DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(In millions, except per share amounts)
YEAR ENDED
DECEMBER 31
---------------------------------------------------------
1996 1995 1994
---------------- ---------------- ----------------
Operating Revenues
Natural gas and petroleum products
Sales of natural gas and petroleum products $ 5,848.0 $ 3,397.2 $ 3,044.0
Transportation and storage of natural gas 1,522.9 1,500.6 1,432.8
Electric
Generation, transmission, and distribution 4,436.6 4,454.6 4,312.4
Trading and marketing of electricity 77.8 9.8 -
Other 417.1 332.5 325.8
---------------- ---------------- ----------------
Total operating revenues 12,302.4 9,694.7 9,115.0
---------------- ---------------- ----------------
Operating Expenses
Natural gas and petroleum products purchased 5,414.3 3,119.3 2,829.4
Fuel used in electric generation 758.5 744.2 705.0
Net interchange and purchased power 456.8 480.2 553.4
Other operation and maintenance 2,382.8 2,209.0 2,171.1
Depreciation and amortization 789.4 737.1 716.8
Property and other taxes 342.0 336.6 333.3
---------------- ---------------- ----------------
Total operating expenses 10,143.8 7,626.4 7,309.0
---------------- ---------------- ----------------
Operating Income 2,158.6 2,068.3 1,806.0
---------------- ---------------- ----------------
Other Income and Expenses
Deferred returns and allowance for funds used
during construction 104.8 113.9 107.0
Other, net 30.8 8.3 (6.0)
---------------- ---------------- ----------------
Total other income and expenses 135.6 122.2 101.0
---------------- ---------------- ----------------
Earnings Before Interest and Taxes 2,294.2 2,190.5 1,907.0
Interest Expense 499.2 508.2 484.5
Minority Interests 6.2 - -
---------------- ---------------- ----------------
Earnings Before Income Taxes 1,788.8 1,682.3 1,422.5
Income Taxes 697.8 664.2 558.4
---------------- ---------------- ----------------
Income Before Extraordinary Charge 1,091.0 1,018.1 864.1
Extraordinary Charge (net of tax) 16.7 - -
---------------- ---------------- ----------------
Net Income 1,074.3 1,018.1 864.1
Dividends on Preferred and Preference Stock 44.2 48.9 49.7
---------------- ---------------- ----------------
Earnings Available for Common Stockholders $ 1,030.1 $ 969.2 $ 814.4
================ ================ ================
Common Stock Data
Average shares outstanding 361.2 361.2 360.2
Earnings per share (before extraordinary charge) $ 2.90 $ 2.68 $ 2.26
Earnings per share $ 2.85 $ 2.68 $ 2.26
Dividends per share $ 1.57 $ 1.50 $ 1.44
See Notes to Consolidated Financial Statements
4
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
YEAR ENDED
DECEMBER 31
---------------------------------------------------------
1996 1995 1994
---------------- ---------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,074.3 $ 1,018.1 $ 864.1
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation and amortization 964.9 953.8 904.5
Deferred income taxes 74.7 115.2 209.0
Purchased capacity levelization 73.5 (33.1) (268.9)
Transition cost recoveries 90.9 (85.2) (104.9)
(Increase) Decrease in
Receivables (645.6) (286.0) 106.5
Inventory 45.1 (26.2) (24.2)
Other current assets 27.0 85.5 116.0
Increase (Decrease) in
Accounts payable 576.7 53.5 (104.5)
Taxes accrued (11.0) 25.7 (68.8)
Interest accrued (18.5) 5.6 2.9
Other current liabilities (10.0) 17.7 (41.3)
Other, net 93.2 (12.4) (87.3)
---------------- ---------------- ----------------
Net cash provided by operating activities 2,335.2 1,832.2 1,503.1
---------------- ---------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (1,393.9) (1,223.0) (1,436.5)
Investment expenditures (156.1) (67.7) (15.2)
Decommissioning, retirements and other investing (18.2) (26.9) (72.8)
---------------- ---------------- ----------------
Net cash used in investing activities (1,568.2) (1,317.6) (1,524.5)
---------------- ---------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of
Long-term debt 362.8 421.5 974.9
Common stock 11.8 16.5 17.6
Payments for the redemption of
Long-term debt (527.0) (480.9) (379.7)
Common stock (159.0) - -
Preferred stock - (100.5) (1.5)
Net change in notes payable and commercial paper 159.3 193.2 67.9
Dividends paid (609.3) (590.5) (546.6)
Other (12.1) (4.8) (23.2)
---------------- ---------------- ----------------
Net cash provided by (used in) financing activities (773.5) (545.5) 109.4
---------------- ---------------- ----------------
Net increase (decrease) in cash and cash equivalents (6.5) (30.9) 88.0
Cash flows of Associated Natural Gas Corporation
for the three months ended December 31, 1994 - - (116.6)
Cash and cash equivalents at beginning of period 172.5 203.4 232.0
---------------- ---------------- ----------------
Cash and cash equivalents at end of period $ 166.0 $ 172.5 $ 203.4
================ ================ ================
See Notes to Consolidated Financial Statements
5
DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In millions)
December 31, December 31,
1996 1995
---------------- ----------------
ASSETS
Current Assets
Cash and cash equivalents $ 166.0 $ 172.5
Receivables 1,888.0 1,194.8
Inventory 433.5 477.6
Current portion of natural gas transition costs 67.9 70.0
Current portion of purchased capacity costs 51.3 73.5
Other 157.1 171.4
---------------- ----------------
Total current assets 2,763.8 2,159.8
---------------- ----------------
Investments and Other Assets
Investments in affiliates 502.9 327.6
Nuclear decommissioning trust funds 362.6 273.5
Pre-funded pension costs 360.6 339.3
Goodwill, net 222.1 247.5
Other 142.4 143.2
---------------- ----------------
Total investments and other assets 1,590.6 1,331.1
---------------- ----------------
Property, Plant and Equipment
Cost 24,468.2 23,722.0
Less accumulated depreciation and amortization 9,199.1 8,857.0
---------------- ----------------
Net property, plant and equipment 15,269.1 14,865.0
---------------- ----------------
Regulatory Assets
Purchased capacity costs 840.7 892.0
Debt expense 244.0 248.3
Regulatory asset related to income taxes 493.5 491.6
Natural gas transition costs 250.0 310.0
Environmental clean-up costs 153.2 197.9
Other 350.0 372.2
---------------- ----------------
Total regulatory assets 2,331.4 2,512.0
---------------- ----------------
Total Assets $ 21,954.9 $ 20,867.9
================ ================
See Notes to Consolidated Financial Statements
6
DUKE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(In millions)
December 31, December 31,
1996 1995
---------------- ----------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable $ 1,286.5 $ 734.9
Notes payable and commercial paper 459.7 300.3
Taxes accrued 74.8 99.9
Interest accrued 124.3 142.8
Current portion of natural gas transition liabilities 84.4 125.0
Current portion of environmental clean-up liabilities 32.4 56.3
Current maturities of long-term debt 350.6 191.7
Other 508.3 441.7
---------------- ----------------
Total current liabilities 2,921.0 2,092.6
---------------- ----------------
Long-term Debt 5,485.1 5,803.0
---------------- ----------------
Deferred Credits and Other Liabilities
Deferred income taxes 3,568.5 3,484.3
Investment tax credit 250.1 261.3
Nuclear decommissioning costs externally funded 362.6 273.5
Natural gas transition liabilities 121.9 165.0
Environmental clean-up liabilities 188.9 225.8
Other 948.2 864.7
---------------- ----------------
Total deferred credits and other liabilities 5,440.2 5,274.6
---------------- ----------------
Minority Interests 83.4 1.2
---------------- ----------------
Preferred and Preference Stock
Preferred & preference stock with sinking fund requirements 234.0 234.0
Preferred & preference stock without sinking fund requirements 450.0 450.0
---------------- ----------------
Total preferred and preference stock 684.0 684.0
---------------- ----------------
Common Stockholders' Equity
Common stock, no par, 500 million shares authorized; 359.4 million and
361.8 million shares outstanding at December 31, 1996 and
1995, respectively 4,289.3 4,296.8
Retained earnings 3,051.9 2,715.7
---------------- ----------------
Total common stockholders' equity 7,341.2 7,012.5
---------------- ----------------
Total Liabilities and Stockholders' Equity $ 21,954.9 $ 20,867.9
================ ================
See Notes to Consolidated Financial Statements
7
DUKE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(In millions)
YEAR ENDED
DECEMBER 31
---------------------------------------------------------
1996 1995 1994
---------------- ---------------- ----------------
Common Stock
Balance at beginning of year $ 4,296.8 $ 4,275.8 $ 4,242.7
Stock issued for purchase of assets - 2.5 10.0
Stock repurchased for merger (30.8) - -
Dividend reinvestment and employee benefits 23.3 18.5 23.1
---------------- ---------------- ----------------
Balance at end of year 4,289.3 4,296.8 4,275.8
---------------- ---------------- ----------------
Retained Earnings
Balance at beginning of year 2,715.7 2,292.2 1,974.4
Net income 1,074.3 1,018.1 864.1
Common stock dividends paid (565.6) (542.2) (496.4)
Preferred and preference stock dividends paid (44.2) (48.9) (49.7)
Capital stock transactions, net (128.3) (3.5) (0.7)
Conform fiscal year end of Associated Natural Gas - - 0.5
---------------- ---------------- ----------------
Balance at end of year 3,051.9 2,715.7 2,292.2
---------------- ---------------- ----------------
Total Common Stockholders' Equity $ 7,341.2 $ 7,012.5 $ 6,568.0
================ ================ ================
See Notes to Consolidated Financial Statements
8
DUKE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
NOTE 1. OPERATIONS AND ACCOUNTING POLICIES
Nature Of Operations
Duke Energy Corporation (the Company) is one of North America's leading energy
and energy services companies, involved in the production, transmission and
sales of energy and delivery of energy related services worldwide.
On June 18, 1997, Duke Power Company (Duke Power) changed its name to Duke
Energy Corporation in accordance with the terms of a merger agreement with
PanEnergy Corp (PanEnergy), pursuant to which the Company issued 158.3 million
shares of its common stock in exchange for all of the outstanding common stock
of PanEnergy. PanEnergy is involved in the transportation, storage, gathering
and processing of natural gas, the production of natural gas liquids and is a
marketer of natural gas, electricity, liquefied petroleum gases and related
energy services. Pursuant to the merger, each share of PanEnergy common stock
outstanding was converted into the right to receive 1.0444 shares of the
Company's common stock. In addition, each outstanding option to purchase
PanEnergy common stock became an option to purchase common stock of the Company,
adjusted accordingly. The merger was accounted for as a pooling of interests
and, accordingly, the consolidated financial statements for periods prior to the
combination were restated to include the results of operations of PanEnergy.
