NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
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Consolidated Statements of Income and Retained Earnings
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In thousands of dollars
For the year ended December 31, 1993 1992 1991
Operating revenues:
Electric $3,332,464 $3,147,676 $2,907,293
Gas 600,967 553,851 475,225
3,933,431 3,701,527 3,382,518
Operating expenses:
Operation:
Fuel for electric generation 231,064 323,200 438,957
Electricity purchased 863,513 650,379 398,882
Gas purchased 326,273 287,316 247,502
Other operation expenses 821,247 748,023 706,400
Maintenance 236,333 226,127 227,812
Depreciation and amortization 276,623 274,090 258,816
(Note 1)
Federal and foreign income 162,515 183,233 158,137
taxes (Note 6)
Other taxes 491,363 484,833 420,578
3,408,931 3,177,201 2,857,084
Operating income 524,500 524,326 525,434
Other income and deductions:
Allowance for other funds used
during construction 7,119 9,648 8,251
(Note 1)
Federal and foreign income 15,440 27,729 24,242
taxes (Note 6)
Other items (net) 7,035 (16,338) (13,599)
29,594 21,039 18,894
Income before interest charges 554,094 545,365 544,328
Interest charges:
Interest on long-term debt . 279,902 290,734 302,062
Other interest 11,474 9,982 9,577
Allowance for borrowed funds
used during construction (9,113) (11,783) (10,680)
282,263 288,933 300,959
Net income 271,831 256,432 243,369
Dividends on preferred stock 31,857 36,512 40,411
Balance available for common 239,974 219,920 202,958
stock
Dividends on common stock 133,908 103,784 43,552
106,066 116,136 159,406
Retained earnings at beginning 445,266 329,130 169,724
of year
Retained earnings at end of $ 551,332 $ 445,266 $ 329,130
year
Average number of shares of
Common stock outstanding (in 140,417 136,570 136,100
thousands)
Balance available per average $ 1.71 $ 1.61 $ 1.49
share of common stock
Dividends paid per share $ .95 $ .76 $ .32
() Denotes deduction
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets In thousands of dollars
At December 31, 1993 1992
ASSETS
Utility plant (Note 1):
Electric plant . . . . . . . . . . . . . . . . . . . $ 7,991,346 $7,590,062
Nuclear fuel . . . . . . . . . . . . . . . . . . . . 458,186 445,890
Gas plant . . . . . . . . . . . . . . . . . . . . . 845,299 787,448
Common plant . . . . . . . . . . . . . . . . . . . . 244,294 231,425
Construction work in progress . . . . . . . . . . . 569,404 587,437
Total utility plant . . . . . . . . . . . . . . . 10,108,529 9,642,262
Less: Accumulated depreciation and amortization . . 3,231,237 2,975,977
Net utility plant . . . . . . . . . . . . . . . . 6,877,292 6,666,285
Other property and investments . . . . . . . . . . . 221,008 274,169
Current assets:
Cash, including temporary cash investments of
$100,182 and $4,121, respectively. . . . . . . . . 124,351 43,894
Accounts receivable (less allowance for doubtful
accounts of $3,600) (Note 8) . . . . . . . . . . . 258,137 221,165
Unbilled revenues (Note 1) . . . . . . . . . . . . . 197,200 180,000
Electric margin recoverable. . . . . . . . . . . . . 21,368 11,595
Materials and supplies, at average cost:
Coal and oil for production of electricity . . . 29,469 78,517
Gas storage . . . . . . . . . . . . . . . . . . . 31,689 20,466
Other . . . . . . . . . . . . . . . . . . . . . . 163,044 172,637
Prepayments:
Taxes . . . . . . . . . . . . . . . . . . . . . . 23,879 14,414
Pension expense (Note 5) . . . . . . . . . . . . 37,238 33,631
Other . . . . . . . . . . . . . . . . . . . . . . . 29,498 32,522
915,873 808,841
Regulatory and other assets:
Unamortized debt expense . . . . . . . . . . . . . . 154,210 140,803
Deferred recoverable energy costs . . . . . . . . . 67,632 61,944
Deferred finance charges (Note 1) . . . . . . . . . 239,880 239,880
Income taxes recoverable (Note 6). . . . . . . . . . 527,995 -
Recoverable environmental restoration costs (Note 8) 240,000 215,000
Other . . . . . . . . . . . . . . . . . . . . . . . 175,187 183,613
1,404,904 841,240
$ 9,419,077 $8,590,535
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets In thousands of dollars
At December 31, 1993 1992
CAPITALIZATION AND LIABILITIES
Capitalization (Note 4):
Common stockholders' equity:
Common stock, issued 142,427,057 and $ 142,427 $ 137,160
137,159,607 shares, respectively. . . . . . . . . .
1,762,706 1,658,015
Capital stock premium and expense . . . . . . . . . .
Retained earnings . . . . . . . . . . . . . . . . . . 551,332 445,266
2,456,465 2,240,441
Non-redeemable preferred stock . . . . . . . . . . . . . 290,000 290,000
Mandatorily redeemable preferred stock . . . . . . . . . 123,200 170,400
Long-term debt . . . . . . . . . . . . . . . . . . . . . 3,258,612 3,491,059
Total capitalization . . . . . . . . . . . . . . . . 6,128,277 6,191,900
Current liabilities:
Short-term debt (Note 2) . . . . . . . . . . . . . . . . 368,016 227,698
Long-term debt due within one year (Note 4). . . . . . . 216,185 57,722
Sinking fund requirements on redeemable preferred
stock (Note 4) . . . . . . . . . . . . . . . . . . . . 27,200 27,200
Accounts payable . . . . . . . . . . . . . . . . . . . . 299,209 275,744
Payable on outstanding bank checks . . . . . . . . . . . 35,284 41,738
Customers' deposits . . . . . . . . . . . . . . . . . . 14,072 13,059
Accrued taxes . . . . . . . . . . . . . . . . . . . . . 56,382 52,033
Accrued interest . . . . . . . . . . . . . . . . . . . . 70,529 70,882
Accrued vacation pay . . . . . . . . . . . . . . . . . . 40,178 38,515
Other . . . . . . . . . . . . . . . . . . . . . . . . . 82,145 40,220
1,209,200 844,811
Regulatory and other liabilities:
Accumulated deferred income taxes (Notes 1 and 6). . . . 1,313,483 755,421
Deferred finance charges (Note 1) . . . . . . . . . . . 239,880 239,880
Unbilled revenues (Note 1) . . . . . . . . . . . . . . . 94,968 77,768
Deferred pension settlement gain (Note 5) . . . . . . . 62,282 68,292
Customers refund for replacement power cost
disallowance.. . . . . . . . . . . . . . . . . . . . . 23,081 46,801
Other . . . . . . . . . . . . . . . . . . . . . . . . . 107,906 150,662
1,841,600 1,338,824
Commitments and contingencies (Note 8):
Liability for environmental restoration. . . . . . . . . 240,000 215,000
$9,419,077 $8,590,535
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
Increase (Decrease) in Cash
In thousands of dollars
For the year ended December 31, 1993 1992 1991
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . $ 271,831 $ 256,432 $ 243,369
Adjustments to reconcile net income to net cash
provided by operating activities:
Amortization of nuclear replacement power cost disallowance. (23,720) (39,547) (28,820)
Depreciation and amortization. . . . . . . . . . . . . . . . 276,623 274,090 258,816
Amortization of nuclear fuel . . . . . . . . . . . . . . . . 35,971 26,159 38,687
Provision for deferred income taxes. . . . . . . . . . . . . 30,067 55,929 68,138
Electric margin recoverable. . . . . . . . . . . . . . . . . (9,773) 3,670 (20,173)
Allowance for other funds used during construction . . . . . (7,119) (9,648) (8,251)
Deferred recoverable energy costs. . . . . . . . . . . . . . (5,688) (14,329) 4,931
(Gain)\loss on investments - net . . . . . . . . . . . . . . (5,490) 44,296 30,680
Deferred operating expenses. . . . . . . . . . . . . . . . . 15,746 20,257 31,176
Increase in net accounts receivable . . . . . . . . . . . . (36,972) (44,969) (25,900)
(Increase) decrease in materials and supplies. . . . . . . . 43,581 (28,293) 7,022
Increase in accounts payable and accrued expenses. . . . . . 15,716 31,025 4,221
Increase in accrued interest and taxes . . . . . . . . . . . 3,996 10,133 447
Changes in other assets and liabilities. . . . . . . . . . . 22,581 39,565 17,052
Net cash provided by operating activities . . . . . . . 627,350 624,770 621,395
Cash flows from investing activities:
Construction additions . . . . . . . . . . . . . . . . . . . (506,267) (452,497) (504,485)
Nuclear fuel . . . . . . . . . . . . . . . . . . . . . . . . (12,296) (37,247) (13,236)
Less: Allowance for other funds used during
construction . . . . . . . . . . . . . . . . . . . . . . . 7,119 9,648 8,251
Acquisition of utility plant . . . . . . . . . . . . . . . . (511,444) (480,096) (509,470)
(Increase) decrease in materials and supplies related to
construction. . . . . . . . . . . . . . . . . . . . . . . 3,837 (7,359) 4,682
Increase in accounts payable and accrued expenses
related to construction. . . . . . . . . . . . . . . . . . 3,929 7,756 1,055
Increase in other investments. . . . . . . . . . . . . . . . (38,731) (11,615) (69,648)
Proceeds from sale of investment in oil and gas subsidiary . 95,408 - -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (15,260) (31,588) (13,721)
Net cash used in investing activities . . . . . . . . . (462,261) (522,902) (587,102)
Cash flows from financing activities:
Proceeds from sale of common stock . . . . . . . . . . . . . 116,764 13,340 -
Sale of mortgage bonds . . . . . . . . . . . . . . . . . . . 635,000 835,000 195,600
Issuance of preferred stock. . . . . . . . . . . . . . . . . - - 22,850
Redemption of preferred stock. . . . . . . . . . . . . . . . (47,200) (41,950) (42,830)
Reductions of long-term debt . . . . . . . . . . . . . . . . (641,990) (796,795) (231,941)
Net change in short-term debt and revolving credit
agreements . . . . . . . . . . . . . . . . . . . . . . . . 50,318 90,130 76,606
Dividends paid . . . . . . . . . . . . . . . . . . . . . . . (165,765) (140,296) (83,963)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . (31,759) (44,781) (6,808)
Net cash used in financing activities . . . . . . . . . (84,632) (85,352) (70,486)
Net increase (decrease) in cash . . . . . . . . . . . . . . . . 80,457 16,516 (36,193)
Cash at beginning of year . . . . . . . . . . . . . . . . . . . 43,894 27,378 63,571
Cash at end of year . . . . . . . . . . . . . . . . . . . . . . $ 124,351 $ 43,894 $ 27,378
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest. . . . . . . . . . . . . . . . . . . . . . . . $ 300,791 $ 323,972 $ 331,828
Income taxes. . . . . . . . . . . . . . . . . . . . . . 106,202 76,519 67,509
Supplemental schedule of noncash investing and
financing activities:
Liability for environmental restoration . . . . . . . . . . . . 25,000 15,000 200,000
During June 1992, the Company acquired all of the common stock of Syracuse Suburban Gas Company, Inc. in
exchange for 353,775 shares of the Company's common stock having a value of $6,120,000.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Company is subject to regulation by the PSC and FERC
with respect to its rates for service under a methodology which
establishes prices based on the Company's cost. The Company
maintains its accounting records on the basis of such regulation,
which it believes complies with generally accepted accounting
principles. The Company's accounting policies conform to
generally accepted accounting principles, as applied to regulated
public utilities, and are in accordance with the accounting
requirements and ratemaking practices of the regulatory
authorities.
