . . . . . . . . . . . . . . . . . . . 7,706 13,283
TOTAL CURRENT LIABILITIES. . . . . . . . . . 96,584 109,064
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 146,363 145,005
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 17,775 18,397
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 4,112 1,031
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . $777,174 $772,198
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 9,125 $ 10,362
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 12,557 12,155
Deferred Federal Income Taxes. . . . . . . . . . . . . . 415 (1,041)
Deferred Investment Tax Credits. . . . . . . . . . . . . (622) (629)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 60 (835)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (5,129) 501
Accrued Utility Revenues . . . . . . . . . . . . . . . . 7,247 4,218
Accounts Payable . . . . . . . . . . . . . . . . . . . . (5,091) (3,726)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (1,797) (519)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (123) (2,624)
Net Cash Flows From Operating Activities . . . . . . 16,642 17,862
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (18,181) (16,827)
Proceeds from Sales of Property. . . . . . . . . . . . . . 250 -
Net Cash Flows Used For Investing Activities . . . . (17,931) (16,827)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 10,000 -
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 50,000 38,647
Change in Short-term Debt (net). . . . . . . . . . . . . . 29,975 (28,250)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (74,738) -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (12,132) (11,460)
Net Cash Flows From (Used For) Financing Activities. 3,105 (1,063)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,816 (28)
Cash and Cash Equivalents at Beginning of Period . . . . . . 1,031 879
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 2,847 $ 851
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $12,114,000 and $11,646,000
and for income taxes was $4,505,000 and $2,027,000 in 1996 and 1995, respectively.
Noncash acquisitions under capital leases were $2,831,000 and $1,857,000 in 1996
and 1995, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be
read in conjunction with the 1995 Annual Report as incorporated
in and filed with the Form 10-K.
2. FINANCING ACTIVITIES
The Company received from its parent a cash capital
contribution of $10 million in March 1996 which was credited
to paid-in capital. In April 1996 the Company refinanced $45
million of 7-7/8% first mortgage bonds due in 2002 with the
proceeds of two $25 million term loan agreements due in 1999
and 2000 at 6.42% and 6.57% annual interest rates,
respectively. The redemption of this series of first mortgage
bonds removed the restriction on the use of retained earnings
for common stock dividends.
3. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and as required by the new open access rule
filed a new non-discriminatory open access transmission tariff
that is basically the same as the previously filed open access
transmission tariff. The open access final rule also provides
under certain conditions for the recovery of stranded costs
from a utility's departing wholesale customers -- that is costs
that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule
provides for the manner in which the open access rule will be
administered. Management does not expect these final rules to
adversely impact financial condition.
The Company continues to be involved in certain other
matters discussed in its 1995 Annual Report.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
Although revenues increased $6 million or 8% in the comparative
second quarter period and $9.3 million or 6% in the comparative
year-to-date period, net income decreased 7% or $0.2 million for
the quarter and 12% or $1.2 million for the year-to-date period.
The net income decrease for the quarter was attributable to
increased maintenance and federal income taxes. The net income
decrease for the year-to-date period was caused by increased
operation expenses, maintenance and federal income taxes and a
write-down of certain demand side management program equipment to
estimated market value recorded in nonoperating income.
Income statement items which changed significantly were:
Increase
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $ 6.0 8 $ 9.3 6
Fuel Expense . . . . . . . . 1.7 9 2.1 5
Purchased Power Expense. . . 1.8 9 2.0 5
Other Operation Expense. . . - - 2.0 9
Maintenance Expense. . . . . 1.1 17 1.7 12
Federal Income Taxes . . . . 1.3 N.M. 1.8 131
N.M. - Not Meaningful
The increase in operating revenues was due to increased energy
sales, increased transmission services and the recovery of demand
side management costs from retail customers. Energy sales to
retail customers rose as customer usage increased in response to
colder winter weather and cooler April and warmer May weather.
Wholesale energy sales rose mainly due to an increase in energy
sales by the AEP System Power Pool (Power Pool) to unaffiliated
utilities reflecting the increased weather-related demand for
energy. Transmission services provided to an unaffiliated utility
under a one year contract that began in January 1996 accounted for
the increase in transmission service revenues.
Fuel expense rose as a result of increased generation
reflecting additional availability in 1996 of the Company's Big
Sandy Plant and the increased demand.
The increase in purchased power expense in the second quarter
and year-to-date periods resulted from increased purchases from
unaffiliated utilities for pass-through sales to other unaffiliated
utilities, reflecting the unseasonable weather; additional
purchases to meet the increased demand from an affiliated company
which is not a member of the AEP Power Pool; and increased
purchases from the AEP Power Pool to meet increased wholesale
energy sales demand.
In the year-to-date period other operation expense increased
mainly due to increased accruals for incentive pay, demand side
program expenses and increased AEP Service Corporation billings for
engineering and other professional services. Maintenance expense
rose in both comparative periods as a result of an increased level
of scheduled steam plant maintenance work at the Big Sandy Plant.
The increase in federal income tax expense attributable to
operations in both periods was primarily due to increases in pre-tax operating
income, changes in certain book/tax differences
accounted for on a flow-through basis for ratemaking and financial
reporting purposes and the completion of the amortization of
deferred federal income taxes in excess of the statutory tax rate
as ordered by the Kentucky Public Service Commission.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . $449,383 $435,976 $954,124 $852,803
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . 144,426 141,301 322,752 272,979
Purchased Power. . . . . . . . . . . . . . 16,175 9,561 31,240 29,803
Other Operation. . . . . . . . . . . . . . 78,985 82,106 161,876 141,806
Maintenance. . . . . . . . . . . . . . . . 42,083 36,302 71,150 71,200
Depreciation and Amortization. . . . . . . 34,369 33,839 68,643 67,729
Taxes Other Than Federal Income Taxes. . . 40,532 41,817 82,735 87,154
Federal Income Taxes . . . . . . . . . . . 25,530 23,180 60,601 46,933
TOTAL OPERATING EXPENSES . . . . . 382,100 368,106 798,997 717,604
OPERATING INCOME . . . . . . . . . . . . . . 67,283 67,870 155,127 135,199
NONOPERATING INCOME. . . . . . . . . . . . . 128 1,702 2,262 5,409
INCOME BEFORE INTEREST CHARGES . . . . . . . 67,411 69,572 157,389 140,608
INTEREST CHARGES . . . . . . . . . . . . . . 23,462 23,774 46,904 47,068
NET INCOME . . . . . . . . . . . . . . . . . 43,949 45,798 110,485 93,540
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . 2,240 3,893 4,480 7,718
EARNINGS APPLICABLE TO COMMON STOCK. . . . . $ 41,709 $ 41,905 $106,005 $ 85,822
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1996 1995 1996 1995
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . $546,611 $492,248 $518,029 $483,222
NET INCOME . . . . . . . . . . . . . . . . . 43,949 45,798 110,485 93,540
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . 35,714 34,857 71,428 69,714
Cumulative Preferred Stock . . . . . . . 2,194 3,825 4,388 7,650
Capital Stock Expense. . . . . . . . . . . 47 34 93 68
BALANCE AT END OF PERIOD . . . . . . . . . . $552,605 $499,330 $552,605 $499,330
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
/TABLE
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
ASSETS
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . . . . $2,537,828 $2,534,893
Transmission . . . . . . . . . . . . . . . . . . . . . . . 806,518 798,854
Distribution . . . . . . . . . . . . . . . . . . . . . . . 844,410 833,944
General (including mining assets). . . . . . . . . . . . . 689,601 688,253
Construction Work in Progress. . . . . . . . . . . . . . . 69,682 59,278
Total Electric Utility Plant . . . . . . . . . . . 4,948,039 4,915,222
Accumulated Depreciation and Amortization. . . . . . . . . 2,160,821 2,091,148
NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,787,218 2,824,074
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 107,439 107,510
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 74,385 44,000
Accounts Receivable (net). . . . . . . . . . . . . . . . . 198,284 199,293
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 138,027 126,952
Materials and Supplies . . . . . . . . . . . . . . . . . . 78,084 80,468
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 36,948 40,100
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . 58,755 42,286
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 584,483 533,099
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 547,796 562,329
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 89,066 129,552
TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,116,002 $4,156,564
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1996 1995
(in thousands)
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares. . . . . . . . . . . . . $ 321,201 $ 321,201
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . . 459,567 459,474
Retained Earnings. . . . . . . . . . . . . . . . . . . . . 552,605 518,029
Total Common Shareholder's Equity. . . . . . . . . 1,333,373 1,298,704
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . . . . 41,240 41,240
Subject to Mandatory Redemption. . . . . . . . . . . . . 115,000 115,000
Long-term Debt . . . . . . . . . . . . . . . . . . . . . . 1,049,175 1,138,425
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . 2,538,788 2,593,369
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . . 225,818 214,726
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . . . . 20,673 89,207
Short-term Debt. . . . . . . . . . . . . . . . . . . . . . 117,921 9,400
Accounts Payable . . . . . . . . . . . . . . . . . . . . . 77,215 102,580
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . 138,227 161,430
Interest Accrued . . . . . . . . . . . . . . . . . . . . . 19,668 20,807
Obligations Under Capital Leases . . . . . . . . . . . . . 24,665 25,172
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 72,305 80,507
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . . 470,674 489,103
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . 726,701 731,959
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . 48,166 49,860
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . . 105,855 77,547
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,116,002 $4,156,564
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1996 1995
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,485 $ 93,540
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . . . 82,863 75,004
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . 1,180 19,058
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . . (2,368) (10,006)
Amortization of Deferred Property Taxes. . . . . . . . . . . 39,099 38,682
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . 1,009 (18,205)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . (8,691) (24,309)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . 3,152 3,547
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . (16,469) (18,371)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . (25,365) (41,599)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . (23,203) (45,811)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . 33,939 11,763
Net Cash Flows From Operating Activities . . . . . . . . 195,631 83,293
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . (44,831) (56,777)
Proceeds from Sale of Property and Other . . . . . . . . . . . 5,529 1,601
Net Cash Flows Used For Investing Activities . . . . . . (39,302) (55,176)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . . . 108,521 74,115
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (158,649) -
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (71,428) (69,714)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . . (4,388) (7,650)
Net Cash Flows Used For Financing Activities . . . . . . (125,944) (3,249)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . 30,385 24,868
Cash and Cash Equivalents at Beginning of Period . . . . . . . . 44,000 30,700
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 74,385 $ 55,568
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $46,627,000 and $45,880,000 and
for income taxes was $39,244,000 and $34,447,000 in 1996 and 1995, respectively.
Noncash acquisitions under capital leases were $14,108,000 and $17,504,000 in 1996 and
1995, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should
be read in conjunction with the 1995 Annual Report
as incorporated in and filed with the Form 10-K.
2. FINANCING ACTIVITY
During the first six months of 1996, the Company and a
subsidiary retired three series of long-term debt at maturity:
$8 million of 5-1/8% Series Sinking Fund Debentures, $39
million of 5% Series First Mortgage Bonds and $8 million of
5.79% Notes Payable.