Operating revenues and net income previously reported by the separate companies
and the combined amounts presented in the accompanying consolidated financial
statements are as follows:
In Millions Duke Power PanEnergy Adjustments Combined
- ---------------------------------------------- --------------- ----------------- -------------
Year Ended December 31, 1996
Operating revenues $4,758.0 $7,505.6 $38.8 $12,302.4
Net income $ 729.9 $ 344.4 - $ 1,074.3
Year Ended December 31, 1995
Operating revenues $4,676.6 $4,967.5 $50.6 $9,694.7
Net income $ 714.5 $ 303.6 - $1,018.1
Year Ended December 31, 1994
Operating revenues $4,489.0 $4,585.1 $40.9 $9,115.0
Net income $ 638.9 $ 225.2 - $ 864.1
The adjustment to operating revenues reflects a reclassification of PanEnergy's
equity in earnings of unconsolidated affiliates from other income to revenues to
be consistent with the Company's presentation.
Consolidations
The Company's consolidated financial statements reflect consolidation of all of
its majority-owned subsidiaries. Investments in other entities that are not
majority owned are accounted for using the equity method (see also Note 8).
Intercompany transactions have been eliminated in consolidation.
Use Of Estimates
The consolidated financial statements are prepared in conformity with generally
accepted accounting principles appropriate in the circumstances to reflect in
all material respects the substance of events and transactions which should be
included. In preparing these statements, management makes informed judgments and
estimates of the expected effects of events and transactions that are currently
being reported. However, actual results could differ from these estimates.
9
Reclassifications
Certain amounts have been reclassified in the consolidated financial statements
to conform to the current presentation.
Cost-Based Regulation
The Company's Electric Operations segment is subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC), the North
Carolina Utilities Commission and The Public Service Commission of South
Carolina. The interstate natural gas transmission and storage operations of the
Company's Natural Gas Transmission segment are also subject to the rules and
regulations of the FERC.
These regulated operations are subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Accordingly, the
Company records certain assets and liabilities that result from the effects of
the ratemaking process that would not be recorded under generally accepted
accounting principles for non-regulated entities. The regulatory assets of the
Company are classified as "Regulatory Assets" and regulatory liabilities are
classified as "Deferred Credits and Other Liabilities" on the Consolidated
Balance Sheets. The Company regularly evaluates the continued applicability of
SFAS No. 71, considering such factors as regulatory changes and the impact of
competition. Discontinuance of regulation or increased competition might require
entities to reduce their asset balances to reflect a market basis less than cost
and would also require entities to write off their associated regulatory assets.
Management cannot predict the potential impact, if any, of discontinuance of
regulation or increased competition on the Company's future financial position
and results of operations. However, the Company continues to position itself to
effectively meet these challenges by maintaining prices that are locally,
regionally and nationally competitive.
Revenues
The Company recognizes revenues on sales of electricity as service is rendered,
on sales of natural gas and petroleum products in the period of delivery, and
transportation and storage revenues in the period service is provided.
"Receivables" on the Consolidated Balance Sheets included $210 million and
$206.8 million as of December 31, 1996 and 1995, respectively, for electric
service that has been rendered but not yet billed to customers. When rate cases
associated with the transportation of natural gas are pending final FERC
approval, a portion of the revenues collected by interstate natural gas
pipelines is subject to possible refund. The Company has established adequate
reserves where required for such cases. (See also Note 4.)
Commodity Price Risk Management
Commodity derivatives utilized as hedges include futures, swaps and options. In
order to qualify as a hedge, the price movements in the underlying commodity
derivatives must be highly correlated with the hedged commodity. Gains and
losses related to commodity derivatives which qualify as hedges of commodity
commitments are recognized in income when the underlying hedged physical
transaction closes and are included in "Natural gas and petroleum products
purchased" or "Net interchange and purchased power" in the Consolidated
Statement of Income. Gains and losses related to such instruments, to the extent
settled in cash, are reported as "Other Current Liabilities" or "Other Current
Assets" as appropriate, in the Consolidated Balance Sheet until recognized in
income. Commodity derivatives utilized for trading include futures, swaps and
options. Gains and losses on derivatives utilized for trading are recognized on
a current basis and are also included in "Natural gas and petroleum products
purchased" or "Net interchange and purchased power". (See also Note 7.)
Nuclear Fuel
Amortization of nuclear fuel is included in "Fuel used in electric generation"
in the Consolidated Statements of Income. The amortization is recorded using the
units-of-production method.
Under provisions of the Nuclear Waste Policy Act of 1982, the Company has
entered into contracts with the Department of Energy (DOE) for the disposal of
spent nuclear fuel. Payments made to the DOE for disposal costs are based on
nuclear output and are included in "Fuel used in electric generation" in the
Consolidated Statements of Income.
A provision in the Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the DOE's uranium enrichment plants.
Licensees are subject to an annual assessment for 15 years based on their pro
rata share of past enrichment services. The annual assessment is recorded as
fuel expense. The Company paid $9.5 million during 1996 and has
10
paid $45 million cumulatively related to its ownership interest in nuclear
plants. The Company has reflected the remaining liability and regulatory asset
of $94.7 million in the Consolidated Balance Sheet at December 31, 1996.
Deferred Returns And Allowance For Funds Used During Construction (AFUDC)
Deferred returns represent the estimated financing costs associated with funding
certain regulatory assets. These regulatory assets primarily arise from the
Company's funding of purchased capacity costs above levels collected in rates.
Deferred returns are non-cash items. They are primarily recognized as an
addition to "Purchased capacity costs" and as an offsetting credit to "Other
Income and Expenses."
AFUDC represents the estimated debt and equity costs of capital funds necessary
to finance the construction of new regulated facilities. AFUDC, a non-cash item,
is recognized as a cost of "Property, Plant and Equipment," with an offsetting
credit to "Other Income and Expenses." After construction is completed, the
Company is permitted to recover these costs, including a fair return, through
their inclusion in rate base and in the provision for depreciation.
Rates used for capitalization of deferred returns and AFUDC by the Company's
regulated operations are calculated in compliance with FERC rules.
Inventory
Inventory consists primarily of materials and supplies, gas held for operations
and coal held for electric generation. Inventory is recorded at the lower of
cost or market primarily using the average cost method.
Property, Plant And Equipment
Property, plant and equipment is stated at original cost. The Company
capitalizes all construction-related direct labor and materials, as well as
indirect construction costs. Indirect costs include general engineering, taxes
and the cost of money. The cost of renewals and betterments of regulated units
of property is also capitalized. The cost of repairs and replacements is charged
to expense.
At the time property, plant and equipment maintained by the Company's regulated
operations are retired, the original cost plus the cost of retirement, less
salvage, is charged to accumulated depreciation and amortization. When entire
regulated operating units are sold or non-regulated properties are retired or
sold, the property and related accumulated depreciation and amortization
accounts are reduced and any gain or loss is recorded to income, unless
otherwise required by FERC.
Depreciation of plant, property and equipment is generally computed using the
straight-line method.
Property, plant and equipment is evaluated for potential impairment based on the
ability to identify separate cash flows generated therefrom. In accordance with
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of," the Company recognizes impairment losses
on long-lived assets when book values exceed expected future cash flows.
Goodwill Amortization
The Company amortizes goodwill related to the purchases of Texas Eastern
Corporation (TEC), certain other natural gas gathering, transmission and
processing facilities, and certain engineering consulting businesses on a
straight-line basis over 40 years, 15 years and 15 years, respectively.
Accumulated amortization of goodwill at December 31, 1996 and 1995 was $99.7
million and $96.3 million, respectively. (See also Note 6.)
Unamortized Debt Premium, Discount And Expense
Expenses incurred in connection with the issuance of presently outstanding
long-term debt issued for regulated operations, and premiums and discounts
relating to such debt, are being amortized over the terms of the respective
issues. Also, any call premiums or unamortized expenses associated with
refinancing higher-cost debt obligations used to finance regulated assets and
operations are being amortized consistent with regulatory treatment of these
items.
11
Income Taxes
Duke Power and its subsidiaries and PanEnergy and its subsidiaries each file a
consolidated federal income tax return. Federal income taxes have been provided
by the Company on the basis of its separate company income and deductions in
accordance with established practices of the consolidated group.
Deferred income taxes have been provided for temporary differences. Temporary
differences occur when events and transactions recognized for financial
reporting result in taxable or tax-deductible amounts in different periods.
Investment tax credits have been deferred and are being amortized over the
estimated useful lives of the related properties.
Common Stock Options
The Company follows the intrinsic value method of accounting for common stock
options and awards issued to employees. (See also Note 12.)
Earnings Per Common Share
The computation of earnings per common share is based on the monthly
weighted-average number of shares of common stock outstanding. Convertible debt
and unexercised stock options do not have a dilutive effect on the reported
amount of earnings per common share. (See Notes 11, 12 and 13.)
Consolidated Statements Of Cash Flows
All liquid investments with maturities at date of purchase of three months or
less are considered cash equivalents.
Total income taxes paid were $549.9 million, $519.9 million and $418.4 million
for the years ended December 31, 1996, 1995 and 1994, respectively. Interest
paid, net of amounts capitalized, was $493.1 million, $481.6 million and $457.7
million for the years ended December 31, 1996, 1995 and 1994, respectively.
NOTE 2. BUSINESS COMBINATIONS
PanEnergy Trading And Market Services, L.L.C.
On August 1, 1996, a wholly-owned subsidiary of the Company formed a natural gas
and power marketing joint venture with Mobil Corporation (Mobil) affiliates. The
marketing company (PTMS) conducts business as PanEnergy Trading and Market
Services, L.L.C. in the United States and as PanEnergy Marketing L.P. in Canada.
The Company operates the new entity and owns a 60% interest, with Mobil owning a
40% minority interest.
Associated Natural Gas Corporation
On December 15, 1994, a wholly-owned subsidiary of the Company merged with
Associated Natural Gas Corporation (Associated), now PanEnergy Natural Gas
Corporation, on a tax-free, stock-for-stock basis. The merger was accounted for
under the pooling of interests method.
The consolidated financial statements of the Company were restated in 1994 to
include the results of Associated for the 12 months ended September 30.
Effective with the date of the merger, the fiscal year end of Associated was
changed from September 30 to December 31. Associated's net income for the three
months ended December 31, 1994 was recorded directly to retained earnings and
its cash activity for that period is shown separately on the consolidated
statement of cash flows.
12
NOTE 3. BUSINESS SEGMENTS
The Electric Operations segment is engaged in the generation, transmission,
distribution and sale of electric energy in central and western North Carolina
and the western portion of South Carolina, comprising the area known as the
Piedmont Carolinas. These electric operations are subject to the rules and
regulations of the Federal Energy Regulatory Commission (FERC), the North
Carolina Utilities Commission and The Public Service Commission of South
Carolina.