Principles of Consolidation: The consolidated financial
statements include the Company and its wholly-owned subsidiaries.
All significant intercompany balances and transactions have been
eliminated. Assets and liabilities of its Canadian energy
subsidiary, Opinac Energy Corporation, are translated into U.S.
dollars at the exchange rate in effect at the balance sheet date.
Revenue and expense accounts are translated at the average
exchange rate in effect during the year. Currency translation
adjustments are recorded as a component of equity and do not have
a significant impact on financial condition. The results of
operations of the Company's oil and gas subsidiary are included
in other income and deductions on the Consolidated Statements of
Income and Retained Earnings.
Subsidiary oil and gas properties: During 1993, the Company sold
its interest in its Canadian oil and gas company, Opinac
Exploration Limited. This was done to streamline the Company's
business and focus on its core electric and gas utility assets.
The sale did not have a material impact on the Company's results
of operations or financial condition. The Company retained its
ownership of Opinac Energy Corporation and the Company's
subsidiary, Canadian Niagara Power Limited, an Ontario electric
utility company.
The net book value of oil and gas properties and equipment,
less related deferred income taxes, was limited to the sum of the
after tax present value of net revenues from proved oil and gas
reserves and the lower of cost or fair value of unproved
properties. The calculation of future net revenues was based
upon prices and costs in effect at the end of the year. Based
upon the calculation of this "ceiling test" at December 31, 1991
and March 31, 1992, the Company recorded reserves of
approximately $23 million and $21 million, or an after tax effect
of $.07 and $.09 per share, respectively. At December 31, 1992,
the Company recorded a valuation reserve of $24 million, or an
after tax effect of $.09 per share, in light of a significant
decline in previous estimates of proved reserves as indicated by
lower than expected production volumes. The net investment in
such properties was approximately $101 million at December 31,
1992.
Utility Plant: The cost of additions to utility plant and of
replacements of retirement units of property is capitalized.
Cost includes direct material, labor, overhead and AFC.
Replacement of minor items of utility plant and the cost of
current repairs and maintenance is charged to expense. Whenever
utility plant is retired, its original cost, together with the
cost of removal, less salvage, is charged to accumulated
depreciation.
Allowance for Funds Used During Construction: The Company
capitalizes AFC in amounts equivalent to the cost of funds
devoted to plant under construction. AFC rates are determined in
accordance with FERC and PSC regulations. The AFC rate in effect
at December 31, 1993 was 6.5%. AFC is segregated into its two
components, borrowed funds and other funds, and is reflected in
the Interest Charges section and the Other Income and Deductions
section, respectively, of the Consolidated Statements of Income.
In 1985, pursuant to PSC authorization, the Company
discontinued accruing AFC on construction work in progress (CWIP)
for which a cash return was being allowed through inclusion in
rate base of that portion of the investment in Unit 2. Amounts
equal to Unit 2's AFC which was no longer accrued have been
accumulated in deferred debit and credit accounts up to the
commercial operation date of Unit 2, (each amounting to $239.9
million at December 31, 1993 and 1992), and await future
ratemaking disposition by the PSC. A portion of the deferred
credit could be utilized to reduce future revenue requirements
over a period shorter than the life of Unit 2, with a like amount
of deferred debit amortized and recovered in rates over the
remaining life of Unit 2.
Depreciation, Amortization and Nuclear Generating Plant
Decommissioning Costs: For accounting and regulatory purposes,
depreciation is computed on the straight-line basis using the
average or remaining service lives by classes of depreciable
property. The total provision for depreciation and amortization,
including amounts charged to clearing accounts, was $277.9
million for 1993, $275.3 million for 1992, and $260.2 million for
1991. The percentage relationship between the total provision
for depreciation and average depreciable property was 3.2% for
1993, 3.3% for 1992 and 3.2% for 1991. The Company performs
depreciation studies on a continuing basis and, upon approval by
the PSC, periodically adjusts the rates of its various classes of
depreciable property.
Estimated decommissioning costs (costs to remove a nuclear
plant from service in the future) for the Company's Unit 1 and
its share of decommissioning costs of Unit 2 are being accrued
over the service life of the Unit, recovered in rates through an
annual allowance and charged to operations through depreciation
(See Note 7. "Nuclear Plant Decommissioning"). The Company
expects to commence decommissioning shortly after cessation of
operations using a method which removes or decontaminates Unit
components promptly.
Amortization of the cost of nuclear fuel is determined on
the basis of the quantity of heat produced for the generation of
electric energy. The cost of disposal of nuclear fuel, which
presently is $.001 per kilowatt-hour of net generation available
for sale, is based upon a contract with the U.S. Department of
Energy. These costs are charged to operating expense and
recovered from customers through base rates or through the fuel
adjustment clause.
Revenues: Revenues are based on cycle billings rendered to
certain customers monthly and others bi-monthly. Although the
Company commenced the practice in 1988 of accruing electric
revenues for energy consumed and not billed at the end of the
fiscal year, the impact of such accruals has not yet been fully
recognized in the Company's results of operations. At December
31, 1993 and 1992, approximately $95.0 million and $77.8 million,
respectively, of unbilled revenues remained unrecognized in
results of operations and are included in Deferred Credits, and
may be used to reduce future revenue requirements. The amount of
the remaining deferred credit balance fluctuates as the amount of
accrued electric unbilled revenues is recalculated each year end.
At December 31, 1993, pursuant to PSC authorization the Company
accrued $20.9 million of unbilled gas revenues which will
similarly be used to reduce future gas revenue requirements, with
a portion to be used in 1994.
The Company's tariffs include electric and gas adjustment
clauses under which energy and purchased gas costs, respectively,
above or below the levels allowed in approved rate schedules, are
billed or credited to customers. The Company, as authorized by
the PSC, charges operations for energy and purchased gas cost
increases in the period of recovery. The PSC has periodically
authorized the Company to make changes in the level of allowed
energy and purchased gas costs included in approved rate
schedules. As a result of such periodic changes, a portion of
energy costs deferred at the time of change would not be
recovered or may be overrecovered under the normal operation of
the electric and gas adjustment clauses. However, the Company
has been permitted to defer and bill or credit such portions to
customers, through the electric and gas adjustment clauses, over
a specified period of time from the effective date of each
change.
The Company's electric fuel adjustment clause provides for
partial pass-through of fuel and purchased power cost
fluctuations from amounts forecast, with the Company absorbing a
specific portion of increases or retaining a portion of decreases
up to a maximum of $15 million per rate year. Thereafter, 100%
of the fluctuation is to be passed on to ratepayers. The Company
also shares with ratepayers fluctuations from amounts forecast
for net resale margin and transmission benefits, with the Company
retaining/absorbing 20% and passing 80% through to ratepayers.
The amounts absorbed in 1991 through 1993 are not material.
Beginning in 1991, the Company's rate agreements provide for
NERAM, which requires the Company to reconcile actual results to
forecast electric public sales gross margin as defined and
utilized in establishing rates. Depending on the level of actual
sales, a liability to customers is created if sales exceed the
forecast and an asset is recorded for a sales shortfall, thereby
generally holding recorded electric gross margin to the level
forecast in establishing rates. The 1994 rate settlement
provides for the operation of the NERAM through December 31,
1994. Recovery or refund of accruals pursuant to the NERAM is
accomplished by a surcharge (either plus or minus) to customers
over a twelve month period, to begin when cumulative amounts
reach certain specified levels.
Rate agreements since 1991 also include MERIT, under which
the Company has the opportunity to achieve earnings above its
allowed return on equity based on attainment of specified goals
associated with its self-assessment process. The MERIT program
provides for specific measurement periods and reporting for PSC
approval of MERIT earnings. Approved MERIT awards are billed to
customers over a period not greater than twelve months. The
Company records MERIT earnings when attainment of goals is
approved by the PSC or when objectively measured criteria are
achieved.
Federal Income Taxes: In accordance with PSC requirements, the
tax effect of book and tax timing differences is flowed through
except as required by the Internal Revenue Code or unless
authorized by the PSC to be deferred. As directed by the PSC,
the Company defers any amounts payable pursuant to the
alternative minimum tax rules. The Company has claimed
investment tax credits and deferred the benefits of such credits
as realized in accordance with PSC directives. Deferred
investment credits are amortized to Other Income and Deductions
over the useful life of the underlying property. For purposes of
computing capital cost recovery deductions and normalization, the
asset basis has been reduced by all or a portion of the credit
claimed consistent with then current tax laws.
Since it is the Company's intention to reinvest the
undistributed earnings of its foreign subsidiaries, no provision
is made for federal income taxes on these earnings. At December
31, 1993, the cumulative amount of undistributed earnings of
foreign subsidiaries on which the Company has not provided
deferred taxes was approximately $109 million. It is expected
that the federal income taxes associated with these undistributed
earnings would be substantially reduced by foreign tax credits.
On January 1, 1993, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for
Income Taxes. The adoption of SFAS 109 changes the Company's
method of accounting for income taxes from the deferred method to
an asset and liability approach. The asset and liability
approach requires the recognition of deferred tax liabilities and
assets for the expected future tax consequences of temporary
differences between the recorded book bases and the tax bases of
assets and liabilities. The adoption of SFAS 109 did not have a
significant impact on the Company's 1993 results of operations,
and accordingly the effect of adoption has been included in
federal and foreign income taxes.
Amortization of Debt Issue Costs: The premium or discount and
debt expenses on long-term debt issues and on certain debt
retirements prior to maturity are amortized ratably over the
lives of the related issues and included in interest on long-term
debt in accordance with PSC directives.
Statement of Cash Flows: The Company considers all highly liquid
investments, purchased with a remaining maturity of three months
or less, to be cash equivalents.
Reclassifications: Certain amounts from prior years have been
reclassified on the accompanying Consolidated Financial
Statements to conform with the 1993 presentation.
NOTE 2. BANK CREDIT ARRANGEMENTS
---------------------------------
At December 31, 1993, the Company had $461 million of bank
credit arrangements with 19 banks. These credit arrangements
consisted of $220 million in commitments under Revolving
Credit Agreements (including a Revolving Credit Agreement for
HYDRA-CO Enterprises, Inc., a wholly-owned subsidiary of the
Company), $140 million in one-year commitments under Credit
Agreements, $1 million in lines of credit and $100 million under
a Bankers Acceptance Facility Agreement. The Revolving Credit
Agreements which extend into 1994 are renewed annually, and the
interest rate applicable to borrowing is based on certain rate
options available under the Agreements. All of the other bank
credit arrangements are subject to review on an ongoing basis
with interest rates negotiated at the time of use. The Company
also issues commercial paper. Unused bank credit facilities are
held available to support the amount of commercial paper
outstanding. In addition to these credit arrangements, the
Company obtained $100 million in bank loans which will expire in
1994.
The Company pays fees for substantially all of its bank
credit arrangements. The Bankers Acceptance Facility Agreement,
which is used to finance the fuel inventory for the Company's
generating stations, provides for the payment of fees only at the
time of issuance of each acceptance.
