UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended August 31, 1995
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ______________________ to _____________________
Commission file number 1-3789
SOUTHWESTERN PUBLIC SERVICE COMPANY
(Exact name of registrant as specified in its charter)
New Mexico 75-0575400
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
Tyler at Sixth, Amarillo, Texas 79101
(Address of principal executive offices) (Zip Code)
Registrant's Telephone Number, including area code (806) 378-2121
Securities Registered Pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each Class on which registered
Common Stock New York Stock Exchange
Common Stock Purchase Rights Pacific Stock Exchange
Chicago Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock
(Title of Class)
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 __
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 con-
tained, to the best of registrant's knowledge, in definitive proxy or informa-
tion statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
As of November 3, 1995, 40,917,908 shares of the Company's common stock
were outstanding. The aggregate market value of this common stock held by
nonaffiliates based on the closing price on the New York Stock Exchange was
approximately $1,370,750,000.
The definitive proxy statement relating to the Annual Meeting of
Stockholders to be held on January 31, 1996, is incorporated by reference in
Item 10, Item 11, Item 12 and Item 13 of Part III of this Form 10-K.
SOUTHWESTERN PUBLIC SERVICE COMPANY
FORM 10-K
For the Fiscal Year Ended August 31, 1995
TABLE OF CONTENTS
Item Description
PART I
1 Business
General
Construction Program
Peak Load and Capability
Interconnections
Fuel Supply and Purchased Power
Regulation
Environmental Matters
Employee Relations
Nonutility Businesses
Other
Statistical Summary
Executive Officers of the Registrant
2 Properties
Electric Generating Stations
Water Supply
3 Legal Proceedings
4 Submission of Matters to a Vote of Security Holders
PART II
5 Market for Registrant's Common Equity and Related
Stockholder Matters
6 Selected Financial Data
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations
8 Financial Statements and Supplementary Data
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
PART III
10 Directors and Executive Officers of the Registrant
11 Executive Compensation
12 Security Ownership of Certain Beneficial Owners and Management
13 Certain Relationships and Related Transactions
PART IV
14 Exhibits, Financial Statement Schedules and Reports on Form 8-K
Signatures
Exhibit 12. Statements re Computation of Ratio of Earnings
PART I
ITEM 1. BUSINESS
GENERAL
The Company
Southwestern Public Service Company (the Company) was incorporated in
New Mexico in 1921. The Company's principal business is the generation,
transmission, distribution and sale of electric energy. Substantially all of its
operating revenues were so derived during each of the fiscal years ended August
31, 1995, 1994 and 1993. The Company has two wholly owned subsidiaries, Utility
Engineering Corporation (UE) and Quixx Corporation (Quixx). See NONUTILITY
BUSINESSES and Note (1) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
On August 22, 1995, the Company and Denver-based Public Service Company
of Colorado (PSCo) entered into a definitive agreement providing for a "merger
of equals" of the two companies. Under the agreement, a registered public
utility holding company would be the parent company of the Company and PSCo. See
Note (2) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for further information
on this business combination. Reference is made to the Company's current report
on Form 8-K filed with the Securities and Exchange Commission on August 23,
1995, including the Agreement and Plan of Reorganization and other documents
filed as exhibits thereto. The information set forth in this Form 10-K (unless
otherwise indicated) does not take into account changes that would result from
the merger.
The Company has called for redemption on December 27, 1995, all of its
outstanding Cumulative Preferred Stock which is redeemable by its terms. The
Company will also purchase all 2,600 shares of its 14.50% Cumulative Preferred
Stock (which is not redeemable by its terms). These 2,600 shares of preferred
stock are held by Don Maddox, a director of the Company, as one of two
co-personal representatives of the Estate of James M. Murray, Jr., in which Mr.
Maddox shares voting and investment power. These shares were acquired by Mr.
Murray in connection with the acquisition in 1982 by the Company of the
electrical distribution system of Cochran Power and Light Company. This
preferred stock purchase is being negotiated. As a consequence, upon the above
redemptions and purchase, there will be no shares of Preferred Stock
outstanding. However, the Company plans, subject to market conditions, to
reissue Preferred Stock in 1996 subsequent to its Annual Meeting of Shareholders
(scheduled to be held January 31, 1996) at which holders of its Common Stock
will be requested to approve the amendment of the Company's Restated Articles of
Incorporation (Articles) with respect to the Preferred Stock so as to modernize
such provisions and eliminate covenants imposed thereby. The redemption and
purchase of the outstanding Cumulative Preferred Stock is being undertaken for
the purpose of facilitating obtaining shareholder approval of the merger of the
Company and PSCo and modernizing the Preferred Stock provisions of the Articles.