The Company also retired six series of long-term debt
before maturity in 1996: four series of first mortgage bonds
totaling $94 million with rates ranging from 7-5/8% to 9-7/8%
and two series of sinking fund debentures totaling $9 million
with rates of 6-5/8% and 7-7/8%.
As a result of the early redemption of the 9-7/8% Series
First Mortgage Bonds due in 2020, the restriction on the use
of retained earnings for common stock dividends was reduced
from $156.5 million to $23.9 million.
3. CONTINGENCIES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access
transmission and stranded cost recovery in the wholesale
market. In the open access final rule, all public utilities
with transmission lines are required to file non-discriminatory
open access tariffs that offer non-affiliated wholesale
customers the same transmission service at the same terms and
costs as they provide to themselves and their affiliates. The
Company adopted with FERC approval a non-discriminatory open
access transmission tariff in 1995 under the provisions of a
proposed FERC rule and as required by the new open access rule
filed a new non-discriminatory open access transmission tariff
that is basically the same as the previously filed open access
transmission tariff. The open access final rule also provides
under certain conditions for the recovery of stranded costs
from a utility's departing wholesale customers -- that is costs
that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule
provides for the manner in which the open access rule will be
administered. Management does not expect these final rules to
adversely impact financial condition.
The Company continues to be involved in certain other
matters discussed in the 1995 Annual Report.
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1996 vs. SECOND QUARTER 1995
AND
YEAR-TO-DATE 1996 vs. YEAR-TO-DATE 1995
RESULTS OF OPERATIONS
Although energy sales increased 16% in the comparative second
quarter, net income decreased 4% or $1.8 million due to the effect
on comparable net income of an $8.3 million after tax adjustment to
revenues recorded in June 1995 under a major industrial contract.
Net income increased 18% or $16.9 million in the comparative year-to-date period
primarily due to a 27% increase in energy sales.
Income statement items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $ 13.4 3 $101.3 12
Fuel Expense . . . . . . . 3.1 2 49.8 18
Purchased Power Expense. . 6.6 69 1.4 5
Other Operation Expense. . (3.1) (4) 20.1 14
Maintenance Expense. . . . 5.8 16 (0.1) -
Federal Income Taxes . . . 2.3 10 13.7 29
Operating revenues increased in both periods as a result of
increased energy sales, which more than offset the effect of the
1995 adjustment to industrial revenues, and a retail rate increase
in the year-to-date period. Sales volume to wholesale customers
was up 52% in the second quarter of 1996 and 98% in the year-to-date period
primarily due to an increase in energy supplied to the
AEP System Power Pool (Power Pool) reflecting increased weather-related demand
of affiliated members of the Power Pool and, in the
year-to-date period, the increased availability of the Company's
two Gavin Plant generating units. The Gavin units had been out-of-service for
extended periods during the first three months of 1995
for maintenance and the installation of flue gas desulfurization
systems (scrubbers). Wholesale energy sales by the Power Pool to
unaffiliated utilities also increased in both comparative periods
largely as a result of unseasonable weather.
Retail energy sales increased 2% in the comparative second
quarter period and 3% in the comparative year-to-date period
reflecting increased energy sales in all major retail customer
classes largely as a result of increased usage due to unseasonable
weather and growth in the number of customers. A retail base rate
increase in March 1995 also contributed to the higher revenues in
the comparative year-to-date period.
The increase in fuel expense in both periods was mainly due to
increased generation resulting from the higher demand for energy
and, in the year-to-date period, the increased availability of the
Gavin Plant units. Increased energy purchases from unaffiliated
utilities for pass-through sales to other unaffiliated utilities as
a result of the unseasonable weather in 1996 was the major reason
for the substantial increase in purchased power expense in the
comparative second quarter period.
Other operation expense declined in the second quarter of 1996
reflecting reduced steam generation expenses as a result of a
scheduled outage in 1996 at both of the Gavin units for inspection
and repairs. The increase in other operation expense during the
first six months of this year was primarily due to rent and other
operating costs of the recently installed Gavin Plant scrubbers and
the amortization, commensurate with recovery in rates, of
previously deferred Gavin scrubber expenses.
The increase in maintenance expense in the comparative second
quarter period was due to the 1996 maintenance outage at both of
the Gavin units.
The increase in both periods in federal income tax expense
attributable to operations was due to an increase in pre-tax
operating income and in the comparative second quarter period due
to changes in certain book/tax differences accounted for on a flow-through basis
for ratemaking and financial reporting purposes.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months of 1996 were $59 million.
During the first six months of 1996, the Company and a
subsidiary retired $158 million principal amount of long-term debt
with interest rates ranging from 5% to 9-7/8% and increased short-term debt by
$109 million.
As a result of the early redemption of the remaining $2.5
million outstanding balance of the 9-7/8% Series First Mortgage
Bonds due in 2020, the restriction on the use of retained earnings
for common stock dividends was reduced from $156.5 million to $23.9
million.
NEW FERC RULES
On April 24, 1996 the Federal Energy Regulatory Commission
(FERC) issued two Final Rules regarding open access transmission
and stranded cost recovery in the wholesale market. In the open
access final rule, all public utilities with transmission lines are
required to file non-discriminatory open access tariffs that offer
non-affiliated wholesale customers the same transmission service at
the same terms and costs as they provide to themselves and their
affiliates. The Company adopted with FERC approval a non-discriminatory
open access transmission tariff in 1995 under the
provisions of a proposed FERC rule and as required by the new open
access rule filed a new non-discriminatory open access transmission
tariff that is basically the same as the previously filed open
access transmission tariff. The open access final rule also
provides under certain conditions for the recovery of stranded
costs from a utility's departing wholesale customers -- that is
costs that were prudently incurred to serve departing wholesale
customers that would go unrecovered if these customers use open
access to move to another supplier. The other final rule provides
for the manner in which the open access rule will be administered.
Management does not expect these final rules to adversely impact
financial condition.
<PAGE>
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
Indiana Michigan Power Company ("I&M")
Reference is made to page 20 of the Annual Report on Form
10-K for the year ended December 31, 1995 ("1995 10-K") for a
discussion of a petition for review filed by I&M and other
unaffiliated utilities in the U.S. Court of Appeals for the
District of Columbia Circuit regarding nuclear waste disposal.
On July 23, 1996, the court ruled that the Nuclear Waste Policy
Act of 1982 imposes on the U.S. Department of Energy ("DOE") an
unconditional obligation to begin acceptance of spent nuclear
fuel and high level radioactive waste by January 31, 1998. The
court did not determine an appropriate remedy, holding that DOE
has not yet defaulted upon either its statutory or contractual
obligations.
American Electric Power Company, Inc. ("AEP") and Ohio Power
Company ("OPCo")
Reference is made to pages 25, 26 and 34 of the 1995 10-K
and page II-1 of the Quarterly Report on Form 10-Q for the
quarter ended March 31, 1996 for a discussion of proceedings
instituted by the U.S. Environmental Protection Agency ("Federal
EPA"), and the settlement thereof, which alleged that OPCo's
Kammer Plant was operating in violation of applicable federally
enforceable air pollution control requirements for sulfur dioxide
since January 1, 1989. On May 20, 1996, the U.S. District Court
for the Northern District of West Virginia entered an order
approving the consent decree.
Appalachian Power Company ("APCo")
Reference is made to page 33 of the 1995 10-K for a discus-
sion of a complaint filed against APCo and Global Power Company,
an independent contractor retained by APCo, by Federal EPA
related to an asbestos abatement project at APCo's Kanawha River
Plant. APCo and Global have entered into a Consent Agreement,
dated July 30, 1996, with Federal EPA to settle this matter by
paying a civil penalty of $58,000, which shall be shared by APCo
and Global.
Item 4. Submission of Matters to a Vote of Security Holders.
AEP
The annual meeting of shareholders was held in Columbus,
Ohio on April 24, 1996. The holders of shares entitled to vote
at the meeting or their proxies cast votes at the meeting with
respect to the following two matters, as indicated below:
1. Election of 12 directors to hold office until the next
annual meeting and until their successors are duly
elected. Each nominee for director was elected by a
vote of the shareholders as follows:
II-1
<PAGE>
<PAGE>
Number of Shares Number of
Nominee Voted For Votes Withheld
Peter J. DeMaria 142,522,136 2,086,655
E. Linn Draper, Jr. 142,496,525 2,112,266
Robert M. Duncan 142,377,695 2,231,096
Robert W. Fri 142,359,083 2,249,708
Arthur G. Hansen 142,312,097 2,296,694
Lester A. Hudson, Jr. 142,491,624 2,117,167
Gerald P. Maloney 142,534,248 2,074,543
Angus E. Peyton 142,435,230 2,173,561
Donald G. Smith 142,496,778 2,112,013
Linda Gillespie Stuntz 142,009,723 2,599,068
Morris Tanenbaum 142,406,307 2,202,484
Ann Haymond Zwinger 142,300,604 2,308,187
2. Approve the appointment by the Board of Directors of
Deloitte & Touche LLP as independent auditors of AEP for
the year 1996. The proposal was approved by a vote of
the shareholders as follows:
Votes FOR 142,603,261
Votes AGAINST 870,975
Votes ABSTAINED 1,134,555
Broker NON-VOTES* 0
*A non-vote occurs when a nominee holding shares for a
beneficial owner votes on one proposal, but does not
vote on another proposal because the nominee does not
have discretionary voting power and has not received
instructions from the beneficial owner.
APCo
The annual meeting of stockholders was held on April 23,
1996 at 1 Riverside Plaza, Columbus, Ohio. At the meeting,
13,499,500 votes were cast FOR each of the following seven
persons for election as directors and there were no votes with-
held and such persons were elected directors to hold office for
one year or until their successors are elected and qualify:
Peter J. DeMaria Gerald P. Maloney
E. Linn Draper, Jr. James J. Markowsky
Henry W. Fayne Joseph H. Vipperman
William J. Lhota
No other business was transacted at the meeting.
I&M
The annual meeting of stockholders was held on April 23,
1996 at 1 Riverside Plaza, Columbus, Ohio. At the meeting,
1,400,000 votes were cast FOR each of the following thirteen
persons for election as directors and there were no votes with-
held and such persons were elected directors to hold office for
one year or until their successors are elected and qualify:
C. R. Boyle, III James J. Markowsky
G. A. Clark Albert H. Potter
Peter J. DeMaria David B. Synowiec
William N. D'Onofrio Dale M. Trenary
E. Linn Draper, Jr. Joseph H. Vipperman
William J. Lhota William E. Walters
Gerald P. Maloney
No other business was transacted at the meeting.
II-2
<PAGE>
OPCo
The annual meeting of shareholders was held on May 7, 1996
at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,478
votes were cast FOR each of the following seven persons for elec-
tion as directors and there were no votes withheld and such per-
sons were elected directors to hold office for one year or until
their successors are elected and qualify:
Peter J. DeMaria Gerald P. Maloney
E. Linn Draper, Jr. James J. Markowsky
Henry W. Fayne Joseph H. Vipperman
William J. Lhota
No other business was transacted at the meeting.
Item 5. Other Information.