The Natural Gas Transmission segment is involved in interstate transportation
and storage of natural gas for customers in the Mid-Atlantic, New England,
Midwest and Gulf Coast states. The interstate natural gas transmission and
storage operations of the Company's wholly owned subsidiaries Texas Eastern
Transmission Corporation (TETCO), Algonquin Gas Transmission Company
(Algonquin), Panhandle Eastern Pipe Line Company (PEPL), and Trunkline Gas
Company (Trunkline) are also subject to the rules and regulations of the FERC.
The Energy Services segment is comprised of several separate business units.
Field Services gathers and processes natural gas and produces natural gas
liquids. The Trading and Marketing operations focus on marketing of natural gas,
electricity and liquefied petroleum gases. Other business activities in this
segment include ownership and operation of energy-related facilities,
engineering consulting, construction and other related energy services.
Parent and Other Operations include real estate operations, communications
services, corporate costs and intersegment eliminations.
- ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------
Earnings
Before Depreciation Capital and
Unaffiliated Intersegment Total Operating Interest & Investment Identifiable
In Millions Revenues Revenues Revenues Income & Taxes Amortization Expenditures Assets
- ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------
- ----------------------------
Year Ended December 31, 1996
- ----------------------------
Electric Operations $4,498.4 $ - $4,498.4 $1,303.6 $1,419.5 $481.1 $609.8 $12,661.7
Natural Gas Transmission 1,468.8 86.4 1,555.2 584.5 596.2 228.2 185.3 5,267.2
Energy Services 6,186.6 12.4 6,199.0 197.0 202.7 67.1 590.5 2,772.2
Parent and Other Operations 148.6 (98.8) 49.8 73.5 75.8 13.0 164.4 1,253.8
--------- ---------- --------- -------- -------- ------- -------- ---------
Total Consolidated $12,302.4 $ - $12,302.4 $2,158.6 $2,294.2 $789.4 $1,550.0 $21,954.9
========= ========== ========= ======== ======== ====== ======== =========
- ------------------------------
Year Ended December 31, 1995
- ------------------------------
Electric Operations $4,512.4 $ - $4,512.4 $1,308.7 $1,381.2 $451.2 $704.0 $12,673.1
Natural Gas Transmission 1,480.2 53.1 1,533.3 564.1 569.7 228.5 227.0 5,352.6
Energy Services 3,528.7 1.0 3,529.7 118.5 130.1 44.4 247.8 1,600.6
Parent and Other Operations 173.4 (54.1) 119.3 77.0 109.5 13.0 111.9 1,241.6
--------- ---------- --------- -------- -------- ------- -------- ---------
Total Consolidated $9,694.7 $ - $9,694.7 $2,068.3 $2,190.5 $737.1 $1,290.7 $20,867.9
======== ========== ======== ======== ======== ====== ======== =========
- ------------------------------
Year Ended December 31, 1994
- ------------------------------
Electric Operations $4,362.9 $ - $4,362.9 $1,131.3 $1,228.5 $454.7 $796.6 $12,273.5
Natural Gas Transmission 1,642.0 44.8 1,686.8 533.9 521.6 216.8 303.4 5,655.8
Energy Services 2,946.0 60.2 3,006.2 79.1 89.6 34.5 274.1 1,247.9
Parent and Other Operations 164.1 (105.0) 59.1 61.7 67.3 10.8 77.6 1,077.0
--------- ---------- --------- -------- -------- ------- -------- ---------
Total Consolidated $9,115.0 $ - $9,115.0 $1,806.0 $1,907.0 $716.8 $1,451.7 $20,254.2
======== ========== ======== ======== ======== ====== ======== =========
- ------------------------------ ------------ ------------ ---------- ---------- ---------- ------------ ------------- ------------
NOTE 4. RATE MATTERS
Electric Operations
The North Carolina Utilities Commission (NCUC) and The Public Service Commission
of South Carolina (PSCSC) must approve rates for retail sales within their
respective states. The Federal Energy Regulatory Commission (FERC) must approve
the Company's rates for electric sales to wholesale customers. Electric sales to
the other joint owners of the Catawba Nuclear Station, which represent a
substantial majority of the Company's electric wholesale revenues, are set
through contractual agreements (see Note 5).
Fuel costs are reviewed semiannually in the wholesale jurisdiction and annually
in the South Carolina retail jurisdiction, with provisions for changing such
costs in base rates. In the North Carolina retail jurisdiction, a review of fuel
costs in rates is required annually and during general rate case proceedings.
All jurisdictions allow the Company to adjust electric rates for past over- or
under-recovery of fuel costs. Therefore, the Company reflects in revenues the
difference between actual fuel costs incurred for electric operations and fuel
costs recovered through rates.
The PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement
rider of 0.432 cents per kilowatt-hour, or an average of approximately 8
percent, affecting South Carolina retail customers. South Carolina retail sales
represent approximately 30 percent of the Company's total electric retail sales.
The rate reduction was reflected on bills rendered on or after June 1, 1996.
This net decrement rider reflects an interim true-up decrement adjustment
associated with the levelization of Catawba Nuclear Station purchased capacity
costs and an interim true-up increment associated with amortization of the
demand-side management deferral account. The rate adjustment was made because,
in the South Carolina retail jurisdiction, cumulative levelized revenues
associated with the recovery of Catawba purchased capacity costs had exceeded
purchased capacity payments and accrual of deferred returns, and certain
demand-side costs had exceeded the level reflected in rates (see also Note 5).
Certain of the Company's electric wholesale customers, excluding the other
Catawba joint owners, initiated proceedings in 1995 before the FERC concerning
rate matters. The Company and nine of its eleven wholesale customers entered
into a settlement in July 1996 which reduced the customers' electric rates by
approximately 9 percent and renewed their contracts with the Company through the
year 2000. Both of the customers that did not enter into the settlement have
signed agreements to purchase electricity from other suppliers beginning in
1997. The eleven wholesale customers involved in this matter accounted for less
than 2 percent of the Company's overall electric revenues during 1996. The two
customers that have signed agreements with other suppliers accounted for less
than 0.5 percent of the Company's 1996 overall electric revenues.
Jurisdictional Transportation And Sales Rates For Natural Gas
As noted previously, the interstate natural gas transmission operations of Texas
Eastern Transmission Corporation (TETCO), Algonquin Gas Transmission Company
(Algonquin), Panhandle Eastern Pipe Line Company (PEPL) and Trunkline Gas
Company (Trunkline), and the liquefied natural gas (LNG) operations of Trunkline
LNG Company and Algonquin LNG, Inc. are subject to the rules and regulation of
the Federal Energy Regulatory Commission (FERC).
PEPL. On April 1, 1992 and November 1, 1992, PEPL placed into effect, subject to
refund, general rate increases. On September 12, 1996, PEPL filed a settlement
proposal relating to both rate proceedings on behalf of itself and the majority
of its largest customers. On December 20, 1996, FERC approved PEPL's settlement
agreement which resolves refund matters and establishes prospective rates for
settling parties. The agreement, which remains subject to rehearing, terminates
other actions relating to these proceedings as well as PEPL's restructuring of
rates and transition cost recoveries related to Order 636.
As a result of the resolution of certain proceedings, PEPL recorded earnings
before interest and taxes of $8 million, $20.6 million and $25 million in 1996,
1995 and 1994, respectively.
Trunkline. Effective August 1, 1996, Trunkline placed into effect a general rate
increase, subject to refund.
Algonquin. On June 14, 1996, Algonquin submitted a compliance filing reflecting
changes in net plant, property and equipment pursuant to a previous rate
settlement. On October 16, 1996, FERC accepted the filing and denied all
protests.
14
FERC Order 636 And Transition Costs
The Company's interstate natural gas pipelines primarily provide transportation
and storage services pursuant to FERC Order 636. Order 636 allows pipelines to
recover eligible costs resulting from implementation of the order (transition
costs). On July 16, 1996, the U.S. Court of Appeals for the District of Columbia
upheld, in general, all aspects of Order 636 and remanded certain issues for
further explanation. One of the issues remanded for further explanation is
whether pipelines should be entitled to recover 100% of gas supply realignment
(GSR) costs. This matter is substantially mitigated by TETCO's and PEPL's
transition cost settlements.
In 1994, TETCO refunded $84 million to customers pursuant to a FERC-approved
settlement that resolved regulatory issues related primarily to Order 636
transition costs and a number of other issues related to services prior to Order
636. TETCO's final and nonappealable settlement provides for the recovery of
certain transition costs through volumetric and reservation charges through 2002
and beyond, if necessary. Pursuant to the settlement, TETCO will absorb a
certain portion of the transition costs, the amount of which continues to be
subject to change dependent upon natural gas prices and deliverability levels.
In 1995, based upon producers' discoveries of additional natural gas reserves,
TETCO increased the estimated liabilities for transition costs by $125.8
million. Under the terms of the existing settlement, regulatory assets were
increased $85.8 million and TETCO recognized a $40 million charge to operating
expenses ($26 million after tax).
The Company believes the exposure associated with gas purchase contract
commitments is substantially mitigated by transition cost recoveries pursuant to
customer settlements, Order 636 and other mechanisms, and that this issue will
not have a material adverse effect on consolidated results of operations or
financial position.
NOTE 5. JOINT OWNERSHIP OF GENERATING FACILITIES
The Company previously sold interests in both units of the Catawba Nuclear
Station. The other owners of portions of the Catawba Nuclear Station and
supplemental information regarding their ownership are as follows:
Owner Ownership Interest
in the Station
------------------------------------------- ------ -------------------
North Carolina Municipal Power Agency 37.5%
Number 1 (NCMPA)
North Carolina Electric Membership 28.125%
Corporation (NCEMC)
Piedmont Municipal Power Agency 12.5%
(PMPA)
Saluda River Electric Cooperative, Inc. 9.375%
(Saluda River)
Each owner has provided its own financing for its ownership interest in the
station.
The Company retains a 12.5 percent ownership interest in the Catawba Nuclear
Station. As of December 31, 1996, $497.3 million of "Property, plant and
equipment" represents the Company's investment in Units 1 and 2. Accumulated
depreciation and amortization of $192.1 million associated with Catawba has been
recorded as of year-end 1996. The Company's share of operating costs of Catawba
is included in the Consolidated Statements of Income.
In connection with the joint ownership, the Company has entered into contractual
agreements with the other joint owners to purchase declining percentages of the
generating capacity and energy from the plant. These purchased power agreements
were effective beginning with the commercial operation of each unit. Unit 1 and
Unit 2 began commercial operation in June 1985 and August 1986, respectively.
The purchased power agreements were established for 15 years for NCMPA and PMPA
and 10 years for NCEMC and Saluda River. While the purchased power agreements
with NCMPA and PMPA extend for 15 years, a
15
significant decrease in the percentage of capacity and energy the Company is
obligated to purchase occurs in the 11th calendar year of operation for each
unit. This significant decrease occurred in 1995 for Unit 1 and 1996 for Unit 2.
