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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-3591
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TEXAS UTILITIES COMPANY
(Exact name of registrant as specified in its charter)
A Texas I.R.S. Employer
Corporation No. 75-0705930
Energy Plaza, 1601 Bryan Street, Dallas, Texas 75201
(Formerly 2001 Bryan Tower, Dallas, Texas 75201)
Telephone Number (214) 812-4600
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Securities Registered Pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
------------------- ------------------------
Common Stock, without par value New York Stock Exchange, Inc.
The Chicago Stock Exchange,
Incorporated The Pacific Stock
Exchange Incorporated
Securities Registered Pursuant to Section 12(g) of the Act: None
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
---------------
Aggregate market value of Common Stock held by non-affiliates, based on the
last reported sale price on the composite tape on February 28, 1995:
$7,396,293,962
Common Stock outstanding at February 28, 1995: 225,841,037 shares, without
par value
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement pursuant to Regulation 14A,
which will be mailed to the Commission for filing on or about April 1, 1995, are
incorporated by reference into Part III of this report.
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<PAGE>
TABLE OF CONTENTS
ITEM DESCRIPTION PAGE
- ---- ----------- ----
PART I
<TABLE>
<CAPTION>
<C> <S> <C>
1 Business............................................................... 1
The Company and Its Subsidiaries.................................... 1
Peak Load and Capability............................................ 2
Fuel Supply and Purchased Power..................................... 3
Regulation and Rates................................................ 7
Competition......................................................... 10
Environmental Matters............................................... 12
2 Properties............................................................. 14
Capital Expenditures................................................ 15
The TU Electric and SESCO Systems................................... 17
3 Legal Proceedings...................................................... 18
4 Submission of Matters to a Vote of Security Holders.................... 19
Executive Officers of the Registrant................................... 19
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters.. 20
6 Selected Financial Data................................................ 21
Consolidated Financial Statistics................................... 21
Consolidated Operating Statistics................................... 22
7 Management's Discussion and Analysis of Financial Condition and
Results of Operation................................................ 23
8 Financial Statements and Supplementary Data............................ 28
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................................ 58
PART III
10 Directors and Executive Officers of the Registrant..................... 58
11 Executive Compensation................................................. 58
12 Security Ownership of Certain Beneficial Owners and Management......... 58
13 Certain Relationships and Related Transactions......................... 58
PART IV
14 Exhibits, Financial Statement Schedules and Reports on Form 8-K........ 59
</TABLE>
<PAGE>
PART I
ITEM 1. BUSINESS
THE COMPANY AND ITS SUBSIDIARIES
Texas Utilities Company (Company) was incorporated under the laws of the State
of Texas in 1945 and has perpetual existence under the provisions of the Texas
Business Corporation Act. The Company is a holding company which owns all of
the outstanding common stock of Texas Utilities Electric Company (TU Electric),
which is the principal subsidiary of the Company, Southwestern Electric Service
Company (SESCO) and six other wholly-owned subsidiaries which perform
specialized functions within the Texas Utilities Company system. The Company
and its subsidiaries are referred to herein as "System Companies".
The Company holds no franchises other than its corporate franchise. TU
Electric and SESCO possess all of the necessary franchises and certificates
required to enable them to conduct their respective businesses (see Regulation
and Rates).
TU Electric is engaged in the generation, purchase, transmission, distribution
and sale of electric energy in the north central, eastern and western parts of
Texas, with a population estimated at 5,730,000 - about one-third of the
population of Texas. Electric service is provided in 91 counties and 372
incorporated municipalities, including Dallas, Fort Worth, Arlington, Irving,
Plano, Waco, Mesquite, Grand Prairie, Wichita Falls, Odessa, Midland,
Carrollton, Tyler, Richardson and Killeen. The area is a diversified commercial
and industrial center with substantial banking, insurance, communications,
electronics, aerospace, petrochemical and specialized steel manufacturing, and
automotive and aircraft assembly. The territory served includes major portions
of the oil and gas fields in the Permian Basin and East Texas, as well as
substantial farming and ranching sections of the State. It also includes the
Dallas-Fort Worth International Airport and the Alliance Airport.
SESCO is engaged in the purchase, transmission, distribution and sale of
electric energy in ten counties in the eastern and central parts of Texas with a
population estimated at 125,000. SESCO generates no electric energy.
For consolidated energy sales and operating revenues contributed by TU
Electric and SESCO for each customer classification, see Item 6. Selected
Financial Data - Consolidated Operating Statistics.
Texas Utilities Fuel Company (Fuel Company) owns a natural gas pipeline
system, acquires, stores and delivers fuel gas and provides other fuel services
at cost for the generation of electric energy by TU Electric.
Texas Utilities Mining Company (Mining Company) owns, leases and operates fuel
production facilities for the surface mining and recovery of lignite at cost for
the generation of electric energy by TU Electric.
Texas Utilities Services Inc. (TU Services) provides financial, accounting,
information technology, personnel, procurement and other administrative services
at cost to the System Companies. TU Services also acts as transfer agent,
registrar and dividend paying agent with respect to the common stock of the
Company and the preferred stock of TU Electric and as agent for participants
under the Company's Automatic Dividend Reinvestment and Common Stock Purchase
Plan.
In May 1994, Texas Utilities Properties Inc. (TU Properties), a new wholly-
owned subsidiary of the Company, was incorporated under the laws of the State of
Texas. The principal function of TU Properties is to own, lease and manage real
and personal properties, primarily for System Companies.
Basic Resources Inc. was organized for the purpose of developing natural
resources, primarily energy sources, and related technology and services.
1
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
THE COMPANY AND ITS SUBSIDIARIES -- (CONCLUDED)
Chaco Energy Company (Chaco) was organized to own and operate facilities for
the acquisition, production, sale and delivery of coal and other fuels and
currently leases extensive coal reserves.
At December 31, 1994, the System Companies had 10,798 full-time employees.
PEAK LOAD AND CAPABILITY
TU Electric's and SESCO's net capability, peak load and reserve, in megawatts
(MW), at the time of peak were as follows during the years indicated:
<TABLE>
<CAPTION>
PEAK LOAD (a)
-----------------------
INCREASE
(DECREASE) FIRM
NET OVER PEAK
YEAR CAPABILITY AMOUNT PRIOR YEAR LOAD RESERVE(b)
- ----- ------------- ------ ---------- ---- ----------
<S> <C> <C> <C> <C> <C>
1994................... 22,493(c),(d) 18,173 (0.8)% 17,658 4,835
1993................... 21,697(d),(e) 18,324 4.6 17,852 3,845
1992................... 21,697(e) 17,525 3.4 17,102 4,595
</TABLE>
__________________
(a) The 1994 peak load occurred on August 18. TU Electric peak load includes
interruptible load at the time of peak of 656 MW in 1994, 499 MW in 1993
and 463 MW in 1992. At the time of 1994 peak load, SESCO purchased 143 MW
of firm load outside the system.
(b) Amount of net capability in excess of firm peak load at the time of peak.
(c) Included in net capability are 1,487 MW of firm purchased capacity, of
which 1,264 MW were cogeneration and small power production.
(d) In November 1993, the emissions chimney serving Unit 3 (750 MW) of the
Monticello lignite-fueled generating station (Monticello) collapsed,
rendering the unit inoperable. The unit will be rebuilt and operated as a
lignite/coal-fueled facility. TU Electric expects the unit to be returned
to service in mid-1995. Such unit is included in net capability.
(e) For 1993 and 1992, included 1,771 MW of firm purchased capacity, of which
1,691 MW were cogeneration and small power production, and excluded
Comanche Peak Unit 2 (1150 MW) which was placed into commercial service
after the 1993 peak load.
The peak load changes from 1993 to 1994 resulted primarily from milder than
normal temperatures. The peak load changes in the prior periods resulted
primarily from customer growth in the service area and weather factors. TU
Electric expects to continue to purchase capacity in the future from various
sources. (See Fuel Supply and Purchased Power and Note 11 to Consolidated
Financial Statements.)
Firm peak load increases over the next ten years are expected to average
approximately 2.0% annually, after giving effect to load management programs
(including interruptible contracts). Load management programs are designed to
improve the efficient use of the TU Electric generating units and help delay the
need to add new capacity. TU Electric periodically reviews its resource plans.
When compared to the previous resource plan, the current plan reflects a three-
year delay of the in-service date of the first 750 MW Twin Oak lignite unit and
a delay of the second 750 MW Twin Oak lignite unit beyond the ten-year planning
period (see Item 2. Properties - Capital Expenditures). In addition, the
current plan reflects a two-year acceleration in the planned in-service dates of
two 650 MW combined-cycle combustion turbines based on a phased installation
approach as compared to the previous plan.
2
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
PEAK LOAD AND CAPABILITY-- (CONCLUDED)
In October 1994, TU Electric filed an application for approval by the Public
Utility Commission of Texas (PUC) of its Integrated Resource Plan (IRP) for the
ten-year period 1995-2004. The IRP, developed as an experimental pilot project
in conjunction with regulatory and customer groups, includes initiatives that
address demand-side management resources, purchased power and future generating
capacity which includes renewable energy sources. TU Electric expects to
obtain approval of this application by mid-1995. The components of the IRP (see
Item 2. Properties - Capital Expenditures) are as follows:
<TABLE>
<CAPTION>
INTEGRATED RESOURCE PLAN
1995-2004
--------------------------
FIRM
CAPABILITY
RESOURCE ADDITIONS (MW) percent
------------------ ----------- -------
<S> <C> <C>
Combustion Turbines (a)................................................... 1,496 31%
Load Management (b)(d).................................................... 1,220 26
Purchased Power........................................................... 941 20
Lignite/Coal.............................................................. 750 16
Renewable Resources(c)(d)................................................. 340 7
----- ----
Total.................................................................. 4,747 100%
===== ====
</TABLE>
____________
(a) Excluded is 306 MW of gas-fueled backup of wind capacity included in
Renewable Resources.
(b) TU Electric has negotiated contracts with eight suppliers of demand-side
management services designed to displace a total of 72 MW by 2004.
(c) TU Electric has negotiated one purchased power contract for 4 MW of firm
wind-powered resources to be placed in service by 1997 and plans to
construct 30 MW of firm wind-powered resources.
(d) Subject to the approval by the PUC of a cost recovery mechanism.
None of the aforementioned additions requires significant construction
expenditures before 1997.
FUEL SUPPLY AND PURCHASED POWER
Net system input for 1994 was 93,868 million kilowatt-hours (kWh) of which
81,321 million kWh were generated by TU Electric. Average fuel and purchased
power cost (excluding capacity charges) per kWh of net input was 1.76 cents for
1994, 1.92 cents for 1993 and 1.85 cents for 1992. The decrease for 1994
primarily reflects the first full year of operation of Comanche Peak Unit 2. A
comparison of the resource mix for net kWh input and the unit cost per million
British thermal units (Btu) of fuel during the last three years is as follows:
<TABLE>
<CAPTION>
MIX FOR NET UNIT COST
KWH INPUT PER MILLION BTU
-------------------------- ---------------------------
1994 1993 1992 1994 1993 1992
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Fuel for Electric Generation:
Gas/Oil (a)................................. 34.2% 33.6% 34.4% $2.53 $2.81 $2.69
Lignite/Coal (b)............................ 36.9 40.2 44.2 1.04 1.10 1.05
Nuclear..................................... 15.6 12.4 8.1 0.67 0.71 (c) 0.41
----- ----- -----
Total/Weighted Average Fuel Cost............ 86.7 86.2 86.7 $1.58 $1.73 $1.65
Purchased Power................................. 13.3 13.8 13.3
----- ----- -----
Total....................................... 100.0% 100.0% 100.0%
===== ===== =====
</TABLE>
________________
(a) Fuel oil was an insignificant component of total fuel and purchased power
requirements.
(b) Lignite cost per ton to TU Electric was $13.34 in 1994, $13.98 in 1993 and
$13.19 in 1992.
(c) Unit cost per million Btu in 1993 includes avoided cost of fuel during
trial operations. The 1993 cost, excluding costs associated with Comanche
Peak Unit 2 while in trial operations, was $0.62.
3
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
FUEL SUPPLY AND PURCHASED POWER -- (CONTINUED)
GAS/OIL
Fuel gas for units at nineteen of the principal generating stations of TU
Electric, having an aggregate net gas/oil capability of 12,861 MW, was provided
during 1994 by Fuel Company. Fuel Company supplied approximately 44% of such
fuel gas requirements under contracts with producers at the wellhead and under
other contracts with dedicated reserves and 56% under contracts with commercial
suppliers. Additional gas/oil-fueled combustion turbines, with an aggregate net
capability of 1,802 MW, are planned for the future (see Peak Load and
Capability and Item 2. Properties - Capital Expenditures).
Fuel Company has acquired under contracts expiring at intervals through 2008,
with producers at the wellhead, supplies of gas which are generally expected to
be produced over a ten to fifteen year period. As gas production under contract
declines and contracts expire, new contracts are expected to be negotiated to
replenish or augment such supplies. Fuel Company has negotiated gas purchase
contracts, with terms ranging from one to twenty years, with a number of
commercial suppliers. Additionally, Fuel Company has entered into a number of
short-term gas purchase contracts with other commercial suppliers at spot market
prices; however, these contracts typically do not provide for a firm supply
obligation from the seller or a firm purchase obligation from Fuel Company. In
the past, curtailments of gas deliveries have been experienced during periods of
winter peak gas demand; however, such curtailments have been of relatively short
duration, have had a minimal impact on operations and have generally required
utilization of fuel oil and gas storage inventories to replace the gas
curtailed. During 1994, no curtailments were experienced.
Fuel Company owns and operates an intrastate natural gas pipeline system which
extends from the gas-producing area of the Permian Basin in West Texas to the
East Texas gas fields and southward to the Gulf Coast area. This system
includes a one-half interest in a 36-inch pipeline which extends 395 miles from
the Permian Basin area of West Texas to a point of termination south of the
Dallas-Fort Worth area and has a total estimated capacity of 885 million cubic
feet per day with existing compression facilities. Additionally, Fuel Company
owns a 39% undivided interest in another 36-inch pipeline connecting to this
pipeline and extending 58 miles eastward to one of Fuel Company's underground
gas storage facilities. Fuel Company also owns and operates approximately 1,650
miles of various smaller capacity lines which are used to gather and transport
natural gas from other gas-producing areas. The pipeline facilities of Fuel
Company form an integrated network through which fuel gas is gathered and
transported to certain TU Electric generating stations for use in the generation
of electric energy.
Fuel Company also owns and operates three underground gas storage facilities
with a usable capacity of 27.2 billion cubic feet with approximately 23.8
billion cubic feet of gas in inventory at December 31, 1994. Gas stored in these
facilities currently can be withdrawn for use during periods of peak demand, to
meet seasonal and other fluctuations or curtailment of deliveries by gas
suppliers. Under normal operating conditions, up to 400 million cubic feet can
be withdrawn each day for a ten-day period, with withdrawals at lower rates
thereafter.
Fuel oil is stored at all nineteen of the principally gas-fueled generating
stations. At December 31, 1994, the System Companies had fuel oil storage
capacity sufficient to accommodate approximately 6.5 million barrels of oil,
with approximately 2.3 million barrels of oil in inventory. Fuel Company has
access to an oil pipeline and owns a terminal facility to provide for more
dependable and efficient movement of oil. Generally, oil required to replenish
that oil removed from storage will be obtained through purchases in the open
market.
4
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
FUEL SUPPLY AND PURCHASED POWER -- (CONTINUED)
LIGNITE/COAL
Lignite is used as the primary fuel in two units at the Big Brown generating
station (Big Brown), three units at Monticello, three units at the Martin Lake
generating station (Martin Lake) and one unit at the Sandow generating station
(Sandow), having an aggregate net capability of 5,845 MW. One other lignite-
fueled unit, with a net capability of 750 MW, is included in the current IRP
(see Peak Load and Capability and Item 2. Properties - Capital Expenditures). TU
Electric's lignite units have been constructed adjacent to surface mined lignite
reserves. At the present time, TU Electric owns in fee or has under lease an
estimated 578 million tons of proven reserves dedicated to existing power plants
and approximately 271 million tons dedicated to planned future power plants.
Mining Company owns, leases and operates equipment to remove the overburden and
to recover lignite. One of TU Electric's lignite units, Sandow 4, is fueled from
lignite deposits owned by Alcoa, which furnishes fuel at no cost to TU Electric
for that portion of energy generated from such unit which is equal to the amount
of energy delivered to Alcoa (see Item 6. Selected Financial Data - Consolidated
Operating Statistics).
Lignite production operations at Big Brown, Monticello and Martin Lake are
accompanied by an extensive reclamation program which returns the land to
productive uses such as wildlife habitats, commercial timberland and pasture
land. Similar programs are planned for future lignite-fueled production
operations. For information concerning federal and state laws with respect to
surface mining, see Environmental Matters.
TU Electric supplemented TU Electric-owned lignite fuel at its Monticello and
Big Brown plants with western coal from the Powder River Basin (PRB) in Wyoming.
The coal was purchased and transported on an "as available, as required" basis.
Because current mine capacity in the PRB is greater than demand, ample amounts
of western coal are available at favorable prices. Fuel requirements at
Monticello were reduced as a result of the November 1993 collapse of the
emissions chimney at Unit 3. Consequently, deliveries of western coal were
discontinued and lignite mining operations at the Monticello mines were reduced.
When Unit 3 returns to service, lignite mining operations and western coal
deliveries at Monticello will resume. TU Electric is also considering the use
of western coal as a supplemental fuel at its other existing lignite-fueled
plants and as a long-term alternative fuel for existing and future units. For
information concerning applicable air quality standards, see Environmental
Matters.
Chaco has rights to sub-bituminous coal reserves totaling more than 120
million recoverable tons located in the Star Lake region of San Juan and
McKinley counties in northwest New Mexico. In 1990, Chaco entered into a
revised lease agreement with a major mineral interest owner, Hospah Coal Company
(Hospah), a subsidiary of Santa Fe Industries, Inc. (Santa Fe), estimated to
cover more than 300 million additional tons of recoverable coal in the same area
of New Mexico. Chaco and Santa Fe also entered into a separate agreement
providing for the transportation of coal mined from both of these deposits. In
1993, Santa Fe transferred the coal-related assets of Hospah to Hanson Natural
Resources Company. This transfer of assets includes the lease agreement between
Chaco and Hospah. This agreement will continue in accordance with its terms.
Because of the ample availability of western coal at favorable prices from other
mines, Chaco has delayed plans to commence mining operations, and accordingly,
is reassessing its alternatives with respect to its coal properties including
seeking other purchasers thereof. (See Note 11 to Consolidated Financial
Statements and Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation.)
5
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
FUEL SUPPLY AND PURCHASED POWER -- (CONTINUED)
NUCLEAR
TU Electric owns and operates two nuclear-fueled generating units at the
Comanche Peak nuclear generating station (Comanche Peak), each of which is
designed for a net capability of 1,150 MW. (See Peak Load and Capability.)
The nuclear fuel cycle requires the mining and milling of uranium ore to
provide uranium oxide concentrate (U/3/O/8/), the conversion of U/3/O/8/ to
uranium hexafluoride (UF/6/), the enrichment of the UF/6/ and the fabrication of
the enriched uranium into fuel assemblies. TU Electric has on hand or has
contracted for the raw materials and services it expects to need for its nuclear
units through future years as follows: uranium (2001), conversion (2003),
enrichment (2014), and fabrication (2002). Although TU Electric cannot predict
the future availability of uranium and nuclear fuel services, TU Electric does
not currently expect to have difficulty obtaining U/3/O/8/ and the services
necessary for its conversion, enrichment and fabrication into nuclear fuel for
years later than those shown above.
The National Energy Policy Act of 1992 (Energy Act) has provisions for the
recovery of a portion of the costs associated with the decommissioning and
decontamination of the gaseous diffusion plants used to enrich uranium for fuel.
These costs are being recovered in fees paid to the Department of Energy as
determined by the Secretary of Energy. The total annual assessment for all
domestic utilities is capped at $150 million per federal fiscal year assessable
for fifteen years. TU Electric's share, as established by the Department of
Energy, is estimated to be about $900,000 per year.
The Nuclear Waste Policy Act of 1982, as amended (NWPA), provides for the
development by the federal government of interim storage and permanent disposal
facilities for spent nuclear fuel and/or high level radioactive waste materials.
TU Electric is unable to predict when the federal government will be able to
provide such storage and disposal facilities. Under provisions of the NWPA,
funding for the program is provided by a one-mill per kWh fee currently levied
on electricity generated and sold from nuclear reactors, including the Comanche
Peak units. Onsite storage capability for spent fuel is sufficient to
accommodate the operation of Comanche Peak through the year 2001. TU Electric
is currently evaluating options for increasing its storage capability, subject
to approval by the Nuclear Regulatory Commission (NRC).
PURCHASED POWER
In 1994, TU Electric and SESCO purchased an aggregate of 12,547 million kWh or
approximately 13% of their energy requirements and had available 1,487 MW of
firm purchased capacity, or approximately 7% of net capability under contract at
the time of peak load. As a result of the renewable resources solicitation that
was part of the IRP, TU Electric has negotiated a 15-year contract with a
developer for the purchase of energy produced from wind turbines equivalent
to approximately 40 MW (or 4 MW purchased power at peak load) beginning in 1997.
This contract is currently under review and subject to the approval of the PUC
as part of the IRP filing. TU Electric and SESCO may also acquire purchased
power capacity in the future to accommodate a portion of system load and they
continue to investigate potential available sources. For information concerning
the IRP, see Peak Load and Capability and Note 10 to Consolidated Financial
Statements.