APCo
Reference is made to pages 9 and 10 of the 1995 10-K for a
discussion of competition and restructuring in the electric
utility industry and an order by the Virginia State Corporation
Commission ("Virginia SCC") directing its staff to conduct an
investigation in this regard. On July 31, 1996, the staff issued
its report which concludes that "it is unnecessary and inadvis-
able to implement a massive restructuring of the industry at this
juncture." The staff indicated that "because Virginia is a low
cost state, the staff believes there may be little to gain and
much to lose by being on the leading edge of a restructuring
movement."
Reference is made to pages 11 and 12 of the 1995 10-K for a
discussion of APCo's proposed new transmission facilities. On
June 18, 1996, the U.S. Forest Service ("Forest Service") re-
leased a Draft Environmental Impact Statement ("EIS"). The
Forest Service preliminarily identified a "No Action Alternative"
as its preferred alternative. If this alternative is incorpo-
rated in the Final EIS, APCo would not be authorized to cross the
federally-administered lands of the Forest Service with the pro-
posed transmission line. Given the findings set forth in the
Draft EIS and the preliminary position of the Forest Service,
APCo cannot presently predict the schedule for completion of the
state and federal permitting process.
On July 25, 1996, the Virginia SCC issued an order extending
indefinitely the date for filing comments and suspending its pro-
ceeding on the transmission line due to the findings of the Draft
EIS. However, the Virginia SCC ordered APCo to file, on or be-
fore December 1, 1996, a proposal detailing its intentions with
regard to meeting the need for major additional transmission
capacity identified in the Virginia SCC's interim order of
December 13, 1995.
APCo and Kentucky Power Company ("KEPCo")
Reference is made to page 12 of the 1995 10-K for a discus-
sion of APCo's and KEPCo's proposed transmission system improve-
ment project. The Kentucky Public Service Commission approved
the project in its order dated June 11, 1996. Construction is
scheduled to begin in October 1996.
II-3
<PAGE>
<PAGE>
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo and OPCo
Exhibit 10 - American Electric Power System Manage-
ment Incentive Compensation Plan - 1996.
APCo, Columbus Southern Power Company ("CSPCo"), I&M,
KEPCo and OPCo
Exhibit 12 - Statement re: Computation of Ratios.
AEP, AEP Generating Company ("AEGCo"), APCo, CSPCo, I&M,
KEPCo and OPCo
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K:
AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
No reports on Form 8-K were filed during the quarter
ended June 30, 1996.
II-4
<PAGE>
In the opinion of the companies, the financial statements contained herein
reflect all adjustments (consisting of only normal recurring accruals) which
are necessary to a fair presentation of the results of operations for the
interim periods.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Controller
and Secretary
AEP GENERATING COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
APPALACHIAN POWER COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
COLUMBUS SOUTHERN POWER COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
INDIANA MICHIGAN POWER COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
KENTUCKY POWER COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
OHIO POWER COMPANY
G.P. Maloney P.J. DeMaria
G.P. Maloney, Vice President P.J. DeMaria, Vice President
and Controller
Date: August 13, 1996
II-5
AMERICAN ELECTRIC POWER SYSTEM
MANAGEMENT INCENTIVE COMPENSATION PLAN
1996
TABLE OF CONTENTS
Page
----
INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . iv
1.0 OVERVIEW . . . . . . . . . . . . . . . . . . . . . . . . . 1
1.1 Participation in MICP . . . . . . . . . . . . . . 1
1.2 MICP Award Limitation . . . . . . . . . . . . . . 2
2.0 TARGET AWARD ALLOCATIONS . . . . . . . . . . . . . . . . . 3
3.0 AEP CORPORATE PERFORMANCE CRITERIA . . . . . . . . . . . . 5
3.1 Average Annual ROE . . . . . . . . . . . . . . . 5
3.2 Total Investor Return . . . . . . . . . . . . . . 6
3.3 Realization Ratio . . . . . . . . . . . . . . . . 7
4.0 T&D ENERGY DELIVERY PERFORMANCE CRITERIA . . . . . . . . . 8
4.1 Customer Satisfaction & Loyalty . . . . . . . . . 8
4.2 Safety Performance . . . . . . . . . . . . . . . 10
4.3 O&M Expense vs. Budget. . . . . . . . . . . . . . 11
4.4 Customer Service Reliability Index . . . . . . . 13
4.5 Material & Supply Inventory Reduction . . . . . . 13
4.6 Marketing Performance . . . . . . . . . . . . . . 14
5.0 MARKETING BUSINESS UNIT PERFORMANCE CRITERIA . . . . . . . 17
5.1 Annual Marketing Objective . . . . . . . . . . . 17
5.2 Annual Account Management Objective . . . . . . . 18
5.3 Market Share of Electricity . . . . . . . . . . . 19
5.4 Market Share of Energy . . . . . . . . . . . . . 20
5.5 Loyalty Objective . . . . . . . . . . . . . . . . 20
6.0 POWER PLANT MANAGERS . . . . . . . . . . . . . . . . . . . 22
7.0 REGION PLANT SERVICES . . . . . . . . . . . . . . . . . . 22
8.0 CENTRAL MACHINE SHOP MANAGER . . . . . . . . . . . . . . . 22
9.0 FUEL SUPPLY PERFORMANCE CRITERIA . . . . . . . . . . . . . 23
9.1 Adjusted Cost of Coal Produced from
Affiliated Mines . . . . . . . . . . . . . . . 23
9.2 PUCO Cap Performance . . . . . . . . . . . . . . 24
9.3 Safety Performance . . . . . . . . . . . . . . . 24
9.4 Senior Vice President and Senior Staff-Fuel
Supply - Delivered Fuel Prices . . . . . . . . 25
9.5 Vice President - Fuel Procurement Measures . . . 25
9.6 General Mine Manager/General Superintendent
Measures . . . . . . . . . . . . . . . . . . . 26
9.7 Manager-River Transportation Measures . . . . . . 26
9.8 Manager-Cook Coal Terminal Measures . . . . . . . 27
9.9 Managing Director-Transportation Measures . . . . 28
9.10 Senior Vice President, Vice Presidents, Senior
Staff-Fuel Supply & Managing Director-
Transportation. . . . . . . . . . . . . . . . . 28
10.0 POWER GENERATION PERFORMANCE CRITERIA . . . . . . . . . 29
11.0 DEPARTMENT/BUSINESS UNIT OBJECTIVES . . . . . . . . . . 29
12.0 THE MICP IN ACTION . . . . . . . . . . . . . . . . . . . 30
13.0 PAYMENT RIGHTS AT TERMINATION OF ACTIVE EMPLOYMENT . . . 33
13.1 Termination After Completion of Plan Year. . . 33
13.2 Termination Due to Death, Retirement, or
Disability . . . . . . . . . . . . . . . . . 33
13.3 Involuntary Termination During Plan Year . . . 34
14.0 CHANGES IN SALARY/POSITION/PARTICIPATION . . . . . . . . 35
15.0 PLAN ADMINISTRATION . . . . . . . . . . . . . . . . . . 36
16.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS . . . . . . . . . A-1
17.0 POSSIBLE ADJUSTMENTS TO CORPORATE PERFORMANCE DATA . . . A-3
18.0 FUEL SUPPLY PAYMENT SCHEDULES . . . . . . . . . . . . . A-4
18.1 Senior Vice President-Fuel Supply. . . . . . . A-4
18.2 Delivered Fuel Prices. . . . . . . . . . . . . A-4
18.3 Vice President-Fuel Procurement. . . . . . . . A-5
18.4 Delivered Fuel Prices. . . . . . . . . . . . . A-5
18.5 Power Generation Production Cost . . . . . . . A-6
18.6 General Mine Managers/General Super-
intendent (Meigs). . . . . . . . . . . . . . A-6
18.7 Southern Ohio Coal Company - Meigs . . . . . . A-6
18.8 Central Ohio Coal Company. . . . . . . . . . . A-7
18.9 Windsor Coal Company . . . . . . . . . . . . . A-7
18.10 All Coal Mines - Safety Incidence Rate . . . . A-8
18.11 Manager - River Transportation . . . . . . . . A-9
18.12 River Transportation Operating Cost Per
Ton Mile . . . . . . . . . . . . . . . . . . A-9
18.13 River Transportation Safety Incidence Rate . . A-9
18.14 Manager-Cook Coal Terminal . . . . . . . . . . A-10
18.15 Cook Coal Terminal Adjusted Cost Per Ton . . . A-10
18.16 Cook Coal Terminal Safety Incidence Rate . . . A-10
18.17 Managing Director-Transportation . . . . . . . A-11
18.18 Cook Coal Terminal Adjusted Cost Per Ton . . . A-11
18.19 River Transportation Operating Cost
Per Ton Mile . . . . . . . . . . . . . . . . A-11
18.20 Delivered Fuel Prices. . . . . . . . . . . . . A-12
18.21 River Transportation and Cook Coal Terminal
Safety Incidence Rate. . . . . . . . . . . . A-12
19.0 POWER GENERATION DEPARTMENT/BUSINESS UNIT
PAYMENT SCHEDULES . . . . . . . . . . . . . . . . . . A-13
19.1 O & M Expenditure . . . . . . . . . . . . . . A-13
19.2 Power Generation Production Cost . . . . . . . A-13
19.3 Capital Expenditures . . . . . . . . . . . . . A-14
19.4 Equivalent Availability. . . . . . . . . . . . A-14
19.5 Heat Rate. . . . . . . . . . . . . . . . . . . A-15
<PAGE>
<PAGE>
INTRODUCTION
The American Electric Power System is continuing the Management
Incentive Compensation Plan (MICP) during 1996, with revisions
from the 1995 Plan. The Plan's purpose is to bring together the
interests of key managers with those of the AEP System's
customers and shareholders by providing performance incentives to
serve customers' needs and meet shareholders' financial
expectations at the highest possible levels.
Through the MICP, a key manager can receive an annual monetary
award in addition to base salary, if certain performance levels
are met. The Plan is designed to help motivate a consistent
level of superior Company performance by rewarding those
principally accountable for achieving it.
This Plan provides an element of compensation which will vary
directly with Company performance. It will ensure that key
managers are compensated competitively and consistent with the
AEP System's financial and operating performance.
Any questions about the Plan should be directed to the Director-
Compensation and Benefits through the respective business unit
head.<PAGE>
1.0 OVERVIEW OF THE
MANAGEMENT INCENTIVE COMPENSATION PLAN
A participant's MICP annual target award is expressed as a
percentage of annual base earnings. Actual awards can vary from
0% to 150% of the target award, based on performance.
Performance criteria are established annually for the following
organizational units:
- AEP Corporate
- Energy Delivery T&D Business Group
- Power Generation
- Marketing
- Fuel Supply
- Individual Units
Each participant's target award is allocated by organizational
unit. The organization's success in meeting the year's
established performance criteria determines the participant's
actual award.
During the first part of the year following each performance year
a participant will receive 80% of any actual award in cash unless
a deferral election had been made in accordance with Section
16.2. The remaining 20% is deferred in the form of AEP common
stock units payable 3 years later (see Addendum page A-1) unless
a deferral election had been made in accordance with Section
16.2.