The agreements also provide for supplemental power sales by the Company to the
other joint owners. Such power sales are to satisfy capacity and energy needs of
the other joint owners beyond the capacity and energy which they retain from
Catawba or potentially acquire in the form of other resources. The agreements
further provide the other joint owners the ability to secure such supplemental
requirements outside of these contractual agreements following an appropriate
notice period. NCEMC and Saluda River have given appropriate notice that they
intend to acquire their supplemental capacity requirements outside of these
agreements effective January 1, 2001 and January 1, 2002, respectively, thus
relieving the Company of the obligation to serve this portion of load. As the
joint owners retain more capacity and energy from Catawba, or a third party,
supplemental power sales are expected to decline.
The agreements with each of the other joint owners include provisions that the
Company will provide generating reserves to backstand the other joint owners'
retained capacity in the Catawba plant at the system average cost of installed
capacity. Additionally, the agreements include certain reliability exchanges
designed to manage outage-related risks by exchanging energy entitlements
between the Catawba Nuclear Station and the McGuire Nuclear Station, impacting
the Company as well as all the other joint owners.
Purchased energy cost payments are based on variable operating costs and are a
function of the generation output of Catawba. Purchased capacity payments are
based on the fixed costs of the plant and include the capital costs and fixed
operating and maintenance costs. Actual purchased capacity costs for 1996 and
projected obligations for 1997 through 2001, including the impact of the 1995
settlement agreement with NCMPA and PMPA (see Note 15), are as follows (dollars
in millions):
Purchased Purchased Total
Year Capacity Capacity Purchased
Capital Cost Fixed O&M Capacity
--------------- --------------- -------------- --------------
1996 Actual $84.3 $40.5 $124.8
1997 Projected $67.0 $34.9 $101.9
1998 Projected $48.4 $26.4 $ 74.8
1999 Projected $35.3 $19.1 $ 54.4
2000 Projected $ 4.3 $ 2.5 $ 6.8
2001 Projected --- --- ---
Effective in its November 1991 rate order, the North Carolina Utilities
Commission reaffirmed the Company's recovery, on a levelized basis, of the
capital costs and fixed operating and maintenance costs of capacity purchased
from the other joint owners. The Public Service Commission of South Carolina in
its November 1991 rate order reaffirmed the Company's recovery on a levelized
basis of the capital costs of capacity purchased from the other joint owners.
Levelization was reaffirmed through inclusion in rates approved in March 1992 by
the Federal Energy Regulatory Commission (FERC). The portion of purchased
capacity subject to levelization not currently recovered in rates is being
deferred, and the Company is recording a deferred return on the accumulated
balance. The Company recovers the accumulated balance, including the deferred
return, when the sum of the declining purchased capacity payments and accrual of
deferred returns for the current period drops below the levelized revenues.
Jurisdictional levelizations are intended to recover total costs, including
deferred returns, and are subject to adjustments, including final true-ups. The
Company recovers the costs of purchased energy and the non-levelized portion of
purchased capacity on a current basis.
The current levelized revenues approved in the Company's last general rate
proceedings are $211.4 million, $94.1 million and $6.8 million for North
Carolina retail, South Carolina retail and Other Wholesale (FERC), respectively.
Purchased power costs, subject to levelization, are deferred based on allocation
factors of approximately 62 percent, 26 percent and 2 percent for North Carolina
retail, South Carolina retail and Other Wholesale (FERC), respectively. The
PSCSC, on May 7, 1996, ordered a rate reduction in the form of a decrement rider
for an interim true-up adjustment (see Note 4). The Company also recovers an
allocated amount of purchased power costs in the pricing of supplemental sales
made to the other joint owners on a current basis.
During 1996, in the North Carolina retail and FERC wholesale jurisdictions,
annual levelized revenues exceeded purchased capacity payments and the accrual
of deferred returns for the first time. In the South Carolina retail
jurisdiction, cumulative levelized revenues have exceeded purchased capacity
payments and accrual of deferred returns.
For the years ended December 31, 1996, 1995 and 1994, the Company recorded
purchased capacity and energy costs from the other joint owners of $151.2
million, $388.2 million and $604.5 million, respectively. These amounts, after
adjustments for the costs of capacity purchased not reflected in current rates,
are included in "Net interchange and purchased power" in the
16
Consolidated Statements of Income. As of December 31, 1996 and 1995, $892
million and $965.5 million, respectively, associated with the cost of capacity
purchased but not reflected in current rates have been accumulated in the
Consolidated Balance Sheets as "Purchased capacity costs" and "Current portion
of purchased capacity costs".
NOTE 6. INCOME TAX EXPENSE
Income tax expense for the years ended December 31, 1996, 1995 and 1994
consisted of the following (dollars in millions):
1996 1995 1994
--------- --------- ----------
Current Income Taxes
Federal $514.3 $452.0 $290.6
State 108.8 97.0 58.8
----- ----- -----
Total current income taxes 623.1 549.0 349.4
----- ----- -----
Deferred taxes, net
Federal 73.1 105.2 178.0
State 12.8 21.2 42.3
----- ----- -----
Total deferred taxes, net 85.9 126.4 220.3
---- ----- -----
Investment tax credit amortization (11.2) (11.2) (11.3)
------ ------ ------
Total income tax expense $697.8 $664.2 $558.4
====== ====== ======
Total income tax differs from the amount computed by applying the federal income
tax rate to income before income tax. The reasons for this difference are as
follows (dollars in millions):
1996 1995 1994
------------ ------------ ---------------
Federal income tax rate 35% 35% 35%
=== === ===
Income tax, computed at the statutory rate $626.1 $588.8 $497.9
Adjustments resulting from:
State income tax, net of federal income tax effect 78.6 76.5 64.9
Other items, net (6.9) (1.1) (4.4)
----- ----- -----
Total income tax $697.8 $664.2 $558.4
====== ====== ======
Effective tax rate 39.0% 39.5% 39.3%
===== ===== =====
The tax effects of temporary differences that resulted in deferred income tax
assets and liabilities, and a description of the significant items that created
these differences, are as follows (dollars in millions):
December 31, December 31,
1996 1995
---------------- ----------------
Property, plant and equipment * $2,290.6 $2,247.8
Regulatory assets * 687.4 757.6
Regulatory asset related to restating to pre-tax basis 601.9 606.1
Deferred credits and other liabilities (334.3) (375.1)
Other 322.9 247.9
-------- --------
Total deferred income taxes $3,568.5 $3,484.3
======== ========
* The net regulatory asset related to income taxes is $493.4 million for 1996
and $491.6 million for 1995.
17
Total deferred income tax liabilities were $4,409 million and $4,452.7 million
at December 31, 1996 and 1995, respectively. Total deferred income tax assets
were $981.6 million and $1,110.9 million at December 31, 1996 and 1995,
respectively. The valuation reserve for deferred tax assets was $141.1 million
and $142.5 million at December 31, 1996 and 1995, respectively.
In 1990, the Internal Revenue Service (IRS) issued regulations which disallow
for tax purposes losses incurred in the Company's 1989 sales of certain assets
that were acquired in the purchase of Texas Eastern Corporation. Consequently,
the Company established a provision in 1990 for this and certain other issues,
resulting in an increase in goodwill and deferred income tax liability.
Following further discussions with the IRS, the Company revised its estimates in
1994 with respect to the disallowed loss issue, and in 1995 and 1996 with
respect to the remaining issues. As a result, the Company reduced the related
goodwill and deferred income tax liability by approximately $40 million, $100
million and $200 million in 1996, 1995 and 1994, respectively.
NOTE 7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Financial Instruments
In order to obtain variable rate financing at an attractive cost, the Company
entered into various interest rate swap agreements. At December 31, 1996 and
1995, the following swaps were outstanding (dollars in millions):
Weighted Weighted Weighted
Average Average Average
Face Rate Rate Rate
Series Issued Year Due Value 1996 1995 1994
---------------- ---------- ----------- ---------- ----------- ------------ ------------
8% Series B 1994 1999 $200 5.64% 6.14% 5.95%
7 1/2% Series B 1995 2025 $100 6.69% 7.06% ---
The interest rate swaps are reset quarterly based upon the three-month London
Interbank Offered Rate (LIBOR). As a result of the interest rate swap contracts,
interest expense on the Consolidated Statements of Income is recognized at the
weighted average rate for the year tied to the LIBOR rate.
The Company has implemented an agreement to sell with limited recourse, on a
continuing basis, current accounts receivable at a discount. The Company
received $100 million for accounts receivable sold that remained outstanding at
December 31, 1996. In 1996, TETCO received $98.6 million from the sale of the
right to collect certain Order 636 transition costs, with limited recourse. In
1993, the Company sold LNG project settlement receivables, with limited
recourse. At December 31, 1996, $87.3 million and $29.9 million remained
outstanding on the transition cost recovery rights sold and the LNG settlement
receivables sold, respectively. In the opinion of management, the probability
that the Company will be required to perform under any of the above recourse
provisions is remote.
Duke Energy Group, Inc. entered into a hedge transaction in 1995 to offset
currency fluctuations between the U.S. dollar and the Chilean peso associated
with expected equity contributions to an affiliate in 1995, 1996 and 1997. The
hedge transaction has a notional amount of approximately $4.4 million at
December 31, 1996. Duke Energy Group, Inc. records any realized gains or losses
associated with the hedge as an adjustment to investments in affiliates.
Fair Market Value Of Financial Instruments
The fair value of the Company's financial instruments is summarized below.
Judgment is required in interpreting market data to develop the estimates of
fair value. Accordingly, the estimates determined as of December 31, 1996 and
1995 are not necessarily indicative of the amounts the Company could have
realized in current market exchanges.
18
- ---------------------------------------- -------------------------- -----------------------------
In Millions December 31, 1996 December 31, 1995
Assets (Liabilities) Assets (Liabilities)
- ---------------------------------------- -------------------------- -----------------------------
Book Value Approximate Book Value Approximate
Fair Value Fair Value
----------- -------------- ----------- -----------------
Cash and cash equivalents $166.0 $166.0 $172.5 $172.5
Notes payable and commercial paper (459.7) (459.7) (300.3) (300.3)
Long-term debt (1) (5,881.5) (5,999.0) (6,048.9) (6,430.5)
Foreign currency exchange contract (3) -- -- 32.7 34.0
Interest rate swaps (3) -- 12.0 -- 23.1
Nuclear decommissioning trust funds (2) 362.6 362.6 273.5 273.5
Preferred stock (1) (684.0) (699.0) (684.0) (689.0)
- ---------------------------------------- ----------- -------------- ----------- -----------------
(1) The majority of estimated fair value amounts of long-term debt and
preferred stock were obtained from independent parties.
(2) External funds have been established, as required by the Nuclear Regulatory
Commission, as a mechanism to fund certain costs of nuclear
decommissioning. Currently, these nuclear decommissioning trust funds are
invested in U.S. stocks, bonds and cash equivalents.
(3) Amounts shown for foreign currency exchange contracts and interest rate
swaps represent estimated amounts the Company would receive if agreements
were settled, considering current market rates and the creditworthiness of
the parties to the agreements.