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS-Liquidity and Capital Resources.
Electric service is provided through an interconnected system to a
population of about one million in a 52,000-square-mile area of the Panhandle
and south plains of Texas, eastern and southeastern New Mexico, the Oklahoma
Panhandle and southwestern Kansas. The Company provides electric energy to
forty-six communities with a population of 2,000 or more, thirty-five in Texas,
nine in New Mexico, and one each in Oklahoma and Kansas. Approximately 56% of
the Company's operating revenues during fiscal 1995, excluding sales to other
utilities, were derived from operations in Texas.
The Company's sales are made to retail and wholesale customers. Retail
sales to ultimate consumers include residential, commercial and industrial
customers. Wholesale sales include sales for resale to rural electric
cooperatives, and firm and non-firm sales to other utilities. These non-firm, or
economy, wholesale sales to other utilities also include sales of interruptible
power made under Federal Energy Regulatory Commission (FERC) approved contracts.
Firm sales are made under contract to other adjoining utilities while non-firm
sales are negotiated on the spot market or sold under the Western Systems Power
Pool (WSPP) agreement. See INTERCONNECTIONS. Non-firm sales are made to
adjoining and other utilities.
The production, transportation and processing of oil and natural gas,
and chemical, mineral and light manufacturing industries are of prime importance
in the area served. Agriculture and the processing of agricultural products,
including wheat, cotton, corn, sugar beets and vegetables, and livestock raising
and meat processing are industries of economic significance. The area also
contains many other diversified industries and commercial enterprises. See
STATISTICAL SUMMARY-ELECTRIC REVENUES.
The Company's largest sales of electric energy are during the summer
months when demand reaches a peak. The Company's 1995 maximum hourly net peak
system demand of 3,952 megawatts (MW) occurred on July 28, 1995 and was an
all-time high peak. The previous maximum net peak of 3,682 MW occurred on July
6, 1994. See PEAK LOAD AND CAPABILITY.
See REGULATION-Competition and Note (8) of NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS for information on the changing utility environment.
CONSTRUCTION PROGRAM
Cash expenditures for the Company's construction program were $94.7
million in fiscal 1995. These expenditures did not include any amounts for the
construction of new base load generating facilities.
The following general discussion of the Company's construction program
and related expenditures are for a stand-alone company; that is, without
consideration to the proposed merger with PSCo. On that basis, the Company's
estimated construction expenditures for the next five years are as follows:
Estimated for fiscal year ending August 31,
1996 1997 1998 1999 2000 TOTAL
(In Millions)
Generating facilities $ 30 $112 $ 80 $ 34 $ 35 $291
Transmission facilities 30 25 29 26 27 137
Distribution facilities 30 30 27 31 32 150
Other 23 19 17 16 12 87
Total cash requirements $113 $186 $153 $107 $106 $665
The estimates in 1997, 1998 and 1999 for generating facilities include
costs for the construction of approximately 400 MW of additional capacity. Such
construction plans include a 200 MW natural-gas-fired cogeneration facility to
be completed in 1998 at a Phillips Petroleum Company complex near Borger, Texas,
and a 198 MW natural-gas-fired combustion turbine to be completed in 1999 at an
existing Company plant site. The Company was recently granted a Notice of Intent
by the Public Utility Commission of Texas (PUCT) to construct approximately 300
MW of the 400 MW of new capacity.
PUCT regulations require that a solicitation be conducted before a
utility seeks certification of a new generating unit. The goal of this
solicitation process is to evaluate and select the most appropriate combination
of resources. Pursuant to these regulations, on September 15, 1995, the Company
issued a request for proposals (RFP) to seek alternatives to its proposed
construction. The Company's solicitation encompasses alternative supply-side
options, renewable resources, off-system transactions (primarily purchases),
demand-side management programs, and existing customer interruptible load
programs. Responses to this RFP are due to a third party evaluator in January
1996.