1.1 PARTICIPATION IN MICP - A select group of key managers and
executives whose performance most significantly affects the
Company's success participate in the MICP. Positions
eligible and individual executives were approved for
participation in the 1996 Plan by the Chief Executive
Officer. The following procedures apply to the addition of
any other positions or executives:
A. NEW PARTICIPANTS - Participation is generally automatic
for employees promoted or transferred to a position
that has been previously approved as eligible for
participation in the Plan, effective on the promotion
or transfer date. However, if an employee is demoted
to a position normally covered by the MICP, approval of
the Chief Executive Officer is required for the demoted
employee to be eligible to continue as a participant.
Prior to becoming a participant in the Plan, specific
approval of the Chief Executive Officer is required for
all employees or positions not previously eligible to
participate in the Plan. Requests for approval by the
Chief Executive Officer should be submitted through the
Director-Compensation & Benefits.
An executive who is not currently a Plan participant
and who is entering an eligible position for the first
time, will generally be eligible to participate in that
year's Plan if the promotion or transfer date is prior
to October 1. If it is after this date, the executive
will be eligible to participate in the following year's
Plan.
1.2 MICP AWARD LIMITATION - No award is payable unless AEP's
dividends remain at prevailing levels and net income is
greater than dividend payments in the current year.
2.0 TARGET AWARD ALLOCATIONS
Target awards of MICP participants are allocated to AEP Corporate
and other organization units, as follows:
<TABLE>
<CAPTION>
Target Award*
as Percent of Percent of Awards Allocated
Participant Base Salary to Organizational Units
- ----------------------- ------------- ------------------------------------------
<S> <C> <C>
Office of the Chairman 30 100 Corporate Performance
EVP-Energy Delivery 25 75 Corporate Performance
Group, Controller, VPs, 25 Department/Business Unit Performance
SVPs and State Presidents or
60 Corporate
40 Department/Business Unit Performance
or
100 Corporate Performance
Fuel Supply SVP and VPs 25 25 Corporate Performance
45 Fuel Supply Performance
25 Delivered Fuel Prices
5 Power Generation Production Cost
AEP Division Managers 20 75 Corporate Performance
and Others as Designated 25 Department/Business Unit Performance
or
60 Corporate Performance
40 Department/Business Unit Performance
or
50 Corporate
50 Department/Business Unit Performance
or
100 Corporate
Region Managers 20 50 Corporate Performance
50 Region/Business Unit Performance
Power Plant Managers 20 25 Corporate Performance
(including Cook) 75 Plant Incentive Plan
Site VP (Cook) 25 25 Corporate Performance
75 Plant Incentive Plan
Region Plant Services 20 25 Corporate Performance
Managers and Production 75 Region Plant Services Performance
Services Manager
Central Machine Shop 20 25 Corporate Performance
Manager 75 Central Machine Shop Performance
Fuel Supply Lancaster 20 25 Corporate Performance
Senior Staff 45 Fuel Supply Performance
25 Delivered Fuel Prices
5 Power Generation Production Cost
Vice President-Fuel 25 25 Corporate Performance
Procurement 20 Fuel Supply Performance
50 Department Performance
5 Power Generation Production Cost
Managing Director- 20 25 Corporate Performance
Transportation 20 Fuel Supply Performance
50 Department Performance
5 Power Generation Production Cost
Fuel Supply General Mine 20 25 Corporate Performance
Managers/General Super- 25 Fuel Supply Performance
intendent (Meigs) 50 Division/Mine Performance
Manager-Cook Coal 20 25 Corporate Performance
Terminal 75 Cook Coal Terminal Performance
Manager-River Trans- 20 25 Corporate Performance
portation 75 River Transportation Performance
VP & General Manager 25 25 Corporate Performance
(Meigs) 25 Fuel Supply Performance
50 Division/Mine Performance
</TABLE>
3.0 AEP CORPORATE PERFORMANCE CRITERIA
There are three AEP Corporate performance criteria which are
weighted to determine a single Corporate performance factor. The
three are as follows:
- - A two-component measure of Annual Return on Average
Stockholder Equity (ROE) for the current year - weighted at
25%;
- - A component measuring the Three-Year Average Total Investor
Return (TIR) - weighted at 25%; and
- - A component comparing the Realization Ratio (Average Price
of Power Sold to Retail Customers vs. Other Utilities) for
the current year - weighted at 50%.
The following describes each in greater detail.
3.1 RETURN ON EQUITY (ROE) is corporate annual after-tax income
as a percentage of average annual stockholder equity. It
is an indication of how profitably AEP manages its
investors' capital. For purposes of the MICP, ROE is
measured in the following two ways, each of which is
weighted 12.5%:
- In terms of absolute performance; and
- Relative to the ranking of the AEP ROE among the 20
other electric utilities that together with AEP make up
the Standard & Poor's Utility Index.
The results of these two measures are averaged to determine
performance on this component.
The following chart indicates both of these ROE
measurements and the performance factors for each.
<TABLE>
<CAPTION> AVERAGE ANNUAL ROE
Performance S&P Utility Performance
Absolute ROE Factor* ROE Ranking** Factor
------------ ----------- ------------- -----------
<S> <C> <C> <C>
16 or more 1.50 1-6 1.50
15 1.25 7 1.40
14 1.00 8 1.30
13 .80 9 1.20
12 .60 10 1.10
11 .40 11 1.00
10 or less 0 12 .80
13 .60
14 .40
15 .20
16 or more 0
*Interpolate at intermediate performance.
**Highest ROE is ranked first.
Example: If AEP's annual ROE is 14%, and AEP achieves an S&P Utility Index
rank of seventh out of 21, the average performance factor will be calculated
this way: (1.00 + 1.40) / 2 = 1.20.
3.2 TOTAL INVESTOR RETURN (TIR) is an indicator of the increase
in value of AEP shareholders' investment. It measures the
annual percentage increase in stock price as well as
dividends paid over a three-year period (the current and
two prior years). AEP System results are then compared
with the other 20 companies in the Standard & Poor's
Utility Index and are ranked for each of the three years.
Performance factors are determined based on the average of
the TIR rankings for the three years, as follows:
THREE-YEAR AVERAGE TOTAL INVESTOR RETURN
AEP TIR Ranking* Performance Factor
---------------- ------------------
6 or higher 1.50
7 1.40
8 1.30
9 1.20
10 1.10
11 1.00
12 .80
13 .60
14 .40
15 .20
16 0
*Highest TIR is ranked first.
Example: If the three-year average rank of AEP is 12 out of
21, the performance factor is .80.
3.3 REALIZATION RATIO is a measure of relative cost efficiency
and productivity -- from AEP customers' perspective. It
compares the AEP System's average price of power sold to
ultimate customers with other utilities' corresponding
average price. The realization ratio is based on average
realization for sales to ultimate customers by other
investor-owned utilities in the seven states in which AEP
operates, weighted by the respective proportions of AEP's
corresponding sales in those states. (Because Kingsport
Power is the only investor-owned electric utility in
Tennessee, the realization ratio for that state is based on
retail rates of TVA Tennessee distributors.) Performance
factors are then derived, as follows:
AEP REALIZATION RATIO
AEP Ratio Performance Factor*
--------- -------------------
.75 or less 1.50
.80 1.25
.85 1.00
.90 .75
.95 .50
1.00 .25
above 1.00 0
*Interpolate at intermediate performance.
Example: If AEP's average realization is 20% below the
seven-state average, its ratio will be .80 and the
performance factor will be 1.25.
4.0 TRANSMISSION AND DISTRIBUTION ENERGY
DELIVERY PERFORMANCE CRITERIA
There are six T&D Energy Delivery performance criteria that are
individually weighed to determine a single performance factor for
the T&D Energy Delivery Group, Energy Distribution, Energy
Transmission and each Region. The six are as follows:
- - Customer Satisfaction and Loyalty - weighted at 20%;
- - Safety - weighted at 20%;
- - O&M Expense vs. Budget - weighted at 20%;
- - Customer Service Reliability Index - weighted at 20%;
- - Material and Supply Inventory Reduction - weighted at 10%;
- - Marketing - weighted at 10%.
The following describes each measure in more detail.
4.1 CUSTOMER SATISFACTION AND LOYALTY is based on a weighted
average of the performance factors of the National Key
Account Benchmark study by TQS Research (TQS), the
Commercial and Industrial Customer Satisfaction Study by RKS
Research and Consulting (RKS) and the Corporate Positioning
and Communication Tracking Study by Market Strategies, Inc.
(MSI) survey instruments in proportions of 61.3%, 28.5%, and
10.2% respectively. The TQS, RKS, and MSI represent the key
accounts, major accounts, and residential segments,
respectively. The "Customer Loyalty-Electric" score will be
utilized from the TQS study, the "Customer Assessment Score"
will be utilized from the RKS study, and the "Overall
Satisfaction" score will be utilized form the MSI study.
The performance factor for each instrument will be computed
in accordance with the following payment schedule. Note
that while a percentile approach is preferred in the
computation of a performance factor with all three of the
instruments, a raw score is utilized in the RKS instrument
as the timing of the study is not anticipated to permit
comparison to other utilities' scores. The award will not
be distinguishable between Transmission and Distribution.
Targets and results will be system-wide. The 1996 targets
and performance factors are:
ENERGY DISTRIBUTION BUSINESS UNIT AND REGION
TARGET AWARD PAYMENT SCHEDULE
TQS AND MSI TARGETS
Ranking Result (percentile) Performance Factor*
--------------------------- -------------------
Top 10% 1.50
15% 1.25
20% 1.00
25% 0.50
Bottom 70% 0.00
*Interpolate at intermediate performance.
ENERGY DISTRIBUTION BUSINESS UNIT AND REGION
TARGET AWARD PAYMENT SCHEDULE
RKS TARGETS
Customer Acceptance Score Performance Factor*
------------------------- -------------------
Over 3.2 1.50
3.1 1.25
3.0 1.00
2.9 0.50
Below 2.85 0.00
*Interpolate at intermediate performance.
The use of the RKS instrument is dependent on receiving
survey results prior to computation of the annual MICP
results. In the event this information is unavailable, the
performance measures of the TQS and MSI will be computed as
a weighted average in the proportions 85%.7% and 14.3%
respectively.
4.2 SAFETY PERFORMANCE of the T&D Energy Delivery Business
Group, the Energy Distribution Business Unit, the Energy
Transmission Business Unit and the transmission and
distribution Regions is measured by two equally weighted
indices. The indices are combined to determine a single
performance factor for each organizational unit.
- RECORDABLE CASE INCIDENCE RATE - Number of recordable
cases per 200,000 work hours.
- LOST AND RESTRICTED WORKDAY (SEVERITY) RATE - Number of
days away from work AND restricted activity days per
200,000 work hours.
The rate for the group and the appropriate Units and Regions
will be compared to the most recently published EEI rate
calculated for each measure. The related performance
factors are determined from the following schedule and
averaged to yield a single performance factor for safety
performance.