The following financial instruments have no book value associated with them and
there are no fair values readily determinable since quoted market prices are not
available: recourse provisions of the TEPPCO Partners, L.P. First Mortgage Notes
(see Note 15); and the LNG project settlement, trade accounts receivable and
Order 636 transition cost recovery sales agreements.
Commodity Risk Management
At December 31, 1996, the Company held or issued several instruments that reduce
the Company's exposure to market fluctuations in the price and transportation
costs of natural gas, petroleum products and power. The Company's market
exposure, primarily within PTMS, arises from inventory balances and fixed-price
purchase and sale commitments that extend for periods of up to 10 years. The
Company uses futures, swaps and options to manage and hedge price and location
risk related to these market exposures. PTMS also provides risk management
services to its customers through a variety of energy commodity financial
instruments. In addition to hedging activities, the Company also engages in the
trading of such instruments, and therefore experiences net open positions in
terms of price, volume and specified delivery point. The Company manages open
positions with strict policies which limit its exposure to market risk and
require daily reporting to management of potential financial exposure. These
policies include statistical risk tolerance limits using historical price
movements to calculate a daily earnings at risk as well as a total value at risk
measurement. The weighted-average life of the Company's commodity risk portfolio
was approximately 11 months at December 31, 1996.
Natural gas futures involve the buying or selling of natural gas at a fixed
price. Over-the-counter swap agreements require the Company to receive or make
payments based on the difference between a specified price and the actual price
of natural gas. The Company uses futures and swaps to manage margins on
offsetting fixed-price purchase or sale commitments for physical quantities of
natural gas. Natural gas options held to hedge price risk provide the right, but
not the requirement, to buy or sell natural gas at a fixed price. The Company
utilizes options to manage margins and to limit overall price risk exposure.
At December 31, 1996 and 1995, the Company had outstanding futures, swaps and
options for an absolute notional contract quantity of 104 billion cubic feet
(Bcf) and 223 Bcf of natural gas, respectively, which are in place to offset the
risk of price fluctuations under fixed-price commitments for delivering and
purchasing natural gas. The gains, losses and costs related to those financial
instruments that qualify as a hedge are not recognized until the underlying
physical transaction occurs. At December 31, 1996 and 1995, the Company had
unrecognized net losses of $5.1 million and $15.4 million, respectively, related
to financial instruments which are offset by corresponding unrecognized net
gains from the Company's obligations to sell physical quantities of gas and
power. The fair value of energy commodity swaps held at December 31, 1996 was an
asset of $86.5 million with a notional amount of $95.9 million.
During 1996, 1995 and 1994, the Company recognized gains of $25.4 million, $10.5
million and $0.7 million, respectively, from trading activities. The values of
energy commodities futures, swaps and options held for trading purposes were as
follows:
19
--------------------------- ------------------------- ----------------------------
In Millions 1996 1995
--------------------------- ------------------------- ----------------------------
Assets Liabilities Assets Liabilities
----------- ------------- ----------- ----------------
Fair Value at December 31 $719 $731 $406 $424
Average Fair Value 458 466 277 289
Notional Amount 698 692 430 447
--------------------------- ----------- ------------- ----------- ----------------
Market And Credit Risk
New York Mercantile Exchange (Exchange) traded futures and option contracts are
guaranteed by the Exchange and have nominal credit risk. On all other
transactions described above, the Company is exposed to credit risk in the event
of nonperformance by the counterparties. For each counterparty, the Company
analyzes their financial condition prior to entering into an agreement,
establishes credit limits and monitors the appropriateness of these limits on an
ongoing basis. The change in market value of Exchange-traded futures and options
contracts requires daily cash settlement in margin accounts with brokers. Swap
contracts and most other over-the-counter instruments are generally settled at
the expiration of the contract term and may be subject to margin requirements
with the counterparty.
NOTE 8. INVESTMENT IN AFFILIATES
Certain investments, where the Company's ownership in domestic and international
affiliates is 50 percent or less, are accounted for by the equity method. These
investments include ownership interests in various power and natural gas
development projects; start-up personal communications services; marketing of
natural gas, electric power, and development of other energy services;
participation in various construction and support activities for fossil-fueled
generating plants; and real-estate development projects. The Company's
proportionate share of net income from these affiliates for the years ended
December 31, 1996, 1995 and 1994 was $32.7 million, $59.8 million and $47.9
million, respectively. These amounts are reflected in "Other operating revenues"
on the Consolidated Statements of Income.
A summary of assets and liabilities of these affiliates follows (dollars in
millions):
------------------------------------- -------------- ---------------
In Millions December 31, December 31,
1996 1995
------------------------------------- -------------- ---------------
Assets of affiliates $7,209.0 $6,232.1
Liabilities of affiliates $4,715.0 $4,250.4
------------------------------------- -------------- ---------------
In addition, the Company had outstanding loans to certain affiliates of $2.9
million and $23.2 million at December 31, 1996 and 1995, respectively.
20
NOTE 9. PROPERTY, PLANT AND EQUIPMENT
A summary of property, plant and equipment by classification follows (dollars in
millions):
Depreciation December 31, December 31,
Rates 1996 1995
--------------- ----------------- ---------------
Electric Plant In Service
Production 2%-5% $ 7,278.4 $ 7,154.3
Transmission 2%-3% 1,543.7 1,532.3
Distribution 2%-4% 4,303.9 4,105.5
General plant 0%-8% 1,068.3 1,030.2
Nuclear fuel --- 604.8 731.7
Construction work in progress --- 389.0 382.6
---------- ---------
Total electric plant in service 15,188.1 14,936.6
---------- ---------
Natural Gas Plant In Service
Transmission 2%-7% 6,206.7 6,044.8
Gathering 1%-7% 431.0 511.9
Processing 4%-5% 508.4 144.1
Underground storage 2%-4% 450.6 488.3
LNG facilities and vessels 0%-3%* 751.0 751.2
General plant 3%-33% 348.1 318.5
Construction work in progress --- 126.7 141.9
---------- ---------
Total natural gas plant in service 8,822.5 8,400.7
---------- ---------
Other Property and Equipment 3%-33% 457.6 384.7
---------- ---------
Total Property, Plant and Equipment 24,468.2 23,722.0
Less accumulated depreciation (including
amortization of nuclear fuel: 1996 - $363.3
million; 1995 - $453.9 million) 9,199.1 8,857.0
---------- ---------
Net property, plant and equipment $ 15,269.1 $14,865.0
========== =========
* A portion of these assets are depreciated using the modified units of
production method.
A summary of accumulated depreciation for property, plant and equipment by
classification follows (dollars in millions):
December 31, December 31,
1996 1995
----------------- ---------------
Electric Plant In Service $ 5,801.8 $ 5,576.1
Natural Gas Plant In Service 3,365.8 3,250.9
Other Property and Equipment 31.5 30.0
--------- ---------
Total Accumulated Depreciation $ 9,199.1 $ 8,857.0
========= =========
21
NOTE 10. SHORT-TERM DEBT AND CREDIT FACILITIES
The following credit facilities were available to the Company at December 31,
1996 and 1995 (dollars in millions):
--------------------------------- --------------- ---------------- -------------- -----------------
Credit Credit
Facilities at Outstanding at Facilities at Outstanding at
December 31, December 31, December December 31,
In Millions 1996 1996 31, 1995 1995
--------------------------------- --------------- ---------------- -------------- -----------------
Annually renewable facilities $ 64.9 $ 8.6 $ 64.9 $ 29.3
364-day facilities (d) 400.0 - - -
Two-year revolving facilities (a) 40.0 - 40.0 -
Four-year revolving facilities (b) 235.0 42.0 210.0 30.0
Five-year facilities (c) 755.0 - 1,155.0 -
-------- ----- ---------- -----
Total Consolidated $1,494.9 $50.6 $ 1,469.9 $59.3
======== ===== ========== =====
--------------------------------- --------------- ---------------- -------------- -----------------
(a) At December 31, 1996 and 1995, the Company had $40 million of pollution
control bonds, included in long-term debt, backed by the two-year revolving
facilities.
(b) The outstanding balance of $42 million and $30 million at December 31, 1996
and 1995, respectively, were included in long-term debt.
(c) The Company had $130 million in commercial paper, included in long-term
debt, outstanding throughout 1996 and 1995 backed by these facilities.
(d) The Company had $194.2 million and $126 million in commercial paper,
included in short-term debt, outstanding at December 31, 1996 and 1995,
respectively, backed by these facilities.
In addition to amounts borrowed under the credit facilities and commercial paper
program, the Company had $251.9 million and $145 million of short-term
borrowings from banks outstanding at December 31, 1996 and 1995, respectively.
A summary of short-term borrowings is as follows (dollars in millions):
1996 1995 1994
------------- ------------ -------------
Amount outstanding at end of period - average rate of 6.16% as of December
31, 1996, 6.09% as of December 31, 1995, and 6.02% as of December $459.7 $300.3 $107.1
31, 1994
Maximum amount outstanding during the period $501.4 $409.3 $147.1
Average amount outstanding during the period $182.4 $152.8 $25.1
Weighted-average interest rate for the period - computed on a daily 5.92% 6.15% 4.42%
basis
22
NOTE 11. LONG-TERM DEBT
Long-term debt outstanding as of December 31, 1996 and 1995 consisted of the
following (dollars in millions):
Year Due December 31, December 31,
1996 1995
------------ ---------------- --------------
Duke Power (a)
First and refunding mortgage bonds:
6.59% 1996 $ -- $3.0
5 3/8% 1997 72.6 72.6
5 5/8% 1997 100.0 100.0
5.17% 1998 50.0 50.0
7.5% 1999 100.0 100.0
6 1/4% 1999 65.0 65.0
5.76% 1999 5.0 5.0
5.78% 1999 25.0 25.0
5.79% 1999 30.0 30.0
8% B 1999 200.0 200.0
7% 2000 100.0 100.0
7% B 2000 100.0 100.0
5 7/8% 2001 150.0 150.0
6 5/8% B 2003 100.0 100.0
5 7/8% C 2003 75.0 75.0
6.125% 2003 75.0 75.0
8% 2004 75.0 75.0
6 1/4% B 2004 100.0 100.0
7.37%-7.41% 2004 100.0 100.0
7% 2005 200.0 200.0
6 3/8% 2008 125.0 125.0
8 3/4% 2021 150.0 150.0
8 3/8% B 2021 150.0 150.0
8 5/8% 2022 100.0 100.0
7 3/8% 2023 200.0 200.0
6 7/8% B 2023 200.0 200.0
7 7/8% 2024 150.0 150.0
6 3/4% 2025 150.0 150.0
7 1/2% B 2025 100.0 100.0
8.27% 2025 21.0 21.0
8.27% 2025 50.0 50.0
8.28% 2025 2.0 2.0
8.30% 2025 5.0 5.0
8.95% 2027 15.6 15.7
7% 2033 150.0 150.0
Pollution control bonds:
7.70% 2012 20.0 20.0
7.75% B 2017 10.0 10.0
7.50% 2017 25.0 25.0
3.58% 2014 40.0 40.0
5.80% 2014 77.0 77.0
Capitalized leases 11.3 7.5
Other long-term debt 146.5 147.4
PanEnergy
Bonds:
7 3/4% 2022 328.0 328.0
Swiss Franc 1996 -- 86.7
8 5/8% Debentures 2025 100.0 100.0
Notes:
Medium term, Series A, 8.5-9% 1996-1997 114.5 139.0
9.55% 1996-1999 41.3 55.0
23
8 5/8% 1999 100.0 100.0
9.9% 2000-2003 45.0 45.0
7 3/8% 2003 100.0 --
9% convertible 1997-2004 10.0 10.0
7 1/4% 2005 100.0 100.0
7% 2006 150.0 --
TETCO
Debentures:
10 1/8% 2011 -- 100.0
10% 2011 -- 150.0
Notes:
10 3/8% 2000 200.0 200.0
10% 2001 100.0 100.0
8% 2002 100.0 100.0
8 1/4% 2004 100.0 100.0
Medium term, Series A, 7.64-9.07% 1999-2012 100.0 100.0
Algonquin
Notes:
8.795-8.936% 1996 -- 50.0
9.13% 2001-2003 100.0 100.0
PEPL
Notes:
7 7/8% 2004 100.0 100.0
Debentures:
7.95% 2023 100.0 100.0
7.2% 2024 100.0 100.0
PanEnergy Natural Gas
6.3% Notes 1999-2003 -- 40.0
Panhandle Gathering Company
4% Notes 1996 -- 4.5
Other -- .1
Crescent Resources, Inc. (b) 118.0 130.7
----------------------------
Nantahala Power and Light Company 68.4 33.3
---------------------------------
Unamortized debt discount and premium, net (60.5) (98.8)
------ ------
Total long-term debt 5,835.7 5,994.7
Current maturities of long-term debt (350.6) (191.7)
------- -------
Total long-term portion $5,485.1 $5,803.0
======== ========
(a) Substantially all of Duke Power's electric plant was mortgaged as of
December 31, 1996.