6
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
FUEL SUPPLY AND PURCHASED POWER -- (CONCLUDED)
GENERAL
Neither TU Electric nor SESCO is able to predict: (i) whether or not problems
may be encountered in the future in obtaining the fuel and purchased power it
will require, (ii) the effect upon its operations of any difficulty it may
experience in protecting its rights to fuel and purchased power now under
contract, or (iii) the cost of fuel and purchased power. All reasonable costs
of fuel and purchased power are generally recoverable subject to the rules of
the PUC. (See Regulation and Rates for information pertaining to the method of
recovery of purchased power and fuel costs.)
REGULATION AND RATES
REGULATION
The Company is a holding company as defined in the Public Utility Holding
Company Act of 1935. However, the Company and its subsidiary companies are
exempt from the provisions of such Act, except Section 9(a)(2) which relates to
the acquisition of securities of public utility companies.
TU Electric and SESCO do not transmit electric energy in interstate commerce
or sell electric energy at wholesale in interstate commerce, or own or operate
facilities therefor, and their facilities are not connected directly or
indirectly to other systems which are involved in such interstate activities,
except during the continuance of emergencies permitting temporary or permanent
connections or under order of the Federal Energy Regulatory Commission (FERC)
exempting TU Electric and SESCO from jurisdiction under the Federal Power Act.
In view thereof, TU Electric and SESCO believe that they are not public
utilities as defined in the Federal Power Act and have been advised by their
counsel that they are not subject to general regulation under such Act.
The PUC has original jurisdiction over electric rates and service in
unincorporated areas and those municipalities that have ceded original
jurisdiction to the PUC and has exclusive appellate jurisdiction to review the
rate and service orders and ordinances of municipalities. Generally, the Texas
Public Utility Regulatory Act (PURA) prohibits the collection of any rates or
charges (including charges for fuel) by a public utility that does not have the
prior approval of the PUC. As a result of a recent review of PURA as required
by state law (Sunset Review), certain issues, including structure and practices
of the PUC, recovery of federal income taxes through rates, flexible pricing,
and deregulation of future wholesale power generation, will be considered in the
current session of the Texas legislature.
The construction of new production facilities of TU Electric is subject to PUC
certification. In October 1994, TU Electric filed Notice of Intent (NOI)
applications with the PUC in connection with the IRP for 1,802 MW of combustion
turbines and 100 MW of renewable resources (wind turbines). An NOI is the first
step in the process leading to PUC approval for construction of utility plant.
(See Peak Load and Capability and Item 2. Properties -Capital Expenditures.)
TU Electric is subject to the jurisdiction of the NRC with respect to nuclear
power plants. NRC regulations govern the granting of licenses for the
construction and operation of nuclear power plants and subject such plants to
continuing review and regulation.
The System Companies are also subject to various other federal, state and
local regulations. (See Environmental Matters.)
7
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
REGULATION AND RATES -- (CONTINUED)
FUEL COST RECOVERY RULE
Pursuant to a PUC rule governing the recovery of fuel costs, the recovery of
TU Electric's eligible fuel costs is provided through fixed fuel factors. The
rule allows a utility's fuel factor to be revised upward or downward every six
months, according to a specified schedule. A utility is required to petition to
make either surcharges or refunds to ratepayers, together with interest based on
a twelve month average of prime commercial rates, for any material, as defined
by the PUC, cumulative under- or over-recovery of fuel costs. If the cumulative
difference of the under- or over-recovery, plus interest, is in excess of 4% of
the annual estimated fuel costs most recently approved by the PUC, it will be
deemed to be material. Accordingly, in August 1993 TU Electric petitioned the
PUC for recovery of under-collected fuel costs for the period July 1992 through
June 1993. The PUC approved recovery of $147.5 million of such costs, including
interest through August 1994. This recovery was applied to mitigate the refund
made by TU Electric in connection with the final order of the PUC in TU
Electric's Docket 11735 rate case.(See Docket 11735.) In August 1994, TU
Electric petitioned the PUC for a recovery of approximately $93 million,
including interest, in under-collected fuel costs for the period July 1993
through June 1994. The PUC approved recovery of this amount over a six-month
period beginning in January 1995. The PUC's approvals of both of these
surcharges have been appealed by certain intervenors to the district courts of
Travis County, Texas. In those appeals, those parties are contending that the
PUC is without authority to allow a fuel cost surcharge without a hearing and
findings that the costs are reasonable and necessary and that the prices charged
to TU Electric by supplying affiliates are no higher than the prices charged by
those affiliates to others for the same item or class of items. TU Electric will
vigorously defend its position in these appeals but is unable to predict their
outcome.
The fuel cost recovery rule also contains a procedure for an expedited change
in the fixed fuel factor in the event of an emergency. Final reconciliation of
fuel costs must be made either in a reconciliation proceeding, which may cover
no more than three years and no less than one year, or in a general rate case.
In a final reconciliation, a utility has the burden of proving that fuel costs
under review were reasonable and necessary to provide reliable electric service,
that it has properly accounted for its fuel-related revenues, and that fuel
prices charged to the utility by an affiliate were reasonable and necessary and
not higher than prices charged for similar items by such affiliate to other
affiliates or nonaffiliates. In addition, for generating utilities like TU
Electric, the rule provides for recovery of purchased power capacity costs with
respect to purchases from qualifying facilities, to the extent such costs are
not otherwise included in base rates. The energy-related costs of such
purchases are included in the fixed fuel factor. For non-generating utilities
like SESCO, the rule provides for the recovery of all costs of power purchased
at wholesale chargeable under rate schedules approved by a federal or state
regulatory authority and all amounts paid to qualifying facilities for the
purchase of capacity and/or energy, to the extent such costs are not otherwise
included in base rates. Penalties of up to 10% will be imposed in the event an
emergency increase has been granted when there was no emergency or when
collections under the PCRF exceed PCRF costs by 10% in any month or 5% in the
most recent twelve months.
FLEXIBLE RATE INITIATIVES
In June 1994, TU Electric filed with the PUC and its municipalities with
original regulatory jurisdiction a package of proposed flexible rates. Two of
the proposed rates would allow for negotiated competitive pricing through
reductions in demand charges to retain existing large retail and wholesale
customers who have viable alternative sources of supply and would otherwise
leave the system. The remaining two rates are an economic development rider and
an environmental technology service rider. The economic development rider would
provide an incentive to attract new businesses and jobs and to encourage
existing customers to expand their facilities within TU Electric's service area.
The environmental technology service rider would provide an incentive for
qualifying customers to convert to advanced technologies that conserve total
energy or improve
8
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
REGULATION AND RATES -- (CONTINUED)
the environment. These new rates have been approved and implemented in over 160
municipalities with original regulatory jurisdiction, including the cities of
Dallas and Ft. Worth, within TU Electric's service territory. Following
hearings on the proposed rates, however, the PUC issued an interim order on the
rate package which either rejected or significantly weakened the proposed
flexible rates, rendering them ineffective. In January 1995, TU Electric
withdrew its package of proposed rates from consideration by the PUC. This
action does not affect the over 160 municipalities with original regulatory
jurisdiction where the flexible rates are already in effect. The Sunset Review
of PURA by the Texas legislature in 1995 will include several of the key issues
involved in this case. Through its involvement at the legislature and the PUC,
TU Electric will continue to pursue the possibility of offering flexible rates.
DOCKET 11735
In July 1994, the TU Electric filed a petition in the 200th Judicial District
Court of Travis County, Texas to seek judicial review of the final order of the
PUC granting a $449 million, or 9.0%, rate increase in connection with TU
Electric's January 1993 rate increase request of $760 million, or 15.3% (Docket
11735). Other parties to the PUC proceedings also filed appeals with respect to
various portions of the order. TU Electric is unable to predict the outcome of
such appeals.
DOCKET 9300
The PUC's final order (Order) in connection with TU Electric's January 1990
rate increase request (Docket 9300) has been reviewed by the 250th Judicial
District Court of Travis County, Texas (District Court) and thereafter was
appealed to the Court of Appeals for the Third District of Texas (Court of
Appeals). In June 1994, the Court of Appeals affirmed a prudence disallowance
of $472 million provided for in the Order with respect to Comanche Peak,
reversed and remanded the portion of the District Court's judgment that had
affirmed a disallowance of $25 million relating to TU Electric's reacquisitions
of the minority owner interests in Comanche Peak nuclear fuel, and affirmed the
District Court's remand of the remainder of the disallowance of $884 million
relating to the reacquisitions of such minority owner interests. Therefore, the
Court of Appeals remanded an aggregate of $909 million of disallowances with
respect to TU Electric's reacquisitions of minority owner interests in Comanche
Peak to the PUC for reconsideration and ordered that such reconsideration be on
the basis of a prudent investment standard.
In addition, the Court of Appeals reversed the District Court's finding that
the PUC erred in ordering a refund of $2.5 million with respect to certain fuel
gas costs. Also, the Court of Appeals specified that, on remand, the PUC will
be required to re-evaluate the appropriate level of TU Electric's CWIP included
in rate base in light of its financial condition at the time of the initial
hearing and to reconsider whether the $442 million revenue increase provided for
in the PUC's final order remains the benchmark in light of this re-examination.
The same Court of Appeals had considered an appeal of another utility's rate
case and ruled, in November 1993, that prior court rulings required that tax
benefits generated by costs, including capital costs, not allowed in rates must
be used to reduce rates charged to customers. In its opinion concerning TU
Electric's Docket 9300 rate case, the Court of Appeals maintained that same
position and, accordingly, reversed the District Court in that regard. TU
Electric believes that such rulings are erroneous and not consistent with PURA.
TU Electric contended that, according to a Private Letter Ruling issued to TU
Electric by the Internal Revenue Service (IRS)
9
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
REGULATION AND RATES -- (CONCLUDED)
with respect to investment tax credits, such ratemaking treatment, to the extent
related to property classified for tax purposes as public utility property,
would result in a violation of the normalization rules under the Internal
Revenue Code of 1986, as amended. Violation of the normalization rules would
result in a significant adverse effect on TU Electric's results of operation and
liquidity. If there are normalization violations, TU Electric will forfeit its
investment tax credits which remain unamortized as of the date of the violation,
and will also forfeit the ability to take advantage of accelerated tax
depreciation in years to which the violative order relates. This could result
in payments to the IRS of up to $1.3 billion.
TU Electric disagrees with certain portions of the decision of the Court of
Appeals, including specifically its decision with respect to federal income
taxes, and has filed an appeal to the Supreme Court of Texas. Other parties
have also filed appeals of this decision to the Supreme Court of Texas. TU
Electric cannot predict whether such appeals will be accepted by the Supreme
Court of Texas, and cannot predict the outcome of any such appeals or any
resulting reconsideration of these appeals on remand by the PUC.
COMPETITION
GENERAL
As legislative, regulatory, economic and technological changes occur, the
energy and utility industries are faced with increasing pressure to become more
competitive while adhering to regulatory requirements. The level of competition
is affected by a number of variables, including price, reliability of service,
the cost of energy alternatives, new technologies and governmental regulations.
Federal legislation such as the Public Utility Regulatory Policies Act of 1978
(PURPA) and, more recently, the Energy Act as well as initiatives in various
states encourage competition among electric utility and non-utility power
producers. Together with increasing customer demand for lower-priced
electricity and other energy services, these measures have accelerated the
industry's movement toward a more competitive pricing and cost structure.
As a result of the shift in emphasis toward greater competition, large and
small industry participants are attempting to penetrate wholesale, industrial
and commercial markets, by offering energy services and energy-related products
that are both economically and environmentally attractive to customers. In
Texas, aggressive marketing of competitive prices by rural electric
cooperatives, municipally-owned electric systems, and energy providers who are
not subject to the traditional governmental regulation experienced by the energy
and utility industries has intensified competition within the state's wholesale
markets and, in multi-certificated areas, retail customer markets.
Furthermore, there is increasing pressure on utilities to reduce costs,
including the cost of power, and to tailor energy services to the specific needs
of customers. Such competitive pressures among electric utility and non-utility
power producers could result in the loss of customers and the cost of certain
assets becoming stranded investment (i.e., assets, the full cost of which may
not be recoverable from customers as a result of competitive pricing). To the
extent stranded investment cannot be recovered from customers, it would be
necessary for it to be borne by shareholders. In response to these competitive
pressures, many utilities are implementing significant restructuring and re-
engineering initiatives designed to make them more competitive. Since the
implementation of an Operations Review and Cost Reduction program in April 1992,
the System Companies continue to take competitive steps to reduce costs by
streamlining business processes and operating practices (see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operation).
10
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
COMPETITION -- (CONTINUED)
WHOLESALE MARKET AND TRANSMISSION ACCESS
In the wholesale power market, TU Electric and SESCO compete with a variety of
utilities and other suppliers, some of which are willing and able to sell at
rates below TU Electric's standard wholesale power service rate as approved by
the PUC. As a result, TU Electric has lost approximately 379 MW of wholesale
load since the beginning of 1993. However, in 1994, wholesale revenues
represented only approximately 4% of the Company's total consolidated operating
revenues. TU Electric is responding to these load losses by proposing to
competitively price its wholesale power so as to retain existing customers, and
attract new wholesale business. At present, any competitive offer is made
subject to appropriate regulatory approval. In connection with its Sunset
Review, the Texas legislature is expected to consider legislation which, among
other things, would deregulate future wholesale power generation. (See
Regulation and Rates.)
The Energy Act empowers the FERC to require utilities to provide transmission
service for the delivery of wholesale power from other power producers to
qualified resellers, such as municipalities, cooperatives, and other utilities.
In December 1993, Tex-La Electric Cooperative of Texas, Inc. (Tex-La) filed with
the FERC an application seeking an order under the Federal Power Act that would
require TU Electric and SESCO to provide transmission, distribution and control
area services necessary to enable Tex-La to purchase power from a competitor.
In December 1994, the FERC ordered that the service be provided under a rate
methodology that TU Electric and SESCO consider to be unduly favorable to Tex-La
and in abrogation of a power supply agreement between TU Electric and Tex-La.
TU Electric and SESCO have petitioned for a rehearing of the FERC's December
order with respect to these issues. TU Electric and SESCO continue to pursue a
rate methodology that more accurately reflects the cost of service to Tex-La.
Tex-La represents approximately 80 MW of wholesale load which will no longer be
supplied by TU Electric, but by a competitor; and an associated amount of
generating costs or purchased power commitments will no longer be supported by
Tex-La.
RETAIL MARKET
TU Electric and SESCO are experiencing competition for retail load in areas
which are multi-certificated with rural electric cooperatives or municipal
utilities. Except in areas where there is multi-certification by the PUC, TU
Electric and SESCO currently have the exclusive right to provide electric
service to the public within their service areas.
Legislatures and regulatory commissions in several states have begun to
examine the possibility of mandated "retail wheeling", or the required delivery
by an electric utility over its transmission and distribution facilities of
energy produced by another entity to retail customers in such utility's service
territory. If implemented, such access could allow a retail customer to
purchase its electric service from any other electric service provider, subject
to the practical constraints of long distance transmission. This issue has not
been actively pursued by the PUC, although as a part of its Sunset Review, the
Texas legislature may consider the issue.
In addition, some energy consumers have the ability to produce their own
electricity or to use alternative forms of energy. Industrial customers may
also be able to relocate their facilities to a lower cost service area. To some
degree, there is competition among utilities with defined service areas to
attract and retain large customers. The System Companies are pursuing efforts
to remain competitive through competitive pricing, economic development and
other initiatives. (See Regulation and Rates.) Industrial customers
represented approximately 17% of the Company's total consolidated operating
revenues in 1994.
11
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
COMPETITION -- (CONCLUDED)
Neither TU Electric nor SESCO are able to predict the extent of future
competitive developments or what impact, if any, such developments may have on
their operations.
ENVIRONMENTAL MATTERS
The System Companies are subject to various federal, state and local
regulations dealing with air and water quality and related environmental
matters. (See Item 2. Properties - Capital Expenditures and Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operation for
environmental expenditures.)
AIR
Under the Texas Clean Air Act, the Texas Natural Resource Conservation
Commission (TNRCC) has jurisdiction over the permissible level of air
contaminant emissions from generating facilities located within the State of
Texas. In addition, the new source performance standards of the Environmental
Protection Agency (EPA) promulgated under the federal Clean Air Act, as amended
(Clean Air Act), which have also been adopted by the TNRCC, are applicable to
generating units, the construction of which commenced after September 18, 1978.
TU Electric's generating units have been constructed to operate in compliance
with current regulations and emission standards promulgated pursuant to these
Acts; however, due to variations in the quality of the lignite fuel,
operation of certain of the lignite-fueled generating units at reduced loads is
required from time to time in order to maintain compliance with these standards.
The Clean Air Act includes provisions which, among other things, place limits
on the sulfur dioxide emissions produced by generating units. In addition to
the new source performance standards applicable to sulfur dioxide, the Clean Air
Act requires that fossil-fueled plants meet new sulfur dioxide emission
allowances by 1995 (Phase I) and additional sulfur dioxide emission allowances
by 2000 (Phase II). TU Electric's generating units are not affected by the
Phase I requirements. The applicable Phase II requirements currently are met by
52 out of the 56 of TU Electric's generating units to which those requirements
apply. Because the sulfur dioxide emissions from the other four units are
relatively low and alternatives are available to enable these units to reduce
sulfur dioxide emissions or utilize compensatory reduction allowances achieved
in other units, compliance with the applicable Phase II sulfur dioxide
requirements is not expected to have a significant impact on TU Electric. In
January 1993, the EPA issued its "core" regulations to implement the sulfur
dioxide reduction program. TU Electric is preparing compliance plans in
accordance with these regulations and expects these plans to be implemented by
January 1, 2000.
To meet these sulfur dioxide requirements, the Clean Air Act provides for the
annual allocation of sulfur dioxide emission allowances to utilities. Under the
Clean Air Act, utilities are permitted to transfer allowances within their own
systems and to buy or sell allowances from or to other utilities. The EPA
grants a maximum number of allowances annually to TU Electric based on the
amount of emissions from units in operation during the period 1985-1987. The
Clean Air Act also provides that TU Electric will be granted additional annual
allowances for certain of TU Electric's units included in the IRP based on part
of their anticipated emissions. TU Electric intends to utilize internal
allocation of emission allowances within its system and, if cost effective, may
purchase additional emission allowances to enable both existing and future
electric generating units to meet the requirements of the Clean Air Act. TU
Electric may sell excess emission allowances. TU Electric is unable to predict
the extent to which it may generate excess allowances or will be able to acquire
allowances from others if needed.
12
<PAGE>
ITEM 1. BUSINESS (CONTINUED)
ENVIRONMENTAL MATTERS -- (CONTINUED)
TU Electric's lignite-fired generating units meet the nitrogen oxide limits
currently required by the Clean Air Act. The TNRCC and the EPA have determined
that the requirements of the Clean Air Act for ozone nonattainment areas will
not require nitrogen oxide emission reductions at TU Electric's natural gas-
fired units in the Dallas-Fort Worth area. The Clean Air Act also requires
studies, which began in 1991, over a four year period by the EPA to assess the
potential for toxic emissions from utility boilers. TU Electric is unable to
predict either the results of such studies or the effects of any subsequent
regulations. Continuous emission monitoring systems were required by the Clean
Air Act to be installed by 1995 on most of TU Electric's fossil-fueled units.
Installation began in 1992 and was completed in 1994 at a cost of approximately
$38 million.
Only certain parts of the regulations implementing the Clean Air Act have been
published as final rules. Until more of these regulations have been promulgated
and specific state requirements developed, TU Electric will not be able to fully
determine the cost or method of compliance with these requirements. TU Electric
believes that it can meet the requirements necessary to be in compliance with
these provisions as they are developed. Estimates for the capital requirements
related to the Clean Air Act are included in TU Electric's estimated
construction expenditures. Any additional required capital costs, as well as
any increased operating costs associated with new requirements or compliance
measures, are expected to be recoverable through rates, as similar costs have
been recovered in the past.
WATER
The TNRCC and the EPA have jurisdiction over all water discharges (including
storm water) from all System Companies' facilities. TU Electric's facilities are
presently in compliance with applicable state and federal requirements relating
to discharge of pollutants into the water. TU Electric, Fuel Company, and
Mining Company have obtained all required waste water discharge permits from the
TNRCC and the EPA for facilities in operation and have applied for or obtained
all such permits for facilities under construction. TU Electric, Fuel Company,
and Mining Company believe they can satisfy the requirements necessary to obtain
any required permits or renewals.
Diversion, impoundment and withdrawal of water for cooling and other purposes
are subject to the jurisdiction of the TNRCC. TU Electric possesses all
necessary permits for these activities from the TNRCC for its present
operations.
OTHER
Federal legislation regulating surface mining was enacted in August 1977 and
regulations implementing the law have been issued. Mining Company's lignite
mining operations are currently regulated at the state level by the Railroad
Commission of Texas, with oversight by the United States Department of the
Interior's Office of Surface Mining, Reclamation and Enforcement. Surface
mining permits have been issued for current Mining Company operations that
provide fuel for Big Brown, Monticello and Martin Lake.
13
<PAGE>
ITEM 1. BUSINESS (CONCLUDED)
ENVIRONMENTAL MATTERS -- (CONCLUDED)
Treatment, storage and disposal of solid and hazardous waste are regulated at
the state level under the Texas Solid Waste Disposal Act (Texas Act) and at the
federal level under the Resource Conservation and Recovery Act of 1976, as
amended (RCRA). The EPA has issued regulations under the RCRA and the TNRCC has
issued regulations under the Texas Act applicable to System Companies'
facilities. TU Electric has registered its solid waste disposal sites and has
obtained or applied for such permits as are required by such regulations.
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended,
the State of Texas is required to provide by 1996, either on its own or jointly
with other states in a compact, for the disposal of all low-level radioactive
waste generated within the state. The State of Texas is taking steps to site,
construct and operate a low-level radioactive waste disposal site by 1997 and
has submitted a license application in March 1992 for such a facility. The
license application has been revised and the TNRCC is charged with processing
the application and granting the permit. The State of Texas has agreed to a
compact with the States of Maine and Vermont, which is subject to ratification
by Congress, for such a facility. Low-level waste material is being stored on-
site. TU Electric's on-site storage capacity is expected to be adequate until
other facilities are available.