T&D ENERGY DELIVERY SAFETY PERFORMANCE
TARGET AWARD PAYMENT SCHEDULE
RATIO TO THE LATEST EEI RATE
Ratio to EEI Performance Performance Factor*
------------------------ -------------------
0.70 1.50
0.85 1.00
0.93 0.50
1.000 or more 0.00
*Interpolate at intermediate performance.
Example: If a Transmission Region achieves a ratio of .9250
to the EEI recordable case incidence rate and a ratio of
.6500 to the EEI lost and restricted workday (severity)
rate, the respective performance factors are .50 and 1.50.
Averaging the two yields a single performance factor of 1.00
The performance factor shall be zero for any Region whose
recordable injuries include a fatality or a permanent total
disability case.
SOURCE OF DATA
- EEI Rate and AEP Data
The EEI rates will be taken from the latest EEI Safety
Statistical Survey Report at the time the awards are
calculated. The data for T&D Energy Delivery is taken
from the year-end AEP System Report of Employee Injuries
and Illnesses. This information is compiled by the
Safety & Health Section of System Human Resources.
The following data for the December cumulative year-to-date
report is to be compiled by the AEP Corporate Safety &
Health Division on or before January 15 of the following
year for the T&D Energy Delivery Group/Unit/Region.
- Total Hours Worked
- Lost Workdays (LWD Case - days away from work)
- Restricted Activity Days
- Lost and Restricted Workday (Severity) Rate
- Recordable Cases
- Recordable Case Incidence Rate
DATA AVAILABILITY, CALCULATIONS AND AWARD DETERMINATIONS
The AEP Corporate Safety & Health Section will calculate the
performance factors for the T&D Energy Delivery Group, and
each Business Unit and Region. The calculations will be
completed by January 30 and approved by the SVP-Human
Resources.
4.3 O&M EXPENSE PERFORMANCE VS. BUDGET is measured by comparing
controllable operating and maintenance expenses against
budget for the current year. Performance factors are
designed to provide increased awards for expense performance
which is below budget. However, because some O&M budgets
are developed based primarily upon historical expenses and
not upon need to complete specific projects, close
monitoring of expenses is required. The EVP-Energy Delivery
Group is responsible for monitoring expenses in each
budgeting organization to ensure that projects that should
have been accomplished are not delayed or omitted in order
to achieve a higher performance factor score. If this is
judged to occur, the approved budget will be commensurately
reduced by an amount equal to the estimated cost of the
project, and a revised performance factor determined.
T&D ENERGY DELIVERY GROUP
BUSINESS UNIT AND REGION
CONTROLLABLE O&M EXPENSES VS. BUDGET
Expenses as Percent of Budget* Performance Factor
------------------------------ ------------------
Less than 91% 1.50
91% but less than 96% 1.25
96% but less than 101% 1.00
101% but less than 103% 0.50
103% but less than 105% 0.25
105% or higher 0.00
*All numbers to be rounded to nearest whole numbers.
Example: If Distribution Region's actual result is 93% of
budget, the Region has placed between the 91% and 96%
bracket, achieving a performance factor of 1.25.
4.4 CUSTOMER SERVICE RELIABILITY INDEX is measured by comparing
the current year annual interruption frequency index and the
interruption duration index against prior five-year average
indices. The reliability index is determined by the
following formula:
[(Cur. Interpt. Freq. Index/5-Year Avg. Intm. Freq.
Index) + (Cur. Interpt. Dur. Index/5-Year Avg. Intm.
Dur. Index)] x 100/2
Resulting performance factors are determined as follows:
T&D ENERGY DELIVERY GROUP, UNITS AND REGIONS
TARGET AWARD PAYMENT SCHEDULE
CUSTOMER SERVICE
RELIABILITY INDEX VS. PRIOR FIVE-YEAR AVERAGE
Service Reliability Index Performance Factor*
------------------------- -------------------
85% or lower 1.50
92.5% 1.25
100% 1.00
105% 0.50
110% or higher 0.00
*Interpolate at intermediate performance.
Example: If a Region's current reliability index is 97%, 3%
better than its five-year average of 100%, the performance
factor is:
[(100%-97%)/(100%-92.5%) x .25] + 1 = 1.10
Special adjustments may be considered for catastrophic
situations.
4.5 MATERIAL AND SUPPLY INVENTORY REDUCTION is based on
attainment of a dollar inventory reduction goal established
for 1996. The goals will be adjusted to accommodate the
Capital Spare Parts transfer to Materials & Supplies that
began last year. Energy Delivery Support participants will
have a $4 million meter inventory reduction goal in lieu of
the M&S inventory reduction goal. The 1996 targets are:
T&D ENERGY DELIVERY GROUP DELIVERY
BUSINESS GROUP, UNITS AND REGIONS
TARGET AWARD PAYMENT SCHEDULE
MATERIAL & SUPPLY INVENTORY REDUCTION
Results as Percent of Goal Performance Factor*
-------------------------- -------------------
150% 1.50
100% 1.00
50% 0.50
0% 0.00
*Interpolate at intermediate performance.
Example: If a region's results as a percent of goal
were 125%, the performance factor is 1.25.
4.6 MARKETING performance is measured by two indices that are
weight-averaged to yield a single performance factor. The
target, results, and award are the same for both the
Transmission and Distribution groups. The indices are
further defined below.
MARKETING results constitute 70% of the marketing
performance factor. The results are measured by comparing
actual performance against marketing objectives for the
current year. Marketing objectives are expressed as a
collection of product goals which are weighted in value
through the assignment of Smart Point equivalents.
Marketing objective performance is computed by dividing the
total Smart points earned by the Smart Point goals assigned.
The total assigned 1996 Smart Points are 6,496,398. The
1996 performance factors are:
ENERGY DELIVERY BUSINESS GROUP, UNITS AND REGIONS
TARGET AWARD PAYMENT SCHEDULE
MARKETING RESULTS
Percent of Goal Performance Factor*
--------------- -------------------
110% 1.50
105% 1.25
100% 1.00
95% 0.50
90% 0.00
*Interpolate at intermediate results.
MARKETING ACCOUNT MANAGEMENT OBJECTIVES constitute 30% of
the marketing performance factor. Achievement is measured
by comparing actual performance with account objectives for
the year. Account management objectives are expressed as a
collection of loyalty enhancing activities, including
identification of decision groups, development of business
plans, customer presentation and agreements, and
implementation of two or more business plan items with
designated customers. These activities are weighted in
value through the assignment of point equivalents as a
function of assigned customers. Account management
objective performance is computed in accordance with the
following tables which are preset to result in a 100 point
base for easy conversion to percentage attainment.
NATIONAL ACCOUNT MANAGEMENT
Maximum Actual
Measurement Goal Accomplishment Score Score*
----------- ---- -------------- ------- ------
Compl. Interv. 70 20
Meter Maps 50 10
ID Decision Groups 50 20
Business Plans 25 35
Cust. Pres. & Agree. 25 15
Bus Plan Impl. 15 10
Total 110
*(Accomplishment/Goal) x Maximum Score = Actual Score (not
to exceed maximum score)
KEY ACCOUNT MANAGEMENT
Maximum Actual
Measurement Goal Accomplishment Score Score*
----------- ---- -------------- ------- ------
ID Decision Groups 170 20
Business Plans 136 50
Cust. Pres & Agree. 110 30
Business Plans 50 10
Total 110
*(Accomplishment/Goal) x Maximum Score = Actual Score (not
to exceed maximum score)
The results for key and national accounts are then weighted
3:1, respectively. The resulting percentage achievement is
utilized in the following payment schedule to determine the
composite account management performance measure for this
index.
ENERGY DELIVERY BUSINESS GROUP, UNITS AND REGIONS
TARGET AWARD PAYMENT SCHEDULE
ACCOUNT MANAGEMENT OBJECTIVES
Results as % of Goal Performance Factor*
-------------------- -------------------
Over 110% 1.50
105% 1.25
100% 1.00
95% 0.50
Below 90% 0.00
*Interpolate at intermediate results.
5.0 MARKETING BUSINESS UNIT PERFORMANCE CRITERIA
The MARKETING PERFORMANCE of the marketing organization is
measured by five indices which are weighted to yield a single
performance factor. These five indices are the annual marketing
objective, the annual account management objective, the electric
market share objective, the energy market share objective, and
the loyalty objective. These indices are weighted at 50%, 25%,
5%, 5%, and 15%, respectively, for computation of a single
performance factor.
The description of each of these indices and the performance
factor computation methodology is as follows:
5.1 ACHIEVEMENT OF THE ANNUAL MARKETING OBJECTIVE is measured by
comparing actual performance against marketing objectives
for the current year. Marketing objectives are expressed as
a collection of product goals which are weighted in value
through the assignment of Smart Point equivalents.
Marketing objective performance is computed by dividing the
total Smart Points earned by the Smart Point goals assigned.
The total Smart Points assigned for 1996 is 6,496,398. The
performance factor is calculated in accordance with the
following payment schedule.
MARKETING BUSINESS UNIT
TARGET AWARD PAYMENT SCHEDULE
ANNUAL MARKETING OBJECTIVE
Results as % of Goal Performance Factor*
-------------------- -------------------
Over 110% 1.50
105% 1.25
100% 1.00
95% 0.50
Below 90% 0.00
*Interpolate at intermediate results.
Example: If 105% of the marketing goals has been achieved,
the performance factor is 1.25. If 108% has been attained,
the performance factor would be calculated as follows:
[(108%-105%)/(110%-105%) x 0.25] + 1.25 = 1.40
5.2 ACHIEVEMENT OF THE ANNUAL ACCOUNT MANAGEMENT OBJECTIVE is
measured by comparing actual performance with account
objectives for the current year. Account management
objectives are expressed as a collection of loyalty-
enhancing activities, including identification of decisions
groups, development of business plans, customer presentation
and agreements, and implementation of two or more business
plan items with designated customers. These activities are
weighted in value through the assignment of point
equivalents as function of assigned customers. Account
management objective performance is computed as per the
following tables, which are preset to result in a 100 point
base for easy conversion to percentage attainment.
NATIONAL ACCOUNT MANAGEMENT
Maximum Actual
Measurement Goal Accomplishment Score Score*
----------- ---- -------------- ------- ------
Compl. Interv. 70 20
Meter Maps 50 10
ID Decision Groups 50 20
Business Plans 25 35
Cust. Pres. & Agree. 25 15
Bus Plan Impl. 15 10
Total 110
*(Accomplishment/Goal) x Maximum Score = Actual Score (not
to exceed maximum score)
KEY ACCOUNT MANAGEMENT
Maximum Actual
Measurement Goal Accomplishment Score Score*
----------- ---- -------------- ------- ------
ID Decision Groups 170 20
Business Plans 136 50
Cust. Pres & Agree. 110 30
Business Plans 50 10
Total 110
*(Accomplishment/Goal) x Maximum Score = Actual Score (not
to exceed maximum score)
The results for key and national accounts are then weighted
3:1, respectively. The resulting percentage achievement is
utilized in the following payment schedule to determine the
composite account management performance measure for this
index.