(b) Substantial amounts of Crescent Resources, Inc.'s real estate development
projects, land and buildings are pledged as collateral.
As of December 31, 1996 and 1995, the Company had $40 million in pollution
control revenue bonds backed by an unused, two-year revolving credit facility of
$40 million. In addition, the Company had $130 million in commercial paper
outstanding throughout 1996 and 1995 backed by unused five-year revolving credit
facilities. These facilities are on a fee basis. Both the $40 million in
pollution control bonds and the $130 million in commercial paper are included in
long-term debt.
As of December 31, 1996, Crescent Resources, Inc. had $45.4 million in mortgage
loans which mature through 1999 and $30.6 million in mortgage loans maturing in
2000 or thereafter. Additionally, Crescent Resources, Inc. had $42 million
outstanding at December 31, 1996, included in long-term debt on a $75 million
four-year revolving credit facility. Interest rates are variable
24
and at December 31, 1996, ranged from 5.95 percent to 7.10 percent. As of
December 31, 1996, Nantahala Power and Light Company had $68 million in senior
notes maturing in 2011, 2012 and 2016. The notes carry fixed interest rates of
9.21 percent, 7.45 percent and 6.90 percent and require monthly payments of
principal beginning in 1997, 1998 and 2002, respectively.
PanEnergy's 9% convertible notes entitle the holders, at their option, to
convert the notes into 451,875 shares of PanEnergy common stock. This conversion
right contains various anti-dilutive provisions, including a provision to adjust
the conversion rate if PanEnergy sells shares at a price less than the current
market price.
The annual maturities of consolidated long-term debt, including capitalized
lease principal payments through 2001 were as follows (dollars in millions):
1997 $350.6
1998 76.6
1999 607.5
2000 459.6
2001 315.0
On October 1, 1996, TETCO redeemed its $150 million, 10% debentures due 2001 and
its $100 million, 10 1/8% debentures also due 2011. TETCO recorded a non-cash
extraordinary charge of $16.7 million (net of income tax of $10.3 million)
related to the unamortized discount on this early retirement of debt. Earnings
per common share for 1996 were reduced $0.05 as a result of this charge.
The Company has authority to issue up to $1 billion aggregate principal amount
of debt securities under a shelf registration statement filed with the
Securities and Exchange Commission (SEC). Such debt securities may be issued as
First and Refunding Mortgage Bonds, Senior Notes or Subordinated Debentures.
PanEnergy, TETCO and PEPL have effective shelf registration statements with the
SEC for the issuance of $50 million, $100 million and $100 million,
respectively, of unsecured debt securities.
NOTE 12. STOCK BASED COMPENSATION
Stock Options and Awards
Effective with the merger, each share of PanEnergy common stock outstanding
immediately prior to the merger was converted into the right to receive 1.0444
shares of the Company's common stock. Each option to purchase PanEnergy common
stock that was outstanding prior to the merger was assumed by the Company and
will be exercisable upon the same terms as under the applicable PanEnergy stock
option plan and option agreement, except that such option will become an option
to purchase the Company's common stock, appropriately adjusted. Each award of
restricted PanEnergy common stock outstanding and not vested prior to the merger
was assumed by the Company and such shares of restricted PanEnergy common stock
will be exchanged for shares of the Company's restricted common stock.
Under the PanEnergy 1994 Long Term Incentive Plan stock options and awards for
up to three million shares of common stock may be granted to employees. Under
the 1989 Nonemployee Directors Stock Option Plan the company may grant options
for up to 200,000 shares to members of the Board of Directors. Under each plan,
the exercise price of each option granted equals the market price of the
Company's common stock on the date of grant. Vesting periods range from one to
five years with a maximum term of 10 years.
In 1996, the Company granted 150,471 performance-based stock awards and 78,330
fixed stock awards with an average grant date fair value of $28 per share. The
Company recognized compensation expense of $8.3 million in 1996 and none in 1995
for stock options and stock awards.
25
A summary of the Company's stock option grants follows:
Options Average
(000's) Exercise Price
-----------------------------------------
Outstanding at Dec. 31, 1993 1,839 $18
Granted 351 23
Exercised (63) 15
Expired (34) 23
Converted * 1,644 12
-----
Outstanding at Dec. 31, 1994 3,737 16
Granted 959 20
Exercised (1,075) 13
Expired (62) 22
----
Outstanding at Dec. 31, 1995 3,559 18
Granted 498 28
Exercised (712) 16
Expired (71) 22
----
Outstanding at Dec. 31, 1996 3,274 20
=====
*Represents conversion of stock options outstanding of Associated Natural Gas
Corporation into equivalent PanEnergy and subsequently Duke Energy options.
The Company had 2,990 options and 2,394 options exercisable at December 31, 1994
and 1995, with average exercise prices of $15 and $16 per option, respectively.
Details of stock options outstanding and options exercisable at December 31,
1996 follows:
Outstanding Exercisable
Range of Average Average Average
Exercise Number Remaining Exercise Number Exercise
Prices (000's) Life (Years) Price (000's) Price
------------------------------------------------------------------------
$10 to $13 266 4.5 $11 266 $11
$15 to $20 784 5.6 17 784 17
$21 to $25 1,705 7.3 22 1,117 22
$26 to $28 392 8.9 28 9 26
$31 to $32 127 7.8 32 20 31
----------- -----------
Total 3,274 2,196 19
=========== ===========
Fair Value Information
The weighted-average fair value of options granted during 1994 and 1995 was $7
per option each year, and $9 per option during 1996. The fair value of each
option grant is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted-average assumptions used for
1995 and 1996 grants: stock dividend yield of 2.6%; expected stock price
volatility of 26%; 1994 Plan risk-free interest rates of 7.7% and 5.7 % for 1995
and 1996, respectively; 1989 Plan risk-free interest rates of 6.9% and 6.8% for
1995 and 1996, respectively; and expected option lives of seven years. Had
compensation expense for stock-based compensation been determined based on the
fair value at the grant dates, the Company's 1996 net income would have been
$1,073.7 million, or $2.85 per share, and 1995 net income would have been
$1,016.9 million, or $2.68 per share.
26
NOTE 13. PREFERRED AND PREFERENCE STOCK
The following shares of stock were authorized with or without sinking fund
requirements as of December 31, 1996 and 1995:
Par Shares
Value (in millions)
-------- -------------
Preferred Stock $100 12.5
Preferred Stock A $ 25 10.0
Preference Stock $100 1.5
As of December 31, 1996 and 1995, there were no shares of preference stock
outstanding.
Preferred stock without sinking fund requirements as of December 31, 1996 and
1995, was as follows (dollars in millions):
Year Shares
Rate/Series Issued Outstanding 1996 1995
--------------------------- ---------- -------------- ----------- -----------
4.50% C 1964 350,000 $35.0 $35.0
5.72% D 1966 350,000 35.0 35.0
6.72% E 1968 350,000 35.0 35.0
7.85% S 1992 600,000 60.0 60.0
7.00% W 1993 500,000 50.0 50.0
7.04% Y 1993 600,000 60.0 60.0
7.72% (Preferred Stock A) 1992 1,600,000 40.0 40.0
6.375% (Preferred Stock A) 1993 2,400,000 60.0 60.0
Auction Series A 1990 750,000 75.0 75.0
------ ------
Total $450.0 $450.0
====== ======
Preferred stock with sinking fund requirements as of December 31, 1996 and 1995,
was as follows (dollars in millions):
Year Shares
Rate/Series Issued Outstanding 1996 1995
--------------------------- ---------- -------------- ----------- -----------
5.95% B (Preferred Stock A) 1992 800,000 $20.0 $20.0
6.10% C (Preferred Stock A) 1992 800,000 20.0 20.0
6.20% D (Preferred Stock A) 1992 800,000 20.0 20.0
7.50% R 1992 850,000 85.0 85.0
6.20% T 1992 130,000 13.0 13.0
6.30% U 1992 130,000 13.0 13.0
6.40% V 1992 130,000 13.0 13.0
6.75% X 1993 500,000 50.0 50.0
------ ------
Total $234.0 $234.0
====== ======
The annual sinking fund requirements through 2001 are $0 in 1997, $4.3 million
in 1998, $24.3 million in 1999, $37.3 million in 2000 and $37.3 million in 2001.
Some additional redemptions are permitted at the Company's option.
The call provisions for the outstanding preferred stock specify various
redemption prices not exceeding 108 percent of par value, plus accumulated
dividends to the redemption date.