14
<PAGE>
ITEM 2. PROPERTIES
The Company owns no utility plant or real property. At December 31, 1994, TU
Electric owned or leased and operated the following units:
<TABLE>
<CAPTION>
ELECTRIC NET
GENERATING CAPABILITY
UNITS FUEL SOURCE (MW) %
---------- ----------- ------ ----
<C> <S> <C> <C>
46 Natural Gas (a).................... 11,866 56.5%
9 Lignite/Coal (b)................... 5,845 27.8
2 Nuclear............................ 2,300 11.0
15 Combustion Turbines (c)............ 975 4.6
10 Diesel............................. 20 0.1
------ -----
Total......................... 21,006 100.0%
====== =====
</TABLE>
____________________
(a) Thirty-seven natural gas units are designed to operate on fuel oil for
short periods when gas supplies are interrupted or curtailed. Five natural
gas units are designed to operate on fuel oil for extended periods. In
1994, one 70 MW natural gas unit was retired.
(b) Includes the Monticello Unit 3 (750 MW), expected to return to service in
mid-1995.(See Peak Load and Capability.)
(c) Natural gas units leased and operated by TU Electric. Such units are
designed to operate on fuel oil for extended periods.
The principal generating facilities and load centers of TU Electric and SESCO
are connected by 3,861 circuit miles of 345,000 volt transmission lines and
9,293 circuit miles of 138,000 and 69,000 volt transmission lines.
TU Electric is connected by six 345,000 volt lines to Houston Lighting & Power
Company; by three 345,000 volt, eight 138,000 volt and nine 69,000 volt lines to
West Texas Utilities Company; by two 345,000 volt, seven 138,000 volt and one
69,000 volt lines to the Lower Colorado River Authority; by four 345,000 volt
and eight 138,000 volt lines to the Texas Municipal Power Agency; and at several
points with smaller systems operating wholly within Texas. SESCO is connected
to TU Electric by three 138,000 volt lines, ten 69,000 volt lines and three
lines at distribution voltage. TU Electric and SESCO are members of the
Electric Reliability Council of Texas (ERCOT), an intrastate network of
investor-owned entities, cooperatives and public entities. ERCOT is the
regional reliability coordinating organization for member electric power systems
in Texas.
The generating stations and other important units of property of TU Electric
and SESCO are located on lands owned primarily in fee simple. The greater
portion of the transmission and distribution lines of TU Electric and SESCO, and
of the gas gathering and transmission lines of Fuel Company, has been
constructed over lands of others pursuant to easements or along public highways
and streets as permitted by law. The rights of the System Companies in the
realty on which their properties are located are considered by them to be
adequate for their use in the conduct of their business. Minor defects and
irregularities customarily found in titles to properties of like size and
character may exist, but any such defects and irregularities do not materially
impair the use of the properties affected thereby. TU Electric, SESCO and Fuel
Company have the right of eminent domain whereby they may, if necessary, perfect
or secure titles to privately held land used or to be used in their operations.
Utility plant of TU Electric and SESCO is generally subject to the liens of
their respective mortgages.
CAPITAL EXPENDITURES
The Company has taken steps to substantially reduce construction expenditures
from amounts previously estimated. Such construction expenditures for utility
related activities, excluding AFUDC (see Note 1 to Consolidated Financial
Statements), and expenditures related to new generating units are presently
estimated at $400 million for each of the years 1995, 1996, and 1997. The
System Companies are subject to federal, state and local regulations dealing
with environmental protection. (See Item 1. Business - Environmental
15
<PAGE>
ITEM 2. PROPERTIES (CONTINUED)
CAPITAL EXPENDITURES -- (CONCLUDED)
Matters.) Expenditures for construction to meet the requirements of such
regulations at existing generating units are estimated to be $58 million for
1995 and were approximately $40 million in 1994, $34 million for 1993 and $25
million for 1992. Expenditures for nuclear fuel and non-utility property are
presently estimated to be $63 million for 1995, $70 million for 1996, and $96
million for 1997.
TU Electric's IRP includes 288 MW of simple-cycle combustion turbines and 214
MW of combined-cycle combustion turbines planned for completion during the peak
season of 1999, a total of 1,300 MW of combined-cycle combustion turbines
planned for completion during the peak seasons of 2000, 2001 and 2002, and a
total of 300 MW (or 30 MW of firm capability) of wind or other renewable
resources (100 MW planned for completion during each of the peak seasons of
1999, 2003 and 2004). Assuming these units are constructed and financed by TU
Electric using traditional methods, approximately $200 million would be added to
construction expenditures in 1997.
TU Electric's IRP also includes one lignite-fueled 750 MW unit at Twin Oak
currently scheduled for service for the peak season of 2003. Estimated
construction expenditures, excluding AFUDC, for the 1995-1997 period do not
include any significant amounts for the resumption of construction of this unit.
Active construction and the accrual of AFUDC on Twin Oak, suspended in 1987 due
to forecast changes in load growth, would need to resume in 1999 in order to
meet the current schedule. Due to the delay, and the possibility of further
delays resulting from forecast changes, in the schedule of Twin Oak, as well as
the lignite-fueled Forest Grove facility which is not included in the ten-year
resource plan, TU Electric is contemplating alternative uses for its investment
in the projects, which might include construction as exempt wholesale
generators, construction at different locations, or sale of the facilities.
Management has no specific plans for alternative uses for, or any knowledge of
an impairment of, such facilities. Some alternative uses, while contributing to
the Company's long-term strategy for maximizing shareholder value, might not
provide for the complete recovery of the Company's current investment in these
facilities and related mining facilities. Such investment was approximately
$807 million as of December 31, 1994.
The re-evaluation of growth expectations, the effects of inflation, additional
regulatory requirements and the availability of fuel, labor, materials and
capital may result in changes in estimated construction costs and dates of
completion. Commitments in connection with the construction program are
generally revocable subject to reimbursement to manufacturers for expenditures
incurred or other cancellation penalties. (See Item 1. Business - Peak Load and
Capability.)
The Company plans to seek new investment opportunities from time to time when
it concludes that such investments are consistent with its business strategies
and will likely enhance the long-term returns to its shareholders. The timing
and amounts of any specific new business investment opportunities are presently
undetermined.
For information regarding financing of capital expenditures, see Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operation.
16
<PAGE>
ITEM 2. PROPERTIES (CONCLUDED)
THE TU ELECTRIC AND SESCO SYSTEMS
DECEMBER 31, 1994
[A MAP OUTLINING THE SERVICE SYSTEMS OF TU ELECTRIC AND SESCO
APPEARS IN THE PAPER FORMAT VERSION OF THE DOCUMENT.]
17
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
In May 1990, Nancy F. King and Rodney B. Shields, allegedly as shareholders of
the Company, filed suit in the United States District Court for the Northern
District of Texas derivatively on behalf of the Company against the Company as a
nominal defendant and James K. Dobey, Jack W. Evans, J. S. Farrington, William
M. Griffin, Margaret N. Maxey, Erle Nye, Charles R. Perry and William H. Seay,
directors of the Company, and Burl B. Hulsey, Jr. and Charles N. Prothro, former
directors of the Company. The plaintiffs alleged mismanagement involving gross
negligence, willful misconduct, breaches of fiduciary duty and waste of
corporate assets on the part of the defendants in connection with activities
relating to Comanche Peak. In September 1991, the Court entered an order which
stayed this suit until thirty days after entry of a final judgment by the
District Court in TU Electric's appeal of the final order of the PUC in Docket
9300. In September 1992, a final judgment in this appeal was entered by the
District Court. (See Item 1. Business -Regulation and Rates.) The plaintiff
refused to extend the stay pending the appeals of this judgment, filed an
amended complaint which claimed damages in excess of $1.247 billion, added as
defendants two former directors of the Company, Perry G. Brittain and James H.
Zumberge, and one current director of the Company, James A. Middleton, and
removed Rodney B. Shields as a plaintiff. In response, the Company moved to
extend the stay through resolution of the appeals or alternatively to dismiss
the suit. In December 1992, this suit was consolidated with a similar suit
described below. In January 1993, the Court entered an order which stayed the
consolidated suit until thirty days after the disposition of all appeals from
the final order of the PUC in Docket 9300. (See Item 1. Business - Regulation
and Rates.)
In November 1991, Sheree Anne Meyer, as custodian for Adam Joseph Davenport,
allegedly as a shareholder of the Company, filed suit in the United States
District Court for the Northern District of Texas derivatively on behalf of the
Company and TU Electric against the Company and TU Electric as nominal
defendants and J. S. Farrington, Erle Nye, James K. Dobey, Jack W. Evans,
William M. Griffin, Margaret N. Maxey, James A. Middleton, Charles R. Perry and
William H. Seay, directors of the Company, and James H. Zumberge, a former
director of the Company, S. S. Swiger, a former officer of the Company, and T.
L. Baker, an officer of TU Electric. The plaintiff alleged breaches of
fiduciary duty and negligence primarily relating to Comanche Peak, which the
plaintiff claims had resulted in damages in an amount not less than $1.381
billion. In December 1991, the Court entered an order which stayed this suit
until thirty days after entry of a final judgment by the District Court in TU
Electric's appeal of the final order of the PUC in Docket 9300. In September
1992, a final judgment in this appeal was entered by the District Court. (See
Item 1. Business - Regulation and Rates.) The plaintiff refused to extend the
stay pending the appeals of this judgment and the Company moved to extend the
stay through resolution of the appeals or alternatively to dismiss the suit. In
December 1992, this suit was consolidated into the suit described above. In
January 1993, the Court entered an order which stayed the consolidated suit
until thirty days after the disposition of all appeals from the final order of
the PUC in Docket 9300. (See Item 1. Business - Regulation and Rates.)
The plaintiffs, the Company and the individual defendants have entered into a
settlement agreement with respect to the consolidated suit. The settlement is
conditioned upon approval by the Court. A special litigation committee of the
Company's Board of Directors, following an extensive evaluation, has approved
the settlement. In February 1995, the Court approved the settlement on a
preliminary basis and ordered the Company to notify its shareholders of the
settlement and their opportunity to object to it. A final hearing on the
settlement has been scheduled for May, 1995. Although such settlement agreement
has not been finalized, tentative amounts of the settlement are considered to be
immaterial.
18
<PAGE>
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
______________________
<TABLE>
<CAPTION>
EXECUTIVE OFFICERS OF THE REGISTRANT
POSITIONS AND OFFICES
PRESENTLY HELD (CURRENT DATE FIRST
TERM EXPIRES MAY 19, ELECTED TO PRESENT BUSINESS EXPERIENCE
NAME OF OFFICER AGE 1995) OFFICE(S) (PRECEDING FIVE YEARS)
- --------------- --- ----------------------- ------------------- ----------------------
<S> <C> <C> <C> <C>
J. S. Farrington 60 Chairman, Chief February 20, 1987 Same.
Executive and
Director
Erle Nye 57 President and February 20, 1987 Same and Chief Executive of
Director TU Electric.
H. Jarrell Gibbs 57 Vice President and November 15, 1991 President of TU Services; prior thereto,
Principal Financial Executive Vice President of TU Electric;
Officer prior thereto, Executive Vice President
of the Texas Electric Service Division of
TU Electric; prior thereto, Vice
President of TU Electric.
</TABLE>
There is no family relationship between any of the above named executive
officers.
19
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York, Chicago and Pacific
stock exchanges (symbol: TXU).
The price range of the common stock of the Company on the composite tape, as
reported by The Wall Street JOURNAL and the dividends paid, for each of the
calendar quarters of 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
Quarter Ended Price Range Dividends Paid
------------- ------------------------------ ----------------
1994 1993 1994 1993
------------- ------------- ---- ----
High Low High Low
----- ---- ----- ---
<S> <C> <C> <C> <C> <C> <C>
March 31................. $43 1/8 $36 1/2 $47 3/8 $41 5/8 $0.77 $0.76
June 30.................. 38 29 7/8 47 7/8 44 1/4 0.77 0.77
September 30............. 34 1/8 29 5/8 49 3/4 45 1/2 0.77 0.77
December 31.............. 34 1/8 30 3/4 47 42 1/4 0.77 0.77
----- -----
$3.08 $3.07
===== =====
</TABLE>
The Company has declared common stock dividends payable in cash in each year
since its incorporation in 1945. The Board of Directors of the Company, at its
February 1995 meeting, declared a regular quarterly dividend of $0.77 a share.
Future dividends, however, may vary depending upon the Company's profit levels
and capital requirements as well as financial and other conditions existing at
the time. Reference is made to Note 4 to Consolidated Financial Statements
regarding limitations upon payment of dividends on common stock of TU Electric
and SESCO.
The approximate number of record holders of the common stock of the Company as
of February 28, 1995, was 107,048.
20
<PAGE>
Item 6. SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1994 1993/*/ 1992 1991/*/ 1990
---- ------- ---- ------- ----
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Total assets -- end of year...................................$20,893,408 $21,518,128 $19,428,568 $18,792,782 $18,650,979
- ----------------------------------------------------------------------------------------------------------------------------------
Utility plant -- gross -- end of year......................... 24,206,351 $23,836,729 $23,043,778 $21,927,788 $20,726,629
Accumulated depreciation and amortization -- end of year.... 5,228,423 4,710,398 4,251,002 3,851,330 3,446,785
Reserve for regulatory disallowances -- end of year......... 1,308,460 1,308,460 1,308,460 1,308,460 --
Construction expenditures (including allowance for
funds used during construction).......................... 444,245 871,450 1,136,971 1,232,239 1,453,594
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization -- end of year
Long-term debt..............................................$ 7,888,413 $ 8,379,826 $ 7,931,981 $ 7,951,086 $ 7,380,575
Preferred stock:
Not subject to mandatory redemption...................... 870,190 1,083,008 909,564 1,007,728 1,007,728
Subject to mandatory redemption.......................... 387,482 396,917 418,748 425,758 426,737
Common stock equity......................................... 6,490,047 6,570,993 6,590,537 6,283,675 6,827,808
----------- ----------- ----------- ----------- -----------
Total....................................................$15,636,132 $16,430,744 $15,850,830 $15,668,247 $15,642,848
=========== =========== =========== =========== ===========
Capitalization ratios -- end of year
Long-term debt.............................................. 50.5% 51.0% 50.0% 50.8% 47.2%
Preferred stock............................................. 8.0 9.0 8.4 9.1 9.2
Common stock equity......................................... 41.5 40.0 41.6 40.1 43.6
----- ----- ----- ----- -----
Total.................................................... 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
- ----------------------------------------------------------------------------------------------------------------------------------
Embedded interest cost on long-term debt -- end of year....... 8.7% 8.7% 9.2% 9.7% 9.8%
Embedded dividend cost on preferred stock -- end of year...... 7.5% 7.6% 8.4% 8.5% 8.6%
- ----------------------------------------------------------------------------------------------------------------------------------
Income (loss) before cumulative effect of a change
in accounting principle..................................... $542,799 $368,660 $619,204 $(409,964) $850,802
Cumulative effect of a change in accounting for unbilled
revenue (Net of taxes of $41,679,000)(Note 12).............. -- -- 80,907 -- --
----------- ----------- ----------- ----------- -----------
Consolidated net income (loss)................................ $542,799 $368,660 $700,111 $(409,964) $850,802
=========== =========== =========== =========== ===========
Dividends declared on common stock............................ $695,590 $682,438 $653,146 $ 624,261 $575,424
- ----------------------------------------------------------------------------------------------------------------------------------
Common stock data
Shares outstanding -- average...............................225,833,659 221,555,218 214,850,225 207,357,881 193,460,523
Shares outstanding -- end of year...........................225,841,037 224,345,422 217,316,054 210,700,373 196,970,326
Earnings per share (on average shares outstanding):
Before cumulative effect of a change in accounting....... $2.40 $1.66 $2.88 $(1.98) $4.40
Cumulative effect of a change in accounting
for unbilled revenue..................................... -- -- 0.38 -- --
----- ----- ----- ----- -----
Total earnings per average share......................... $2.40 $1.66 $3.26 $(1.98) $4.40
===== ===== ===== ===== =====
Dividends declared per share................................ $3.08 $3.08 $3.04 $3.00 $2.96
Book value per share -- end of year......................... $28.74 $29.29 $30.33 $29.82 $34.66
Return on average common stock equity....................... 8.3% 5.6% 10.9% (6.3)% 12.9%
- ----------------------------------------------------------------------------------------------------------------------------------
Ratio of earnings to fixed charges:
Pre-tax..................................................... 2.3 1.9 2.3 0.4 2.4
After-tax................................................... 1.9 1.6 2.0 0.7 2.3
Allowance for funds used during construction as
percent of consolidated net income.......................... 4.1% 71.4% 43.5% -- % 72.6%
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
* Certain financial statistics for the years 1993 and 1991 were affected by TU
Electric recording regulatory disallowances in the rate orders issued by the
Public Utility Commission of Texas in Dockets 11735 and 9300, respectively.
(See Note 10 to Consolidated Financial Statements.)
21
<PAGE>
Item 6. SELECTED FINANCIAL DATA (Concluded)
CONSOLIDATED OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
ELECTRIC ENERGY GENERATED AND
PURCHASED (MWh)
Generated -- net station output............................. 81,320,922 79,105,495 74,652,339 76,326,601 76,044,403
Purchased and net interchange............................... 12,547,047 12,785,246 11,417,251 11,027,061 12,179,724
---------- ---------- ---------- ---------- ----------
Total generated and purchased.............................. 93,867,969 91,890,741 86,069,590 87,353,662 88,224,127
Company use, losses and unaccounted for..................... 4,734,007 6,397,110 5,747,156 4,996,123 4,496,294
---------- ---------- ---------- ---------- ----------
Total electric energy sales................................ 89,133,962 85,493,631 80,322,434 82,357,539 83,727,833
========== ========== ========== ========== ==========
ELECTRIC ENERGY SALES (MWh)
Residential................................................. 30,645,788 30,221,666 27,266,411 28,505,885 28,157,802
Commercial.................................................. 25,226,370 24,044,045 22,959,464 23,012,114 23,429,101
Industrial.................................................. 23,271,474 21,415,721 21,108,894 21,482,750 21,839,196
Government and municipal.................................... 5,653,352 5,377,027 5,032,780 5,056,868 4,914,503
---------- ---------- ---------- ---------- ----------
Total general business..................................... 84,796,984 81,058,459 76,367,549 78,057,617 78,340,602
Other electric utilities.................................... 4,336,978 4,435,172 3,954,885 4,299,922 5,387,231
---------- ---------- ---------- ---------- ----------
Total electric energy sales................................ 89,133,962 85,493,631 80,322,434 82,357,539 83,727,833
========== ========== ========== ========== ==========
OPERATING REVENUES (thousands)
Residential................................................. $2,490,319 $2,254,832 $1,995,767 $2,043,421 $1,859,239
Commercial.................................................. 1,707,306 1,499,266 1,405,546 1,391,995 1,266,030
Industrial.................................................. 986,495 864,452 849,365 852,952 801,821
Government and municipal.................................... 399,906 342,639 304,286 303,597 273,596
---------- ---------- ---------- ---------- ----------
Total general business..................................... 5,584,026 4,961,189 4,554,964 4,591,965 4,200,686
Other electric utilities.................................... 216,172 215,625 209,170 228,075 232,755
---------- ---------- ---------- ---------- ----------
Total from electric energy sales........................... 5,800,198 5,176,814 4,764,134 4,820,040 4,433,441
Other operating revenues (including unbilled revenue
and over/under-recovered fuel revenue)/*/.................. (136,655) 257,698 143,742 73,133 109,182
---------- ---------- ---------- ---------- ----------
Total operating revenues................................. $5,663,543 $5,434,512 $4,907,876 $4,893,173 $4,542,623
========== ========== ========== ========== ==========
ELECTRIC CUSTOMERS (end of year)
Residential................................................. 2,053,235 2,020,667 1,952,916 1,921,119 1,900,005
Commercial.................................................. 225,479 221,422 210,185 205,555 205,359
Industrial.................................................. 21,673 21,954 21,969 22,156 22,214
Government and municipal.................................... 29,437 29,034 28,204 27,719 24,538
---------- ---------- ---------- ---------- ----------
Total general business..................................... 2,329,824 2,293,077 2,213,274 2,176,549 2,152,116
Other electric utilities.................................... 212 220 243 247 63
---------- ---------- ---------- ---------- ----------
Total electric customers.................................... 2,330,036 2,293,297 2,213,517 2,176,796 2,152,179
========== ========== ========== ========== ==========
RESIDENTIAL STATISTICS (excludes master-metered
customers, kWh sales and revenues)
Average kWh per customer................................... 14,283 15,210 13,329 14,099 14,050
Average revenue per kWh.................................... 8.23c 7.59c 7.41c 7.26c 6.69c
______________________
Industrial classification includes service to Alcoa-Sandow:
Electric energy sales (MWh)................................ 3,886,258 3,166,797 3,157,852 3,359,824 3,517,431
Operating revenues (thousands)............................. $54,699 $53,352 $56,043 $55,987 $55,274
</TABLE>
/*/ In 1992, other operating revenues do not include $122,586,000 of unbilled
base rate revenues which were reclassified as a cumulative effect of a
change in accounting principle effective January 1, 1992.