MARKETING BUSINESS UNIT
TARGET AWARD PAYMENT SCHEDULE
ACCOUNT MANAGEMENT OBJECTIVE
Results as % of Goal Performance Factor*
-------------------- -------------------
Over 110% 1.50
105% 1.25
100% 1.00
95% 0.50
Below 90% 0.00
*Interpolate at intermediate performance
5.3 ACHIEVEMENT OF THE MARKET SHARE OF ELECTRICITY OBJECTIVE is
measured by comparing the actual market share performance of
retail electricity sales against the market share of
electricity objectives for the current year. Market share
of electricity is computed by dividing the AEP total retail
electricity sales by the electricity consumed by ultimate
consumers in the 15 state regional market with both values
expressed in kWh units. The performance measure for this
index will be computed in accordance with the following
payment schedule.
MARKETING BUSINESS UNIT
TARGET AWARD PAYMENT SCHEDULE
MARKET SHARE OF ELECTRICITY
Results (market share %) Performance Factor*
------------------------ -------------------
Over 8.25% 1.50
8.20% 1.25
8.15% 1.00
8.00% 0.50
Below 7.90% 0.00
*Interpolate at intermediate performance
5.4 ACHIEVEMENT OF THE MARKET SHARE OF ENERGY OBJECTIVE is
measured by comparing the actual market share performance of
retail energy sales against the market share of electricity
objectives for the current year. Market share of energy is
computed by dividing the AEP total retail energy sales by
the energy consumed in the 15 state regional market with
both values expressed in Btu equivalents. The performance
measure for this index will be computed in accordance with
the following payment schedule.
MARKETING BUSINESS UNIT
TARGET AWARD PAYMENT SCHEDULE
MARKET SHARE OF ENERGY
Results (market share %) Performance Factor*
------------------------ -------------------
Over 3.25% 1.50
3.20% 1.25
3.15% 1.00
3.05% 0.50
Below 3.00% 0.00
*Interpolate at intermediate performance
5.5 ACHIEVEMENT OF THE LOYALTY OBJECTIVE is measured by
comparing the actual performance against loyalty objectives
for the current year. The loyalty objective performance
will be based on a weighted average of the performance
factors of the National Key Account Benchmark study by TQS
Research (TQS), the Commercial and Industrial Customer
Satisfaction Study by RKS Research and Consulting (RKS), and
the Corporate Positioning and Communication Tracking Study
by Market Strategies, Inc. (MSI) survey instruments in
proportions of 61.3%, 28.5%, and 10.2%, respectively. The
TQS, RKS, and MSI represent the key accounts, major
accounts, and residential segments, respectively. The
"Customer Loyalty - Electric" score will be utilized from
the TQS study, the "Customer Assessment Score" will be
utilized from the RKS study and the "Overall Satisfaction"
score will utilized from the MSI study. The performance
factor for each instrument will be computed in accordance
with the following payment schedules. Note that while a
percentile approach is preferred in the computation of a
performance factor with all three of the instruments, a raw
score is utilized in the RKS instrument as the timing of the
study is not anticipated to permit comparison to other
utilities' scores.
MARKETING BUSINESS UNIT
QS AND MSI TARGET AWARD PAYMENT SCHEDULE
TQS AND MSI SCORE
Results (market share %) Performance Factor*
------------------------ -------------------
Top 10% 1.50
15% 1.25
20% 1.00
25% 0.50
Bottom 70% 0.00
*Interpolate at intermediate performance
MARKETING BUSINESS UNIT
RKS TARGET AWARD PAYMENT SCHEDULE
RKS SCORE
Customer Acceptance Score Performance Factor*
------------------------- -------------------
Over 3.2% 1.50
3.1% 1.25
3.0% 1.00
2.9% 0.50
Below 2.85% 0.00
*Interpolate at intermediate performance
The use of the RKS instrument is dependent on receiving
results prior to computation of the annual MICP results. In
the event this information is unavailable, the performance
measures of the TQS and MSI will be computed as a weighed
average in the proportions 85.7% and 14.3%, respectively.
6.0 POWER PLANT MANAGERS
Incentive awards for Power Plant managers are from two sources:
- - AEP Corporate performance - weighted 25%; and
- - Performance as determined by Power Plant Incentive
Compensation Plan - weighted 75%.
7.0 REGION PLANT SERVICES MANAGERS AND
PRODUCTIONS SERVICES MANAGERS
Incentive awards for the managers of the Northern and Southern
Region Plant Services are from two sources:
- - AEP Corporate performance - weighted 25%; and
- - Performance as determined by the Region Plant Services
Incentive Compensation Plan - weighted 75%.
8.0 CENTRAL MACHINE SHOP MANAGER
Incentive awards for the Central Machine Shop Manager are from
two sources:
- - AEP Corporate performance - weighted 25%; and
- - Performance as determined by the Central Machine Shop
Incentive Compensation Plan - weighted 75%.
9.0 FUEL SUPPLY PERFORMANCE CRITERIA
There are three overall Fuel Supply performance measures, which
are weighted to determine a single Fuel Supply performance
factor. These are as follows:
- - Adjusted cost of coal produced from affiliated mines,
measured by cents per million BTU (cents/MM BTU) for the current
year as reduced to reflect extraordinary costs due to
downsizing and/or other special expenses and a volume
adjustment of 55cents/MM BTU for variance from budgeted tons -
weighted at 50%; and
- - Performance relative to the PUCO negotiated EFC cap -
weighted at 25%; and
- - Safety incidence rate as a percent of the industry incidence
rate for the current year - weighted at 25%.
The following describes each in greater detail.
9.1 ADJUSTED COST OF COAL PRODUCED FROM AFFILIATED MINES - The
adjusted cost of coal produced as measured by cents/MM BTU is a
measure of how efficiently affiliated mines produce clean
coal for use in the System's power plants. Performance
factors relate to achievement as follows:
FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE
AFFILIATED MINE COSTS
Cents/MM BTU Performance Factor*
------------ -------------------
154.3 or lower 1.50
156.3 1.25
158.3 1.00
160.3 0.75
162.3 0.50
164.3 0.25
166.3 or higher 0.00
*Interpolate at intermediate performance.
9.2 PUCO CAP PERFORMANCE - The PUCO cap performance measures the
amount of operating loss as defined in the Settlement
Agreement dated February 28, 1995.
FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE
PUCO CAP PERFORMANCE
Cap Performance Performance Factor*
--------------- -------------------
$5.0 million 1.50
$7.5 million 1.25
$10.0 million 1.00
$12.5 million 0.75
$15.0 million 0.50
$17.5 million 0.25
More than $20 million 0.00
*Interpolate at intermediate performance
9.3 SAFETY PERFORMANCE - Achievement of the safety objective is
measured by comparing the incidence rate for the current
year with the comparable coal industry incidence rate
(including Fuel Supply). Performance factors relate to
achievement as follows:
FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE
SAFETY - INCIDENCE RATE VS. COAL INDUSTRY
Incidence Rate -
Percent Industry Rate Performance Factor*
--------------------- -------------------
55 or lower 1.50
65 1.25
75 1.00
85 .75
90 .50
95 .25
higher than 95 0
*Interpolate at intermediate performance.
Example: If Fuel Supply's incidence rate were 92% of the
coal industry rate, the performance factor is:
[(95%-92%)/(95%-90%) x 0.25] + .25 = .40
9.4 SENIOR VICE PRESIDENT AND SENIOR STAFF-FUEL SUPPLY -
DELIVERED FUEL PRICES
In addition to the awards allocated to Corporate performance
and Fuel Supply performance, the Senior Vice President and
Senior Staff-Fuel Supply are assigned a 25% award allocated
to delivered fuel prices. (See Page A-4 for the target
award payment schedule.)
9.5 VICE PRESIDENT - FUEL PROCUREMENT
In addition to the Corporate performance measures weighted
25% and the overall Fuel Supply performance measure weighted
20%, the Vice President - Fuel Procurement has a single
Department performance weighing of 50% for delivered fuel
prices.
Tables showing the performance factors and how they relate
to achievement begin on page A-5 of the Addendum.
9.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS)
MEASURES
In addition to the Corporate performance measures weighted
25% and the overall Fuel Supply performance measures
weighted 25%, the Fuel Supply General Mine Managers and
General Superintendent (Meigs) have two Division/Mine
performance measures which are weighted to determine a
single Division/Mine performance award weighing of 50% for
the mines for which they are responsible. These are as
follows:
- Adjusted cost of coal produced from affiliated mines,
measured by cents per million BTU (cents/MM BTU) for the
current year as reduced to reflect extraordinary costs
due to downsizing and/or other special expenses, and a
+/- volume adjustment of $.55/MM BTU for variance from
budgeted tons - weighted at 75%; and
- Safety incidence rate for the current year as a percent
of the comparable industry incidence rate for either
underground or surface mines (whichever is applicable) -
weighted at 25%.
Tables showing the performance factors and how they relate
to achievement begin on page A-6 of the Addendum.
The performance factor shall be zero for any mine whose lost
workdays charged for any single occurrence total 6,000 days
or higher.
9.7 MANAGER - RIVER TRANSPORTATION MEASURES - The Manager-River
Transportation has, in addition to the overall Corporate
performance measures weighted 25%, two Department perform-
ance measures which are weighted to determine a single
Department performance weighing of 75% for River
Transportation. These are:
- Operating costs measured by adjusted mils per ton mile
(mils/ton mile - $0.00x) for the current year, excluding
cost for fuel, associated taxes and other fixed and
special expenses, as approved by the SVP-Fuel Supply,
with a +/- volume adjustment of 1.55 mils/ton mile for
variance from budgeted mils per ton mile - weighted 75%;
and
- Safety incidence rate for the current year as a percent
of the most recently published incidence rate for the
water transportation industry - weighted 25%.
The performance factor shall be zero for any operation whose
lost workdays charged for any single occurrence total 6,000
days or higher.
Tables showing the performance factors and how they relate
to achievement are on page A-9 of the Addendum.
9.8 MANAGER - COOK COAL TERMINAL MEASURES - The Manager-Cook
Coal Terminal (CCT) has, in addition to the overall
Corporate performance measures weighted 25%, two Department
performance measures which are weighted to determine a
single Department performance weighing of 75% for Cook Coal
Terminal. These are:
- Operating costs measured by adjusted cost per ton of
affiliated coal transloaded less other fixed and special
expenses (e.g., harbor dredging), as approved by the SVP-
Fuel Supply, +/- adjustment volumes times $.28/ton -
weighted 75%; and
- Safety incidence rate at CCT for the current year as a
percent of the most recently published incidence rate for
the coal preparation plants - weighted 25%.
The performance factor shall be zero for any operation whose
lost workdays charged for any single occurrence total 6,000
days or higher.
Tables showing the performance factors and how they relate
to achievement are on page A-10.
9.9 MANAGING DIRECTOR - TRANSPORTATION - In addition to the
Corporate performance measures weighted 25% and the overall
Fuel Supply performance measure weighted 20%, there are two
overall transportation department performance criteria
which are weighted to determine a single department
performance factor. These are:
- Transportation cost of fuel delivered comprised of
performance at Cook Coal Terminal (adjusted cost per
ton), River Transportation (adjusted cost per ton mile)
and delivered fuel prices - each weighted 25%; and
- Safety incidence rate at River Transportation and Cook
Coal for the current year as a percent of the most
recently published comparable industry rate for each
location (RTD vs water transportation industry; CCT vs
coal preparation plants) - each weighted 12.5%.