The following table summarizes additional information
applicable to short-term debt:
In thousands of dollars
At December 31: 1993 1992
Short-term debt:
Commercial paper $210,016 $ 93,248
Notes payable 153,000 104,450
Bankers acceptances 5,000 30,000
$368,016 $227,698
Weighted average interest rate (a) 3.60% 4.33%
For Year Ended December 31:
Daily average outstanding $165,458 $110,313
Monthly weighted average interest rate (a)
3.72% 4.80%
Maximum amount outstanding $368,016 $227,698
(a) Excluding fees.
NOTE 3. JOINTLY-OWNED GENERATING FACILITIES
The following table reflects the Company's share of jointly-
owned generating facilities at December 31, 1993. The Company is
required to provide its respective share of financing for any
additions to the facilities. Power output and related expenses
are shared based on proportionate ownership. The Company's share
of expenses associated with these facilities is included in the
appropriate operating expenses in the Consolidated Statements of
Income.
In thousands of dollars
Percentage Accumulated Construction
Ownership Utility Plant depreciation work in
progress
Roseton Steam Station 25 $ 87,691 $ 40,263 $ 760
Units No. 1 and 2 (a). . . . .
Oswego Steam Station
Unit No. 6 (b) . . . . . . . . 76 $ 270,301 $ 97,856 $ 4,207
Nine Mile Point Nuclear
Station Unit No. 2 (c) . . . . 41 $1,504,703 $214,825 $11,434
(a) The remaining ownership interests are Central Hudson Gas and Electric Corporation, the operator of the plant (35%)
and Consolidated Edison Company of New York, Inc. (40%). Central Hudson Gas and Electric Corporation has agreed
to acquire the Company's 25% interest in the plant in ten equal installments of 2.5% (30 mw.) starting on December
31, 1994 and on each December 31 thereafter. The Company then has the option to repurchase its 25% interest in 2004.
The agreement is subject to PSC approval. Output of Roseton Units No. 1 and 2, which have a capability of 1,200,000
kw., is shared in the same proportions as the cotenants' respective ownership interests.
(b) The Company is the operator. The remaining ownership interest is Rochester Gas and Electric Corporation (24%).
Output of Oswego Unit No. 6, which has a capability of 850,000 kw., is shared in the same proportions as the
cotenants' respective ownership interests.
(c) The Company is the operator. The remaining ownership interests are Long Island Lighting Company (18%), New York
State Electric and Gas Corporation (18%), Rochester Gas and Electric Corporation (14%), and Central Hudson Gas and
Electric Corporation (9%). Output of Unit 2, which has a capability of 1,062,000 kw., is shared in the same proportions
as the cotenants' respective ownership interests.
NOTE 4. CAPITALIZATION
CAPITAL STOCK
The Company is authorized to issue 150,000,000 shares of
common stock, $1 par value; 3,400,000 shares of preferred stock,
$100 par value; 19,600,000 shares of preferred stock, $25 par
value; and 8,000,000 shares of preference stock, $25 par value.
The table below summarizes changes in the capital stock issued
and outstanding and the related capital accounts for 1991, 1992
and 1993:
Common Stock Preferred Stock
$1 par value $100 par value
Non-
Shares Amount* Shares Redeemable* Redeemable*
December 31, 1990: 136,099,654 $136,100 2,548,000 $210,000 $44,800(a)
Issued - - - - -
Redemptions (58,000) - (5,800)
Foreign currency
translation adjustment
December 31, 1991: 136,099,654 136,100 2,490,000 210,000 39,000(a)
Issued 1,059,953 1,060 - - -
Redemptions (78,000) - (7,800)
Foreign currency
translation adjustment
December 31, 1992: 137,159,607 137,160 2,412,000 210,000 31,200(a)
Issued 5,267,450 5,267 - - -
Redemptions (18,000) (1,800)
Foreign currency
translation adjustment
December 31, 1993: 142,427,057 $142,427 2,394,000 $210,000 $29,400 (a)
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1993 was $(7,099).
Preferred Stock
$25 par value
Non- Capital Stock Premium
Shares Redeemable* Redeemable* and Expense (Net)*
December 31, 1990: 11,789,204 $80,000 $214,730 (a) $1,649,294
Issued 914,005 - 22,850 -
Redemptions (1,481,204) - (37,030) 340
Foreign currency
translation adjustment 678
December 31, 1991: 11,222,005 80,000 200,550 (a) 1,650,312
Issued - - - 18,401
Redemptions (1,366,000) - (34,150) 796
Foreign currency
translation adjustment (11,494)
December 31, 1992: 9,856,005 80,000 166,400 (a) 1,658,015
Issued - - - 111,497
Redemptions (1,816,000) (45,400) (2,471)
Foreign currency
translation adjustment (4,335)
December 31, 1993: 8,040,005 $80,000 $121,000 (a) $1,762,706
* In thousands of dollars
(a) Includes sinking fund requirements due within one year.
The cumulative amount of foreign currency translation adjustment at December 31, 1993 was $(7,099).
NON-REDEEMABLE PREFERRED STOCK (Optionally Redeemable)
The Company has certain issues of preferred stock which provide for optional redemption at December 31, as follows:
In thousands of dollars Redemption price per share
(Before adding accumulating dividends)
Series Shares 1993 1992
Preferred $100 par value:
3.40% 200,000 $ 20,000 $ 20,000 $103.50
3.60% 350,000 35,000 35,000 104.85
3.90% 240,000 24,000 24,000 106.00
4.10% 210,000 21,000 21,000 102.00
4.85% 250,000 25,000 25,000 102.00
5.25% 200,000 20,000 20,000 102.00
6.10% 250,000 25,000 25,000 101.00
7.72% 400,000 40,000 40,000 102.36
Preferred $25 par
value:
Adjustable Rate
Series A 1,200,000 30,000 30,000 25.00
Series C 2,000,000 50,000 50,000 25.75(1)
$290,000 $290,000
(1) Eventual minimum $25.00.
MANDATORILY REDEEMABLE PREFERRED STOCK
The Company has certain issues of preferred stock which provide for mandatory and optional redemption at December 31,
as follows:
Redemption price per
Shares In thousands of share
dollars (Before adding
accumulated dividends)
Eventual
Series 1993 1992 1993 1992 1993 minimum
Preferred $100 par value:
7.45% 294,000 312,000 $ 29,400 $ 31,200 $102.65 $100.00
Preferred $25 par value:
7.85% 914,005 914,005 22,850 22,850 (a) 25.00
8.375% 500,000 600,000 12,500 15,000 25.44 25.00
8.70% 600,000 1,000,000 15,000 25,000 25.50 25.00
8.75% 600,000 1,800,000 15,000 45,000 25.50 25.00
9.75% 276,000 342,000 6,900 8,550 25.26 25.00
Adjustable Rate
Series B 1,950,000 2,000,000 48,750 50,000 25.75 25.00
150,400 197,600
Less sinking fund requirements 27,200 27,200
$123,200 $170,400
(a) Not redeemable until 1996.
These series require mandatory sinking funds for annual
redemption and provide optional sinking funds through which the
Company may redeem, at par, a like amount of additional shares
(limited to 120,000 shares of the 7.45% series and 300,000 shares
of the 9.75% series). The option to redeem additional amounts is
not cumulative.
The Company's five year mandatory sinking fund redemption
requirements for preferred stock, in thousands, for 1994 through
1998 are as follows: $27,200; $12,200; $14,150; $10,120; and
$10,120, respectively.
LONG-TERM DEBT
Long-term debt at December 31, consisted of the following:
In thousands of dollars
Series Due 1993 1992
First mortgage bonds:
8 7/8% 1994 $ 150,000 $ 150,000
4 5/8% 1994 40,000 40,000
5 7/8% 1996 45,000 45,000
6 1/4% 1997 40,000 40,000
**9 7/8% 1998 - 200,000
6 1/2% 1998 60,000 60,000
10 1/4% 1999 100,000 100,000
10 3/8% 1999 100,000 100,000
9 1/2% 2000 150,000 150,000
**7 3/8% 2001 - 65,000
9 1/4% 2001 100,000 100,000
**7 5/8% 2002 - 80,000
**7 3/4% 2002 - 80,000
5 7/8% 2002 230,000 -
6 7/8% 2003 85,000 -
7 3/8% 2003 220,000 220,000
**8 1/4% 2003 - 80,000
8% 2004 300,000 300,000
6 5/8% 2005 110,000 -
9 3/4% 2005 150,000 150,000
**8.35% 2007 - 66,640
**8 5/8% 2007 - 30,000
*6 5/8% 2013 45,600 45,600
*11 1/4% 2014 75,690 75,690
*11 3/8% 2014 40,015 40,015
9 1/2% 2021 150,000 150,000
8 3/4% 2022 150,000 150,000
8 1/2% 2023 165,000 165,000
7 7/8% 2024 210,000 -
*8 7/8% 2025 75,000 75,000
Total First Mortgage Bonds 2,791,305 2,757,945
Promissory notes:
*Adjustable Rate Series due
July 1, 2015 100,000 100,000
December 1, 2023 69,800 69,800
December 1, 2025 75,000 75,000
December 1, 2026 50,000 50,000
March 1, 2027 25,760 25,760
July 1, 2027 93,200 93,200
Unsecured notes payable:
Medium Term Notes, Various rates, 55,500 87,700
due 1993-2004
Swiss Franc Bonds due December 15, 50,000 50,000
1995
Oswego Facilities Trust - 90,000
Other 176,888 157,829
Unamortized premium (discount) (12,656) (8,453)
TOTAL LONG-TERM DEBT 3,474,797 3,548,781
Less long-term debt due within one 216,185 57,722
year
$3,258,612 $3,491,059
*Tax-exempt pollution control related issues
**Retired prior to maturity
Several series of First Mortgage Bonds and Notes were issued
to secure a like amount of tax-exempt revenue bonds issued by the
New York State Energy Research and Development Authority
(NYSERDA). Approximately $414 million of such notes bear
interest at a daily adjustable interest rate (with a Company
option to convert to other rates including a fixed interest rate
which would require the Company to issue First Mortgage Bonds to
secure the debt) which averaged 2.14% for 1993 and 2.43% for 1992
and are supported by bank direct pay letters of credit. Pursuant
to agreements between NYSERDA and the Company, proceeds from such
issues were used for the purpose of financing the construction of
certain pollution control facilities at the Company's generating
facilities or refund outstanding tax-exempt bonds and notes.
The $115.7 million of tax-exempt bonds due 2014 will be
refinanced at 7.2% during 1994 pursuant to a forward refunding
agreement entered into in 1992.
Notes Payable include a Swiss franc bond issue maturing in
1995 equivalent to $50 million in U.S. funds. Simultaneously
with the sale of these bonds, the Company entered into a currency
exchange agreement to fully hedge against currency exchange rate
fluctuations.
Other long-term debt in 1993 consists of obligations under
capital leases of approximately $45.3 million (See Note 8.
"Lease Commitments"), a liability to the U.S. Department of
Energy for nuclear fuel disposal of approximately $93.5 million
(See Note 7. "Nuclear Fuel Disposal Costs") and liabilities for
unregulated generator contract termination of approximately $38.1
million.
Certain of the Company's debt securities provide for a
mandatory sinking fund for annual redemption. The aggregate
maturities of long-term debt for the five years subsequent to
December 31, 1993, excluding capital leases, are approximately
$211 million, $73 million, $61 million, $46 million and $66
million, respectively.