The estimates in 1998 and 1999 for transmission facilities include
expenditures of $18 million for a 230 KV transmission line to be constructed
from Amarillo, Texas to Clovis, New Mexico in order to improve the reliability
of the Company's system. Expenditures are also planned to upgrade transmission
and distribution lines and substations to preserve reliability and efficiency.
These estimated expenditures have been prepared for planning purposes
as part of the Company's resource planning process (discussed below), and are
subject to review and revision. Actual expenditures will vary from these
estimates, as they have in the past, due to a number of factors, including
regulatory requirements related to the planning and siting of facilities,
changes in the rate of inflation, construction scheduling, environmental
matters, the cost and availability of funds, the rate of kilowatt-hour (kwh)
sales growth and other changes in business conditions, regulation and
legislation. The completion of the merger with PSCo could significantly impact
these estimates.
The Company's resource planning process is designed to determine the
optimal mix of capacity resources that would reliably meet its load and reserve
requirements at the least possible cost, while providing flexibility to respond
to uncertainty in the forecasts of load, fuel prices, and financial and other
conditions. The Company typically considers its load forecast, demand-side
management programs, Southwest Power Pool (SPP) reserve requirements, and new
generating unit alternatives, and after consideration of these and any other
relevant factors, arrives at a capacity expansion plan which balances cost and
system operations.
During the five fiscal years ended August 31, 1995, the Company had
property additions (including work in progress) to utility plant of $437 million
and retirements of $43 million. At August 31, 1995, net utility plant was
approximately $1.5 billion.
See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS-Liquidity and Capital Resources for information on the
Company's estimated capital expenditures and financing program. Also see
NONUTILITY BUSINESSES-QUIXX for information on Quixx's investment expenditures.
PEAK LOAD AND CAPABILITY
Plant capability, peak load, capacity margin and load factor were as
follows for the last three fiscal years:
Net Net Net Net
Fiscal Capability Peak Load Increase (Decrease) Capacity Load
Year (MW) (MW) Over Prior Year Margin Factor
1995 4,135 3,952* 7.3% 4.4% 58.4%
1994 4,062 3,682 9.3 9.4 61.7
1993 4,062 3,370 5.1 17.0 63.6
*This is an all-time high peak.
As a member of the SPP, the Company's policy is to maintain a net
capacity margin in accordance with SPP criteria. For steam-based utilities, the
SPP guideline is a minimum capacity margin of 13%. Because of the high peak load
experienced in 1995, the Company's capacity margin was 4.4% for that year.
However, through the expansion of an existing interruptible program for
irrigation load, the initiation of a new interruptible program for industrial
load, purchased power and the consideration of additional capacity on the
system, the Company expects to be within the SPP guideline through the remainder
of the decade. See CONSTRUCTION PROGRAM.
During the period 1996 through 2000, the Company currently estimates
that its compound annual growth rates will be 2.5% for wholesale sales,
excluding non-firm sales, and 2.0% for retail sales. Total kwh sales estimates
show a compound annual growth rate of 1.3% for this forecast period. The Company
periodically reviews expected growth patterns in its service area and these
growth rate estimates are subject to change. See MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
INTERCONNECTIONS
The Company is connected with utilities west of its service territory
through two high voltage direct current (HVDC) interconnections in New Mexico
and has four interconnecting transmission lines with utilities of the SPP. These
interconnections are described in the following table:
Voltage (kilovolts)
Location Interconnecting Utility The Company Other Utility In-Service Date
Near Artesia, NM El Paso Electric Company and
Texas-New Mexico Power Company 230* 345 9/84
Near Clovis, NM Public Service Company of New Mexico 230* 345 1/85
Near Oklaunion, TX Public Service Company of Oklahoma 345 345 6/85
Near Elk City, OK Public Service Company of Oklahoma 230 230 5/72
Near Shamrock, TX West Texas Utilities 115 115 7/72
Near Guymon, OK West Plains Energy 115 115 3/63
*These are HVDC interconnections owned by the interconnecting
utilities. The Company has scheduling capabilities over these facilities through
the WSPP agreement and pursuant to the agreements with the interconnecting
utilities described below.
Transactions with the SPP are handled through interties near Elk City
and Guymon, Oklahoma, and Shamrock and Oklaunion, Texas. These interties allow
the Company to sell or to purchase energy from the eastern electrical grid.
Sales through eastern interties accounted for 2.0% of fiscal 1995 total sales.