22
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION
LIQUIDITY AND CAPITAL RESOURCES
The primary capital requirements of Texas Utilities Company (Company) in 1994
and as estimated for 1995 through 1997 are as follows:
<TABLE>
<CAPTION>
1994 1995 1996 1997
---- ---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C>
Cash construction expenditures (excluding
allowance for funds used during construction)................. $ 435,000 $400,000 $400,000 $400,000
Nuclear fuel (excluding allowance for funds used
during construction) and non-utility property................. 71,000 63,000 70,000 96,000
Maturities and redemptions of long-term debt,
sinking fund requirements and redemptions
of preferred stock............................................ 1,224,000 99,000 110,000 405,000
---------- -------- -------- --------
Total...................................................... $1,730,000 $562,000 $580,000 $901,000
========== ======== ======== ========
</TABLE>
For information concerning construction work contemplated by the Texas
Utilities Company System (System Companies) and the commitments with respect
thereto, see Item 2. Properties -- Capital Expenditures and Note 11 to
Consolidated Financial Statements.
The System Companies have generated cash from operations sufficient to meet
operating needs, pay dividends on capital stock and finance capital
requirements. For 1994, all of the cash needed for construction expenditures
was generated from operations by the System Companies. Factors affecting the
continued ability of Texas Utilities Electric Company (TU Electric) to fund its
capital requirements from operations include responsive regulatory practices
allowing recovery of capital investment through adequate depreciation rates,
normalization of federal income taxes (see Note 10 to Consolidated Financial
Statements), recovery of the cost of fuel and purchased power and the
opportunity to earn competitive rates of return required in the capital markets.
In order to remain competitive, the Company is aggressively managing its
operating costs and capital expenditures through streamlined business processes
and is developing and implementing strategies to address an increasingly
competitive environment (see Item 1. Business - Competition). These strategies
include initiatives to improve the Company's return on corporate assets and to
maximize shareholder value through new marketing programs, creative rate design,
and new business opportunities. Additional initiatives under consideration
include the potential disposition or alternative utilization of existing assets
and the restructuring of strategic business units. Some of the Company's
assets, including approximately $807 million invested in partially completed
generating facilities on which construction is temporarily suspended and
related mining facilities (see Item 2. Properties - Capital Expenditures) and
approximately $563 million invested in coal properties of Chaco Energy Company
(see Item 1. Business - Fuel Supply and Purchased Power and Note 11 to
Consolidated Financial Statements), are not contributing to earnings and, as a
result, the Company is considering possible alternatives to the scheduled
development, operation and recovery of such assets through traditional means.
While the Company currently believes that its investment in these assets can be
recovered, such alternatives, while contributing to the Company's long-term
strategy for maximizing shareholder value, might include disposition for amounts
which may be less than current book value with respect to these assets. It is
not possible at this time to predict the effect any of these possible
initiatives might have on the carrying value of the Company's assets or its
results of operation.
Although TU Electric cannot predict the outcome of its appeals of the Docket
9300 and 11735 rate decisions, future regulatory actions or any changes in
economic and securities market conditions, no changes are expected in trends or
commitments, other than those discussed above, which might significantly alter
its basic financial position. (See Note 10 to Consolidated Financial
Statements.)
23
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION (Continued)
LIQUIDITY AND CAPITAL RESOURCES -- (CONTINUED)
External funds of a permanent or long-term nature are obtained through the
sales of common stock, preferred stock and long-term debt by the System
Companies. The capitalization ratios of the Company and its subsidiaries at
December 31, 1994, consisted of approximately 50% long-term debt, 8% preferred
stock and 42% common stock equity.
Financings by System Companies totalled $440,442,000 in 1994. Proceeds from
such financings were used primarily for the early redemption or reacquisition of
debt and preferred stock. Financings in 1994 by the System Companies included
the following:
<TABLE>
<CAPTION>
LONG-TERM DEBT (TU ELECTRIC):
PRINCIPAL
DESCRIPTION AMOUNT INTEREST RATE MATURITY
----------- ------------- --------------- --------
<S> <C> <C> <C>
First mortgage and collateral trust bonds.................. $300,000,000 6.06% 1999
Pollution control revenue bonds............................ 78,340,000 3.65% to 4.50% 2029
------------
Total................................................ $378,340,000
============
COMMON STOCK (COMPANY):
NET
DESCRIPTION SHARES PROCEEDS
----------- --------- -----------
Automatic dividend reinvestment and common stock purchase plan (a).................. 1,364,690 $56,671,000
Employees' thrift plan (a).......................................................... 130,925 5,431,000
--------- -----------
Total......................................................................... 1,495,615 $62,102,000
========= ===========
</TABLE>
_______________________
(a) Beginning March 1994, common stock requirements for these plans have been
met through open market purchases. The Company does not anticipate the
need to issue new shares for these plan requirements.
Since December 31, 1993, the System Companies redeemed, reacquired or made
principal payments of $1,223,723,000 on long-term debt and preferred stock.
Early redemptions of long-term debt and preferred stock may occur from time to
time in amounts presently undetermined. (See Notes 5 and 6 to Consolidated
Financial Statements.)
On February 24, 1995, TU Electric entered into a two-year term credit
agreement with commercial banks for borrowings up to $300,000,000.
The System Companies expect to sell additional debt and equity securities as
needed including (i) the possible future sale by TU Electric of up to
$650,000,000 of First Mortgage Bonds currently registered with the Securities
and Exchange Commission for offering pursuant to Rule 415 under the Securities
Act of 1933 and (ii) the possible future sale by TU Electric of up to 250,000
shares of Cumulative Preferred Stock ($100 liquidation value) similarly
registered. The Company and TU Electric have credit facility agreements
(Agreements) with a group of commercial banks. The Agreements have two
facilities, for each of which the Company pays a fee. Facility A provides for
borrowings up to $300,000,000 and terminates April 28, 1995. The Company and TU
Electric intend to negotiate an extension of this facility. Facility B provides
for borrowings up to $700,000,000 and terminates April 29, 1999. The Company's
borrowings under the Agreements are limited to $250,000,000. Borrowings under
the Agreements will be used for working capital and other corporate purposes,
including commercial paper backup. For more information regarding short-term
financings of the Company, see Note 2 to Consolidated Financial Statements.
24
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION (Continued)
LIQUIDITY AND CAPITAL RESOURCES -- (CONCLUDED)
In June 1994, Texas Utilities Properties Inc., a wholly-owned subsidiary of
the Company, entered into an operating lease agreement with a bank leasing
company for a 48-story office building which is being utilized as the corporate
headquarters of the System Companies.
The Company's capital requirements have not been significantly affected by the
requirements of the federal Clean Air Act, as amended (Clean Air Act). Although
TU Electric is unable to fully determine the cost of compliance with the Clean
Air Act, it is not expected to have a significant impact on the Company. During
1994, installation of continuous emissions monitoring systems was completed at a
total cost of approximately $38 million. Any additional required capital costs,
as well as any increased operating costs, associated with these new requirements
or compliance measures are expected to be recoverable through rates, as similar
costs have been recovered in the past. Environmental expenditures for 1995 are
estimated to be $58 million.
The National Energy Policy Act of 1992 (Energy Act) addresses a wide range of
energy issues and is intended to increase competition in electric generation and
broaden access to electric transmission systems. In addition, legislation is
currently being considered by the Texas legislature which, if enacted, could
impact the structure of the Public Utility Commission of Texas (PUC) and its
regulatory practices and could lead to increased competition in some aspects of
the electric utility industry. Although TU Electric and Southwestern Electric
Service Company (SESCO) are unable to predict the ultimate impact of the Energy
Act and any related regulations or any potential state legislation on their
operations, they believe that such actions are consistent with the trend toward
increased competition in the energy industry.
While TU Electric and SESCO have experienced competitive pressures in the
wholesale market resulting in approximately 379 MW loss of load for TU Electric
since the beginning of 1993, wholesale sales represented a relatively low
percentage of total consolidated operating revenues in 1994. TU Electric and
SESCO are unable to predict the extent of future competitive developments in
either the wholesale or retail markets or what impact, if any, such developments
may have on their operations. (See Item 1. Business - Competition.)
RESULTS OF OPERATION
Operating revenues increased approximately 4% and 11% for the years ended
December 31, 1994 and 1993, respectively. The following table details the
factors contributing to these changes:
<TABLE>
<CAPTION>
INCREASE (DECREASE)
-------------------
FACTORS 1994 1993
------- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Base rate revenue............................ $452,677 $357,076
Fuel revenue................................. (130,077) 150,707
Power cost recovery factor revenue........... (38,955) (1,313)
Unbilled revenue and other................... (54,614) 20,166
-------- --------
Total...................................... $229,031 $526,636
======== ========
</TABLE>
Base rate revenue increased during the last two years due to increased energy
sales and higher rate levels implemented in August 1993. Energy sales increased
approximately 4% and 6% for 1994 and 1993, respectively. The increase in energy
sales in 1994 was due primarily to increased billing days and an increase in
commercial and industrial usage, partially offset by milder than normal weather.
The increase in 1993 resulted from more normal weather conditions and an
increase in customers. The rate increase placed in effect in August 1993
increased TU Electric's base rate revenues, net of amounts ultimately refunded,
by approximately $343 million and $177 million in 1994 and 1993, respectively.
Fuel revenue decreased in 1994
25
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION (Continued)
RESULTS OF OPERATION -- (CONTINUED)
due primarily to a reduction in gas prices and increased nuclear generation as
compared to 1993. The increase in fuel revenue in 1993 resulted from increased
energy sales and fuel costs. The decrease in unbilled revenue and other in 1994
resulted from milder than normal weather in December 1994 and an increase in the
number of billing days in 1994. (See Note 12 to Consolidated Financial
Statements.)
With respect to operating expenses, fuel and purchased power expense decreased
approximately 7% and increased approximately 11% for 1994 and 1993,
respectively. Fuel and purchased power expense decreased in 1994 primarily due
to a reduction in gas prices, lignite requirements, and purchase power
commitments, and an increased utilization of nuclear fuel, offset by increased
energy sales. Fuel and purchased power expense increased for 1993 primarily due
to increased energy sales and gas prices partially offset by increased
utilization of nuclear fuel. (See Item 1. Business -- Fuel Supply and Purchased
Power and Item 6. Selected Financial Data -- Consolidated Operating Statistics.)
Total operating expenses, excluding fuel and purchased power, increased
approximately 9% and 16% for 1994 and 1993, respectively. Operation and
depreciation expenses increased in 1994 primarily as a result of a full year's
operation of Comanche Peak Unit 2, and increases in uncollectible accounts
expense and demand-side management program costs. Operation, maintenance and
depreciation expenses increased in 1993 as a result of the commencement of
commercial operation of Comanche Peak Unit 2 in August 1993. Operation expense
in 1993 also increased due to higher pension costs and other postretirement
benefits costs, partially offset by lower employee labor costs. Maintenance
expense for both periods was also affected by a 1993 review of TU Electric's
inventory and subsequent adjustments recorded during the third and fourth
quarters of 1993. Taxes other than income increased in both periods due
primarily to increased local gross receipts taxes resulting from higher tax
rates and increased revenues and an increase in ad valorem taxes charged to
operation which were previously capitalized, and increased in 1994, due to a
refund of franchise taxes in the prior period of approximately $23,875,000.
AFUDC decreased approximately 92% and 14% in 1994 and 1993, respectively. The
decrease in both periods was primarily due to the discontinuation of the accrual
of AFUDC on Comanche Peak Unit 2 when such unit achieved commercial operation
in August 1993.
The regulatory disallowances in 1993 reflect charges resulting from a
settlement agreement among the parties in Docket 11735.
Other income and deductions -- net decreased over the prior period primarily
due to changes in interest income on temporary cash investments and a decrease
in interest income on under-recovered fuel revenue.
Federal income taxes -- other income increased in 1994 and decreased in 1993
due primarily to the effect of recording taxes associated with the regulatory
disallowance recorded in 1993. (See Note 7 to Consolidated Financial
Statements.)
Total interest charges, excluding AFUDC, decreased approximately 3% and less
than 1% for 1994 and 1993, respectively. Interest on mortgage bonds decreased
over the prior period as a result of reduced interest requirements due to the
Company's refinancing efforts, partially offset by increased interest
requirements for new issues sold. Interest on other long-term debt decreased in
both periods due to the continuing retirement
26
<PAGE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATION (Concluded)
RESULTS OF OPERATION -- (CONCLUDED)
of debt incurred on the purchases of the minority ownership interests in
Comanche Peak. Other interest expense increased over the prior period due
primarily to interest on bonded rates refunded, an increase in short-term
interest rates, and increased amortization of debt issuance expenses and
redemption premiums.
Preferred stock dividends decreased approximately 12% and 3% for 1994 and
1993, respectively, primarily due to the redemption of series with higher
dividend rates partially offset, in 1993, by dividends on new issues.
The major factors affecting earnings in 1994 and 1993 were the implementation
of the Docket 11735 rate increase, the effect of recording regulatory
disallowances, the discontinuation of the accrual of AFUDC on Comanche Peak Unit
2 and the commencement of depreciation on approximately $668 million of
investment in Comanche Peak Unit 2 incurred after the end of the Docket 11735
test year which was not included in rates. Consolidated net income increased
and decreased over the prior periods by approximately 47% for 1994 and 1993,
respectively.
POSSIBLE CHANGE IN ACCOUNTING STANDARDS
The Financial Accounting Standards Board (FASB) is expected to issue during
1995 a new accounting standard addressing the impairment of long-lived assets.
Based upon FASB's exposure draft, which is subject to change, and its
deliberations, any new standard would likely prescribe a methodology for
assessing and measuring impairments in the carrying values of certain assets.
If such new standard were adopted, the Company may be subject to a stricter
standard for assessing asset impairment in the future.
27
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
OPERATING REVENUES.............................................. $5,663,543 $5,434,512 $4,907,876
---------- ---------- -----------
OPERATING EXPENSES
Fuel and purchased power....................................... 1,729,091 1,858,054 1,678,514
Operation...................................................... 872,272 812,555 731,344
Maintenance.................................................... 304,941 350,004 301,251
Depreciation and amortization.................................. 549,539 439,548 421,300
Federal income taxes (Notes 7 and 10).......................... 316,995 322,118 171,088
Taxes other than income........................................ 559,144 465,307 441,060
---------- ---------- -----------
Total operating expenses...................................... 4,331,982 4,247,586 3,744,557
---------- ---------- -----------
OPERATING INCOME................................................ 1,331,561 1,186,926 1,163,319
---------- ---------- -----------
OTHER INCOME (LOSS)
Allowance for equity funds used during construction............ 10,774 150,125 194,462
Regulatory disallowances....................................... -- (359,556) --
Other income and deductions -- net............................. 27,605 33,518 35,837
Federal income taxes (Notes 7 and 10).......................... (9,643) 112,574 (11,417)
---------- ---------- -----------
Total other income (loss)..................................... 28,736 (63,339) 218,882
---------- ---------- -----------
TOTAL INCOME.................................................... 1,360,297 1,123,587 1,382,201
---------- ---------- -----------
INTEREST CHARGES
Interest on mortgage bonds..................................... 567,543 611,090 598,235
Interest on other long-term debt............................... 92,524 109,459 122,494
Other interest................................................. 66,809 32,254 33,586
Allowance for borrowed funds used during construction.......... (11,261) (113,108) (109,736)
---------- ---------- -----------
Total interest charges........................................ 715,615 639,695 644,579
PREFERRED STOCK DIVIDENDS OF SUBSIDIARY......................... 101,883 115,232 118,418
---------- ---------- -----------
Income before cumulative effect of a change
in accounting principle........................................ 542,799 368,660 619,204
Cumulative effect of a change in accounting for unbilled
revenue (Net of taxes of $41,679,000)(Note 12)................. -- -- 80,907
---------- ---------- -----------
CONSOLIDATED NET INCOME......................................... $ 542,799 $ 368,660 $ 700,111
========== ========== ===========
Average shares of common stock outstanding (thousands).......... 225,834 221,555 214,850
Earnings per share (on average shares outstanding):
Before cumulative effect of a change in accounting principle... $2.40 $1.66 $2.88
Cumulative effect of a change in accounting
for unbilled revenue.......................................... -- -- 0.38
----- ----- ------
Total earnings per share...................................... $2.40 $1.66 $3.26
===== ===== ======
Dividends declared per share of common stock.................... $3.08 $3.08 $3.04
</TABLE>
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
BALANCE AT BEGINNING OF YEAR.................................... $1,842,413 $2,171,018 $2,125,889
ADD -- Consolidated net income.................................. 542,799 368,660 700,111
LESOP dividend deduction tax benefit (Note 7)............ 6,733 6,975 --
---------- ---------- -----------
Total.......................................................... 2,391,945 2,546,653 2,826,000
DEDUCT -- Dividends declared on common stock (for amounts per
share, see Statements of Consolidated Income)........ 695,590 682,438 653,146
Preferred stock redemption costs (net)................ 5,105 21,802 1,836
---------- ---------- -----------
BALANCE AT END OF YEAR.......................................... $1,691,250 $1,842,413 $2,171,018
========== ========== ===========
</TABLE>
28
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Consolidated net income............................................... $ 542,799 $ 368,660 $ 700,111
Adjustments to reconcile consolidated net income to cash
provided by operating activities:
Depreciation and amortization (including amounts charged to fuel).... 710,196 543,441 477,201
Deferred federal income taxes -- net................................. 261,452 82,290 171,487
Federal investment tax credits -- net................................ (26,427) (22,383) (22,957)
Allowance for equity funds used during construction.................. (10,774) (150,125) (194,462)
Regulatory disallowances............................................. -- 359,556 --
Cumulative effect of a change in accounting for
unbilled revenue - net.............................................. -- -- (80,907)
Changes in assets and liabilities:
Receivables......................................................... 10,408 (90,561) 103,394
Inventories......................................................... 2,673 11,112 (23,545)
Accounts payable.................................................... (43,684) 2,797 20,599
Interest and taxes accrued.......................................... (77,795) 14,449 2,267
Other working capital............................................... (131,506) 126,919 10,757
Over/(under) - recovered fuel revenue -- net of deferred taxes...... 113,693 (83,501) (27,854)
Voluntary retirement/severance program.............................. -- -- (119,668)
Other -- net........................................................ 68,549 29,751 10,179
----------- ----------- -----------
Cash provided by operating activities.............................. 1,419,584 1,192,405 1,026,602
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Sales of securities:
First mortgage bonds................................................. 378,340 2,448,465 1,808,595
Other long-term debt................................................. -- 325,000 --
Preferred stock...................................................... 123 731,342 --
Common stock......................................................... 62,102 240,971 253,660
Retirement of long-term debt and preferred stock...................... (1,176,023) (2,944,339) (1,851,325)
Change in notes payable............................................... 363,886 (253,100) --
Common stock dividends paid........................................... (694,355) (674,869) (646,002)
Debt premium, discount, financing and reacquisition expenses.......... (21,799) (141,545) (126,916)
----------- ----------- -----------
Cash used in financing activities.................................. (1,087,726) (268,075) (561,988)
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures............................................. (444,245) (871,450) (1,136,971)
Allowance for equity funds used during construction (excluding
amount for nuclear fuel)............................................. 4,802 138,950 179,519
Change in construction receivables/payables -- net.................... 3,897 (32,847) (2,907)
----------- ----------- -----------
Cash construction expenditures...................................... (435,546) (765,347) (960,359)
Non-utility property -- net........................................... (14,967) (10,171) (12,024)
Nuclear fuel (excluding allowance for equity funds used
during construction)................................................. (62,655) (16,889) (33,656)
Other investments..................................................... (23,848) (17,213) (9,399)
----------- ----------- -----------
Cash used in investing activities.................................. (537,016) (809,620) (1,015,438)
----------- ----------- -----------
NET CHANGE IN CASH AND CASH EQUIVALENTS................................ (205,158) 114,710 (550,824)
CASH AND CASH EQUIVALENTS -- BEGINNING BALANCE......................... 212,584 97,874 648,698
----------- ----------- -----------
CASH AND CASH EQUIVALENTS -- ENDING BALANCE............................ $ 7,426 $ 212,584 $ 97,874
=========== =========== ===========
</TABLE>
29
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
UTILITY PLANT
In service:
Production.......................................................... $16,516,326 $16,476,725
Transmission........................................................ 1,573,634 1,542,399
Distribution........................................................ 4,048,867 3,822,202
General............................................................. 456,212 477,515
----------- -----------
Total.............................................................. 22,595,039 22,318,841
Less accumulated depreciation....................................... 5,023,003 4,595,533
----------- -----------
Utility plant in service less accumulated depreciation............. 17,572,036 17,723,308
Construction work in progress......................................... 1,060,731 1,040,483
Nuclear fuel (net of accumulated amortization: 1994 -- $205,420,000;
1993 -- $114,865,000)................................................ 298,964 320,891
Held for future use................................................... 46,197 41,649
----------- -----------
Utility plant less accumulated depreciation and amortization....... 18,977,928 19,126,331
Less reserve for regulatory disallowances (Note 10)................... 1,308,460 1,308,460
----------- -----------
Net utility plant.................................................. 17,669,468 17,817,871
----------- -----------
INVESTMENTS
Non-utility property.................................................. 569,337 554,370
Other investments..................................................... 122,906 99,748
----------- -----------
Total investments.................................................. 692,243 654,118
----------- -----------
CURRENT ASSETS
Cash in banks......................................................... 7,426 7,841
Temporary cash investments -- at cost................................. -- 204,743
Special deposits...................................................... 1,002 21,975
Accounts receivable:
Customers (Note 9).................................................. 201,687 224,670
Other............................................................... 38,712 27,439
Allowance for uncollectible accounts................................ (5,095) (6,394)
Inventories -- at average cost:
Materials and supplies.............................................. 194,271 194,226
Fuel stock.......................................................... 145,662 148,380
Prepaid taxes......................................................... 21,629 17,776
Other prepayments..................................................... 41,871 44,250
Deferred federal income taxes (Note 7)................................ 37,113 43,543
Other current assets.................................................. 11,216 10,716
----------- -----------
Total current assets............................................... 695,494 939,165
----------- -----------
DEFERRED DEBITS
Unamortized regulatory assets:
Debt reacquisition costs............................................ 284,563 287,430
Cancelled lignite unit costs........................................ 18,049 20,678
Rate case costs..................................................... 64,862 66,508
Litigation and settlement costs..................................... 72,685 72,685
Voluntary retirement/severance program.............................. 184,340 212,367
Recoverable deferred federal income taxes -- net (Note 7)........... 1,201,688 1,230,418
Other regulatory assets............................................. 15,939 21,242
Under-recovered fuel revenue.......................................... 29,860 204,772
Other deferred debits................................................. 36,902 63,559
----------- -----------
Total deferred debits.............................................. 1,908,888 2,179,659
Less reserve for regulatory disallowances (Note 10)................... 72,685 72,685
----------- -----------
Net deferred debits................................................ 1,836,203 2,106,974
----------- -----------
Total............................................................ $20,893,408 $21,518,128
=========== ===========
</TABLE>
30
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
CAPITALIZATION
Common stock without par value -- net (Note 3):
Authorized shares -- 500,000,000
Outstanding shares: 1994 -- 225,841,037; 1993 -- 224,345,422....... $ 4,798,797 $ 4,728,580
Retained earnings.................................................... 1,691,250 1,842,413
----------- -----------
Total common stock equity.......................................... 6,490,047 6,570,993
Preferred stock:
Not subject to mandatory redemption (Note 5)........................ 870,190 1,083,008
Subject to mandatory redemption (Note 5)............................ 387,482 396,917
Long-term debt, less amounts due currently (Note 6).................. 7,888,413 8,379,826
----------- -----------
Total capitalization............................................... 15,636,132 16,430,744
----------- -----------
CURRENT LIABILITIES
Notes payable -- commercial paper (Note 2)........................... 363,886 --
Long-term debt due currently......................................... 74,610 151,105
Accounts payable..................................................... 219,661 260,634
Dividends declared................................................... 197,564 200,410
Customers' deposits.................................................. 56,391 50,798
Taxes accrued........................................................ 243,753 310,091
Interest accrued..................................................... 183,545 195,002
Refunds due to customers............................................. -- 141,153
Other current liabilities............................................ 95,329 106,192
----------- -----------
Total current liabilities.......................................... 1,434,739 1,415,385
----------- -----------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Accumulated deferred federal income taxes (Note 7)................... 2,852,462 2,686,409
Unamortized federal investment tax credits........................... 679,104 705,531
Other deferred credits and noncurrent liabilities.................... 290,971 280,059
----------- -----------
Total deferred credits and other noncurrent liabilities............ 3,822,537 3,671,999
COMMITMENTS AND CONTINGENCIES (Note 11)............................... ----------- -----------
Total.............................................................. $20,893,408 $21,518,128
=========== ===========
</TABLE>
See accompanying Notes to Consolidated Financial Statements.