NOTE 5. PENSION AND OTHER RETIREMENT PLANS
-------------------------------------------
The Company and certain of its subsidiaries have non-
contributory, defined-benefit pension plans covering
substantially all their employees. Benefits are based on the
employee's years of service and compensation level. The pension
cost was $16.9 million for 1993, $23.2 million for 1992 and $23.9
million for 1991 ($5.6 million for 1993, $6.2 million for 1992
and $6.0 million for 1991 was related to construction labor and,
accordingly, was charged to construction projects). The
Company's general policy is to fund the pension costs accrued
with consideration given to the maximum amount that can be
deducted for Federal income tax purposes. Contributions are
intended to provide not only for benefits attributed to service
to date but also for those expected to be earned in the future.
Net pension cost for 1993, 1992 and 1991 included the following components:
In thousands of dollars
1993 1992 1991
$
Service cost - benefits earned during the period. . . . $ 30,100 27,100 $ 27,000
Interest cost on projected benefit obligation . . . . . 54,200 48,800 43,500
Actual return on Plan assets . . . . . . . . . . . . . (106,100) (59,600) (116,600)
Net amortization and deferral . . . . . . . . . . . . . 38,700 6,900 70,000
Net pension cost. . . . . . . . . . . . . . . . . . . . $ 16,900 $ 23,200 $ 23,900
The following table sets forth the plan's funded status and amounts recognized in the Company's Consolidated
Balance Sheets:
In thousands of dollars
At December 31, 1993 1992
Actuarial present value of accumulated benefit obligations:
Vested benefits. . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 501,900 $ 419,582
Non-vested benefits. . . . . . . . . . . . . . . . . . . . . . . . . . 64,973 46,563
Accumulated benefit obligations . . . . . . . . . . . . . . . . . . . . . . 566,873 466,145
Additional amounts related to projected pay increases . . . . . . . . . . . 236,906 193,630
Projected benefits obligation for service rendered to date. . . . . . . . . 803,779 659,775
Plan assets at fair value, consisting primarily of listed stocks,
bonds, other fixed income obligations and insurance contracts. . . . . 913,200 796,843
Plan assets in excess of projected benefit obligations. . . . . . . . . . . 109,421 137,068
Unrecognized net obligation at January 1, 1987 being recognized over
approximately 19 years . . . . . . . . . . . . . . . . . . . . . . . . 32,392 35,184
Unrecognized net gain from actual return on plant assets different from
that assumed. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (114,536) (84,077)
Unrecognized net gain from past experience different from that assumed
and effects of changes in assumptions amortized over 10 years. . . . . (39,652) (90,636)
Prior service cost not yet recognized in net periodic pension cost. . . . . 49,613 36,092
Pension costs included in the consolidated balance sheets . . . . . . . . . $ 37,238 $ 33,631
In 1993 and 1992, the discount rate and rate of increase
in future compensation levels used in determining the
actuarial present value of the projected benefit obligations
were 7.3% and 8.25% and 3.25% and 4.25% (plus merit
increases), respectively. The expected long-term rate of
return on plan assets was 9.00% in 1993 and 1992.
In addition to providing pension benefits, the Company and
its subsidiaries provide certain health care and life
insurance benefits for active and retired employees and
dependents. Under current policies, substantially all of the
Company's employees may be eligible for continuation of some
of these benefits upon normal or early retirement. These
benefits are provided through insurance companies whose
charges and premiums are based on the claims paid during the
year.
On January 1, 1993, the Company adopted SFAS No. 106,
Employers' Accounting for Postretirement Benefits Other Than
Pensions (OPEB). This Statement requires accrual accounting
by employers for postretirement benefits other than pensions
reflecting currently earned benefits. During 1993 the
Company established various trust funds to begin the funding
of the OPEB obligation. The Company made an initial
contribution, equal to the amount received in 1993 rates, of
approximately $12 million and anticipates contributing
approximately $23 million in 1994.
Net postretirement benefit cost for 1993 included the
following components:
In
thousands
of dollars
1993
Service cost - benefits attributed to
service during the period $12,300
Interest cost on accumulated
benefit obligation 32,800
Amortization of the transition
obligation over 20 years 20,400
Net postretirement benefit cost
$65,500
The following table sets forth the plan's funded status
and amounts recognized in the Company's Consolidated Balance
Sheet:
In thousands of dollars
At December 31, 1993
Actuarial present value of accumulated benefit
obligation:
Retired and surviving spouses $224,936
Active eligible 73,474
Active ineligible 220,420
Accumulated benefit obligation 518,830
Plan assets at fair value, consisting primarily of
cash equivalents 11,967
Accumulated postretirement benefit obligation in
excess of plan assets 506,863
Unrecognized net loss from past experience
different from that assumed and effects of changes 82,756
in assumptions
Unrecognized transition obligation to be amortized
over 20 years 388,600
Accrued postretirement benefit liability included $35,507
in the consolidated balance sheet
At December 31, 1993, a pre-65 and post-65 health care
cost trend rate of 10.05% and 7.05%, respectively, was
assumed, trending down to 4.8% by 1999. If the health care
cost trend rate was increased by one percent, the accumulated
postretirement benefit obligation as of December 31, 1993
would increase by approximately 8.7% and the aggregate of the
service and interest cost component of net periodic
postretirement benefit cost for the year would increase by
approximately 7.8%. The discount rate used in determining
the accumulated postretirement benefit obligation was 7.3%.
During 1993, the PSC issued a Statement of Policy (SOP)
regarding the accounting for pension and postretirement
costs. With respect to postretirement benefits, the PSC
mandated a transition to full accrual accounting in rates
over a period not to exceed five years, with recovery of any
resultant deferrals over a period not to exceed twenty years
from the year of adoption. In accordance with its rate
agreement and the SOP, the Company has a $30.7 million
regulatory asset at December 31, 1993 relating to the rate
transition for postretirement costs. The SOP requires
deferral of the difference between actual costs and rate
allowances and ten year amortization of actuarial gains and
losses for both pensions and postretirement costs effective
January 1, 1993. The 1993 pension cost was reduced by
approximately $8 million to reflect the effect of the change
in the amortization period of an actuarial gain of $90.6
million as of January 1, 1993. The Company does not expect
the true-up requirements or the change to amortization of
actuarial gains and losses to have a material impact on its
periodic benefit costs or results of operations.
In November 1992, the FASB issued SFAS No. 112 "Employees'
Accounting for Postemployment Benefits" which is effective
for fiscal years beginning after December 15, 1993. This
Statement, which the Company will adopt for 1994, requires
employers to recognize the obligation to provide
postemployment benefits if the obligation is attributable to
employees' past services, rights to those benefits are
vested, payment is probable and the amount of the benefits
can be reasonably estimated. The Company typically accounts
for such costs on a cash basis. The Company estimates the
postemployment benefit obligation to be approximately $11.4
million at January 1, 1994. In its 1994 rates, the Company
has included approximately $2.9 million, including capital,
representing the pay-as-you-go portion of the postemployment
benefit. The difference between the postemployment benefit
obligation and the rate allowance will be deferred, with the
proposed recovery occurring equally over three years
beginning in 1995. The Company believes that these costs
will be recovered based on current ratemaking principles.
NOTE 6. FEDERAL AND FOREIGN INCOME TAXES
Components of United States and foreign income before income
taxes:
In thousands of dollars
1993 1992 1991
United States $438,914 $410,283 $394,596
Foreign (24,845) 18,394 (6,252)
Consolidating eliminations 4,837 (16,741) (11,080)
Income before income taxes $418,906 $411,936 $377,264
Following is a summary of the components of Federal and
foreign income tax and a reconciliation between the amount
of Federal income tax expense reported in the Consolidated
Statements of Income and the computed amount at the
statutory tax rate:
Summary Analysis: In thousands of dollars
COMPONENTS OF FEDERAL AND FOREIGN INCOME TAXES:
1993 1992 1991
Current tax expense:
Federal $118,918 $119,929 $ 75,452
Foreign 8,445 915 597
127,363 120,844 76,049
Deferred tax expense:
Federal 35,152 54,858 74,983
Foreign - 7,531 7,105
35,152 62,389 82,088
Income taxes included in
Operating Expenses: 162,515 183,233 158,137
Current Federal and foreign
income tax credits included
in Other Income and
Deductions (16,061) (31,787) (24,734)
Deferred Federal and foreign
income tax expense
(credits) included in Other
Income and Deductions 621 4,058 492
Total $147,075 $155,504 $133,895
COMPONENTS OF DEFERRED FEDERAL AND FOREIGN INCOME TAXES
(NOTE 1):
Depreciation related $ 78,467 $ 90,897
Investment tax credit (8,067) (8,137)
Alternative minimum tax (1,197) (27,276)
Recoverable energy and
purchased gas costs (1,926) 8,066
Deferred operating expenses 10,867 (2,179)
Nuclear settlement
disallowance 20,099 12,865
MERIT recovery (4,263) 9,935
Opinac reserve for oil and (19,706) (13,083)
gas properties
Bond reacquisition premium 7,379 -
Other (15,206) 11,492
Deferred Federal income
taxes (net) $ 66,447 $ 82,580
RECONCILIATION BETWEEN FEDERAL AND FOREIGN INCOME TAXES AND
THE TAX COMPUTED AT PREVAILING U.S. STATUTORY RATE ON
INCOME BEFORE INCOME TAXES:
Computed tax $146,617 $140,058 $128,270
Reduction (increase) attributable to flow-through of
certain tax adjustments:
Depreciation
(35,153) (37,543) (36,440)
Allowance for funds used
during construction 2,951 11,205 7,540
Cost of removal 7,822 6,845 5,781
Deferred investment tax
credit amortization 8,018 8,024 7,891
Other 15,904 (3,977) 9,603
(458) (15,446) (5,625)
Federal and foreign income
taxes $147,075 $155,504 $133,895
The Omnibus Budget Reconciliation Act of 1993 (OBRA of
1993) was signed into law in August 1993. One of the
provisions of the OBRA of 1993 raises the federal corporate
statutory tax rate from 34% to 35%, retroactive to January
1, 1993. A provision of the 1993 Settlement provides for the
deferral of the effects of tax law changes.
SFAS 109 increased the accumulated deferred income tax
liability at January 1, 1993 by approximately $507 million,
represented substantially by tax benefits flowed-through to
rate payers in prior years (in the form of lower rates) upon
which deferred taxes had not been provided. At December 31,
1993, the deferred tax liabilities (assets) were comprised of
the following:
(In thousands)
Alternative minimum tax $ (95,071)
Other (208,217)
Total deferred tax assets (303,288)
Depreciation related 1,318,600
Investment tax credit related 108,140
Other 190,031
Total deferred tax liabilities 1,616,771
Accumulated deferred income taxes $1,313,483
The Company believes that the more significant effects of
adopting this pronouncement are (i) providing deferred taxes
for tax benefits flowed through to ratepayers, (ii)
adjustment of deferred tax assets and liabilities for enacted
changes in tax law or rates and (iii) prohibition of net-of-
tax accounting.