Tables showing the performance factors and how they relate
to achievement are on page A-11.
9.10 SENIOR VICE PRESIDENT, VICE PRESIDENTS, SENIOR STAFF-FUEL
SUPPLY, AND MANAGING DIRECTOR-TRANSPORTATION
In addition to other measures, the Lancaster based
participants are assigned a 5% award allocated to Power
Generation Production Costs. The Power Generation
Production Cost measures the cost of fuel consumed and the
operating and maintenance costs at the fossil power plants.
(See page A-6 for the target award payment schedule.)
10.0 POWER GENERATION PERFORMANCE CRITERIA
There are five performance criteria that are used as part of the
power plant and power plant technical support portion of the
performance for Power Generation Group. The participant's
function within the organization determines the performance
criteria weighting.
Tables showing the performance factors and how they relate to
achievement begin on page A-13 of the Addendum.
11.0 DEPARTMENT/BUSINESS UNIT OBJECTIVES
Performance criteria, with appropriate weightings, may be
established each year based on agreed objectives in each
department/business unit.
The performance rating scale is similar to those used in other
measures, with ratings from 0 to 1.5, and 1.0 as target
performance. Department/Business Unit Heads who set objectives
which are subjective in nature will determine the degree of
accomplishment in accordance with the 0 to 1.5 scale, taking into
consideration such factors as timeliness, degree of
accomplishment, acceptability of results, etc.
In situations where a participant who has been assigned
objectives leaves the position during a Plan year, his successor
will generally assume the same objectives and both participants
will share the final performance factor score.
12.0 THE MICP IN ACTION
Following is an illustration to demonstrate the mechanics of the
MICP. For purposes of this example, assume that an Energy
Distribution Region Manager with annual base salary earnings of
$100,000 has a target award of 20%, or $20,000. This
individual's target award is allocated among the following
performance criteria:
- AEP Corporate Performance: 50%, or $10,000
- Energy Distribution Region: 50%, or $10,000
12.1 In determining the AEP Corporate portion of the MICP award,
results are measured for three separate Corporate
performance criteria to arrive at a single Corporate
performance factor. ROE is measured in two ways, averaged,
and given a 25% weighing; Total Investor Return (TIR) is
given a 25% weighing; and Realization Ratio is given a 50%
weighing.
ROE 14% actual ROE = 1.00
S&P ranking (7th) = 1.40
--------------------------
Average 1.20 x 25% = .30
TIR S&P ranking (12th) = .80 x 25% = .20
Realization
Ratio AEP ratio (.80) = 1.25 x 50% = .625
Corporate Performance Factor = 1.125
The AEP Corporate award, then, is 1.125 x $10,000, or $11,250.
12.2 In determining the Energy Distribution Region's portion of
the MICP award, results are measured against six Energy
Distribution performance criteria to arrive at the Region's
performance factor.
Customer Result
Satisfaction TQS/MSI = 15% (1.25) = 1.20 x 20% = 0.24
& Loyalty RSK = 2.95 (0.75)
Safety
Performance Result = 0.70 = 1.50 x 20% = 0.30
O&M Expense
Performance
vs. Budget Result = 93% = 1.25 x 20% = 0.25
M&S Inventory
Reduction Result = 75% = 0.75 x 10% = 0.075
Customer Service
Reliability Result = 105% = 0.50 x 20% = 0.10
Index Marketing
Performance Result = 100% = 1.00 x 10% = 0.10
======
Energy Distribution Performance Factor = 1.065
The Energy Distribution Business Unit Award, then, is 1.065 x $10,000
or $10,650.
12.3 The Energy Distribution Region Manager in our example
earned a total award of $20,700, as follows:
- AEP Corporate $11,250.00
- Energy Distribution Business Unit 10,650.00
$21,900.00
Of that amount, 80%, or $17,520.00 is paid during the first
part of the following year, assuming the participant has
not elected to defer receipt of that payment under Section
16.2. The balance, $4,380.00, is deferred in AEP common
stock units for three years. (No actual shares of stock
are purchased--the amount deferred is merely treated as if
shares had been purchased with these funds.) During that
time dividends, which are credited on the deferred stock
units, are used to "purchase" additional deferred stock
units. After three years, the individual will receive a
cash payment in the amount of the deferred units' value,
which shall be equal to the average daily high and low
market price of AEP common stock for the quarter preceding
the payment date.(See page A-1 in the Addendum for further
details.) A participant may elect to defer the 20% award
beyond the mandatory three years in accordance with Section
16.2.
13.0 PAYMENT RIGHTS AT TERMINATION
OF ACTIVE EMPLOYMENT
13.1 TERMINATION AFTER COMPLETION OF PLAN YEAR - A participant
who is actively employed on December 31 of the Plan year is
entitled to receive the regular cash award (80%) for that
year and, if applicable, the value of his prior deferred
award that has met the three calendar year requirement.
For example, an employee who is actively employed on
12/31/96, and subsequently terminates is entitled to the
80% cash award for Plan year 1996, and if applicable, the
value of any 1993 Plan year deferred amount.
Alternatively, a participant may elect to defer receipt of
awards in accordance with Section 16.2.
13.2 TERMINATION DUE TO DEATH, RETIREMENT, OR DISABILITY - If a
participant should leave active employment during a Plan
year because of death, retirement, or disability, the award
will be pro-rated based on the time the participant was
actively employed in positions covered by the Plan during
that year. Full payment of 100% of the pro-rated award
will be made as soon as practicable in the following year.
The mandatory deferrals of the 20% portions of any awards
are normally paid as soon as practicable after the
participant's death, retirement, or disability. For
purposes of this Plan, disability shall mean the employee
meets the definition of permanent and total disability
under the AEP System Retirement Plan. For purposes of this
Section 13.2 and Section 13.4, "retirement" occurs on the
date an employee who is at least age 55 and who has five or
more years of vesting service, ceases active employment
with the company.
In situations where a participant retires, plan
participation ends on the date that full control and
responsibility for the function ceased. The manager who is
on vacation prior to and extending immediately into
retirement has effectively ended his responsibility for
managing the unit.
Upon the death of an active or terminated participant, all
deferred awards are immediately payable to the
participant's surviving spouse. If the participant's
spouse is not living, the deferred awards are immediately
payable to the participant's estate.
13.3 INVOLUNTARY TERMINATION DURING PLAN YEAR - If a participant
is involuntarily terminated from employment during a Plan
year because of (1) the permanent closing of an office,
plant or other facility, or (2) as a direct result of
restructuring, consolidation, change in control of the
corporation or downsizing, the award will be pro-rated
based on the time the participant was actively employed in
positions covered by the Plan during that year. Full
payment of 100% of the pro-rated award will be made as
soon as practicable in the following year. Deferred awards
are payable as soon as practicable after the participant's
involuntary termination.
13.4 Any potential award for the current Plan year, and all
mandatory deferrals of the 20% portions of any awards that
have not met the three calendar year requirement pursuant
to Section 16.1, are forfeited when a participant
terminates active employment during the Plan year for
reasons other than (1) death, retirement, disability, or
(2) involuntary termination as described in Section 13.3.
14.0 CHANGES IN SALARY/POSITION/PARTICIPATION
Awards are paid as a percentage of the performance year's annual
base earnings, including merit and promotional increases.
In situations where participation changes as a result of job
assignment, the employee will be entitled to a pro-rata share of
any incentive award earned during the period he or she is
employed in a position covered by the Plan.
In the event an MICP participant is transferred from a position
covered by the Plan to another such covered position within the
AEP System, the participant will be entitled to a pro-rata share
of any incentive award earned during the period he or she is
employed in each of the positions.
If the participant is subject to different target awards as a
percent of base salary in the same performance year, each target
award percentage will be applied to the base salary earned during
the period employed in the related position.
15.0 PLAN ADMINISTRATION
The MICP is administered by the Human Resources Committee of the
American Electric Power Company, Inc. Board of Directors through
the Executive Compensation Committee of AEPSC. Subject to the
approval of the Chief Executive Officer, the Executive
Compensation Committee's interpretation of the Plan's provisions
are conclusive and binding on all participants. Participation in
the MICP in any Plan year shall not be viewed as conferring any
right to continued employment, or to continued participation in
the MICP.
Subject to the approval of the Chief Executive Officer, the
Executive Compensation Committee of AEPSC may vary performance
criteria, weights, and/or performance factor schedules from time
to time when appropriate, enlarge or diminish the number of
participants, or make other adjustments or amendments to improve
the workings of the Plan.
The Board of Directors reserves a right to amend or terminate the
MICP. Amendment or termination of the Plan will not adversely
affect any funds deferred into stock unit accounts prior to the
amendment or termination.
For good and sufficient cause, on petition by a senior officer of
the Company, and with the approval of the Chief Executive
Officer, any performance factor(s) for any participant(s) may be
varied not more than plus or minus 25% to reflect exceptional
circumstance.
16.0 MICP AWARD DISTRIBUTIONS AND DEFERRALS
16.1 When all of the necessary data are available after the end
of the Plan year, performance results will be calculated
and awards made as soon as practicable. Unless the
participant has made an election to defer receipt of an
additional portion of the entire award in accordance with
Section 16.2, eighty percent of the award earned will be
paid in cash. Twenty percent of any awards made under the
MICP will be deferred. All deferrals are invested in AEP
stock unit accounts. No AEP stock is actually purchased --
the amount deferred is treated as if actual shares had been
purchased.
The number of stock units is determined by dividing the
amount deferred by the average of the daily high and low
AEP common stock prices during the Plan year in which the
incentive award was earned.
An amount equal to AEP common stock dividends is credited
on the date payable each calendar quarter commencing with
the first quarter of the year following the year in which
the award was earned. Those amounts are "reinvested" to
"purchase" additional deferred stock units at the average
of the daily high and low market price for the quarter in
which the stock dividend applies.
Amounts deferred in stock units are payable in cash to
participants after the end of three calendar years
following the end of the year for which the 80% portion of
the award was scheduled to be paid. However, a participant
may elect to defer receipt as outlined in Section 16.2.
The value of stock units paid is based on the average daily
high and low market price of AEP common stock for the
quarter immediately preceding the date of payment.
Because amounts held in deferred stock unit accounts do not
involve the actual purchase of stock, Plan participants are
not entitled to voting or certain other rights applicable
to an actual shareholder.
Amounts held in deferred stock unit accounts may not be
assigned, transferred, or pledged by a Plan participant nor
will they be subject to execution, attachment or other
similar process.
If the Executive Compensation Committee determines that the
occurrence of any merger, reclassification, consolidation,
recapitalization, stock dividend or stock split requires an
adjustment in order to preserve the benefits intended under
the Plan, then the Committee may, in its discretion, make
equitable proportionate adjustments in the number of
deferred stock units held by participants.