31
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES
System of Accounts -- The accounting records of Texas Utilities Electric
Company (TU Electric), the principal subsidiary of Texas Utilities Company
(Company), and Southwestern Electric Service Company (SESCO) are maintained in
accordance with the Federal Energy Regulatory Commission's Uniform System of
Accounts as adopted by the Public Utility Commission of Texas (PUC).
Consolidation -- The consolidated financial statements include the Company and
its subsidiaries (System Companies). All significant intercompany items and
transactions have been eliminated in consolidation. Certain financial statement
items for 1993 and 1992 have been reclassified to conform to the 1994
presentation.
In May 1994, Texas Utilities Properties Inc. (TU Properties), a new wholly-
owned subsidiary of the Company, was incorporated under the laws of the State of
Texas. The principal function of TU Properties is to own, lease and manage real
and personal properties, primarily for System Companies. The activities of TU
Properties are not expected to have a material effect on the Company's results
of operation or financial position.
Utility Plant -- Utility plant is stated at original cost. The cost of
property additions to utility plant includes labor and materials, applicable
overhead and payroll-related costs and an allowance for funds used during
construction.
Allowance For Funds Used During Construction -- Allowance for funds used
during construction (AFUDC) is a cost accounting procedure whereby amounts based
upon interest charges on borrowed funds and a return on equity capital used to
finance construction are added to utility plant. The accrual of AFUDC is in
accordance with generally accepted accounting principles for the industry, but
does not represent current cash income.
TU Electric is capitalizing AFUDC, compounded semi-annually, on expenditures
for ongoing construction work in progress (CWIP) and nuclear fuel in process not
otherwise allowed in rate base by regulatory authorities. In connection with the
implementation of Financial Accounting Standards Board Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (Statement 109) in
1993, TU Electric uses a rate that reflects the cost of funds plus a component
for income taxes (gross rate). For 1994, a gross rate of 8.6% was used to
capitalize AFUDC. This rate was effective in December 1994, retroactive to
January 1994. Prior to the implementation of this rate, AFUDC was capitalized at
a rate of 9.25% in 1994. In 1993, a gross rate of 10.4% was used for all CWIP.
In 1992, TU Electric used a net-of-tax rate of 8.8% on projects commenced before
March 1, 1986, and a gross rate of 10.4% on projects commenced thereafter. Rates
were determined on the basis of, but are less than, the cost of capital used to
finance the construction program.
Depreciation of Utility Plant -- Depreciation is generally based upon an
amortization of the original cost of depreciable properties (net of regulatory
disallowances) on a straight-line basis over the estimated service lives of the
properties. Depreciation as a percent of average depreciable property
approximated 2.6%, 2.5% and 2.8% for 1994, 1993 and 1992, respectively.
Depreciation also includes an amount for Comanche Peak nuclear generating
station (Comanche Peak) decommissioning costs which is being accrued over the
lives of the units and deposited to external trust funds. (See Note 11.)
32
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
1. SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
Amortization of Nuclear Fuel and Refueling Outage Costs -- The amortization of
nuclear fuel in the reactors (net of regulatory disallowances) is calculated on
the units of production method and, subsequent to commercial operation, is
included in nuclear fuel expense. TU Electric accrues a provision for costs
anticipated to be incurred during the next scheduled Comanche Peak refueling
outage.
Other Investments -- The difference of $45,462,000 between the amount at which
the investments in subsidiaries is carried by the Company and the underlying
book equity of such subsidiaries at the respective dates of acquisition is
included in other investments.
Revenues -- Revenues include billings under approved rates (including a fixed
fuel factor) applied to meter readings each month on a cycle basis and an
accrual of base rate revenue for energy provided after cycle billing but not
billed through the end of each month (see Note 12). Revenues also include an
amount for under- or over-recovery of fuel revenue representing the difference
between actual fuel cost and billings under the approved fixed fuel factor and a
provision that generally allows recovery through a Power Cost Recovery Factor,
on a monthly basis, of the capacity portion of purchased power cost and wheeling
cost from qualifying facilities not included in base rates. The fuel portion of
purchased power cost is included in the fixed fuel factor. A utility's fuel
factor can be revised upward or downward every six months, according to a
specified schedule. A utility is required to petition to make either surcharges
or refunds to ratepayers, together with interest based on a twelve month average
of prime commercial rates, for any material cumulative under- or over-recovery
of fuel costs. If the cumulative difference of the under- or over-recovery, plus
interest, is in excess of 4% of the annual estimated fuel costs most recently
approved by the PUC, it will be deemed to be material. A procedure exists for an
expedited change in fuel factors in the event of an emergency. Final
reconciliation of fuel costs must be made either in a reconciliation proceeding,
which may cover no more than three years and no less than one year, or in a
general rate case. TU Electric plans to file for a fuel reconciliation
proceeding by the end of 1995 for the reconciliation period of July 1992 through
June 1995.
Federal Income Taxes -- The System Companies file a consolidated federal
income tax return and federal income taxes are allocated to all System Companies
based upon their taxable income or loss. Deferred federal income taxes are
currently provided for temporary differences between the book and tax basis of
assets and liabilities (including the provision for regulatory disallowances).
Generally, such differences result primarily from the use of liberalized
depreciation and cost recovery deductions allowable under the Internal Revenue
Code, the under- or over-recovery of fuel revenue and unbilled revenues accrued
for tax purposes. Investment tax credits are normally amortized to income over
the estimated service lives of the properties. For 1992, the System Companies'
taxes were provided for under the provisions of Accounting Principles Board
Opinion No. 11, "Accounting for Income Taxes". (See Note 7 for change in
accounting for income taxes.)
Consolidated Cash Flows -- For purposes of reporting cash flows, temporary
cash investments purchased with a remaining maturity of three months or less are
considered to be cash equivalents.
33
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1. SIGNIFICANT ACCOUNTING POLICIES -- (CONCLUDED)
The supplemental schedule below details cash payments and noncash investing
and financing activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
CASH PAYMENTS
Interest (net of amounts capitalized)....... $678,682 $637,186 $600,273
Income taxes................................ $220,316 $ 74,756 $ 28,033
NONCASH INVESTING AND FINANCING ACTIVITIES
Acquisition of SESCO:
Book value of assets acquired.............. $ -- $ 69,521 $ --
Goodwill acquired.......................... -- 32,059 --
Less: Liabilities assumed................. -- (39,991) --
Less: Stock issued -- (59,976) --
--------- -------- --------
Cash paid................................. -- 1,613 --
Less: Cash acquired........................ -- 376 --
--------- -------- --------
Net cash.................................. $ -- $ 1,237 $ --
========= ======== ========
</TABLE>
2. SHORT-TERM FINANCING
At December 31, 1994, the Company and TU Electric had joint lines of credit
aggregating $1,000,000,000 under credit facility agreements (Agreements) with a
group of commercial banks. The Agreements have two facilities, for each of which
the Company pays a fee. Facility A provides for borrowings up to $300,000,000
and terminates April 28, 1995. The Company and TU Electric intend to negotiate
an extension of this facility. Facility B provides for borrowings up to
$700,000,000 and terminates April 29, 1999. The Company's borrowings under the
Agreements are limited to $250,000,000. Borrowings under the Agreements will be
used for working capital and other corporate purposes, including commercial
paper backup.
At December 31, 1994, TU Electric had $363,886,000 of commercial paper
outstanding with interest rates ranging from 5.99% to 6.80%. During the years
1994, 1993 and 1992, average amounts outstanding to banks for borrowings were
$66,042,000, $84,934,000 and $277,306,000, respectively and to holders of
commercial paper were $238,401,000, $54,401,000 and $8,069,000, respectively.
During such periods, weighted average interest rates to banks for borrowings
were 4.92%, 3.84% and 4.28%, respectively and to holders of commercial paper
were 4.94%, 3.72% and 3.79%, respectively. At December 31, 1994, the total of
short-term borrowings authorized by the Board of Directors of the Company from
banks or other lenders was $1,075,000,000.
34
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
3. COMMON STOCK
The Company issued shares of its authorized but unissued common stock as
follows:
<TABLE>
<CAPTION>
AUTOMATIC DIVIDEND EMPLOYEES' THRIFT PLAN
REINVESTMENT AND COMMON AND EMPLOYEE
PUBLIC OFFERING STOCK PURCHASE PLAN STOCK OWNERSHIP PLAN TOTAL
----------------------- ----------------------- ------------------------ --------------------------
YEAR SHARES/*/ AMOUNT SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
- ---- --------- ------ ------ ------ ------ ------- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1994 -- -- 1,364,690 $ 56,671,000 130,925 $ 5,431,000 1,495,615 $ 62,102,000
1993 1,420,316 $ 59,976,000 5,163,587 220,848,000 445,465 20,123,000 7,029,368 300,947,000
1992 -- -- 6,004,151 229,278,000 611,530 24,382,000 6,615,681 253,660,000
___________________
</TABLE>
* Shares issued for public offering in 1993 were used in connection with the
acquisition of SESCO.
At December 31, 1994, 1,997,005 shares of the authorized but unissued common
stock of the Company were reserved for issuance and sale pursuant to the above
plans.
In February 1994, the Company amended its Automatic Dividend Reinvestment and
Common Stock Purchase Plan. The amendments included, among other things, the
option to purchase common stock in the open market through an independent broker
to meet share requirements under the plan. Beginning in March 1994, requirements
under the Automatic Dividend Reinvestment and Common Stock Purchase Plan and the
Employees' Thrift Plan of the Texas Utilities Company System (Thrift Plan) have
been met through open market purchases of common stock.
In 1990, the Thrift Plan borrowed $250,000,000 in the form of a note payable
from an outside lender and purchased 7,142,857 shares of common stock (LESOP
Shares) from the Company in connection with the leveraged employee stock
ownership provision of the Thrift Plan. LESOP Shares are held by the trustee
until allocated to Thrift Plan participants when required to meet the System
Companies' obligations under terms of the Thrift Plan. The Company has purchased
the note from the outside lender, which has been recorded as a reduction to
common stock equity. The Thrift Plan uses dividends on the LESOP Shares
purchased and contributions from the System Companies, if required, to repay
interest and principal on the note. Common stock equity increases at such time
as LESOP Shares are allocated to participants' accounts even though shares of
common stock outstanding include unallocated LESOP Shares held by the trustee.
Allocations to participants' accounts in 1994, 1993 and 1992 increased common
stock equity by $8,115,000, $8,114,000 and $8,072,000, respectively.
The Company has 50,000,000 authorized shares of serial preference stock having
a par value of $25 a share, none of which has been issued.
4. RETAINED EARNINGS
The articles of incorporation and the mortgages, as supplemented, of TU
Electric and SESCO, contain provisions which, under certain conditions, restrict
distributions on or acquisitions of their common stock. At December 31, 1994,
$154,542,000 of retained earnings were thus restricted as a result of such
provisions. Retained earnings at such date also included $431,243,000,
representing the Company's equity in undistributed earnings since acquisition
included in transfers by TU Electric from its retained earnings to stated value
of common stock. The total of such restricted retained earnings at December 31,
1994 was $585,785,000.
35
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. AUTHORIZED PREFERRED STOCK OF TU ELECTRIC (CUMULATIVE, WITHOUT PAR VALUE,
ENTITLED UPON LIQUIDATION TO A $100 SHARE; 17,000,000 SHARES)
<TABLE>
<CAPTION>
REDEMPTION PRICE PER SHARE
SHARES OUTSTANDING AMOUNT (BEFORE ADDING ACCUMULATED DIVIDENDS)
-------------------------------------
DIVIDEND RATE DECEMBER 31, DECEMBER 31, DECEMBER 31,1994 EVENTUAL MINIMUM
- ---------------------------------- -------------------- --------------------- ---------------- ------------------
1994 1993 1994 1993
---- ---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C> <C> <C>
NOT SUBJECT TO MANDATORY REDEMPTION
- -----------------------------------
$ 4.50 series................... 74,367 74,367 $ 7,440 $ 7,440 $110.00 $110.00
4.00 series (Dallas Power).... 70,000 70,000 7,049 7,049 103.56 103.56
4.56 series (Texas Power)..... 133,628 133,628 13,371 13,371 112.00 112.00
4.00 series (Texas Electric) 110,000 110,000 11,000 11,000 102.00 102.00
4.56 series (Texas Electric) 64,947 64,947 6,560 6,560 112.00 112.00
4.24 series................... 100,000 100,000 10,081 10,081 103.50 103.50
4.64 series................... 100,000 100,000 10,016 10,016 103.25 103.25
4.84 series................... 70,000 70,000 7,000 7,000 101.79 101.79
4.00 series (Texas Power)..... 70,000 70,000 7,000 7,000 102.00 102.00
4.76 series................... 100,000 100,000 10,000 10,000 102.00 102.00
5.08 series................... 80,000 80,000 8,004 8,004 103.60 103.60
4.80 series................... 100,000 100,000 10,009 10,009 102.79 102.79
4.44 series................... 150,000 150,000 15,061 15,061 102.61 102.61
7.20 series................... 200,000 200,000 20,044 20,044 103.21 103.21
7.80 series................... -- 299,875 -- 30,021 -- --
6.84 series................... 200,000 200,000 20,023 20,023 103.05 103.05
7.24 series................... 249,800 249,800 25,100 25,100 103.42 103.42
7.44 series................... -- 300,000 -- 30,006 -- --
7.48 series................... -- 300,000 -- 30,073 -- --
8.20 series................... -- 300,000 -- 30,108 -- --
8.44 series................... -- 300,000 -- 30,046 -- --
8.16 series................... -- 299,475 -- 29,616 -- --
8.20 series (a)............... 1,250,000 1,250,000 120,637 120,759 (b) 100.00
7.98 series................... 500,000 500,000 49,361 49,312 (b) 100.00
7.50 series (a)............... 2,000,000 2,000,000 194,048 194,021 (b) 100.00
7.22 series (a)............... 1.715,925 1,750,000 166,290 169,575 (b) 100.00
Adjustable rate series A (c)..... 1,000,000 1,000,000 98,200 98,200 100.00 100.00
Adjustable rate series B (c)..... 548,561 850,000 53,896 83,513 103.00 100.00
--------- ---------- -------- ----------
Total....................... 8,887,228 11,022,092 $870,190 $1,083,008
========= ========== ======== ==========
SUBJECT TO MANDATORY REDEMPTION (D)
- -----------------------------------
$ 9.64 series (e)............... 900,000 1,000,000 $ 89,902 $ 99,823 (f) (f)
10.375 series................... 750,000 750,000 74,656 74,541 (b) $100.00
9.875 series................... 250,000 250,000 24,843 24,798 (b) 100.00
6.98 series.................... 1,000,000 1,000,000 99,047 98,874 (b) 100.00
6.375 series................... 1,000,000 1,000,000 99,034 98,881 (b) 100.00
--------- ---------- -------- ----------
Total....................... 3,900,000 4,000,000 $387,482 $ 396,917
========= ========== ======== ==========
</TABLE>
- -----------------------------------------
(a) The preferred stock series is the underlying preferred stock for depositary
shares that were issued to the public. Each depositary share represents
one quarter of a share of underlying preferred stock.
(b) Preferred stock series is not redeemable at December 31, 1994.
(c) Adjustable rate series A bears a dividend rate for the period ended January
31, 1995, of $6.50 per annum and adjustable rate series B bears a dividend
rate for the period ended December 31, 1994, of $7.00 per annum.
(d) TU Electric is required to redeem at a price of $100 per share plus
accumulated dividends a specified minimum number of shares annually or
semi-annually on the initial/next dates shown below. These redeemable
shares may be called, purchased or otherwise acquired. Certain issues may
not be redeemed at the option of TU Electric prior to 2003. TU Electric
may annually call for redemption, at its option, an aggregate of up to
twice the number of shares shown below for each series at a price of $100
per share plus accumulated dividends, except for the $9.64 series which may
be redeemed in a minimum amount of 10,000 shares at any time at a price of
$100 per share plus accumulated dividends plus a component at a variable
price per share which is designed to maintain the expected yield at
issuance:
36
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. PREFERRED STOCK OF TU ELECTRIC (CUMULATIVE, WITHOUT PAR VALUE, ENTITLED UPON
LIQUIDATION TO $100 A SHARE; AUTHORIZED 17,000,000 SHARES) -- (CONCLUDED)
<TABLE>
<CAPTION>
MINIMUM REDEEMABLE INITIAL/NEXT DATE OF
SERIES SHARES MANDATORY REDEMPTION
------ ---------------------- --------------------
<S> <C> <C>
$ 9.64 125,000 semi-annually 5/1/95
10.375 150,000 annually 4/1/96
9.875 50,000 annually 10/1/96
6.98 50,000 annually 7/1/03
6.375 50,000 annually 10/1/03
</TABLE>
Preferred stock mandatory redemption requirements for the next five years
are $25 million in 1995, $45 million in 1996, $45 million in 1997, $35
million in 1998 and $20 million in 1999. The carrying value of preferred
stock subject to mandatory redemption is being increased periodically to
equal the redemption amounts at the mandatory redemption dates with a
corresponding increase in preferred stock dividends.
(e) Under certain circumstances relating to a change in federal tax law
governing the dividends received deduction applicable to eligible
corporations, the dividend rate of the $9.64 series may increase to a
maximum of $10.74.
(f) The redemption price is calculated on the business day next preceding the
settlement date at a price of $100 per share plus accumulated dividends plus
a component which is designed to maintain the expected yield at issuance.
In January 1995, TU Electric reacquired 62,500 shares of the $7.22 series
and 23,750 shares of the $7.50 series.