The Company routinely collects the increased tax liability
from previously flowed-through tax benefits. In addition,
the PSC issued effective January 15, 1993 a Statement of
Interim Policy on Accounting and Ratemaking Procedures to
implement SFAS 109. The statement required adoption of SFAS
109 on a revenue-neutral basis, recognizing the PSC's policy
of rate recovery when prior flow-through items reverse. The
Company has recorded income taxes recoverable, a regulatory
asset, in the amount of approximately $528 million, which is
comprised of previously flowed-through tax benefits, and
offset by temporary differences associated with deferred
investment tax credits and excess deferred taxes established
at tax rates greater than 35%. Substantially all of the
excess deferred taxes relate to property and are not subject
to immediate refund to customers in accordance with federal
law.
N O T E 7 . N U C L E A R
OPERATIONS ----------
The Company is the owner and operator of the 613 MW Unit 1
and the operator and a 41% co-owner of the 1,062 MW Unit 2.
Unit 1 was placed in commercial operation in 1969 and Unit 2
in 1988.
Unit 1 Economic Study: Under the terms of a previous
regulatory agreement, the Company agreed to prepare and
update studies of the advantages and disadvantages of
continued operation of Unit 1 prior to the start of the next
two refueling outages. The first report, which recommended
continued operation of Unit 1 over the remaining term of its
license (2009), was filed with the PSC in March 1990.
On November 20, 1992 the Company submitted to the PSC an
updated economic analysis which indicated that Unit 1 can be
expected to provide value to customers and shareholders
through its next fuel cycle, which will end in early 1995.
The study also indicated that the Unit could continue to
provide benefits for the full term of its license if
operating costs can be reduced and generating output improved
above its historical average.
The study analyzed a number of scenarios resulting in
break-even capacity factors, ranging from 44% to 122%. The
"base case" assumes a capacity factor of 61%, consistent with
the target reflected in the Unit 1 operating incentive
mechanism, and also assumes future operating and capital
costs slightly lower than historical performance. While a
marginal benefit would be realized from operating the Unit
for at least the next two years (one fuel cycle) under the
"base case," there would be a negative net present value in
excess of $100 million if the Unit were to be operated over
its remaining 17-year license period. Under an "improved
performance case", the Unit is assumed to operate at a 70%
capacity factor with future operating and capital costs
consistent with average industry performance. The Company
believes these goals are achievable for Unit 1, as indicated
by Unit 1 operating and financial performance in 1993 that
was better than the improved performance case. The "improved
performance case" results in positive net present value in
excess of $100 million if the Unit is operated over its
remaining life. Such results demonstrate the volatility of
the assumptions and uncertainties involved in developing the
Unit's economic forecast. These assumptions include various
levels of the Unit's capacity factor, operating and capital
costs, demand for electricity, supply of electricity
including unregulated generator power, implementation and
compliance costs of the Clean Air Act and other federal and
state environmental requirements and fuel availability and
prices, especially natural gas. Given the potential for
rapid and substantial change in any or all of these
assumptions, the Company has developed operational and
external criteria, other than refueling, which would initiate
a prompt reassessment of the economic viability of the Unit.
An agreement with the PSC allows recovery of all
reasonable and prudently-incurred sunk costs and costs of
retirement, should a prudent decision be made to retire Unit
1 before early 1995. All parties to the 1991 Agreement
reserve the right to petition the PSC to institute a formal
investigation to review the prudence of any Company decision
to retire Unit 1. Any such decision by the Company will be
made in consultation with governmental and regulatory
authorities. The Company's net investment in Unit 1 is
approximately $580 million, exclusive of decommissioning
costs. See Nuclear Plant Decommissioning.
Unit 1 Status: On February 20, 1993, Unit 1 was taken out of
service for a planned 55 day refueling and maintenance
outage. On April 15, 1993, Unit 1 returned to service ahead
of schedule. The next refueling outage is scheduled to begin
in February 1995. Unit 1's capacity factor for 1993 was
approximately 81%.
Unit 2 Status: On October 2, 1993, Unit 2 was taken out of
service for a planned 60 day refueling and maintenance
outage. On November 29, 1993, Unit 2 returned to service
ahead of schedule. The next refueling outage is scheduled to
begin in the spring of 1995. Unit 2's capacity factor for
1993 was approximately 78%.
Nuclear Plant Decommissioning: Based on a 1989 study, the
cost of decommissioning Unit 1, which is expected to begin in
the year 2009, is estimated by the Company to be
approximately $416 million at that time ($257 million in 1993
dollars). The Company's 41% share of the total cost to
decommission Unit 2, expected to begin in 2027, is estimated
by the Company to be approximately $316 million ($109 million
in 1993 dollars). The annual decommissioning allowance
reflected in ratemaking is based upon these estimates, which
include amounts for both radioactive and non-radioactive
dismantlement costs. The non-radioactive dismantlement costs
are estimated in the 1989 study to be $24 million for Unit 1
and $18 million for its share of Unit 2, in 1993 dollars.
Decommissioning costs recovered in rates are reflected in
Accumulated Depreciation and Amortization on the Balance
Sheet and amount to $113.9 million and $90.5 million at
December 31, 1993 and 1992, respectively. The annual
allowance for Unit 1 and the Company's share of Unit 2 for
the years ended December 31, 1993, 1992 and 1991 was
approximately $18.7, $23.1 and $23.0 million, respectively.
The Company will update its Unit 1 decommissioning study
in 1994 in support of the update of the Unit 1 economic
study. The Unit 2 decommissioning study is also expected to
be updated in 1994. Rate allowance adjustments will be
sought when appropriate. There is no assurance that the
decommissioning allowance recovered in rates will ultimately
aggregate a sufficient amount to decommission the units.
However, the Company believes that if decommissioning costs
are higher than currently estimated they would ultimately be
recovered in the rate process.
The NRC issued regulations in 1988 requiring owners of
nuclear power plants to place funds into an external trust to
provide for the cost of decommissioning contaminated portions
of nuclear facilities as well as establishing minimum amounts
that must be available in such a trust for these specified
decommissioning activities at the time of decommissioning.
As of December 31, 1993, the Company has accumulated in an
external trust $63.1 million for Unit 1 and $15.4 million for
its share of Unit 2, which are included in Other Property and
Investments. Earnings on such investments aggregated $8.6
million through December 31, 1993 and, because they are
available to fund decommissioning, have also been included in
Accumulated Depreciation and Amortization. Amounts recovered
for non-radioactive dismantlement are accumulated in an
internal reserve fund which has an accumulated balance of
$35.4 million at December 31, 1993.
Based upon studies applying the 1988 NRC regulations, the
Company had estimated that the minimum funding requirements
for Unit 1 and its share of Unit 2, respectively, would be
$191 million and $87 million in 1993 dollars. In May 1993,
the NRC established new labor, energy and burial cost factors
for determining the NRC minimum funding requirements. A
substantial increase in burial costs, partly offset by
reduced estimates in the volumes of waste to be disposed,
increased the NRC minimum requirement for Unit 1 to $372
million in 1993 dollars and the Company's share of Unit 2 to
$169 million in 1993 dollars. The Company has requested an
annual aggregate increase of approximately $10 million in the
Unit 1 and Unit 2 decommissioning allowances as part of its
1995 rate request, to reflect the increased NRC minimum
requirements.
Nuclear Liability Insurance: The Atomic Energy Act of 1954,
as amended, requires the purchase of nuclear liability
insurance from the Nuclear Insurance Pools in amounts as
determined by the NRC. At the present time, the Company
maintains the required $200 million of nuclear liability
insurance.
In August 1993, the statutory liability limits for the
protection of the public under the Price-Anderson Amendments
Act of 1988 (the Act) were further increased. With respect
to a nuclear incident at a licensed reactor, the statutory
limit, which is in excess of the $200 million of nuclear
liability insurance, was increased to approximately $8.8
billion. This limit would be funded by assessments of up to
$75.5 million for each of the 116 presently licensed nuclear
reactors in the United States, payable at a rate not to
exceed $10 million per reactor per year. Such assessments
are subject to periodic inflation indexing and to a 5%
surcharge if funds prove insufficient to pay claims.
The Company's interest in Units 1 and 2 could expose it to
a potential loss, for each accident, of $106.5 million
through assessments of $14.1 million per year in the event of
a serious nuclear accident at its own or another licensed
U.S. commercial nuclear reactor. The amendments also
provide, among other things, that insurance and indemnity
will cover precautionary evacuations whether or not a nuclear
incident actually occurs.
Nuclear Property Insurance: The Nine Mile Point Nuclear Site
has $500 million primary nuclear property insurance with the
Nuclear Insurance Pools (ANI/MRP). In addition, there is
$800 million in excess of the $500 million primary nuclear
insurance with the Nuclear Insurance Pools (ANI/MRP) and $1.4
billion, which is also in excess of the $500 million primary
and the $800 million excess nuclear insurance, with Nuclear
Electric Insurance Limited (NEIL). NEIL is a utility
industry-owned mutual insurance company chartered in Bermuda.
The total nuclear property insurance is $2.7 billion. NEIL
also provides insurance coverage against the extra expense
incurred in purchasing replacement power during prolonged
accidental outages. The insurance provides coverage for
outages for 156 weeks after a 21 week waiting period.
NEIL insurance is subject to retrospective premium
adjustment under which the Company could be assessed up to
approximately $11.3 million per loss.
Low Level Radioactive Waste: The Federal Low Level
Radioactive Waste Policy Act requires states to join compacts
or individually develop their own low level radioactive waste
disposal site. In response to the Federal law, New York
State decided to develop its own site because of the large
volume of low level radioactive waste it generates and
committed by January 1, 1993 to develop a plan for the
management of low level radioactive waste in New York State
during the interim period until a disposal facility is
available.
New York State is developing disposal methodology and
acceptance criteria for a disposal facility. A revised New
York State low level radioactive waste site development
schedule now assumes two possible siting scenarios, a
volunteer approach and a non-volunteer approach, either of
which would begin operation in 2001. An extension of access
to the Barnwell, South Carolina waste disposal facility was
made available to out-of-region low level radioactive waste
generators by the state of South Carolina through June 30,
1994, and New York State has elected to use this option. The
Company has a low level radioactive waste management program
and contingency plan so that Unit 1 and Unit 2 will be
prepared to properly handle interim on-site storage of low
level radioactive waste for at least a 10 year period, if
required.
Nuclear Fuel Disposal Cost: In January 1983, the Nuclear
Waste Policy Act of 1982 (the Nuclear Waste Act) established
a cost of $.001 per kilowatt-hour of net generation for
current disposal of nuclear fuel and provides for a
determination of the Company's liability to the Department of
Energy (DOE) for the disposal of nuclear fuel irradiated
prior to 1983. The Nuclear Waste Act also provides three
payment options for liquidating such liability and the
Company has elected to delay payment, with interest, until
1998, the year in which the Company had initially planned to
ship irradiated fuel to an approved DOE disposal facility.
Progress in developing the DOE facility has been slow and it
is anticipated that the DOE facility will not be ready to
accept deliveries until at least 2010. The Company does not
anticipate that the DOE will accept all of its spent fuel
immediately upon opening of the facility, but rather expects
a transfer period of as long as 20 years. With Unit 1
expected to be retired in 2009, the Company must consider
some form of storage if it intends to begin immediate
dismantlement. The Company has several alternatives under
consideration to provide additional storage facilities, as
necessary. Each alternative will likely require NRC
approval, may require other regulatory approvals and would
likely require the incurrance of additional costs. The
Company does not believe that the possible unavailability of
the DOE disposal facility until 2006 will inhibit operation
of either Unit.