HVDC interconnections link the Company with the western electrical grid
of the United States. The Company purchases and sells energy through HVDC
interties near Artesia and Clovis, New Mexico. Sales through these interties
accounted for 4.1% of fiscal 1995 total sales.
The Company participates in the bulk power market through the WSPP. In
fiscal 1995, 2.0% of total sales were due to WSPP bulk power sales.
Under an agreement which expires in December 1996, the Company is
selling 50 MW of firm power to El Paso Electric Company (EPE) through the HVDC
interconnection near Artesia, New Mexico. The sale is scheduled to increase to
75 MW in January 1996. For the months of May through August 1995, EPE purchased
an additional 70 MW to help meet increased weather-related demand. Additional
firm power sales through this HVDC connection to Texas-New Mexico Power Company
(TNP) are made under an agreement with an initial term that expires in 2004. TNP
purchased 33 MW of service from September through December 1993, and 66 MW from
January 1994 through December 1995. This sale is scheduled to decrease to 59 MW
in January 1996. TNP may increase or decrease the contract amount by up to 10%
with one year's notice.
The Company has an interconnection agreement with Public Service
Company of New Mexico (PNM) to sell power through the HVDC interconnection near
Clovis, New Mexico. Under this agreement PNM purchased 100 MW of interruptible
power service through April 1995. Beginning in May 1995, PNM began purchasing
200 MW. The agreement provides that PNM will continue purchasing 200 MW annually
thereafter through May 2011 except that they may reduce purchases by 25 MW
increments upon written notice given at least three years in advance of each
increment reduction. However, the purchase may not be reduced by more than one
25 MW increment in any twelve-month period. PNM has not provided any written
notice of intent to reduce its purchases under this agreement.
Under a firm wholesale power agreement which expires in 2014, the
Company has contracted to serve the full requirements load of Cap Rock Electric
Cooperative (Cap Rock). Cap Rock began purchasing 15 MW of service on February
1, 1994, and increased to 100 MW in February 1995.
The Company has entered into an agreement with The Empire District
Electric Company (EDE) to sell interruptible wholesale power through the
interconnections near Elk City, Oklahoma and Oklaunion, Texas. Under this
agreement, which expires in 2001, EDE may purchase available power through
December 1995 and will purchase 35 MW in 1996 with such purchases to increase to
45 MW by 1999. Public Service Company of Oklahoma has agreed to wheel such
service over its transmission system.
Interconnection sales for fiscal 1995 through the eastern electrical
grid totaled 395,490 MWH, including 303,037 MWH of WSPP sales. Sales through the
western electrical grid totaled 820,445 MWH, consisting of 46,595 MWH of firm
sales and 773,850 MWH of non-firm sales, including 90,807 MWH of WSPP sales.
FUEL SUPPLY AND PURCHASED POWER
Fuel Supply
Approximately 53% of the Company's present generating capacity is
fueled by coal, 46% by gas and 1% by inert by-product gases, purchased steam and
oil. See PROPERTIES for information about generating plants.
The Company's actual and anticipated fuel use, as reported in the table
below, is based on MMBtu use for generation of electricity excluding non-firm
sales. The unpredictability of the non-firm sales market precludes its inclusion
as a factor in determining these fuel use projections. These projections do not
consider the proposed merger with PSCo.
Fiscal Estimated for fiscal years ending August 31,
Fuel 1995 1996 1997 1998 1999 2000
Coal 64.4% 65.4% 65.6% 63.0% 62.1% 61.3%
Gas 34.8 33.8 33.6 36.2 37.2 37.9
Other 0.8 0.8 0.8 0.8 0.7 0.8
Anticipated fuel use is based upon numerous assumptions with respect
to, among other things, regulatory requirements relating to cogeneration and
environmental protection, load growth, cost and availability of boiler fuels and
the extent to which the Company receives and can utilize contracted-for gas,
renegotiates present gas contracts and enters into new agreements. Actual fuel
mix in future years may vary substantially from these estimates because these
assumptions may not be realized.