37
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. LONG-TERM DEBT, LESS AMOUNTS DUE CURRENTLY
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
First mortgage bonds:
4-1/2% series due 1995...................... $ -- $ 14,000
4-1/2% series due 1995...................... -- 16,000
4.70 % series due 1995...................... -- 710
4-7/8% series due 1996...................... -- 20,000
5 % series due 1996...................... -- 20,000
5-1/8% series due 1996...................... -- 15,000
5-3/8% series due 1997...................... -- 16,000
5-1/2% series due 1997...................... -- 30,000
6-1/8% series due 1997...................... -- 18,000
6-3/8% series due 1997...................... 175,000 175,000
7-1/8% series due 1997...................... 150,000 150,000
5-1/2% series due 1998...................... 125,000 125,000
5-3/4% series due 1998...................... 150,000 150,000
5-7/8% series due 1998...................... 175,000 175,000
6-1/2% series due 1998...................... 1,095 1,110
7-3/8% series due 1999...................... 100,000 100,000
Floating rate series due 1999 (a)............... 300,000 --
9-1/2% series due 1999....................... 200,000 200,000
8-7/8% series due 2000....................... -- 25,000
7-3/8% series due 2001....................... -- 30,000
7-3/8% series due 2001....................... 150,000 150,000
7-5/8% series due 2002....................... -- 30,000
7.95 % series due 2002....................... 924 936
8 % series due 2002....................... 147,000 147,000
8-1/8% series due 2002....................... 150,000 150,000
6-3/4% series due 2003....................... 200,000 200,000
6-3/4% series due 2003....................... 100,000 100,000
6-1/4% series due 2004....................... 125,000 125,000
8-1/4% series due 2004....................... 100,000 100,000
6-3/4% series due 2005....................... 100,000 100,000
9-1/2% series due 2005....................... -- 50,000
8.60 % series due 2006....................... -- 100,000
8-7/8% series due 2006....................... -- 100,000
10.44% series due 2008....................... 150,000 150,000
9-7/8% series due 2019....................... 111,150 150,000
10 % series due 2019....................... -- 100,000
10-5/8% series due 2020....................... 250,000 250,000
9-3/4% series due 2021....................... 300,000 300,000
8-7/8% series due 2022....................... 175,000 175,000
9 % series due 2022....................... 100,000 100,000
7-7/8% series due 2023....................... 300,000 300,000
8-3/4% series due 2023....................... 200,000 200,000
7-7/8% series due 2024....................... 225,000 225,000
8-1/2% series due 2024....................... 175,000 175,000
7-3/8% series due 2025....................... 300,000 300,000
7-5/8% series due 2025....................... 250,000 250,000
Pollution control series:
Sabine River Authority of Texas
9 % series due 2007....................... 55,000 55,000
7-3/4% series due 2016....................... 70,000 70,000
8-1/8% series due 2020....................... 40,000 40,000
8-1/4% series due 2020....................... 11,000 11,000
5.55 % series due 2022....................... 75,000 75,000
6.55 % series due 2022....................... 40,000 40,000
</TABLE>
38
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
6. LONG-TERM DEBT, LESS AMOUNTS DUE CURRENTLY - (CONTINUED)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Brazos River Authority of Texas
8-1/4% series due 2016................................... $ 200,000 $ 200,000
7-7/8% series due 2017................................... 100,000 100,000
9-7/8% series due 2017................................... 112,000 112,000
9-1/4% series due 2018................................... 100,000 100,000
8-1/4% series due 2019................................... 100,000 100,000
8-1/8% series due 2020................................... 50,000 50,000
7-7/8% series due 2021................................... 100,000 100,000
Taxable series due 2021 (b)................................. 100,000 178,340
5-1/2% series due 2022................................... 50,000 50,000
5.85 % series due 2022................................... 33,465 33,465
6-5/8% series due 2022................................... 33,000 33,000
6.70 % series due 2022................................... 16,935 16,935
6-3/4% series due 2022................................... 50,000 50,000
Taxable series due 2023 (b)................................. 100,000 100,000
6.05 % series due 2025................................... 90,000 90,000
6-1/2% series due 2027................................... 46,660 46,660
6.10 % series due 2028................................... 50,000 50,000
Series 1994A due 2029 (c)................................. 39,170 --
Series 1994B due 2029 (c)................................. 39,170 --
Trinity River Authority of Texas
9 % series due 2007.................................... 12,000 12,000
Secured medium-term notes, series A............................... 30,000 45,000
Secured medium-term notes, series B............................... 130,000 140,000
Secured medium-term notes, series C............................... 95,000 135,000
---------- ----------
Total first mortgage bonds.................................... 6,953,569 7,342,156
General obligation bonds............................................ 10,000 10,000
Promissory note and debt assumed for
purchase of utility plant (d)..................................... 338,963 344,161
Senior notes........................................................ 657,164 686,800
Notes payable to banks (e).......................................... -- 75,000
Unamortized premium and discount.................................... (71,283) (78,291)
---------- ----------
Total long-term debt, less amounts
due currently.............................................. $7,888,413 $8,379,826
========== ==========
</TABLE>
_____________________________
(a) Floating rate series due May 1, 1999 bears an interest rate for the period
November 1, 1994 to January 31, 1995 of 6.0625%. Such interest rate is
reset on a quarterly basis.
(b) Taxable pollution control series consist of two series: $100,000,000 of
series 1991D due 2021 at 8.85% through June 1, 1995 and $100,000,000 of
flexible rate series 1993 due 2023 at 5.50% on December 31, 1994. Series
1993 bonds are in a flexible mode and, while in such mode, will be
remarketed for periods of less than 270 days and are secured by an
irrevocable letter of credit with maturities in excess of one year. The
Series 1991D bonds will be repriced on the mandatory tender date of June 1,
1995. TU Electric has existing lines of credit that would allow
refinancing of bonds not supported by the letter of credit on a long-term
basis should remarketing prove unsuccessful.
(c) Series 1994A and Series 1994B due 2029 are in a flexible mode with
interest rates on December 31, 1994 ranging from 3.65% to 4.50% and, while
in such mode, will be remarketed for periods of less than 270 days and are
secured by an irrevocable letter of credit with maturities in excess of one
year.
(d) In 1988, TU Electric purchased the ownership interest in Comanche Peak of
Brazos Electric Power Cooperative and issued a promissory note payable over
33 years. The note is secured by a mortgage on the acquired interest. In
1990, TU Electric purchased the ownership interest in Comanche Peak of Tex-
La Electric Cooperative of Texas, Inc. (Tex-La) and assumed debt of Tex-La
payable over approximately 32 years. The assumption is secured by a
mortgage on the acquired interest. The Company has guaranteed these
various payments.
(e) The interest rate is reset at the beginning of each period, with the
duration of each period being selected by Texas Utilities Fuel Company.
39
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
6. LONG-TERM DEBT, LESS AMOUNTS DUE CURRENTLY -- (CONCLUDED)
In January and February 1995, TU Electric reacquired $18,500,000 of 9-7/8%
First Mortgage and Collateral Trust Bonds due November 1, 2019. On February 24,
1995, TU Electric entered into a two-year term credit agreement with commercial
banks for borrowings up to $300,000,000.
Sinking fund and maturity requirements for the years 1995 through 1999 under
long-term debt instruments in effect at December 31, 1994, were as follows:
<TABLE>
<CAPTION>
SINKING MINIMUM CASH
YEAR FUND MATURITY/*/ REQUIREMENT
- ---- ------- ------------- ------------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
1995.................................................... $23,061 $ 50,710 $ 73,771
1996.................................................... 23,560 41,000 64,560
1997.................................................... 23,996 335,800 359,796
1998.................................................... 25,251 451,065 476,316
1999.................................................... 40,803 630,000 670,803
</TABLE>
________________________
* The maturity requirement does not include in 1995, which is expected to be
the mandatory tender of TU Electric's remarketed. taxable pollution control
series, equal to $100,000,000 in 1995, which is expected to be remarketed.
TU Electric first mortgage bonds are secured by the Mortgage and Deed of Trust
dated as of December 1, 1983, as supplemented, between TU Electric and Irving
Trust Company (now The Bank of New York), Trustee. SESCO first mortgage bonds
are secured by the Mortgage and Deed of Trust dated as of May 1, 1945, as
supplemented, between SESCO and NationsBank of Texas, N.A., successor Trustee.
Electric plant of TU Electric and SESCO is generally subject to the liens of
their respective mortgages.
7. FEDERAL INCOME TAXES
In January 1993, the Company adopted Statement 109, which among other things,
requires the liability method of recognition for all temporary differences,
requires that deferred tax liabilities and assets be adjusted for an enacted
change in tax laws or rates and prohibits net-of-tax accounting and reporting.
Certain provisions of Statement 109 provide that regulated enterprises are
permitted to recognize such adjustments as regulatory assets or liabilities if
it is probable that such amounts will be recovered from or returned to customers
in future rates. Accordingly, at December 31, 1994, the Company's consolidated
balance sheet reflects a regulatory asset of approximately $1.2 billion net of
an approximate $0.6 billion regulatory liability. The cumulative effect on
consolidated net income of adopting Statement 109 was not considered material to
the annual results of operation.
40
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. FEDERAL INCOME TAXES -- (CONTINUED)
The details of federal income taxes are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
Charged (credited) to operating expenses:
Current................................................ $182,160 $126,950 $ 32,934
-------- -------- --------
Deferred -- net:
Differences between depreciation methods and lives... 232,430 205,545 182,039
Certain capitalized construction costs............... (11,504) 33,251 5,189
Under-recovered fuel revenue......................... (59,224) 43,436 13,371
Early redemptions of long-term debt.................. (391) 22,944 35,543
Benefit plans........................................ (8,528) 1,251 (6,765)
Unbilled revenue..................................... 10,992 (11,990) (4,568)
Alternative minimum tax.............................. (140,010) (97,248) (43,494)
Investment tax credit carryforward................... 6,229 25,403 9,451
Amortization of tax rate differences................. (9,619) 16,411 (2,661)
Provision for refunds and related interest -- net.... 49,404 (39,871) 6,282
Prior year adjustments............................... 20,683 (2,643) 1,251
Net operating loss carryforward...................... 91,011 23,430 (73,179)
Voluntary retirement/severance costs................. (9,800) (3,566) 40,288
Other................................................ (10,411) 1,198 (1,636)
--------- --------- --------
Total............................................... 161,262 217,551 161,111
--------- --------- --------
Investment tax credits -- net.......................... (26,427) (22,383) (22,957)
--------- --------- --------
Total to operating expenses........................ 316,995 322,118 171,088
--------- --------- --------
Charged (credited) to other income:
Current................................................ (29,327) (23,484) (13,308)
--------- --------- --------
Deferred -- net:
Alternative minimum tax.............................. (25,806) (4,256) 5,856
Advance royalties.................................... 5,612 5,452 5,452
Amortization of tax rate differences................. -- (18,699) --
Regulatory disallowances............................. -- (102,034) --
Amortization of regulatory disallowances............. 41,276 29,477 22,883
Net operating loss carryforward...................... 20,808 -- (10,005)
Other................................................ (2,920) 970 539
--------- --------- --------
Total............................................... 38,970 (89,090) 24,725
--------- --------- --------
Total to other income............................. 9,643 (112,574) 11,417
--------- --------- --------
Charged (credited) to cumulative effect of a change in
accounting for unbilled revenue -- deferred........... -- -- 41,679
Charged (credited) to retained earnings:
LESOP dividend deduction.............................. (6,733) (6,975) --
--------- --------- --------
Total federal income taxes.......................... $319,905 $202,569 $224,184
========= ========= ========
</TABLE>
41
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. FEDERAL INCOME TAXES -- (CONTINUED)
The significant components of the Company's deferred federal income tax assets
and liabilities reflected net in the consolidated balance sheets are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
DEFERRED TAX ASSETS
Current:
Unbilled revenues................................................. $ 27,552 $ 38,684
Bad debt reserve.................................................. 4,448 4,941
Nuclear outage expense............................................ 5,202 --
Other............................................................. (89) (82)
---------- ----------
Total current.................................................... $ 37,113 $ 43,543
========== ==========
Non-Current:
Unamortized ITC................................................... $ 359,839 $ 373,589
Regulatory disallowances.......................................... 276,717 318,025
Alternative minimum tax........................................... 566,707 418,257
Tax rate differences.............................................. 89,289 94,581
Net operating loss carryforward................................... 30,474 132,593
Other............................................................. 55,295 99,027
---------- ----------
Total non-current................................................ 1,378,321 1,436,072
---------- ----------
DEFERRED TAX LIABILITIES
Non-Current:
Capitalized construction costs..................................... 2,062,626 2,108,906
Differences between depreciation methods and lives................. 1,695,161 1,455,812
Other.............................................................. 472,996 557,763
Total deferred tax liability...................................... 4,230,783 4,122,481
---------- ----------
NET TOTAL NON-CURRENT DEFERRED TAX LIABILITY......................... $2,852,462 $2,686,409
========== ==========
</TABLE>
42
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. FEDERAL INCOME TAXES -- (CONCLUDED)
Federal income taxes were less than the amount computed by applying the
federal statutory rate to pre-tax book income as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
Federal income taxes at statutory rate: 1994 and 1993 -- 35%; 1992 -- 34%............ $339,962 $242,703 $354,522
-------- -------- --------
Reductions in federal income taxes resulting from:
Allowance for funds used during construction......................................... 3,760 52,540 98,221
Depletion allowance.................................................................. 23,361 22,696 22,014
Amortization of investment tax credits............................................... 24,213 22,336 22,957
LESOP dividend deduction............................................................. 7,700 7,675 7,359
Amortization of tax rate differences................................................. 9,732 2,420 2,661
Reversal of prior book/tax differences:
Regulatory disallowances............................................................ -- (21,553) --
Other.............................................................................. (43,157) (27,811) (24,774)
Prior year adjustments.............................................................. (233) 722 1,222
Other............................................................................... (5,319) (18,891) 678
-------- -------- --------
Total reductions................................................................... 20,057 40,134 130,338
-------- -------- --------
Total federal income taxes........................................................ $319,905 $202,569 $224,184
======== ======== ========
Effective tax rate.................................................................... 32.9% 29.2% 21.5%
</TABLE>
The System Companies have net operating loss carryforwards of approximately
$87 million that are available to offset future ordinary taxable income. These
loss carryforwards expire in 2007. In addition, the System Companies have
approximately $567 million of alternative minimum tax credit carryforwards which
are available to offset future taxes.
As a part of its ongoing large case audit program, the Internal Revenue
Service (IRS) has audited the consolidated Federal income tax returns of the
System Companies for the years 1987 through 1990. During the course of the
audit, the IRS proposed a number of adjustments to the returns as filed, the
most significant of which relates to a proposed reclassification of certain
costs incurred in connection with the construction of Comanche Peak Unit 1 as
costs incurred to procure a nuclear operating license. The Company is unable to
predict the ultimate resolution of the issues raised in the audit and therefore
is unable to predict at this time the amount of any additional tax payment which
may be required. While the making of additional tax payments would have an
impact on the Company's cash position, the Company does not expect the outcome
of the audit to have a material effect on its financial position or results of
operation.
8. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
The System Companies have uniform retirement plans covering substantially all
employees. An employee's benefits are based on years of accredited service and
average annual earnings received during the three years of highest earnings. The
costs of the plans were determined by independent actuaries. Contributions to
the plans were determined using the frozen attained age method which is one of
the
43
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS -- (CONTINUED)
several actuarial methods allowed by the Employee Retirement Income Security
Act of 1974. For financial reporting purposes, pension cost has been determined
using the projected unit credit actuarial method. The cumulative difference
between pension cost as determined for financial reporting purposes and
contributions to the plans is recorded either as prepaid pension cost or as
accrued pension liability.
Total pension costs, including amounts charged to fuel cost, deferred and
capitalized, were comprised of the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1994 1993 1992
---- ---- ----
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
Service cost -- benefits earned during the period....................... $ 27,185 $ 23,872 $ 31,178
Interest cost on projected benefit obligation........................... 64,142 62,017 71,788
Actual return on plan assets............................................ 5,641 (93,850) (81,987)
Net amortization and deferral........................................... (72,700) 37,722 (2,468)
-------- -------- --------
Net periodic pension cost............................................... 24,268 29,761 18,511
Deferred termination cost............................................... -- -- 137,733
-------- -------- --------
Total pension cost................................................... $ 24,268 $ 29,761 $156,244
======== ======== ========
</TABLE>
The table below details the plans' funded status and amount recognized in the
Company's consolidated balance sheets as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Actuarial present value of accumulated benefits:
Accumulated benefit obligation (including vested benefits of
$599,439,000 for 1994 and $635,071,000 for 1993)........................................ $(646,967) $(686,124)
========= =========
Projected benefit obligation for service rendered to date................................ $(782,446) $(860,461)
Plan assets at fair value -- primarily equity investments,
government bonds and corporate bonds..................................................... 845,881 869,487
--------- ---------
Plan assets in excess of projected benefit obligation...................................... 63,435 9,026
Unrecognized net gain from past experience different from
that assumed and effects of changes in assumptions....................................... (193,802) (147,876)
Prior service cost not yet recognized in net periodic pension expense...................... 18,616 19,423
Unrecognized plan assets in excess of projected benefit obligation at initial application.. (7,042) (7,947)
--------- ---------
Accrued pension cost.................................................................... $(118,793) $(127,374)
========= =========
</TABLE>
Assumptions used in determination of the projected benefit obligation include
a discount rate of 8.75% for 1994 and 7.875% for 1993 and an increase in
compensation levels of 4.7% for each year. The assumed long-term rate of return
on plan assets was 9.0% for 1994 and 8.75% for 1993 and 1992.
In addition to the retirement plans, the System Companies offer certain health
care and life insurance benefits to substantially all its employees and their
eligible dependents at retirement which normally is age 65 but may be as early
as age 55 with 15 years of service. Retirees currently pay a portion of the
cost of providing such benefits and are expected to continue to do so in
the future. In January 1993, the Company adopted Statement of Financial
Accounting Standards No. 106" Employers' Accounting for Postretirement
Benefits Other Than Pensions" (Statement 106), which requires a change in the
accounting
44
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS -- (CONCLUDED)
for a company's obligation to provide health care and certain other benefits to
its retirees from the "pay-as-you-go" method to an accrual method and requires
the cost of the obligation to be recognized in the period from employment date
until full eligibility for benefits.
The System Companies' net periodic postretirement benefits cost other than
pensions, including amounts charged to fuel cost, deferred and capitalized, were
comprised of the following components:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Service cost -- benefits earned during the period......................................... $11,525 $ 8,423
Interest cost on the accumulated postretirement benefit obligation........................ 33,120 32,063
Amortization of the transition obligation................................................. 16,900 18,657
Actual return on plan assets.............................................................. 44 --
Net amortization and deferral............................................................. 1,313 --
------- -------
Net postretirement benefits cost........................................................ $62,902 $59,143
======= =======
</TABLE>
The table below details the funded status for other postretirement benefits
and amount recognized by the System Companies :
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1994 1993
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Accumulated postretirement benefit obligation (APBO):
Retirees................................................................................ $(295,910) $(260,520)
Fully eligible active employees......................................................... (16,150) (6,401)
Other active employees.................................................................. (145,766) (177,228)
--------- ---------
Total APBO................................................................................ (457,826) (444,149)
Plan assets at fair value................................................................. 21,577 --
--------- ---------
APBO in excess of plan assets............................................................. (436,249) (444,149)
Unrecognized net loss..................................................................... 78,082 53,486
Unrecognized prior service cost........................................................... 986 --
Unrecognized transition obligation........................................................ 305,605 354,489
--------- ---------
Accrued postretirement benefits cost.................................................... $ (51,576) $ (36,174)
========= =========
</TABLE>
The expected increase in costs of future benefits covered by the plan is
projected using a health care cost trend rate of 6.5% in 1995, 5.5% in 1996,
5.0% in 1997 and thereafter. A one percentage point increase in the assumed
health care cost trend rate in each future year would increase the APBO at
December 31, 1994 by approximately $57.4 million and other postretirement
benefits cost for 1994 by approximately $6.9 million. The assumed discount rate
used to measure the APBO is 8.75% for 1994 and 7.875% for 1993.
45
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
9. SALES OF ACCOUNTS RECEIVABLE
In November 1993, TU Electric terminated its then existing receivables
facility to sell receivables to certain financial institutions and entered into
a new facility with other financial institutions. Under such new facility, TU
Electric is entitled to sell and such financial institutions may purchase, on an
ongoing basis, undivided interests in customer accounts receivable representing
up to an aggregate of $350,000,000. Additional receivables are continually sold
to replace those collected. At December 31, 1994 and 1993, accounts receivable
was reduced by $300,000,000 to reflect the sales of such receivables to
financial institutions under such agreements.
10. RATE PROCEEDINGS
DOCKET 11735
In July 1994, TU Electric filed a petition in the 200th Judicial District
Court of Travis County, Texas to seek judicial review of the final order of the
PUC granting a $449 million, or 9.0%, rate increase in connection with TU
Electric's January 1993 rate increase request of $760 million, or 15.3% (Docket
11735). Other parties to the PUC proceedings also filed appeals with respect to
various portions of the order. TU Electric is unable to predict the outcome of
such appeals.
DOCKET 9300
The PUC's final order (Order) in connection with TU Electric's January 1990
rate increase request (Docket 9300) has been reviewed by the 250th Judicial
District Court of Travis County, Texas (District Court) and thereafter was
appealed to the Court of Appeals for the Third District of Texas (Court of
Appeals). In June 1994, the Court of Appeals affirmed a prudence disallowance of
$472 million provided for in the Order with respect to Comanche Peak, reversed
and remanded the portion of the District Court's judgment that had affirmed a
disallowance of $25 million relating to TU Electric's reacquisitions of the
minority owner interests in Comanche Peak nuclear fuel, and affirmed the
District Court's remand of the remainder of the disallowance of $884 million
relating to the reacquisitions of such minority owner interests. Therefore, the
Court of Appeals remanded an aggregate of $909 million of disallowances with
respect to TU Electric's reacquisitions of minority owner interests in Comanche
Peak to the PUC for reconsideration and ordered that such reconsideration be on
the basis of a prudent investment standard.
In addition, the Court of Appeals reversed the District Court's finding that
the PUC erred in ordering a refund of $2.5 million with respect to certain fuel
gas costs. Also, the Court of Appeals specified that, on remand, the PUC will be
required to re-evaluate the appropriate level of TU Electric's CWIP included in
rate base in light of its financial condition at the time of the initial hearing
and to reconsider whether the $442 million revenue increase provided for in the
PUC's final order remains the benchmark in light of this re-examination.
The same Court of Appeals had considered an appeal of another utility's rate
case and ruled, in November 1993, that prior court rulings required that tax
benefits generated by costs, including capital costs, not allowed in rates must
be used to reduce rates charged to customers. In its opinion concerning TU
Electric's Docket 9300 rate case, the Court of Appeals maintained that same
position and, accordingly, reversed the District Court in that regard. TU
Electric believes that such rulings are erroneous and not consistent with the
Texas Public Utility Regulatory Act (PURA). TU Electric contended that,
according to a Private Letter Ruling issued to TU Electric by the IRS with
respect to investment tax credits, such ratemaking treatment, to the extent
46
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
10. RATE PROCEEDINGS - (CONTINUED)
related to property classified for tax purposes as public utility property,
would result in a violation of the normalization rules under the Internal
Revenue Code of 1986, as amended. Violation of the normalization rules would
result in a significant adverse effect on TU Electric's results of operation and
liquidity. If there are normalization violations, TU Electric will forfeit its
investment tax credits which remain unamortized as of the date of the violation,
plus the ability to take advantage of accelerated tax depreciation in years to
which the violative order relates. This could result in payments to the IRS of
up to $1.3 billion.