The Energy Policy Act provides for the establishment of a
federal decontamination and decommissioning fund to provide
for the environmentally safe closure of DOE uranium
processing facilities, funded in part by nuclear utilities.
The Company has recorded its estimated liability to this fund
based on prior DOE nuclear fuel processing services it
received and its initial assessment during 1993. The
liability is expected to be recovered as a fuel expense as
provided by the Act and is payable over 14 years ending in
2007, with annual assessments indexed for inflation.
NOTE 8. COMMITMENTS AND CONTINGENCIES
--------------------------------------
Construction Program: The Company is committed to an ongoing
construction program to assure reliable delivery of its
electric and gas services. The Company presently estimates
that the construction program for the years 1994 through 1998
will require approximately $1.57 billion, excluding AFC,
nuclear fuel and certain overheads capitalized. For the
years 1994 through 1998, the estimates are $408 million, $295
million, $287 million, $291 million and $285 million,
respectively. These amounts are reviewed by management as
circumstances dictate.
Long-term Contracts for the Purchase of Electric Power: At
January 1, 1994,the Company had long-term contracts to
purchase electric power from the following generating
facilities owned by the New York Power Authority (NYPA):
Purchased Estimated annual
Facility Expiration date of capacity capacity cost
contract in kw.
Niagara - hydroelectric project . . . . . 2007 928,000 $20,300,000
St. Lawrence - hydroelectric project. . . 2007 104,000 1,300,000
Blenheim-Gilboa - pumped storage
generating station. . . . . . . . . . . 2002 270,000 7,500,000
Fitzpatrick - nuclear plant . . . . . . . year-to-year
basis 40,000 (a) 7,200,000
1,342,000 $36,300,000
(a) 40,000 kw for summer of 1994; 63,000 kw for winter of 1994-95.
The purchase capacities shown above are based on the
contracts currently in effect. The estimated annual capacity
costs are subject to price escalation and are exclusive of
applicable energy charges. The total cost of purchases under
these contracts was approximately $72.2 million, $64.4
million and $61.2 million for the years 1993, 1992 and 1991,
respectively.
Under the requirements of the Federal Public Utility
Regulatory Policies Act of 1978, the Company is required to
purchase power generated by unregulated generators, as
defined therein. Of the 147 facilities providing energy to
the Company at December 31, 1993, five require the Company to
make capacity payments, including payments when a production
plant is not operating, and are subject to price escalation.
Each facility must meet certain availability and performance
obligations prior to receiving capacity payments. The terms
of these five contracts allow the Company to schedule energy
deliveries from the facilities and then pay for the energy
that is delivered. These five facilities account for
approximately 380,000 kw of capacity with contract lengths
ranging from 20 to 35 years. The total cost of purchases
under these five contracts in 1993 was $56.6 million and the
1994 estimated annual capacity and energy payments are
estimated to be approximately $105.5 million and $50 million,
respectively, subject to scheduling, the availability and
tested capacity of these facilities, and price escalation.
Capacity payments under these five contracts for 1995 to 1998
would be $109 million, $120 million, $127 million and $130
million, respectively and would aggregate to approximately
$3.5 billion over the terms of the contracts. Contracts
relating to the remaining facilities in service at December
31, 1993, require the Company to pay only when energy is
delivered.
The Company paid approximately $736 million (including the
amount discussed above), $543 million and $268 million in
1993, 1992 and 1991 for 11,720,000 mwhrs, 8,632,000 mwhrs and
4,303,000 mwhrs, respectively, of energy under all
unregulated generator contracts.
Through December 31, 1993, the Company had entered into
agreements with current and prospective unregulated
generators for approximately 2,400 MW of capacity. The
ultimate amount of the commitment and the available capacity
are dependent upon the completion of these projects. Based
upon these contracts as of December 31, 1993, the Company
estimates that it will be obligated to make payments to
unregulated generators of (in millions): $932 in 1994,
$1,057 in 1995, $1,111 in 1996, $1,174 in 1997 and $1,220 in
1998. The Company recovers all payments to unregulated
generators through base rates or through the FAC.
Sale of Customer Receivables: The Company has an agreement
whereby it can sell an undivided interest in a designated
pool of customer receivables, including accrued unbilled
electric revenues, up to a maximum of $200 million. At
December 31, 1993 and 1992, respectively, $200 million of
receivables had been sold under this agreement. The
undivided interest in the designated pool of receivables was
sold with limited recourse. The agreement provides for a
loss reserve pursuant to which additional customer
receivables are assigned to the purchaser to protect against
bad debts. To the extent actual loss experience of the pool
receivables exceeds the loss reserve, the purchaser absorbs
the excess. For receivables sold, the Company has retained
collection and administrative responsibilities as agent for
the purchaser. As collections reduce previously sold
undivided interests, new receivables are customarily sold.
Tax assessments: The Internal Revenue Service (IRS) has
conducted an examination of the Company's Federal income tax
returns for the years 1987 and 1988 and has submitted a
Revenue Agents' Report to the Company. The IRS has proposed
various adjustments to the Company's federal income tax
liability for these years which could increase the Federal
income tax liability by approximately $80 million before
assessment of penalties and interest. Included in these
proposed adjustments are several significant issues involving
Unit 2. The Company is vigorously defending its position on
each of the issues, and submitted a protest to the IRS in
1993. Pursuant to the Unit 2 settlement entered into in
1990, to the extent the IRS is able to sustain disallowances,
the Company will be required to absorb a portion of any
disallowance. The Company believes any such disallowance
will not have a material impact on its financial position or
results of operations.
Litigation: On March 22, 1993, a complaint was filed in the
Supreme Court of the State of New York, Albany County,
against the Company and certain of its officers and
employees. The plaintiff, Inter-Power of New York, Inc.
(Inter-Power), alleges, among other matters, fraud, negligent
misrepresentation and breach of contract in connection with
the Company's alleged termination of a power purchase
agreement in January 1993. The power purchase agreement was
entered into in early 1988 in connection with a 200 MW
cogeneration project to be developed by Inter-Power in
Halfmoon, New York. The plaintiff is seeking enforcement of
the original contract or compensatory and punitive damages on
fourteen causes of action in an aggregate amount that would
not exceed $1 billion, excluding pre-judgment interest.
The Company believes it has done no wrong, and intends to
vigorously defend against this action. On May 7, 1993, the
Company filed an answer denying liability and raising certain
affirmative defenses. Thereafter, the Company and Inter-
Power filed cross-motions for summary judgement. The court
dismissed two of Inter-Power's fourteen causes of action but
otherwise denied the Company's motion. The court also
dismissed two of the Company's affirmative defenses and
otherwise denied Inter-Power's cross-motion. Both parties
have filed Notices of Appeals regarding these dismissals.
Discovery is in progress. The ultimate outcome of the
litigation cannot presently be determined.
On November 12, 1993, Fourth Branch Associates
Mechanicville ("Fourth Branch"), filed suit against the
Company and several of its officers and employees in the New
York Supreme Court, Albany County, seeking compensatory
damages of $50 million, punitive damages of $100 million and
injunctive and other related relief. The suit grows out of
the Company's termination of a contract for Fourth Branch to
operate and maintain a hydroelectric plant the Company owns
in the Town of Halfmoon, New York. Fourth Branch's complaint
also alleges claims based on the inability of Fourth Branch
and the Company to agree on terms for the purchase of power
from a new facility that Fourth Branch hoped to construct at
the Mechanicville site. On January 3, 1994, the defendants
filed a joint motion to dismiss Fourth Branch's complaint.
The Company believes that it has substantial defenses to
Fourth Branch's claims, but is unable to predict the outcome
of this litigation.
Accordingly, no provision for liability, if any, that may
result from either of these suits has been made in the
Company's financial statements. Environmental Contingencies:
The public utility industry typically utilizes and/or
generates in its operations a broad range of potentially
hazardous wastes and by-products. These wastes or by-
products may not have previously been considered hazardous,
and may not be considered hazardous currently, but may be
identified as such by Federal, state or local authorities in
the future. The Company believes it is handling identified
wastes and by-products in a manner consistent with Federal,
state and local requirements and has implemented an
environmental audit program to identify any potential areas
of concern and assure compliance with such requirements. The
Company is also currently conducting a program to investigate
and restore, as necessary to meet current environmental
standards, certain properties associated with its former gas
manufacturing process and other properties which the Company
has learned may be contaminated with industrial waste, as
well as investigating identified industrial waste sites as to
which it may be determined that the Company contributed. The
Company has been advised that various Federal, state or local
agencies believe that certain properties require
investigation and has prioritized the sites based on
available information in order to enhance the management of
investigation and remediation, if determined to be necessary.
The Company is currently aware of 82 sites with which it
has been or may be associated, including 42 which are
Company-owned. The Company-owned sites include 23 former
coal gasification (MGP) sites, 14 industrial waste sites and
5 operating property sites where corrective actions may be
deemed necessary to prevent, contain and/or remediate
contamination of soil and/or water in the vicinity. Of these
Company-owned sites, Saratoga Springs is on the Federal
National Priorities List for Uncontrolled Hazardous Waste
Sites (NPL) as published by the Environmental Protection
Agency in the Federal Register. The 40 non-owned sites with
which the Company has been or may be associated are generally
industrial waste sites where the Company is alleged to be a
PRP and may be required to contribute some proportionate
share towards investigation and clean-up. Not included in
the 82 sites are seven sites where the Company has reached
settlement agreements with other PRP's and three sites where
remediation activities have been completed. There also exist
approximately 20 formerly-owned MGP sites with which the
Company has been or may be associated that may require future
investigation and remediation. To date, the Company has not
been made aware of any claims. Also, approximately 22 fire
training sites owned or used by the Company have been
identified but not investigated. Presently, the Company is
unable to determine its potential involvement with such sites
and has made no provision for liability, if any, at this
time.
Investigations at each of the Company-owned sites are
designed to (1) determine if environmental contamination
problems exist, (2) determine the extent, rate of movement
and concentration of pollutants, (3) if necessary, determine
the appropriate remedial actions required for site
restoration and (4) where appropriate, identify other parties
who should bear some or all of the cost of remediation.
Legal action against such other parties, if necessary, will
be initiated. After site investigations have been completed,
the Company expects to determine site-specific remedial
actions necessary and to estimate the attendant costs for
restoration. However, since technologies are still
developing and the Company has not yet undertaken any full-
scale remedial actions following regulatory requirements at
any identified sites, nor have any detailed remedial designs
been prepared or submitted to appropriate regulatory
agencies, the ultimate cost of remedial actions may change
substantially as investigation and remediation progresses.
The Company has estimated that it is probable that 36 of
the 42 owned sites will require some degree of investigation,
remediation and monitoring. This conclusion is based upon a
number of factors, including the nature of the identified or
potential contaminants, the location and size of the site,
the proximity of the site to sensitive resources, the status
of regulatory investigation and knowledge of activities at
similarly situated sites. Although the Company has not
extensively investigated many of those sites, it believes it
has sufficient information to estimate a range of cost of
investigation and remediation. As a consequence of site
characterizations and assessments completed to date, the
Company has accrued a liability of $210 million for these
owned sites, representing the low end of the range of the
estimated cost for investigation and remediation. The high
end of the range is presently estimated at approximately $520
million.