16.2 Elections to defer receipt of a portion of the Plan's 80%
cash award (up to the full amount) or any previously
deferred 20% awards must be executed one year prior to the
date each award would otherwise be payable. The initial
elective deferral period is one 3-year term for the 80%
cash award. Subsequent deferrals, following the initial
deferral period, shall apply to the aggregate amounts
initially deferred and shall be for periods of not less
than one year; however, if the participant's elective
deferral period extends beyond the participant's employment
termination date and the participant's termination occurred
under circumstances other than those described in Section
13.3, payment will be made no later than five years after
the participant's termination of employment.
All amounts deferred in accordance with the preceding are
reinvested in AEP stock unit accounts described in Section
16.1.
17.0 POSSIBLE ADJUSTMENTS TO CORPORATE
PERFORMANCE DATA
If estimated data are required to calculate corporate performance
awards, or if corrections are made to data previously reported as
final, adjustments to awards may be made when final data are
available.
18.0 FUEL SUPPLY PAYMENT SCHEDULES
18.1 SENIOR VICE PRESIDENT - FUEL SUPPLY
18.2 FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE
DELIVERED FUEL PRICES
Cents/MM BTU Performance Factor*
------------ -------------------
135.0 1.50
136.5 1.25
138.0 1.00
139.5 0.75
141.0 0.50
142.5 0.25
144.0 0.00
*Interpolate at intermediate performance.
18.3 VICE PRESIDENT - FUEL PROCUREMENT
18.4 Fuel Supply Target Award Payment Schedule
DELIVERED FUEL PRICES
Cents/MM BTU Performance Factor*
------------ -------------------
135.0 1.50
136.5 1.25
138.0 1.00
139.5 0.75
141.0 0.50
142.5 0.25
144.0 0.00
*Interpolate at intermediate performance.
18.5 FUEL SUPPLY TARGET AWARD PAYMENT SCHEDULE
POWER GENERATION PRODUCTION COST
mils/KWH Performance Factor*
-------- -------------------
16.78 or lower 1.50
16.98 1.25
17.18 1.00
17.38 0.50
17.58 0.00
*Interpolate at intermediate performance.
18.6 GENERAL MINE MANAGERS/GENERAL SUPERINTENDENT (MEIGS)
18.7 SOUTHERN OHIO COAL COMPANY - MEIGS
ADJUSTED COST OF COAL PRODUCED
Cents/MM BTU Performance Factor*
------------ -------------------
150.4 or lower 1.50
152.4 1.25
154.4 1.00
156.4 0.75
158.4 0.50
160.4 0.25
162.4 or higher 0.00
*Interpolate at intermediate performance.
18.8 CENTRAL OHIO COAL COMPANY
ADJUSTED COST OF COAL PRODUCED
Cents/MM BTU Performance Factor*
------------ -------------------
226.4 or lower 1.50
228.4 1.25
230.4 1.00
232.4 0.75
234.4 0.50
236.4 0.25
238.4 or higher 0.00
*Interpolate at intermediate performance.
18.9 WINDSOR COAL COMPANY
ADJUSTED COST OF COAL PRODUCED
Cents/MM BTU Performance Factor*
------------ -------------------
127.2 or lower 1.50
129.2 1.25
131.2 1.00
133.2 0.75
135.5 0.50
137.2 0.25
139.2 or higher 0.00
*Interpolate at intermediate performance.
18.10 ALL COAL MINES
SAFETY INCIDENCE RATE
Incidence Rate -
Percent Industry Rate Performance Factor*
--------------------- -------------------
55 or lower 1.50
65 1.25
75 1.00
85 0.75
90 0.50
95 0.25
Higher than 95 0.00
*Interpolate at intermediate performance.
18.11 MANAGER - RIVER TRANSPORTATION
18.12 RIVER TRANSPORTATION
OPERATING COST PER TON MILE
Mils/Ton Mile
($.00x) Performance Factor*
------------- -------------------
4.07 or lower 1.50
4.12 1.25
4.17 1.00
4.22 0.75
4.27 0.50
4.32 0.25
4.37 or higher 0.00
*Interpolate at intermediate performance.
18.13 RIVER TRANSPORTATION
SAFETY INCIDENCE RATE
Incidence Rate -
% Industry Rate Performance Factor*
---------------- -------------------
55 or lower 1.50
65 1.25
75 1.00
85 0.75
90 0.50
95 0.25
Higher than 95 0.00
*Interpolate at intermediate performance.
18.14 MANAGER - COOK COAL TERMINAL
18.15 COOK COAL TERMINAL
ADJUSTED COST PER TON
Adjusted Cost per Ton Performance Factor*
--------------------- -------------------
$1.47 or better 1.50
$1.49 1.25
$1.51 1.00
$1.53 0.75
$1.55 0.50
$1.57 0.25
$1.59 or higher 0.00
*Interpolate at intermediate performance.
18.16 COOK COAL TERMINAL
SAFETY INCIDENCE RATE
Incidence Rate -
% Industry Rate Performance Factor*
---------------- -------------------
55 or better 1.50
65 1.25
75 1.00
85 0.75
90 0.50
95 0.25
Higher than 95 0.00
*Interpolate at intermediate performance.
18.17 MANAGING DIRECTOR - TRANSPORTATION
18.18 COOK COAL TERMINAL
ADJUSTED COST PER TON
Adjusted Cost Ton Performance Factor*
----------------- -------------------
$1.47 or better 1.50
$1.49 1.25
$1.51 1.00
$1.53 0.75
$1.55 0.50
$1.57 0.25
$1.59 or higher 0.00
*Interpolate at intermediate performance.
18.19 RIVER TRANSPORTATION
OPERATING COST PER TON MILE
Mils/Ton Mile ($.00x) Performance Factor*
--------------------- -------------------
4.07 or lower 1.50
4.12 1.25
4.17 1.00
4.22 0.75
4.27 0.50
4.32 0.25
4.37 or higher 0.00
*Interpolate at intermediate performance.
18.20 DELIVERED FUEL PRICES
Cents/MM BTU Performance Factor*
------------ -------------------
135.0 1.50
136.5 1.25
138.0 1.00
139.5 0.75
141.0 0.50
142.5 0.25
Higher than 144.0 0.00
*Interpolate at intermediate performance
18.21 RIVER TRANSPORTATION AND COOK COAL TERMINAL
SAFETY INCIDENCE RATE
Incidence Rate -
% Industry Rate Performance Factor*
---------------- -------------------
55 or lower 1.50
65 1.25
75 1.00
85 0.75
90 0.50
95 0.25
Higher than 95 0.00
*Interpolate at intermediate performance
19.0 POWER GENERATION DEPARTMENT/
BUSINESS UNIT PAYMENT SCHEDULES
19.1 O&M EXPENDITURE
Actual O&M (Mils/KWH) Performance Factor*
--------------------- -------------------
3.29 or lower 1.50
3.34 1.25
3.39 1.00
3.44 0.50
3.49 or higher 0.00
*Interpolate at intermediate performance
19.2 POWER GENERATION PRODUCTION COST
Actual O&M (Mils/KWH) Performance Factor*
--------------------- -------------------
16.78 or lower 1.50
16.98 1.25
17.18 1.00
17.38 0.50
17.59 or higher 0.00
*Interpolate at intermediate performance.
19.3 CAPITAL EXPENDITURES
Actual Capital
Exenditures ($ Million) Performance Factor*
----------------------- -------------------
135.5 or lower 1.50
140.3 1.25
145.3 1.00
150.3 0.50
155.4 or higher 0.00
*Interpolate at intermediate performance
19.4 EQUIVALENT AVAILABILITY
Equivalent Availability (%) Performance Factor*
--------------------------- -------------------
84.0 1.50
82.0 1.25
80.0 1.00
78.0 0.75
76.0 0.50
74.0 or lower 0.00
*Interpolate at intermediate performance
19.5 HEAT RATE
Heat Rate (BTU/KWH) Performance Factor*
------------------- -------------------
9,655 1.50
9,663 1.25
9,670 1.00
9,677 0.75
9,685 0.50
9,700 or Higher 0.00
*Interpolate at intermediate performance.
</TABLE>
<TABLE>
EXHIBIT 12
APPALACHIAN POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1991 1992 1993 1994 1995 6/30/96
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $ 72,800 $ 84,177 $ 80,472 $ 75,815 $ 80,777 $ 82,857
Interest on Other Long-term Debt. . . . . . . . 18,282 17,986 16,846 16,415 16,404 16,259
Interest on Short-term Debt . . . . . . . . . . 3,089 1,792 1,615 3,366 5,119 4,916
Miscellaneous Interest Charges. . . . . . . . . 3,011 2,617 2,954 3,913 5,323 7,050
Estimated Interest Element in Lease Rentals . . 5,700 6,700 7,900 7,700 7,000 7,000
Total Fixed Charges. . . . . . . . . . . . $102,882 $113,272 $109,787 $107,209 $114,623 $118,082
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . $140,419 $131,419 $125,132 $102,345 $115,900 $137,207
Plus Federal Income Taxes . . . . . . . . . . . 47,227 46,017 51,681 39,599 53,355 59,625
Plus State Income Taxes . . . . . . . . . . . . 3,650 2,649 8,887 5,910 7,273 6,959
Plus Fixed Charges (as above) . . . . . . . . . 102,882 113,272 109,787 107,209 114,623 118,082
Total Earnings . . . . . . . . . . . . . . $294,178 $293,357 $295,487 $255,063 $291,151 $321,873
Ratio of Earnings to Fixed Charges. . . . . . . . 2.85 2.58 2.69 2.37 2.54 2.72
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000006879
<NAME> APPALACHIAN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,872,707
<OTHER-PROPERTY-AND-INVEST> 30,111
<TOTAL-CURRENT-ASSETS> 371,581
<TOTAL-DEFERRED-CHARGES> 55,159
<OTHER-ASSETS> 430,754
<TOTAL-ASSETS> 3,760,312
<COMMON> 260,458
<CAPITAL-SURPLUS-PAID-IN> 550,419
<RETAINED-EARNINGS> 208,399
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,019,276
190,082
55,000
<LONG-TERM-DEBT-NET> 1,299,447
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
150
<CAPITAL-LEASE-OBLIGATIONS> 33,493
<LEASES-CURRENT> 14,884
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,147,980
<TOT-CAPITALIZATION-AND-LIAB> 3,760,312
<GROSS-OPERATING-REVENUE> 820,859
<INCOME-TAX-EXPENSE> 39,260
<OTHER-OPERATING-EXPENSES> 654,743
<TOTAL-OPERATING-EXPENSES> 694,003
<OPERATING-INCOME-LOSS> 126,856
<OTHER-INCOME-NET> 576
<INCOME-BEFORE-INTEREST-EXPEN> 127,432
<TOTAL-INTEREST-EXPENSE> 55,702
<NET-INCOME> 71,730
8,201
<EARNINGS-AVAILABLE-FOR-COMM> 63,529
<COMMON-STOCK-DIVIDENDS> 54,150
<TOTAL-INTEREST-ON-BONDS> 41,861
<CASH-FLOW-OPERATIONS> 136,875
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