NOTE 14. NUCLEAR DECOMMISSIONING COSTS
Estimated site-specific nuclear decommissioning costs, including the cost of
decommissioning plant components not subject to radioactive contamination, total
approximately $1.3 billion stated in 1994 dollars based on decommissioning
studies completed
27
in 1994. This amount includes the Company's 12.5 percent ownership in the
Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station
are responsible for decommissioning costs related to their ownership interests
in the station. Both the North Carolina Utilities Commission and The Public
Service Commission of South Carolina have granted the Company recovery of
estimated decommissioning costs through retail rates over the expected remaining
service periods of the Company's nuclear plants. Such estimates presume each
unit will be decommissioned as soon as possible following the end of their
license life. Although subject to extension, the current operating licenses for
the Company's nuclear units expire as follows: Oconee 1 and 2 - 2013, Oconee 3 -
2014; McGuire 1 - 2021, McGuire 2 - 2023; and Catawba 1 - 2024, Catawba 2 -
2026.
In accordance with a 1988 Nuclear Regulatory Commission order, during 1996, the
Company expensed approximately $56.5 million which was contributed to the
external funds for decommissioning costs and accrued an additional $1.6 million
to the internal reserve. Nuclear units are depreciated at a rate of 4.70
percent, of which 1.61 percent is for decommissioning. The balance of the
external funds as of December 31, 1996, was $362.6 million. The balance of the
internal reserve as of December 31, 1996, was $207.8 million and is reflected in
accumulated depreciation and amortization on the Consolidated Balance Sheets.
Management's opinion is that the decommissioning costs being recovered through
rates, when coupled with assumed after-tax fund earnings of 5.5 percent to 5.9
percent, are currently sufficient to provide for the cost of decommissioning.
NOTE 15. COMMITMENTS AND CONTINGENCIES
Environmental
TETCO is currently conducting PCB (polychlorinated biphenyl) assessment and
cleanup programs at certain of its compressor station sites under conditions
stipulated by a U.S. Consent Decree. The programs include on- and off-site
assessment, installation of on-site source control equipment and groundwater
monitoring wells, and on- and off-site cleanup work. TETCO expects to complete
these cleanup programs during 1997. Groundwater monitoring activities will
continue beyond 1997.
In 1987, the Commonwealth of Kentucky instituted a suit in state court against
TETCO, alleging improper disposal of PCBs at TETCO's three compressor station
sites in Kentucky. This suit, which is still pending, seeks penalties for
violations of Kentucky environmental statutes. The Company previously
established a reserve for potential fines and penalties. In 1996, TETCO
completed cleanup of these sites.
The Company has also identified environmental contamination at certain sites on
the PEPL and Trunkline systems and is undertaking cleanup programs at these
sites. The contamination resulted from the past use of lubricants containing
PCBs and the prior use of wastewater collection facilities and other on-site
disposal areas. Soil and sediment testing, to date, has detected no significant
off-site contamination. The Company has communicated with the Environmental
Protection Agency and appropriate state regulatory agencies on these matters.
Environmental cleanup programs are expected to continue until 2002.
At December 31, 1996 and 1995, the Company had accrued liabilities for remaining
estimated cleanup costs on the TETCO, PEPL and Trunkline systems. These cost
estimates represent gross cleanup costs expected to be incurred, have not been
discounted or reduced by customer recoveries and do not include fines, penalties
or third-party claims. Estimated liabilities for remaining TETCO PCB cleanup
costs were reduced $77.6 million in the fourth quarter 1995 as a result of
lower-than-projected cleanup costs incurred on completed sites. As a result of
the reduction in estimated cleanup costs, TETCO's share of the cleanup estimate
was lowered, which decreased operating expenses by $33 million ($21.5 million
after tax) and reduced related regulatory assets by $44.6 million. At December
31, 1996 and 1995, the Company had regulatory assets recorded representing costs
to be recovered from customers.
The federal and state cleanup programs are not expected to interrupt or diminish
the Company's ability to deliver natural gas to customers. The Company believes
the resolution of matters relating to the environmental issues discussed above
will not have a material adverse effect on consolidated results of operations or
financial position.
Litigation
In December 1996, TETCO received notification that Marathon Oil Company
(Marathon) intended to commence substitution of other gas reserves,
deliverability and leases for those dedicated to a certain natural gas purchase
contract (the Contract) with TETCO. In TETCO's view, the tendered substitute gas
reserves, deliverability and leases are not subject to the Contract and TETCO
filed a declaratory judgment action seeking a ruling that Marathon's
interpretation of the Contract is incorrect. Marathon filed a counterclaim
seeking a declaratory judgment enforcing its interpretation of the Contract. The
potential liability of the Company should TETCO be contractually obligated to
purchase natural gas based upon the substitute gas reserves,
28
deliverability and leases, and the effect on transition cost recoveries pursuant
to TETCO's Order 636 settlement involve numerous complex legal and factual
matters which will take a substantial period of time to resolve. While this
matter is in the early stages of litigation, based on information currently
available to the Company, Management believes the resolution of this matter will
not have a material adverse effect on financial position of the Company.
In connection with a rupture and fire that occurred on TETCO's natural gas
pipeline in 1994 in Edison, New Jersey, claims have been made and numerous
lawsuits have been filed against TETCO and other private and governmental
entities by or on behalf of hundreds of individuals and businesses. These
claimants seek compensatory damages for personal injuries, property losses
and/or lost business income, as well as punitive damages. The claimants include
Quality Materials, Inc. (Quality), the owner of the asphalt plant where the
rupture occurred. TETCO has filed a counterclaim against Quality and has settled
the claims of some individuals and businesses while retaining the right to seek
recovery of those settlement amounts from other defendants. The findings of an
investigation of the incident by the National Transportation Safety Board
indicate third-party damage to be the cause of the rupture. The Company recorded
a provision in 1994 for costs related to this incident that are not recoverable
under the Company's insurance policies. Management is of the opinion that the
final disposition of these proceedings will not have a material adverse effect
on the results of operations or financial position of the Company.
The Company and North Carolina Municipal Power Agency Number 1 and Piedmont
Municipal Power Agency, two of the four other joint owners of the Catawba
Nuclear Station, entered into a settlement in September 1995 which resolved
outstanding issues related to how certain calculations affecting bills under the
Catawba joint ownership contractual agreements should be performed. The
settlement was approved by the North Carolina Utilities Commission on January
16, 1996 and The Public Service Commission of South Carolina on January 23,
1996. As part of the settlement, the Company agreed to purchase additional
megawatts (MW) of Catawba capacity during the period 1996 through 1999 and
remove certain restrictions related to sales of surplus energy by these two
joint owners. The additional capacity purchases are 215 MW in 1996, 165 MW in
1997, 120 MW in 1998 and 100 MW in 1999. The Company expects to recover the
costs associated with this settlement as part of the purchased capacity
levelization, consistent with prior orders of the retail regulatory commissions.
Therefore, the Company believes these matters should not have a material adverse
effect on the results of operations or the financial position of the Company.
The Company and all four of the other joint owners of the Catawba Nuclear
Station entered into settlement agreements in 1994 which resolved all issues in
contention in arbitration proceedings related to the Catawba joint ownership
contractual agreements. The basic contention in each proceeding was that certain
calculations affecting bills under these agreements should be performed
differently. These items are covered by the agreements between the Company and
the other Catawba joint owners which have been previously approved by the
Company's retail regulatory commissions. (For additional information, see Note
5.) In 1994, the Company settled its cumulative net obligation through 1993 of
approximately $205 million related to these settlement agreements. Billings for
1994 and later years will conform to the settlement agreements, which have been
approved by the Company's retail regulatory commissions. Because the Company
expects the costs associated with these settlements to be recovered as part of
the purchased capacity levelization, which has been approved by the Company's
retail regulatory commissions, the Company included approximately $205 million
as an increase to "Purchased capacity costs" on its Consolidated Balance Sheets
in 1994. Therefore, the Company believes these matters should not have a
material adverse effect on the results of operations or financial position of
the Company.
The Company is also involved in legal, tax and regulatory proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business, some of which involve
substantial amounts. Where appropriate, the Company has made accruals in
accordance with Statement of Financial Accounting Standards No. 5, "Accounting
for Contingencies," in order to provide for such matters. Management is of the
opinion that the final disposition of these proceedings will not have a material
adverse effect on the results of operations or financial position of the
Company.
Nuclear Insurance
The Company maintains nuclear insurance coverage in three areas: liability
coverage, property, decontamination and decommissioning coverage, and extended
accidental outage coverage to cover increased generating costs and/or
replacement power purchases. The Company is being reimbursed by the other joint
owners of the Catawba Nuclear Station for certain expenses associated with
nuclear insurance premiums paid by the Company.
Pursuant to the Price-Anderson Act, the Company is required to insure against
public liability claims resulting from nuclear incidents to the full limit of
liability of approximately $8.9 billion. The maximum required private primary
insurance of $200 million has been purchased along with a like amount to cover
certain worker tort claims. The remaining amount, currently $8.7 billion, which
will be increased by $79.3 million as each additional commercial nuclear reactor
is licensed, has been provided through a mandatory industry-wide excess
secondary insurance program of risk pooling. The $8.7 billion could also be
reduced by $79.3 million for certain nuclear reactors that are no longer
operational and may be exempted from the risk pooling insurance
29
program. Under this program, licensees could be assessed retrospective premiums
to compensate for damages in the event of a nuclear incident at any licensed
facility in the nation. If such an incident occurs and public liability damages
exceed primary insurances, licensees may be assessed up to $79.3 million for
each of their licensed reactors, payable at a rate not to exceed $10 million a
year per licensed reactor for each incident. The $79.3 million amount is subject
to indexing for inflation and may be subject to state premium taxes. The $79.3
million includes a surcharge of 5 percent (which is also included in the above
$8.7 billion figure) if funds are insufficient to pay claims and associated
costs. If retrospective premiums were to be assessed, the other joint owners of
the Catawba Nuclear Station are obligated to assume their pro rata share of such
assessment.
The Company is a member of Nuclear Mutual Limited (NML), which provides $500
million in primary property damage coverage for each of the Company's nuclear
facilities. If NML's losses ever exceed its reserves, the Company will be
liable, on a pro rata basis, for additional assessments of up to $34 million.
This amount represents 5 times the Company's annual premium to NML. The other
joint owners of Catawba are obligated to assume their pro rata share of any
liability for retrospective premiums and other premium assessments resulting
from the NML policies applicable to Catawba.
The Company is also a member of Nuclear Electric Insurance Limited (NEIL) and
purchases insurance through NEIL's excess property, decontamination and
decommissioning liability insurance program. NEIL provides excess insurance
coverage of $2.25 billion for the Catawba Nuclear Station and $1.5 billion for
each of the Oconee and McGuire Nuclear Stations. If losses ever exceed the
accumulated funds available to NEIL for the excess property, decontamination and
decommissioning liability program, the Company will be liable, on a pro rata
basis, for additional assessments of up to $40 million. This amount is limited
to 5 times the Company's annual premium to NEIL for excess property,
decontamination and decommissioning liability insurance. The other joint owners
of Catawba are obligated to assume their pro rata share of any liability for
retrospective premiums and other premium assessments resulting from the NEIL
policies applicable to Catawba.