The majority of these cost estimates relate to the MGP
sites. Of the 23 MGP sites, Harbor Point (Utica, NY) and
Saratoga Springs are subject to regulatory enforcement
actions and to date have remedial investigation and/or
feasibility study work in progress. The remaining 21 MGP
sites are the subject of an Order on Consent executed with
the New York State Department of Environmental Conservation
(DEC) providing for an investigation and remediation program
over approximately ten years. Preliminary site assessments
have been conducted or are in process at five of these 21
sites, with remedial investigations either currently in
process or scheduled for 1994. Remedial investigations were
also conducted for two industrial waste sites and for three
operating properties where corrective actions were considered
necessary.
The Company does not currently believe that a clean-up
will be required at the 6 remaining Company-owned sites,
although some degree of investigation of these sites is
included in its investigation and remediation program.
With respect to the 40 sites with which the Company has
been or may be associated as a PRP, 9 are on the NPL. Total
costs to investigate and remediate the sites with which the
Company is associated as a PRP are estimated to be
approximately $590 million; however, the Company estimates
its share of this total at approximately $30 million and this
amount has been accrued at December 31, 1993.
The seven settlement agreements reached with other PRP's
were settled in an amount not material to the Company. Two
of these (Ludlow Landfill and Wide Beach) are on the NPL and
have been settled by the Company in an aggregate amount of
less than $300,000. For the 9 sites included on the NPL, the
Company's potential contribution factor varies for each site.
The estimated aggregate liability for these sites is not
material and is included in the determination of the amounts
accrued.
Estimates of the Company's potential liability for PRP
sites are derived by estimating the total cost of site clean-
up and then applying the related Company contribution factor
to that estimate. Estimates of the total clean-up costs are
determined by using the Company's investigation to date, if
any, discussions with other PRPs and, where no information is
known at the time of estimate, the Environmental Protection
Agency (EPA) estimates based on average costs disclosed in
the Federal Register of June 23, 1993. The contribution
factor is calculated using either the Company's percentage
share based upon the total number of PRPs named or otherwise
identified, which assumes all PRPs will contribute equally,
or the percentage agreed upon with other PRPs through
steering committee negotiations or by other means. Actual
Company expenditures for these sites are dependent upon the
total cost of investigation and remediation and the ultimate
determination of the Company's share of responsibility for
such costs as well as the financial viability of other
identified responsible parties since clean-up obligations are
joint and several. The Company has denied any responsibility
in certain of these PRP sites and is contesting liability
accordingly.
The EPA advised the Company by letter that it is one of
833 PRPs under Superfund for the investigation and cleanup of
the Maxey Flats Nuclear Disposal Site in Morehead, Kentucky.
The Company has contributed to a study of this site and
estimates that the cost to the Company for its share of
investigation and remediation based on its contribution
factor of 1.3% would approximate $1 million, which the
Company believes will be recoverable in the ratesetting
process.
On July 21, 1988, the Company received notice of a motion
by Reynolds Metals Company to add the Company as a third
party defendant in an ongoing Superfund lawsuit in Federal
District Court, Northern District of New York. This suit
involves PCB oil contamination at the York Oil Site in Moira,
New York. Waste oil was transported to the site during the
1960's and 1970's by contractors of Peirce Oil Company
(owners/operators of the site) who picked up waste oil at
locations throughout Central New York, allegedly including
one or more Company facilities. On May 26, 1992, the Company
was formally served in a Federal Court action initiated by
the government against 8 additional defendants. Pursuant to
the requirements of a case management order issued by the
Court on March 13, 1992, the Company has also been served in
related third and fourth-party actions for contribution
initiated by other defendants. Discovery is now in progress.
The goal of this effort is to provide adequate information to
form a basis for achieving a voluntary allocation of
liability among the parties.
The Company believes that costs incurred in the
investigation and restoration process for both Company-owned
sites and sites with which it is associated will be
recoverable in the ratesetting process. Rate agreements in
effect since 1991 provide for recovery of anticipated
investigation and remediation expenditures, although the PSC
Staff reserves the right to review the appropriateness of the
costs incurred. While the PSC Staff has not challenged any
remediation costs to date, the PSC Staff asserted in the
recently-decided gas rate proceeding that the Company must,
in future rate proceedings, justify why it is appropriate
that remediation costs associated with non-utility property
owned by the Company be recovered from ratepayers. The
Company's 1994 rate settlement includes $21.7 million for
site investigation and remediation. Based upon management's
assessment that remediation costs will be recovered from
ratepayers, a regulatory asset has been recorded representing
the future recovery of remediation obligations accrued to
date.
The Company also agreed in rate agreements to a cost
sharing arrangement with respect to one industrial waste
site. The Company does not believe that this cost sharing
agreement, as it relates to this particular industrial waste
site, will have a material effect on the Company's financial
position or results of operations.
The Company is also in the process of providing notices of
insurance claims to carriers with respect to the
investigation and remediation costs for manufactured gas
plant and industrial waste sites. The Company is unable to
predict whether such insurance claims will be successful.
Federal Energy Regulatory Commission Order 636: In 1992, the
FERC issued Order 636, which requires interstate pipelines to
unbundle pipeline sales services from pipeline transportation
service. These changes enable the Company to arrange for its
gas supply directly with producers, gas marketers or
pipelines, at its discretion, as well as arrange for
transportation and gas storage services.
As a result of these structural changes, pipelines face
"transition" costs from implementation of the Order. The
principal costs are: unrecovered gas cost that would
otherwise have been billable to pipeline customers under
previously existing rules, costs related to restructuring
existing gas supply contracts and costs of assets needed to
implement the order (such as meters, valves, etc.). Under
the Order, pipelines are allowed to recover 100% of prudently
incurred costs from customers. Prudence will be determined
by FERC review.
The amount of restructuring costs ultimately billed to the
Company will be determined in accordance with pipeline
restructuring plans which have been submitted to the FERC for
approval. There are four pipelines to which the Company has
some liability. The Company is actively participating in
FERC hearings on these matters to ensure an equitable
allocation of costs. The restructuring costs will be
primarily reflected in demand charges paid to reserve space
on the various interstate pipelines and will be billed over a
period of approximately 7 years, with billings more heavily
weighted to the first 3 years.
Based upon information presently available to the Company
from the petitions filed by the pipelines, the Company's
participation in settlement negotiations, and the three
settlements to which it is a party, its liability for the
pipelines' unrecovered gas costs is expected to be as much as
$31 million and its liability for pipeline restructuring
costs could be as much as $38 million. The Company has
recorded a liability of $31 million at December 31, 1993,
representing the low end of the range of such transition
costs. The Company is unable to predict the final outcome of
current pipeline restructuring settlements and the ultimate
amounts for which it will be liable or the period over which
this liability will be billed.
Based upon Management's assessment that transition costs
will be recovered from ratepayers, a regulatory asset has
been recorded representing the future recovery of transition
costs accrued to date. Currently, such costs billed to the
Company are treated as a cost of purchased gas and
recoverable through the operation of the gas adjustment
clause mechanism.
NOTE 9 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL
INSTRUMENTS ------------------------------------------------
------------
The following methods and assumptions were used to estimate
the fair value of each class of financial instruments:
Cash and short-term investments: The carrying amount
approximates fair value because of the short maturity of the
financial instruments.
Long-term investments: The carrying value and market value
are not material to the financial statements.
Mandatorily redeemable preferred stock: Fair value of the
mandatorily redeemable preferred stock has been determined by
one of the Company's brokers or estimated by management based
on discounted cash flows.
Long-term debt: The fair value of the Company's long-term
debt has been estimated by one of the Company's brokers. The
carrying value of NYSERDA bonds, the Oswego Facilities Trust
and other long-term debt are considered to approximate fair
value.
The estimated fair values of the Company's financial
instruments are as follows:
December 31,
(In thousands of dollars)
1992
1993
Carrying Carrying
Amount Fair Value Amount Fair
Value
Cash and short-term investments $ 124,351 $ 124,351 $ 43,894 $ 43,894
Mandatorily redeemable preferred stock 150,400 155,326 197,600 199,114
2,791,305 2,969,228 2,757,945 2,888,022
Long-term debt: First Mortgage Bonds
55,500 62,458 87,700 93,890
Medium Term Notes
413,760 413,760 413,760 413,760
NYSERDA bonds
Swiss franc bond 50,000 73,794 50,000 62,374
Other 131,587 131,587 104,665 104,665
Oswego Facilities Trust - - 90,000 90,000
NOTE 10. INFORMATION REGARDING THE ELECTRIC AND GAS
BUSINESSES
The Company is engaged in the electric and natural gas
utility businesses. Certain information regarding these
segments is set forth in the following table. General
corporate expenses, property common to both segments and
depreciation of such common property have been allocated to
the segments in accordance with practice established for
regulatory purposes. Identifiable assets include net utility
plant, materials and supplies, deferred finance charges,
deferred recoverable energy costs and certain other deferred
debits. Corporate assets consist of other property and
investments, cash, accounts receivable, prepayments,
unamortized debt expense and other deferred debits.
In thousands of dollars
1993 1992 1991
Operating revenues:
. . . . . . . . . . .
Electric . . . . . . . . . $3,332,464 $3,147,676 $2,907,293
Gas . . . . . . . . . . . . 600,967 553,851 475,225
Total . . . . . . . . . $3,933,431 $3,701,527 $3,382,518
Operating income before taxes:
Electric . . . . . . . . . $ 625,852 $ 645,696 $ 644,084
Gas . . . . . . . . . . . . 61,163 61,863 39,487
Total . . . . . . . . . $ 687,015 $ 707,559 $ 683,571
Pretax operating income, including AFC:
Electric . . . . . . . . . $ 641,435 $ 666,269 $ 662,258
Gas . . . . . . . . . . . . 61,812 62,721 40,244
Total . . . . . . . . . 703,247 728,990 702,502
Income taxes, included in operating expenses:
Electric . . . . . . . . . 148,695 176,901 152,840
Gas . . . . . . . . . . . 13,820 6,332 5,297
Total . . . . . . . . . 162,515 183,233 158,137
Other (income) and deductions 22,475 (11,391) (10,643)
Interest charges . . . . . 291,376 300,716 311,639
Net income . . . . . . . . $ 271,831 $ 256,432 $ 243,369
Depreciation and amortization:
Electric . . . . . . . . . $ 255,718 $ 255,256 $ 240,887
Gas . . . . . . . . . . . . 20,905 18,834 17,929
Total . .. . . . . . . . . $ 276,623 $ 274,090
$258,816
Construction expenditures
(including nuclear fuel):
Electric . . . . . . . . . $ 429,265 $ 442,741 $ 445,298
Gas . . . . . . . . . . . . 90,347 59,503 77,176
Total . . . . . . . . . $ 519,612 $ 502,244 $ 522,474
Identifiable assets:
Electric . . . . . . . . . $7,042,762 $7,000,659 $6,760,375
Gas . . . . . . . . . . . . 926,648 783,766 725,553
Total . . . . . . . . . 7,969,410 7,784,425 7,485,928
Corporate assets . . . . 1,449,667 806,110 755,548
Total assets . . . . . $9,419,077 $8,590,535 $8,241,476
NOTE 11. Quarterly Financial Data (Unaudited)
Operating revenues, operating income, net income and earnings per
common share by quarters from 1993, 1992 and 1991, respectively, are
shown in the following table. The Company, in its opinion, has included
all adjustments necessary for a fair presentation of the results of
operations for the quarters. Due to the seasonal nature of the utility
business, the annual amounts are not generated evenly by quarter during
the year.