TU Electric disagrees with certain portions of the decision of the Court of
Appeals, including specifically its decision with respect to federal income
taxes, and has filed an appeal to the Supreme Court of Texas. Other parties have
also filed appeals of this decision to the Supreme Court of Texas. TU Electric
cannot predict whether such appeals will be accepted by the Supreme Court of
Texas, and cannot predict the outcome of any such appeals or any resulting
reconsideration of these issues on remand by the PUC.
FUEL COST RECOVERY RULE
In August 1993, in accordance with the rules of the PUC, TU Electric
petitioned the PUC for recovery of under-collected fuel costs for the period
July 1992 through June 1993. The PUC approved recovery of $147.5 million of such
costs, including interest through August 1994. This recovery was applied to
mitigate the refund made by TU Electric in connection with the final order of
the PUC in TU Electric's Docket 11735 rate case. In August 1994, TU Electric
petitioned the PUC for a recovery of approximately $93 million, including
interest, in under-collected fuel costs for the period July 1993 through June
1994. The PUC approved the recovery of this amount over a six-month period
beginning in January 1995. The PUC's approvals of both these surcharges have
been appealed by certain intervenors to the district courts of Travis County,
Texas. In those appeals, those parties are contending that the PUC is without
authority to allow a fuel cost surcharge without a hearing and findings that the
costs are reasonable and necessary and that the prices charged to TU Electric by
supplying affiliates are no higher than the prices charged by those affiliates
to others for the same items or class of items. TU Electric will vigorously
defend its position in these appeals but is unable to predict their outcome.
FLEXIBLE RATE INITIATIVES
In June 1994, TU Electric filed with the PUC and municipalities with original
regulatory jurisdiction a package of proposed flexible rates. Two of the
proposed rates would allow for negotiated competitive pricing through reductions
in demand charges to retain existing large retail and wholesale customers who
have viable alternative sources of supply and would otherwise leave the system.
The remaining two rates are an economic development rider and an environmental
technology service rider. The economic development rider would provide an
incentive to attract new businesses and jobs and to encourage existing customers
to expand their facilities within TU Electric's service area. The environmental
technology service rider would provide an incentive for qualifying customers to
convert to advanced technologies that conserve total energy or improve the
environment. These new rates have been approved and implemented in over 160
municipalities with original regulatory jurisdiction, including the cities of
Dallas and Fort Worth, within TU Electric's service territory. Following
hearings on the proposed rates, however, the PUC issued an interim order on the
rate package which either rejected or significantly weakened the proposed
flexible rates, rendering them ineffective. In January 1995, TU Electric
withdrew its package of proposed rates from consideration by the PUC. This
action does not affect the over 160 municipalities where the flexible rates are
already in effect. The Sunset Review of PURA by the Texas legislature in 1995
will include several of the key issues involved in this case. Through its
involvement at the legislature and the PUC, TU Electric will continue to pursue
the possibility to offer flexible rates.
47
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. RATE PROCEEDINGS -- (CONCLUDED)
INTEGRATED RESOURCE PLAN
In October 1994, TU Electric filed an application for approval by the PUC of
its Integrated Resource Plan (IRP) for the ten-year period 1995-2004. The IRP
includes initiatives that address demand-side management resources, purchased
power, and future generating capacity which includes renewable energy sources.
TU Electric's IRP includes 288 MW of simple-cycle combustion turbines and
1,514 MW of combined-cycle combustion turbines and 300 MW of wind or other
renewable resources. Assuming these units are financed by TU Electric using
traditional methods, approximately $200 million would be added to capital
expenditures in 1997. TU Electric's IRP also includes one lignite-fueled 750 MW
unit at Twin Oak. The second lignite-fueled Twin Oak unit has been delayed
beyond the ten-year period. TU Electric expects to obtain approval of this
application by mid-1995.
11. COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURES
The Company has taken steps to substantially reduce construction expenditures
from amounts previously estimated. Such expenditures for utility related
activities, excluding AFUDC and expenditures relating to new generating units,
are presently estimated at $400 million for each of the years 1995, 1996 and
1997. Active construction and the accrual of AFUDC on Twin Oak, suspended in
1987 due to forecast changes in load growth, would need to resume in 1999 in
order to meet the current schedule. Due to the delay, and the possibility of
further delays resulting from forecast changes, in the schedule of Twin Oak, as
well as the lignite-fueled Forest Grove facility which is not included in the
ten-year resource plan, TU Electric is contemplating alternative uses for its
investment in the projects, which might include construction as exempt wholesale
generators, construction at different locations, or sale of the facilities.
Management has no specific plans for alternative uses for, or any knowledge of
an impairment of, such facilities. Some alternative uses, while contributing to
the Company's long-term strategy for maximizing shareholder value, may not
provide for the complete recovery of the Company's investment in these
facilities and related mining facilities. Such investment was approximately $807
million as of December 31, 1994. Expenditures for nuclear fuel and non-utility
property are presently estimated at $63 million for 1995, $70 million for 1996,
and $96 million for 1997. The re-evaluation of growth expectations, the effects
of inflation, additional regulatory requirements and the availability of fuel,
labor, materials and capital may result in changes in estimated construction
costs and dates of completion. Commitments in connection with the construction
program are generally revocable subject to reimbursement to manufacturers for
expenditures incurred or other cancellation penalties.
The Company plans to seek new investment opportunities from time to time when
it concludes that such investments are consistent with its business strategies
and will likely enhance the long-term returns to its shareholders. The timing
and amounts of any specific new business investment opportunities are presently
undetermined.
CLEAN AIR ACT
The federal Clean Air Act, as amended (Clean Air Act) includes provisions
which, among other things,
48
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
place limits on the sulfur dioxide emissions produced by generating units. To
meet these sulfur dioxide requirements, the Clean Air Act provides for the
annual allocation of sulfur dioxide emission allowances to utilities. Under the
Clean Air Act, utilities are permitted to transfer allowances within their own
systems and to buy or sell allowances from or to other utilities. The EPA grants
a maximum number of allowances annually to TU Electric based on the amount of
emissions from units in operation during the period 1985 through 1987. The
Company's capital requirements have not been significantly affected by the
requirements of the Clean Air Act. Although TU Electric is unable to fully
determine the cost of compliance with the Clean Air Act, it is not expected to
have a significant impact on the Company. During 1994, installation of
continuous emissions monitoring systems was completed at a total cost of
approximately $38 million. Any additional capital costs, as well as any
increased operating costs, associated with these new requirements are expected
to be recoverable through rates, as similar costs have been recovered in the
past.
PURCHASED POWER CONTRACTS
TU Electric and SESCO have entered into purchased power contracts to purchase
portions of the generating output of certain qualifying cogenerators and
qualifying small power producers through the year 2005. These contracts provide
for capacity payments subject to a facility meeting certain operating standards
and energy payments based on the actual power taken under the contracts. The
cost of these and other purchased power contracts is recovered currently through
base rates, power cost and fuel recovery factors applied to customer billings.
Capacity payments under these contracts for the years ended December 31, 1994,
1993 and 1992 were $236,991,000, $251,610,000 and $240,341,000, respectively.
Assuming operating standards are achieved, future capacity payments under the
agreements are estimated as follows:
<TABLE>
<CAPTION>
YEARS THOUSANDS OF DOLLARS
----- --------------------
<S> <C>
1995................................. $ 229,340
1996................................. 232,987
1997................................. 240,884
1998................................. 246,535
1999................................. 199,962
Thereafter........................... 454,679
----------
Total.............................. $1,604,387
==========
</TABLE>
LEASES
The System Companies have entered into operating leases covering various
facilities and properties including combustion turbines, transportation, mining
and data processing equipment, and office space. Lease costs charged to
operation expense for the years ended December 31, 1994, 1993 and 1992 were
$140,370,000, $138,184,000 and $127,446,000, respectively.
The Company's future minimum lease commitments under such operating leases
that have initial or remaining noncancellable lease terms in excess of one year
as of December 31, 1994, were as follows:
<TABLE>
<CAPTION>
YEARS THOUSANDS OF DOLLARS
----- --------------------
<S> <C>
1995................................. $ 75,920
1996................................. 73,320
1997................................. 49,141
1998................................. 37,404
1999................................. 39,035
Thereafter........................... 664,151
--------
Total minimum lease commitments.... $938,971
========
</TABLE>
49
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
COOLING WATER CONTRACTS
TU Electric has entered into contracts with public agencies to purchase
cooling water for use in the generation of electric energy. In connection with
certain contracts, TU Electric has agreed, in effect, to guarantee the
principal, $36,650,000 at December 31, 1994, and interest on bonds issued to
finance the reservoirs from which the water is supplied. The bonds mature at
various dates through 2011 and have interest rates ranging from 5-1/2 to 7%. TU
Electric is required to make periodic payments equal to such principal and
interest, including amounts assumed by a third party and reimbursed to TU
Electric, for the years 1995 through 1999 as follows: $4,431,000 for 1995;
$4,430,000 for 1996; $4,435,000 for 1997; $4,435,000 for 1998 and $4,435,000 for
1999. Payments made by TU Electric, net of amounts assumed by a third party
under such contracts, for 1994, 1993 and 1992 were $3,615,000, $2,954,000 and
$2,849,000, respectively. In addition, TU Electric is obligated to pay certain
variable costs of operating and maintaining the reservoirs. TU Electric has
assigned to a municipality all contract rights and obligations of TU Electric in
connection with $84,610,000 remaining principal amount of bonds at December 31,
1994, issued for similar purposes which had previously been guaranteed by TU
Electric. TU Electric is, however, contingently liable in the unlikely event of
default by the municipality.
CHACO COAL PROPERTIES
Chaco Energy Company (Chaco) has a coal lease agreement for the rights to
certain surface mineable coal reserves located in New Mexico. The agreement
provides for minimum advance royalty payments of approximately $16 million per
year through 2017, covering approximately 228 million tons of coal. The Company
has entered into a surety agreement to assure the performance by Chaco with
respect to this agreement. At December 31, 1994 and 1993, $499,890,000 and
$483,855,000, respectively, of minimum advance royalties paid by Chaco are
included in non-utility property. In addition, Chaco has under lease with the
federal government certain coal reserves with a carrying value of approximately
$44 million as of December 31, 1994. A provision in this lease requires that
substantial mining be completed by September 1997. Chaco is currently reviewing
its options with regard to this provision. Because of the ample availability of
western coal at favorable prices from other mines, Chaco has delayed plans to
commence mining operations, and accordingly, is reassessing its alternatives
with respect to its coal properties including seeking other purchasers thereof.
NUCLEAR INSURANCE
With regard to liability coverage, the Price-Anderson Act (Act) provides
financial protection for the public in the event of a significant nuclear power
plant incident. The Act sets the statutory limit of public liability for a
single nuclear incident currently at $8.9 billion and requires nuclear power
plant operators to provide financial protection for this amount. As required, TU
Electric provides this financial protection for a nuclear incident at Comanche
Peak resulting in public bodily injury and property damage through a combination
of private insurance and industry-wide retrospective payment plans. As the first
layer of financial protection, TU Electric has purchased $200 million of
liability insurance from American Nuclear Insurers (ANI), which provides such
insurance on behalf of two major stock and mutual insurance pools, Nuclear
Energy Liability Insurance Association and Mutual Atomic Energy Liability
Underwriters. The second layer of financial protection is provided under an
industry-wide retrospective payment program called Secondary
50
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. COMMITMENTS AND CONTINGENCIES -- (CONTINUED)
Financial Protection (SFP). Under the SFP, each operating licensed reactor in
the United States is subject to an assessment of up to $79.275 million, subject
to increases for inflation every five years, in the event of a nuclear incident
at any nuclear plant in the United States. Assessments are limited to $10
million per operating licensed reactor per year per incident. All assessments
under the SFP are subject to a 3% insurance premium tax which is not included in
the amounts above.
With respect to nuclear decontamination and property damage insurance, NRC
regulations require that nuclear plant license-holders maintain not less than
$1.06 billion of such insurance and require the proceeds thereof to be used to
place a plant in a safe and stable condition, to decontaminate it pursuant to a
plan submitted to and approved by the NRC before the proceeds can be used for
plant repair or restoration or to provide for premature decommissioning. TU
Electric maintains nuclear decontamination and property damage insurance for
Comanche Peak in the amount of $3.6 billion, above which TU Electric is self-
insured. The primary layer of coverage of $500 million is provided by ANI. The
remaining coverage includes premature decommissioning coverage and is provided
by ANI in the amount of $850 million and Nuclear Electric Insurance Limited
(NEIL), a nuclear electric utility industry mutual insurance company, in the
amount of $2.25 billion. TU Electric is subject to a maximum annual assessment
from NEIL of $30 million in the event NEIL's losses under this type of insurance
for major incidents at nuclear plants participating in this program exceed its
accumulated funds and reinsurance.
TU Electric maintains Extra Expense Insurance through NEIL to cover the
additional costs of obtaining replacement power from another source if one or
both of the units at Comanche Peak are out of service for more than twenty-one
weeks as a result of covered direct physical damage. The coverage provides for
weekly payments of $3.5 million for the first and $2.8 million for the second
and third fifty-two week periods of each outage, respectively, after the initial
twenty-one week period. The total maximum coverage is $473 million per unit. The
coverage amounts applicable to each unit will be reduced to 80% if both units
are out of service at the same time as a result of the same accident. Under this
coverage, TU Electric is subject to a maximum assessment of $10 million per
year.
NUCLEAR DECOMMISSIONING AND DISPOSAL OF SPENT FUEL
TU Electric has established a reserve, charged to depreciation expense and
accumulated depreciation, for the decommissioning of Comanche Peak, whereby
decommissioning costs are being recovered from customers over the life of the
plant and deposited in external trust funds (included in other investments). At
December 31, 1994, such reserve totaled $55,880,000 which includes an accrual of
$18,179,000 for the year ended December 31, 1994. As of December 31, 1994, the
market value of deposits in the external trust for decommissioning of Comanche
Peak was $54,477,000. Realized earnings on funds deposited in the external trust
are recognized in the reserve. Based on a site-specific study during 1992 using
the prompt dismantlement method and then-current dollars, decommissioning costs
for Comanche Peak Unit 1, and Unit 2 and common facilities were estimated to be
$255,000,000 and $344,000,000, respectively. Decommissioning activities are
projected to begin in 2030 and 2032 for Comanche Peak Unit 1, and Unit 2 and
common facilities, respectively. TU Electric is recovering such costs based upon
the 1992 study through the rates placed in effect under Docket 11735 (see Note
10).
51
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (Continued)
11. COMMITMENTS AND CONTINGENCIES -- (CONCLUDED)
TU Electric has a contract with the United States Department of Energy for the
future disposal of spent nuclear fuel at a cost of one mill per kilowatt-hour of
Comanche Peak net generation. The disposal fee is included in nuclear fuel
expense.
GENERAL
In addition to the above, the Company and its subsidiaries are involved in
various legal and administrative proceedings which, in the opinion of the
Company, should not have a material effect upon its financial position or
results of operation.
12. CHANGE IN ACCOUNTING FOR UNBILLED REVENUE
Effective January 1, 1992, TU Electric began recording base rate revenue for
energy sold but not billed through the end of each month to achieve a better
matching of revenues and expenses. Prior to the change in accounting method,
revenues were recognized based on customer billings on a cycle basis. The change
in accounting increased consolidated net income in 1992 by $102,044,000 ($0.48
per share), of which $80,907,000 ($0.38 per share) represents the cumulative
effect of the change in accounting principle at January 1, 1992.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
In December 1991, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 107, "Disclosures about Fair
Value of Financial Instruments" (Statement 107) to provide readers of the
financial statements another method of valuing financial instruments on a
current basis. The following information represents the Company's estimate of
the amount at which the instruments could be exchanged in a current transaction
between willing parties, other than in a forced sale.
The amounts reflected in the consolidated balance sheets for cash, temporary
cash investments and special deposits approximate fair value due to the short
maturity of such instruments. The fair values of financial instruments for which
estimated fair values have not been specifically presented is not materially
different than their related book value.
Other investments includes amounts principally for nuclear decommissioning
fund assets and funds invested pursuant to certain incentive and compensation
agreements. The fair values of the nuclear decommissioning assets and incentive
and compensation assets are estimated based on quoted market prices at year-end
for the instruments in which such funds are invested.
The fair values of long-term debt and preferred stock subject to mandatory
redemption are estimated at the lesser of the call price or the present value of
future cash flows discounted at rates consistent with comparable maturities
adjusted for credit risk.
Common stock -- net has been reduced by the note receivable from the trustee
of the leveraged employee stock ownership provision of the Thrift Plan. The fair
values of such note, long-term debt and preferred stock subject to mandatory
redemption are estimated at the lesser of the Company's call price or the
present value of future cash flows discounted at rates consistent with
comparable maturities adjusted for credit risk.
52
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. FAIR VALUE OF FINANCIAL INSTRUMENTS -- (CONCLUDED)
The carrying amount of other financial liabilities classified as current on
the consolidated balance sheets, such as notes payable and long-term debt due
currently, approximates fair value due to the short maturity of such
instruments. Customer deposits have no defined maturities and, therefore, are
reflected at the amount payable on demand at the date of the balance sheets.
TU Electric has agreed, in effect, to guarantee the principal and interest on
bonds used to finance the reservoirs from which TU Electric uses cooling water
for certain generating units. TU Electric is also the guarantor for the
principal amount of certain bonds issued for similar purposes which were
assigned to a municipality. The outstanding principal at December 31, 1994 and
1993 of the bonds for which TU Electric is contingently liable is approximately
$121,000,000 and $125,000,000, respectively. The fair value of the bonds,
approximately $115,000,000 and $136,000,000 for December 31, 1994 and 1993,
respectively, is based on the present value of the instruments' approximate cash
flows discounted at the year-end risk free rate for issues of comparable
maturities adjusted for credit risk.
The estimated fair value of the System Companies' significant financial
instruments are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1994 DECEMBER 31, 1993
--------------------- --------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
------ ----- ------ -----
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C>
Long-term debt................................... $7,888,413 $7,688,189 $8,379,826 $9,334,454
Preferred stock subject to mandatory redemption.. 387,482 377,621 396,917 408,347
LESOP note receivable............................ 250,000 235,392 250,000 277,521
Other investments................................ 72,170 72,249 53,549 54,839
</TABLE>
53
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONCLUDED)
14. SUPPLEMENTARY FINANCIAL INFORMATION (UNAUDITED)
In the opinion of the Company, the information below includes all adjustments
(constituting only normal recurring accruals) necessary to a fair statement of
such amounts. Quarterly results are not necessarily indicative of expectations
for a full year's operations because of seasonal and other factors, including
rate changes, variations in maintenance and other operating expense patterns,
the impact of the change in AFUDC accruals (see Note 1) and the charges for
regulatory disallowances. For additional information regarding the charges for
regulatory disallowances, see Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operation and Note 10.
<TABLE>
<CAPTION>
EARNINGS PER
CONSOLIDATED SHARE OF
OPERATING REVENUES OPERATING EXPENSES NET INCOME COMMON STOCK/*/
---------------------- ----------------------- ------------------ ----------------
QUARTER ENDED 1994 1993 1994 1993 1994 1993 1994 1993
- ------------- ---- ---- ---- ---- ---- ---- ---- ----
THOUSANDS OF DOLLARS (EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
March 31................................ $1,301,378 $1,142,493 $ 269,912 $243,804 $ 66,746 $153,116 $0.30 $0.70
June 30................................. 1,430,269 1,255,952 345,555 273,292 146,227 162,666 0.65 0.74
September 30............................ 1,702,019 1,786,283 488,950 464,691 294,250 51,671 1.30 0.23
December 31............................. 1,229,877 1,249,784 227,144 205,139 35,576 1,207 0.16 0.01
---------- ---------- ---------- ---------- -------- --------
$5,663,543 $5,434,512 $1,331,561 $1,186,926 $542,799 $368,660
========== ========== ========== ========== ======== ========
</TABLE>
______________________________
* Quarterly earnings per share of common stock are based on the weighted
average number of shares outstanding during the quarter and, as a result, the
sum of the quarters may not equal annual earnings per share.
54
<PAGE>
[THIS PAGE LEFT BLANK INTENTIONALLY]
55
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENT OF RESPONSIBILITY
The management of Texas Utilities Company is responsible for the preparation,
integrity and objectivity of the consolidated financial statements of the
Company and its subsidiaries and other information included in this report. The
consolidated financial statements have been prepared in conformity with
generally accepted accounting principles. As appropriate, the statements include
amounts based on informed estimates and judgments of management.
The management of the Company has established and maintains a system of
internal control designed to provide reasonable assurance, on a cost-effective
basis, that assets are safeguarded, transactions are executed in accordance with
management's authorization and financial records are reliable for preparing
consolidated financial statements. Management believes that the system of
control provides reasonable assurance that errors or irregularities that could
be material to the consolidated financial statements are prevented or would be
detected within a timely period. Key elements in this system include the
effective communication of established written policies and procedures,
selection and training of qualified personnel and organizational arrangements
that provide an appropriate division of responsibility. This system of control
is augmented by an ongoing internal audit program designed to evaluate its
adequacy and effectiveness. Management considers the recommendations of the
internal auditors and independent certified public accountants concerning the
Company's system of internal control and takes appropriate actions which are
cost-effective in the circumstances. Management believes that, as of December
31, 1994, the Company's system of internal control was adequate to accomplish
the objectives discussed herein.