The Company participates in a NEIL program that provides insurance for the
increased cost of generation and/or purchased power resulting from an accidental
outage of a nuclear unit. Each unit of the McGuire and Catawba Nuclear Stations
is insured for up to approximately $3.5 million per week, after a 21-week
deductible period, with declining amounts per unit where more than one unit is
involved in an accidental outage. The Oconee Nuclear Station units are insured
for up to approximately $2.7 million, under like terms. Coverages continue at
100 percent for 52 weeks and 80 percent for the next 104 weeks. If NEIL's losses
for this program ever exceed its reserves, the Company will be liable, on a pro
rata basis, for additional assessments of up to $27 million. This amount
represents 5 times the Company's annual premium to NEIL for insurance for the
increased cost of generation and/or purchased power resulting from an accidental
outage of a nuclear unit. The other joint owners of Catawba are obligated to
assume their pro rata share of any liability for retrospective premiums and
other premium assessments resulting from the NEIL policies applicable to the
joint ownership agreements.
Future Construction Costs
Projected construction and nuclear fuel costs for the Company's electric
operations, both including allowance for funds used during construction, are
$591.8 million and $133.5 million, respectively, for 1997. These projections are
subject to periodic review and revisions. Actual construction and nuclear fuel
costs incurred may vary from such estimates. Cost variances are due to various
factors, including revised load estimates, environmental matters and cost and
availability of capital.
Projected capital and investment expenditures of the natural gas transmission
operations, energy services and parent and other operations are $300 million,
$206.3 million, and $189 million, respectively for 1997. These projections are
subject to periodic review and revisions and actual expenditures may vary
significantly as business plans evolve to meet the opportunities presented by
their markets.
Other Commitments and Contingencies
The Company has a 10% ownership interest in TEPPCO Partners, L.P., a master
limited partnership (MLP) that owns and operates a petroleum products pipeline.
A subsidiary partnership of the MLP had $339.5 million in First Mortgage Notes
outstanding at December 31, 1996 with recourse to the general partner, a
subsidiary of the Company.
In the normal course of business, certain of the Company's affiliates enter into
various contracts, including agreements to buy and sell natural gas or electric
power; futures, swaps and options; and construction contracts, which contain
certain schedule and performance requirements. Such affiliates use risk
management techniques to mitigate their exposure associated with such contracts.
Certain subsidiaries of the Company have guaranteed performance by such
affiliates under some of these contracts.
Management is of the opinion that these commitments and contingencies will not
have a material adverse effect on the results of operations or the financial
position of the Company.
30
NOTE 16. BENEFIT PLANS
RETIREMENT PLANS
The Company and its subsidiaries have defined benefit retirement plans covering
most employees with minimum service requirements. The PanEnergy plan provides
retirement benefits (i) for eligible employees of certain subsidiaries that are
generally based on an employee's years of benefit accrual service and highest
average eligible earnings, and (ii) for eligible employees of certain other
subsidiaries under a cash balance formula. A cash balance plan participant
accumulates a benefit based upon a percentage of current salary, which may vary
with age and years of service, and interest credits. Through December 31, 1996,
the Duke Power retirement plan benefits were based on an age-related formula
which took into account years of benefit accrual service and the employee's
highest average eligible earnings. Effective January 1, 1997, the Duke Power
retirement plan was amended from a plan under which benefits were based upon a
final average pay formula to a plan under which benefits are based upon a cash
balance formula. The Company's policy is to fund amounts, as necessary, on an
actuarial basis to provide assets sufficient to meet benefits to be paid to plan
members.
Net periodic pension cost for the years ended December 31, 1996, 1995 and 1994,
include the following components (dollars in millions):
1996 1995 1994
------------- -------------- ------------
Actual return on plan assets $ (302.6) $ (413.1) $ (4.0)
Amount deferred for recognition 110.4 237.4 (154.4)
------------- -------------- ------------
Expected return on plan assets (192.2) (175.7) (158.4)
Service cost benefit earned during the year 62.7 57.8 55.5
Interest cost on projected benefit obligation 152.8 147.9 132.3
Net amortization 6.4 3.3 4.7
------------- ------------- ------------
Net periodic pension cost $ 29.7 $ 33.3 $ 34.1
============= ============== ============
A reconciliation of the funded status of the plans to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows
(dollars in millions):
1996 1995
-------------- -------------
Accumulated benefit obligation:
Vested benefits $ (1,814.9) $ (1,652.6)
Nonvested benefits (26.7) (23.8)
------------- ------------
Accumulated benefit obligation $ (1,841.6) $ (1,676.4)
============== =============
Fair market value of plan assets* $ 2,445.3 $ 2,214.1
Projected benefit obligation (2,126.4) (2,084.9)
Unrecognized net experience loss 123.1 263.8
Unrecognized prior service cost reduction (45.1) (12.8)
Unrecognized net asset (36.3) (40.9)
------------- -------------
Pre-funded pension cost $ 360.6 $ 339.3
============== =============
* Principally equity and fixed income securities
Assumptions used in the Company's pension accounting (reflecting
weighted-averages across all plans) include:
1996 1995 1994
--------- --------- ---------
Discount rate 7.50% 7.50% 8.31%
Salary increase 4.80% 4.81% 5.30%
Expected long-term rate of return on plan assets 9.18% 9.18% 9.18%
31
During 1995, the Company offered to certain employees an Enhanced Vested
Benefits program (EVB). The Company recorded an additional one-time expense for
special termination benefits associated with EVB of approximately $42.2 million,
including $21.6 million of additional retirement plan costs.
OTHER POSTRETIREMENT BENEFITS
The Company and most of its subsidiaries provide certain health care and life
insurance benefits for retired employees on a contributory and noncontributory
basis. Employees become eligible for these benefits if they have met certain age
and service requirements at retirement, as defined in the plans.
The Company accrues such benefit costs over the active service period of
employees to the date of full eligibility for the benefits. The net unrecognized
transition obligation, resulting from the implementation of accrual accounting,
is being amortized over approximately 20 years.
The Company is using an investment account under section 401(h) of the Internal
Revenue Code, a retired lives reserve (RLR) and multiple voluntary employees'
beneficiary association (VEBA) trusts under section 501(c)(9) of the Internal
Revenue Code to fund postretirement benefits. These vehicles partially fund the
Company's postretirement health care benefits. The Company uses the RLR, which
has tax attributes similar to 401(h) funding, to partially fund its
postretirement life insurance obligations. Certain subsidiaries use the VEBA
trusts to fund accrued postretirement health care benefits. The same
subsidiaries also use the VEBA trusts to fully fund retiree life insurance
obligations based on actuarially-determined requirements.
Net periodic postretirement benefit cost for the years ended December 31, 1996,
1995 and 1994, include the following components (dollars in millions):
1996 1995 1994
------------ -------------- ------------
Actual return on plan assets $ (20.5) $ (29.6) $ (1.7)
Amount deferred for recognition 4.2 16.2 (8.8)
------------ -------------- ------------
Expected return on plan assets (16.3) (13.4) (10.5)
Service cost benefit earned during the year 8.4 7.6 7.6
Interest cost on accumulated postretirement
benefit obligation 43.3 43.5 40.9
Net amortization and deferral 19.3 16.5 16.6
----------- ------------- -----------
Net periodic postretirement benefit cost $ 54.7 $ 54.2 $ 54.6
============ ============== ============
A reconciliation of the funded status of the plans to the amounts recognized in
the Consolidated Balance Sheets as of December 31, 1996 and 1995, is as follows
(dollars in millions):
1996 1995
-------------- -------------
Accumulated postretirement benefit obligation:
Retirees $ (440.5) $ (436.6)
Fully eligible active plan participants (42.6) (28.3)
Other active plan participants (158.6) (134.6)
-------------- -------------
Accumulated post retirement benefit obligation (641.7) (599.5)
Fair market value of plan assets* 225.3 191.9
Unrecognized prior service cost 66.7 .7
Unrecognized net experience loss 27.0 52.7
Unrecognized transitional obligation 273.0 314.1
------------- ------------
Accrued postretirement benefit $ (49.7) $ (40.1)
============== =============
* Principally equity and fixed income securities
32
Assumptions used in the Company's postretirement benefits accounting (reflecting
weighted-averages across all plans) include:
1996 1995 1994
---------- --------- -----------
Discount rate 7.50% 7.50% 8.34%
Salary increase 4.84% 4.84% 5.25%
Expected long-term rate of return on 401(h) assets 9.00% 9.00% 9.00%
Expected long-term rate of return on RLR assets 6.50% 8.00% 6.50%
Expected long-term rate of return on VEBA assets 9.50% 9.50% 9.50%
Assumed tax rate* 39.60% 39.60% 39.60%
* Health care portion of postretirement benefits in VEBA trusts
The weighted-average health care trend rate used to value the different benefits
was 8.59% in 1996. This rate is expected to decrease, with a 5.5% ultimate trend
rate expected to be achieved by 2001. The effect of a 1% increase in the health
care trend rates for each future year is $3.6 million on the annual aggregate
service and interest cost and $42.9 million on the accumulated postretirement
benefit obligation at December 31, 1996.
NOTE 17. COMMON STOCK
On February 27, 1996, the Board of Directors authorized the Company to
repurchase up to $1 billion of its common stock over the next five years. As of
December 31, 1996, approximately 3.3 million shares had been repurchased for
$159 million. On January 28, 1997, the Board of Directors amended the program to
expressly limit the number of shares authorized for repurchase under the
program, from the initiation of the program through a date two years after the
consummation of the merger with PanEnergy Corp, to an amount not to exceed 15
million shares.
33
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of Duke Energy Corporation
Charlotte, North Carolina
We have audited the consolidated balance sheets of Duke Energy Corporation and
subsidiaries (the Company) as of December 31, 1996 and 1995, and the related
consolidated statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 1996. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements based on our
audits. The consolidated financial statements give retroactive effect to the
merger of Duke Power Company and PanEnergy Corp, which has been accounted for as
a pooling of interests as described in Note 1 to the consolidated financial
statements. We did not audit the balance sheet of PanEnergy Corp and
subsidiaries as of December 31, 1996 and 1995, or the related statements of
income, common stockholders' equity, and cash flows of PanEnergy Corp and
subsidiaries for each of the three years in the period ended December 31, 1996,
which statements reflect total assets of (in millions) $8,567.8 and $7,627.3 as
of December 31, 1996 and 1995, respectively, and total operating revenues of (in
millions), $7,536.8, $4,967.5 and $4,585.1 for the years ended December 31,
1996, 1995 and 1994, respectively. Those statements were audited by other
auditors whose report has been furnished to us, and our opinion, insofar as it
relates to the amounts included for PanEnergy Corp and subsidiaries for 1996,
1995 and 1994, is based solely on the report of such other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the financial position of the Company as of December 31, 1996
and 1995, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1996 in conformity with generally
accepted accounting principles.
December 3, 1997
Deloitte & Touche LLP
Charlotte, North Carolina