In thousands of dollars
Earnings
Quarter Operating Operating Net per
Ended revenues income income common share
December 31, 1993 $ 988,195 $ 73,466 $ 30,955 $ .16
1992 963,629 119,181 41,835 .24
1991 848,593 117,139 35,111 .18
September 30, 1993 $ 879,952 $108,539 $ 48,595 $ .29
1992 822,530 89,658 40,401 .23
1991 734,446 102,627 40,783 .23
June 30, 1993 $ 929,245 $154,826 $ 65,325 $ .41
1992 881,427 137,515 71,734 .46
1991 807,024 127,159 57,691 .35
March 31, 1993 $1,136,039 $187,669 $ 126,956 $ .86
1992 1,033,941 177,972 102,462 .68
1991 992,455 178,509 109,784 .73
In the second quarter of 1992 and the third quarter of 1993
and 1991, the Company recorded $22.8 million ($.11 per common
share), $10.3 million ($.05 per common share) and $30 million
($.14 per common share), respectively, for MERIT earned in
accordance with the 1991 Agreement. In the first quarter of
1992 and the fourth quarter of 1992 and 1991, the Company
recorded $21 million ($.09 per common share), $24 million
($.09 per common share) and $23 million ($.07 per common
share), respectively, to write-down its subsidiary investment
in oil and gas properties.
ELECTRIC AND GAS STATISTICS
ELECTRIC CAPABILITY
Thousands of kilowatts
December 31, 1993 % 1992 1991
Owned:
Coal 1,285 14.4 1,285 1,285
Oil 1,496 16.8 1,496 1,961
Dual Fuel - Oil/Gas 700 7.8 700 400
Nuclear 1,048 11.8 1,059 1,059
Hydro 700 7.8 706 708
Natural Gas 74 .8 108 164
5,303 59.4 5,354 5,577
Purchased:
New York Power Authority (NYPA)
- Hydro 1,302 14.6 1,302 1,283
- Nuclear 65 .7 67 76
Unregulated generators 2,253 25.3 1,549 1,027
3,620 40.6 2,918 2,386
Total capability * 8,923 100.0 8,272 7,963
Electric peak load 6,191 6,205 6,093
* Available capability can be increased during heavy load periods by purchases from
neighboring interconnected systems. Hydro station capability is based on average
December stream-flow conditions.
ELECTRIC STATISTICS
1993 1992 1991
Electric sales (Millions of kw-hrs.):
Residential . . . . . . . . . . . . . . . . . . 10,475 10,392 10,321
Commercial . . . . . . . . . . . . . . . . . . 12,079 11,628 11,686
Industrial . . . . . . . . . . . . . . . . . . 7,088 7,477 7,578
Industrial-Special. . . . . . . . . . . . . . . 3,888 3,857 3,784
Municipal service . . . . . . . . . . . . . . . 220 227 228
Other electric systems. . . . . . . . . . . . . 3,974 3,030 3,141
37,724 36,611 36,738
Electric revenues (Thousands of dollars):
Residential . . . . . . . . . . . . . . . . . . $1,171,787 $1,096,418 $ 985,347
Commercial . . . . . . . . . . . . . . . . . . 1,241,743 1,160,643 1,044,725
Industrial . . . . . . . . . . . . . . . . . . 553,921 589,258 521,670
Industrial-Special. . . . . . . . . . . . . . . 42,988 39,409 35,264
Municipal service . . . . . . . . . . . . . . . 50,642 50,327 47,566
Other electric systems . . . . . . . . . . . . 105,044 93,283 106,066
Miscellaneous . . . . . . . . . . . . . . . . . 166,339 118,338 166,655
$3,332,464 $3,147,676 $2,907,293
Electric customers (Average):
Residential . . . . . . . . . . . . . . . . . . 1,398,756 1,389,470 1,378,484
Commercial. . . . . . . . . . . . . . . . . . . 143,078 142,345 145,098
Industrial. . . . . . . . . . . . . . . . . . . 2,132 2,197 2,220
Industrial-Special. . . . . . . . . . . . . . . 76 72 63
Other . . . . . . . . . . . . . . . . . . . . . 3,438 3,262 3,231
1,547,480 1,537,346 1,529,096
Residential (Average):
Annual kw-hr. use per customer. . . . . . . . . 7,489 7,479 7,487
Cost to customer per kw-hr (cents). . . . . . . 11.19 10.55 9.55
Annual revenue per customer . . . . . . . . . . $837.74 $789.09 $714.80
GAS STATISTICS
1993 1992 1991
Gas Sales (Thousands of
dekatherms):
Residential . . . . . . . .
. . . . . . . . 54,908 53,945 48,172
Commercial . . . . . . . .
. . . . . . . . 23,743 22,289 20,226
Industrial . . . . . . . .
. . . . . . . . 4,316 1,772 1,812
Other gas systems . . . . .
. . . . . . . . 234 1,190 1,519
Total sales . . . . .
. . . . . . . . 83,201 79,196 71,729
Spot market . . . . . . . . -
. . . . . . . . 13,223 1,146
Transportation of customer- 50,631
owned gas . . . 67,741 65,845
Total gas delivered .
. . . . . . . . 164,165 146,187 122,360
Gas Revenues (Thousands of
dollars):
Residential . . . . . . . .
. . . . . . . . $370,565 $354,429 $302,900
Commercial . . . . . . . .
. . . . . . . . 144,834 132,609 113,727
Industrial . . . . . . . .
. . . . . . . . 18,482 10,001 8,430
Other gas systems . . . . .
. . . . . . . . 1,066 4,737 6,964
Spot market . . . . . . . . -
. . . . . . . . 29,782 2,576
Transportation of customer- 36,455
owned gas . . . 34,843 42,726
Miscellaneous . . . . . . .
. . . . . . . . 1,395 6,773 6,749
$600,967 $553,851 $475,225
Gas Customers (Average):
Residential . . . . . . . .
. . . . . . . . 455,629 446,571 438,581
Commercial . . . . . . . .
. . . . . . . . 39,662 38,675 37,727
Industrial . . . . . . . .
. . . . . . . . 233 234 260
Other . . . . . . . . . . .
. . . . . . . . 1 1 2
Transportation . . . . . .
. . . . . . . . 673 673 625
496,198 486,154 477,195
Residential (Average):
Annual dekatherm use per
customer . . . . . 120.5 120.8 109.8
Cost to customer per
dekatherm . . . . . . $6.75 $6.57 $6.29
Annual revenue per customer
. . . . . . . . $813.30 $793.67 $690.64
Maximum day gas sendout
(dekatherms) . . . 929,285 905,872 852,404
Exhibit 11
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARIES
COMPUTATION OF AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING
Average Number
of Shares
(1) (2) Outstanding as
Shares of Number (3) Shown on Consolidated
Common of Days Share Days Statement of Income
Year Ended December 31, Stock Outstanding (2 x 1) (3/Number of days in year)
1993
January 1 - May 4 137,159,607 124 17,007,791,268
Shares sold May 5 4,494,000
May 5 - December 31 141,653,607 241 34,138,519,287
Shares sold at various times
during the year -
Employee Savings Fund Plan 140,000 22 3,080,000
Dividend Reinvestment Plan 632,341 * 102,395,031
Acquisition - Syracuse
Suburban Gas Company, Inc. 1,109 * 350,374
142,427,057 51,252,135,960 140,416,811
1992
January 1 - December 31 136,099,654 366 49,812,473,364
Shares sold at various times
during the year -
Employee Savings Fund Plan 240,866 * 45,435,347
Dividend Reinvestment Plan 463,736 * 59,130,626
Acquisition - Syracuse
Suburban Gas Company, Inc. 355,351 * 67,443,538
137,159,607 49,984,482,875 136,569,625
1991
January 1 - December 31 136,099,654 365 49,676,373,710 136,099,654
* Number of days outstanding not shown as shares represent an accumulation of weekly, monthly
and quarterly sales throughout the year. Share days for shares sold are based on
the total number of days each share was outstanding during the year.
Note: Earnings per share calculated on both a primary and fully diluted basis are the same due to the
effects of rounding.
Exhibit 12
NIAGARA MOHAWK POWER CORPORATION AND SUBSIDIARY COMPANIES
Statement Showing Computations of Ratio of Earnings to Fixed Charges,
Ratio of Earnings to Fixed Charges without AFC and Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
Year Ended December 31,
1993 1992 1991 1990 1989
A. Net Income per Statements of Income (a) $271,831 $256,432 $243,369 $ 82,878 $150,783
B. Taxes Based on Income or Profits 147,075 155,504 133,895 61,119 90,333
C. Earnings, Before Income Taxes 418,906 411,936 377,264 143,997 241,116
D. Fixed Charges (b) 319,197 332,413 346,255 347,957 337,552
E. Earnings Before Income Taxes and Fixed
Charges 738,103 744,349 723,519 491,954 578,668
F. Allowance for Funds Used During
Construction 16,232 21,431 18,931 21,414 19,376
G. Earnings Before Income Taxes and Fixed
Charges without AFC $721,871 $722,918 $704,588 $470,540 $559,292
Preferred Dividend Factor:
H. Preferred Dividend Requirements $ 31,857 $ 36,512 $ 40,411 $ 42,300 $ 45,182
I. Ratio of Pre-Tax Income to Net Income
(C / A) 1.54 1.61 1.55 1.74 1.60
J. Preferred Dividend Factor (H x I) $ 49,060 $ 58,784 $ 62,637 $ 73,602 $ 72,291
K. Fixed Charges as above (D) 319,197 332,413 346,255 347,957 337,552
L. Fixed Charges and Preferred Dividends
Combined $368,257 $391,197 $408,892 $421,559 $409,843
M. Ratio of Earnings to Fixed Charges
(E / D) 2.31 2.24 2.09 1.41 1.71
N. Ratio of Earnings to Fixed Charges
without AFC (G / D) 2.26 2.17 2.03 1.35 1.66
O. Ratio of Earnings to Fixed Charges and 2.00 1.90 1.77 1.17 1.41
Preferred Dividends Combined (E / L)
(a) Includes the effects of amortization of amounts deferred, under the 1989 Agreement,$15,746 for 1993, $20,257 for
1992 and $31,176 for 1991.
(b) Includes a portion of rentals deemed representative of the interest factor $27,821 for 1993, $31,697 for 1992,
$34,616 for 1991, $29,088 for 1990 and $30,496 for 1989.
EXHIBIT 24
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectus constituting part of the Registration Statements on
Form S-8 (Nos. 33-36189, 33-42720, 33-42721 and 33-42771) and on
Form S-3 (Nos. 33-45898, 33-50703, 33-51073 and 33-55546) of
Niagara Mohawk Power Corporation of our report dated January 27,
1994 appearing on page 43 of the financial statements included in
the Company's Form 8-K dated February 18, 1994.
PRICE WATERHOUSE
Syracuse, New York
February 18, 1994
SIGNATURE
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.
Date: February 18, 1994
NIAGARA MOHAWK POWER CORPORATION
By /s/ Steven W. Tasker
-------------------------
Steven W. Tasker
Vice President-Controller
and Principal Accounting
Officer