The Board of Directors of the Company addresses its oversight responsibility
for the consolidated financial statements through its Audit Committee, which is
composed of directors who are not employees of the Company. The Audit Committee
meets regularly with the Company's management, internal auditors and independent
certified public accountants to review matters relating to financial reporting,
auditing and internal control. To ensure auditor independence, both the internal
auditors and independent certified public accountants have full and free access
to the Audit Committee.
The independent certified public accounting firm of Deloitte & Touche LLP is
engaged to audit, in accordance with generally accepted auditing standards, the
consolidated financial statements of the Company and its subsidiaries and to
issue their report thereon.
/s/ J. S. FARRINGTON
-----------------------------------------
J. S. Farrington, Chairman of the Board
and Chief Executive
/s/ ERLE NYE
-----------------------------------------
Erle Nye, President
/s/ H. JARRELL GIBBS
-----------------------------------------
H. Jarrell Gibbs, Vice President
and Principal Financial Officer
/s/ H. DAN FARELL
-----------------------------------------
H. Dan Farell, Controller
and Principal Accounting Officer
56
<PAGE>
INDEPENDENT AUDITORS' REPORT
Texas Utilities Company:
We have audited the accompanying consolidated balance sheets of Texas Utilities
Company and subsidiaries as of December 31, 1994 and 1993, and the related
consolidated statements of income, retained earnings and cash flows for each of
the three years in the period ended December 31, 1994. Our audits also included
the financial statement schedule listed in Item 14.(a)2. These financial
statements and the financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Texas Utilities Company and
subsidiaries at December 31, 1994 and 1993, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1994, in conformity with generally accepted accounting principles. Also, in
our opinion, such financial statement schedule, when considered in relation to
the basic consolidated financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.
As discussed in Notes 7 and 8 to the consolidated financial statements, in 1993,
the Company changed its methods of accounting for income taxes and
postretirement benefits other than pensions to conform with Statements of
Financial Accounting Standards No. 109 and No. 106, respectively. Also as
discussed in Note 12 to the consolidated financial statements, in 1992, the
Company changed its method of accounting for base rate revenue sold but not
billed.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 1, 1995
57
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Information with respect to these items is found under the headings Election
of Directors, Executive Compensation, and Beneficial Ownership of Common
Stock of the Company in the definitive proxy statement to be mailed by the
registrant to the Commission for filing on or about March 28, 1995.
Additional information with respect to Executive Officers of the Registrant
is found at the end of Part I.
58
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
(a) Documents filed as part of this Report:
1. Financial Statements (included in Item 8, Financial Statements
and Supplementary Data):
Statements of Consolidated Income for each of the three years in the
period ended December 31, 1994............................................... 28
Statements of Consolidated Retained Earnings for each of the three
years in the period ended December 31, 1994.................................. 28
Statements of Consolidated Cash Flows for each of the three years in
the period ended December 31, 1994........................................... 29
Consolidated Balance Sheets, December 31, 1994 and 1993....................... 30
Notes to Consolidated Financial Statements.................................... 32
Independent Auditors' Report.................................................. 56
Statement of Responsibility................................................... 57
2. Financial Statement Schedule -
For each of the three years in the period ended December 31, 1994:
Schedule II-Valuation and Qualifying Accounts................................. 64
</TABLE>
All other financial statement schedules are omitted because of the absence
of the conditions under which they are required or because the required
information is included in the Financial Statements or notes thereto.
(b) Reports on Form 8-K:
Reports on Form 8-K filed since September 30, 1994, are as follows:
N/A
59
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(CONTINUED)
(C) EXHIBITS:
<TABLE>
<CAPTION>
PREVIOUSLY FILED*
-----------------
WITH
FILE AS
EXHIBITS NUMBER EXHIBIT NUMBER DATED
- -------- ------ ------- ------ -----
<S> <C> <C> <C> <C>
3(a) 33-48880 4(a) - Restated Articles of Incorporation of Texas Utilities Company.
3(b) 33-48880 4(b) - Bylaws, as amended, of Texas Utilities Company.
4(a) 2-90185 4(a) - Mortgage and Deed of Trust, dated as of December 1, 1983,
between Texas Utilities Electric Company and Irving Trust
Company (now The Bank of New York), Trustee.
4(a)-1 - Supplemental Indentures to Mortgage and Deed of Trust:
2-90185 4(b) First April 1, 1984
2-92738 4(a)-1 Second September 1, 1984
2-97185 4(a)-1 Third April 1, 1985
2-99940 4(a)-1 Fourth August 1, 1985
2-99940 4(a)-2 Fifth September 1, 1985
33-01774 4(a)-2 Sixth December 1, 1985
33-9583 4(a)-1 Seventh March 1, 1986
33-9583 4(a)-2 Eighth May 1, 1986
33-11376 4(a)-1 Ninth October 1, 1986
33-11376 4(a)-2 Tenth December 1, 1986
33-11376 4(a)-3 Eleventh December 1, 1986
33-14584 4(a)-1 Twelfth February 1, 1987
33-14584 4(a)-2 Thirteenth March 1, 1987
33-14584 4(a)-3 Fourteenth April 1, 1987
33-24089 4(a)-1 Fifteenth July 1, 1987
33-24089 4(a)-2 Sixteenth September 1, 1987
33-24089 4(a)-3 Seventeenth October 1, 1987
33-24089 4(a)-4 Eighteenth March 1, 1988
33-24089 4(a)-5 Nineteenth May 1, 1988
33-30141 4(a)-1 Twentieth September 1, 1988
33-30141 4(a)-2 Twenty-first November 1, 1988
33-30141 4(a)-3 Twenty-second January 1, 1989
33-35614 4(a)-1 Twenty-third August 1, 1989
33-35614 4(a)-2 Twenty-fourth November 1, 1989
33-35614 4(a)-3 Twenty-fifth December 1, 1989
33-35614 4(a)-4 Twenty-six February 1, 1990
33-39493 4(a)-1 Twenty-seventh September 1, 1990
33-39493 4(a)-2 Twenty-eighth October 1, 1990
33-39493 4(a)-3 Twenty-ninth October 1, 1990
33-39493 4(a)-4 Thirtieth March 1, 1991
33-45104 4(a)-1 Thirty-first May 1, 1991
33-45104 4(a)-2 Thirty-second July 1, 1991
33-46293 4(a)-1 Thirty-third February 1, 1992
33-49710 4(a)-1 Thrity-fourth April 1, 1992
33-49710 4(a)-2 Thirty-fifth April 1, 1992
</TABLE>
60
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(CONTINUED)
<TABLE>
<CAPTION>
PREVIOUSLY FILED*
-----------------------------
WITH
FILE AS
EXHIBITS NUMBER EXHIBIT NUMBER DATED
- -------- ------ ------- ------ -----
<S> <C> <C> <C> <C>
33-49710 4(a)-3 Thirty-sixth June 1, 1992
33-49710 4(a)-4 Thirty-seventh June 1, 1992
33-57576 4(a)-1 Thirty-eighth August 1, 1992
33-57576 4(a)-2 Thirty-ninth October 1, 1992
33-57576 4(a)-3 Fortieth November 1, 1992
33-57576 4(a)-4 Forty-first December 1, 1992
33-60528 4(a)-1 Forty-second March 1, 1993
33-64692 4(a)-1 Forty-third April 1, 1993
33-64692 4(a)-2 Forty-fourth April 1, 1993
33-64692 4(a)-3 Forty-fifth May 1, 1993
33-68100 4(a)-1 Forty-sixth July 1, 1993
33-68100 4(a)-3 Forty-seventh October 1, 1993
33-68100 4(a)-4 Forty-eighth November 1, 1993
33-68100 4(a)-5 Forty-ninth May 1, 1994
33-68100 4(a)-6 Fiftieth May 1, 1994
33-68100 4(a)-7 Fifty-first August 1, 1994
4(b) - Agreement to furnish certain debt instruments.
4(c) 33-68104 4(b)-16 - Deposit Agreement between TU Electric and Chemical Bank, dated
as of January 11, 1993.
4(d) 33-68104 4(b)-17 - Deposit Agreement between TU Electric and Chemical Bank, dated
as of August 4, 1993.
4(e) 0-11442 4(h) - Deposit Agreement between TU Electric and Chemical Bank, dated
Form 10-K as of October 14, 1993.
(1993)
10(a)** 1-3591 10(a) - Deferred and Incentive Compensation Plan of the Texas Utilities
Form 10-K Company System, as amended June 30, 1992.
(1992)
10(b)** 1-3591 10(b) - Salary Deferral Program of the Texas Utilities Company System
Form 10-K as amended May 31, 1992.
(1992)
10(c)** 1-3591 10(c) - Restated Supplemental Retirement Plan for the employees of the
Form 10-K Texas Utilities Company System, dated as of January 1, 1991.
(1992)
21 - Subsidiaries of Texas Utilities Company.
23(a) - Consent of Counsel.
23(b) - Independent Auditors' Consent.
27 - Financial Data Schedule.
99(a) 1-3591 28(b) - Agreement, dated as of February 12, 1988, between TU Electric
Form 10-K and Texas Municipal Power Agency.
(1987)
99(b) 33-55408 99(a) - Agreement, dated as of July 5, 1988, between TU Electric and
the Brazos Electric Power Cooperative, Inc.
</TABLE>
61
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(CONTINUED)
<TABLE>
<CAPTION>
PREVIOUSLY FILED*
-----------------------------
WITH
FILE AS
EXHIBITS NUMBER EXHIBIT DATED
- -------- ------ ------- -----
<S> <C> <C> <C>
99(c) 33-55408 99(b) - Agreement, dated as of January 30, 1990, between TU Electric
and Tex-La Electric Cooperative of Texas, Inc.
99(d) 33-59988 2 - Agreement and plan of merger, dated as of January 25, 1993, by
and among Texas Utilities Company, TUA, Inc., and
Southwestern Electric Service Company.
99(e) 33-23532 4(c)(i) - Trust Indenture, Security Agreement and Mortgage, dated as of
December 1, 1987, as supplemented by Supplement No. 1 thereto
dated as of May 1, 1988 among the Lessor, TU Electric and the
Trustee.
99(f) 33-24089 4(c)-1 - Supplement No. 2 to Trust Indenture, Security Agreement and
Mortgage, dated as of August 1, 1988.
99(g) 33-24089 4(e)-1 - Supplement No. 3 to Trust Indenture, Security Agreement and
Mortgage, dated as of August 1, 1988.
99(h) 0-11442 99(c) - Supplement No. 4 to Trust Indenture, Security Agreement and
Form 10-Q Mortgage, including form of Secured Facility Bond, 1993 Series.
(Quarter ended
June 30, 1993)
99(i) 33-23532 4(d) - Lease Agreement, dated as of December 1, 1987 between the
Lessor and TU Electric as supplemented by Supplement No. 1
thereto dated as of May 20, 1988 between the Lessor and TU
Electric.
99(j) 33-24089 4(f) - Lease Agreement Supplement No. 2, dated as of August 18,
1988.
99(k) 33-24089 4(f)-1 - Lease Agreement Supplement No. 3, dated as of August 25,
1988.
99(l) 33-63434 4(d)(iv) - Lease Agreement Supplement No. 4, dated as of December 1,
1988.
99(m) 33-63434 4(d)(v) - Lease Agreement Supplement No. 5, dated as of June 1, 1989.
99(n) 0-11442 99(d) - Lease Agreement Supplement No. 6, dated as of July 1, 1993.
Form 10-Q
(Quarter ended
June 30, 1993)
99(o) 33-23532 4(e) - Participation Agreement dated as of December 1, 1987, as
amended by a Consent to Amendment of the Participation
Agreement, dated as of May 20, 1988, each among the Lessor,
the Trustee, the Owner Participant, certain banking institutions,
Capcorp, Inc. and TU Electric.
99(p) 33-24089 4(g) - Consent to Amendment of the
Participation Agreement, dated as of August 18, 1988.
99(q) 33-24089 4(g)-1 - Supplement No. 1 to the Participation Agreement, dated as of
August 18, 1988.
99(r) 33-24089 4(g)-2 - Supplement No. 2 to the Participation Agreement, dated as of
August 18, 1988.
99(s) 33-63434 4(e)(v) - Supplement No. 3 to the Participation Agreement, dated as of
December 1, 1988.
</TABLE>
62
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(CONTINUED)
<TABLE>
<CAPTION>
PREVIOUSLY FILED*
--------------------------
WITH
FILE AS
EXHIBITS NUMBER EXHIBIT DATED
- -------- ------ ------- -----
<S> <C> <C> <C>
99(t) 0-11442 99(e) - Supplement No. 4 to the Participation Agreement, dated as of
Form 10-Q June 17, 1993.
(Quarter ended
June 30, 1993)
99(u) 0-11442 99(t) - Competitive Advance and Revolving Credit Facility Agreement,
Form 10-Q "Facility A", dated as of April 29, 1994, among the Company, TU
(Quarter ended Electric, certain banks and Chemical Bank, Agent.
September 30, 1994)
99(v) 0-11442 99(u) - Competitive Advance and Revolving Credit Facility Agreement,
Form 10-Q "Facility B", dated as of April 29, 1994, among the Company,
(Quarter ended TU Electric, certain banks and Chemical Bank, Agent.
September 30, 1994)
99(w) 0-11442 99(v) - Credit Agreement, dated as of February 24, 1995, between TU Electric,
Form 10-K Bank of America and The Bank of New York.
(1994)
</TABLE>
____________________________
* Incorporated herein by reference.
** Management contract or compensation plan or arrangement required to be filed
as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
63
<PAGE>
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
For Each of the Three Years in the Period Ended December 31, 1994
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- --------------------------------------------------------------------------------------------------------------------------
ADDITIONS
----------------------
BALANCE AT CHARGED TO CHARGED
BEGINNING COSTS AND TO OTHER BALANCE AT
CLASSIFICATION OF YEAR EXPENSES ACCOUNTS DEDUCTIONS (A) END OF YEAR
- --------------------------------------------------------------------------------------------------------------------------
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C> <C>
VALUATION ACCOUNT, DEDUCTED FROM RELATED
ASSET ON THE BALANCE SHEET --
Year Ended December 31, 1994
Reserve for regulatory disallowances .... $1,381,145 -- -- -- $1,381,145
Allowance for uncollectible accounts..... 6,394 $30,020 -- $31,319 5,095
Year Ended December 31, 1993
Reserve for regulatory disallowances .... $1,381,145 -- -- -- $1,381,145
Allowance for uncollectible accounts..... 1,613 $21,607 -- $16,826 6,394
Year Ended December 31, 1992
Reserve for regulatory disallowances .... $1,381,145 -- -- -- $1,381,145
Allowance for uncollectible accounts..... 2,931 $ 4,102 -- $ 5,420 1,613
</TABLE>
_____________
(a) Deductions represents uncollectible accounts written off net of recoveries
of amounts previously written off.
64
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS
BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
TEXAS UTILITIES COMPANY
Date: March 2, 1995 By: /s/ J. S. FARRINGTON
-----------------------------------------
(J. S. FARRINGTON, CHAIRMAN OF THE BOARD
AND CHIEF EXECUTIVE)
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATE INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
<TABLE>
<S> <C> <C>
/s/ J. S. FARRINGTON Principal Executive March 2, 1995
- ------------------------------------------------
(J. S. Farrington, Chairman of the Board Officer and Director
and Chief Executive)
/s/ ERLE NYE President and Director March 2, 1995
- ------------------------------------------------
(Erle Nye, President)
/s/ H. JARRELL GIBBS Principal Financial March 2, 1995
- ------------------------------------------------
(H. Jarrell Gibbs, Vice President) Officer
/s/ H. DAN FARELL Principal Accounting March 2, 1995
- ------------------------------------------------
(H. Dan Farell, Controller) Officer
/s/ JACK W. EVANS Director March 2, 1995
- ------------------------------------------------
(Jack W. Evans)
/s/ BAYARD H. FRIEDMAN Director March 2, 1995
- ------------------------------------------------
(Bayard H. Friedman)
/s/ WILLIAM M. GRIFFIN Director March 2, 1995
- ------------------------------------------------
(William M. Griffin)
/s/ KERNEY LADAY Director March 2, 1995
- ------------------------------------------------
(Kerney Laday)
/s/ MARGARET N. MAXEY Director March 2, 1995
- ------------------------------------------------
(Margaret N. Maxey)
/s/ JAMES A. MIDDLETON Director March 2, 1995
- ------------------------------------------------
(James A. Middleton)
/s/ CHARLES R. PERRY Director March 2, 1995
- ------------------------------------------------
(Charles R. Perry)
/s/ HERBERT H. RICHARDSON Director March 2, 1995
- ------------------------------------------------
(Herbert H. Richardson)
</TABLE>
65
<PAGE>
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
SEQUENTIALLY
EXHIBIT NUMBERED
NO. DESCRIPTION OF EXHIBIT PAGE
- ------- ---------------------- -------------
<C> <C> <S>
4(b) - Agreement fo furnish certain debt instruments
21 - Subsidiaries of Texas Utilities Company
23(a) - Consent of Counsel
23(b) - Independent Auditors' Consent
27 - Financial Data Schedule
</TABLE>
1
<PAGE>
Exhibit 4(b)
March 2, 1995
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: Texas Utilities Company
1994 Annual Report on Form 10-K
-------------------------------
Gentlemen:
Pursuant to the exemption afforded by Item 601(b)(4)(iii)(A) of Regulation
S-K, Texas Utilities Company (Company) is not filing as exhibits to its Annual
Report on Form 10-K for 1994 instruments with respect to certain long-term debt
of the Company and/or its subsidiaries. These instruments include (i)
agreements with respect to pollution control revenue bonds and (ii) agreements
with respect to senior notes. Each item of long-term debt referenced above does
not exceed 10% of the total assets of the Company and its subsidiaries on a
consolidated basis. Reference is made to Note 6 to Consolidated Financial
Statements (Item 8 of the Company's Annual Report on Form 10-K for 1994).
The Company agrees to furnish a copy of the above instruments to the
Securities and Exchange Commission upon request.
Sincerely,
/s/ H. Jarrell Gibbs
--------------------------------
H. Jarrell Gibbs
HJG:tr
1
<PAGE>
Exhibit 21
SUBSIDIARIES OF TEXAS UTILITIES COMPANY
<TABLE>
<CAPTION>
STATE OF INCORPORATION
<S> <C>
Texas Utilities Electric Company Texas
Southwestern Electric Service Company Texas
Texas Utilities Fuel Company Texas
Texas Utilities Mining Company Texas
Texas Utilities Services Inc. Texas
Basic Resources Inc. Texas
Chaco Energy Company New Mexico
Texas Utilities Properties Inc. Texas
</TABLE>
1
<PAGE>
Exhibit 23(a)
CONSENT OF COUNSEL
We hereby consent to the incorporation by reference of the statements made
as to matters of law and legal conclusions contained in this Annual Report on
Form 10-K of Texas Utilities Company for the fiscal year ended December 31,
1994, under Part I, Item 1--Business--Regulation and Rates and Environmental
Matters, in Texas Utilities Company's Registration Statement on Form S-3 (No.
33-55931).
WORSHAM, FORSYTHE, SAMPELS
& WOOLDRIDGE, L.L.P.
By: /s/ T.A. Mack
---------------------------
A Partner
March 2, 1995
Dallas, Texas
<PAGE>
Exhibit 23(b)
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Texas Utilities Company's
Registration Statement No. 33-55931 on Form S-3 and Registration Statement No.
33-52395 on Form S-8 of our report dated March 1, 1995, which report includes an
explanatory paragraph concerning the Company's changes during 1993 in its
methods of accounting for income taxes and postretirement benefits other than
pensions to conform with Statements of Financial Accounting Standards No. 109
and No. 106, respectively, and for the change during 1992 in its method of
accounting for base rate revenue sold but not billed, appearing in this Annual
Report on Form 10-K of Texas Utilities Company for the year ended December 31,
1994.
/s/ Deloitte & Touche LLP
Dallas, Texas
March 2, 1995
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
STATEMENTS OF CONSOLIDATED INCOME, STATEMENTS OF CONSOLIDATED CASH FLOWS, AND
CONSOLIDATED BALANCE SHEETS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 17,669,468
<OTHER-PROPERTY-AND-INVEST> 692,243
<TOTAL-CURRENT-ASSETS> 695,494
<TOTAL-DEFERRED-CHARGES> 1,908,888
<OTHER-ASSETS> (72,685)
<TOTAL-ASSETS> 20,893,408
<COMMON> 4,798,797
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,691,250
<TOTAL-COMMON-STOCKHOLDERS-EQ> 6,490,047
387,482
870,190
<LONG-TERM-DEBT-NET> 7,888,413
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 363,886
<LONG-TERM-DEBT-CURRENT-PORT> 74,610
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,818,780
<TOT-CAPITALIZATION-AND-LIAB> 20,893,408
<GROSS-OPERATING-REVENUE> 5,663,543
<INCOME-TAX-EXPENSE> 316,995
<OTHER-OPERATING-EXPENSES> 4,014,987
<TOTAL-OPERATING-EXPENSES> 4,331,982
<OPERATING-INCOME-LOSS> 1,331,561
<OTHER-INCOME-NET> 28,736
<INCOME-BEFORE-INTEREST-EXPEN> 1,360,297
<TOTAL-INTEREST-EXPENSE> 715,615
<NET-INCOME> 644,682
101,883
<EARNINGS-AVAILABLE-FOR-COMM> 542,799
<COMMON-STOCK-DIVIDENDS> 694,355
<TOTAL-INTEREST-ON-BONDS> 567,543
<CASH-FLOW-OPERATIONS> 1,419,584
<EPS-PRIMARY> 2.40
<EPS-DILUTED> 2.40
</TABLE>