Coal
The Company purchases all of its coal requirements for Harrington and
Tolk Stations from TUCO, Inc. (TUCO), a wholly owned subsidiary of Cabot
Corporation, in the form of crushed, ready-to-burn coal delivered by
coal-handling facilities owned by Wheelabrator Coal Services Co. to the
Company's boiler bunkers located within the Company's coal-fueled stations where
it is processed for burning. The coal is transported for TUCO by rail, primarily
from mines located in Wyoming, to TUCO's stockpiles which are adjacent to the
Company's coal-burning generating stations. At August 31, 1995, TUCO's coal
inventories at the Harrington and Tolk sites were 723,091 tons and 652,978 tons
(approximately 60 days supply), respectively. The Company has agreed to purchase
all of the outstanding stock of TUCO from Cabot Corporation for $77 million,
subject to certain regulatory approvals. This acquisition is scheduled to be
completed in fiscal 1996. See Note (2) of NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS.
TUCO has long-term contracts with Atlantic Richfield Company (ARCO) for
a supply of coal in sufficient quantities to meet all of the Company's needs for
Harrington and Tolk Stations. See ITEM 3. LEGAL PROCEEDINGS. Specific coal
reserves in the Powder River Basin in Wyoming have been dedicated by ARCO to
meet the contract quantities. The coal is transported for TUCO by Burlington
Northern Railroad to Harrington Station near Amarillo, Texas, a distance of
approximately 896 railroad miles, and by Burlington Northern Railroad and the
Atchison, Topeka and Santa Fe Railway Company to Tolk Station near Muleshoe,
Texas, a distance of approximately 1,032 railroad miles. Transportation charges
make up approximately 51% of the total cost of the coal.
The coal purchased from TUCO had an average heat content of 8,665 Btu
per pound at Harrington Station and 8,660 Btu per pound at Tolk Station for the
twelve months ended August 31, 1995. The Company expects that the Btu content of
the coal will vary between 8,200 and 9,000 Btu per pound and average 8,700 Btu
per pound.
The low sulfur content of this coal enables the Harrington and Tolk
units to operate without the use of flue gas desulfurization scrubbers and to
meet current state and federal sulfur dioxide (SO2) emissions requirements. Unit
No. 1 at Harrington Station is equipped with an electrostatic precipitator, and
Unit Nos. 2 and 3 at Harrington Station and both units at Tolk Station are
equipped with fabric filtration systems. These units have historically emitted
less than one pound of SO2 per MMBtu of heat input compared to the Environmental
Protection Agency (EPA) New Source Performance Standard applicable to these
units of 1.2 pounds of SO2 per MMBtu of heat input. See ENVIRONMENTAL MATTERS.
Natural Gas
The Company has a number of contracts of short and intermediate terms
with various natural gas suppliers operating in gas fields with long life
expectancies in or near its service area. In fiscal 1995 these gas contracts
allowed the Company to maximize competition between fuel suppliers and helped
minimize the Company's fuel cost during volatile market conditions. During this
period, the Company had under contract sufficient firm gas to meet all its
requirements. However, due to flexible contract terms, approximately 42% of the
Company's gas requirements were purchased under spot agreements.
Oil
Certain of the Company's generating stations can burn oil in emergency
situations. Oil is stored at these stations in sufficient quantities to meet
anticipated emergency requirements. These stations have an aggregate capability
of 975 MW. Small quantities of oil are also burned for maintenance purposes.
Cost of Fuel and Purchased Power
Details of the Company's cost of fuel and purchased power are presented
below:
Fiscal year ended August 31,
1995 1994 1993
Cost of fuel and purchased power (000):
Coal ............................................................ $250,551 $276,825 $268,001
Natural gas ..................................................... 116,481 123,503 107,126
Oil (1) ......................................................... 119 49 40
Other (2) ....................................................... 2,901 2,830 2,752
Purchased power ................................................. 5,241 4,604 4,969
Total fuel and purchased power cost .................... $375,293 $407,811 $382,888
Cost of fuel per MMBtu:
Coal ............................................................ $1.814 $1.801 $1.773
Natural gas ..................................................... 1.631 2.015 2.051
Oil (1) ......................................................... 3.635 3.741 3.233
Other (2) ....................................................... 1.754 1.806 1.812
Average (excluding purchased power) ............................. 1.752 1.862 1.844
Cost of fuel per net kwh generated:
Coal ............................................................ 1.797 1.788 1.767
Natural gas ..................................................... 1.687 2.118 2.176
Oil (1) ......................................................... 3.784 4.160 3.583
Other (2) ....................................................... .934 .953 .956
Average cost of fuel (excluding purchased power) ................ 1.749 1.866 1.854
Average cost of fuel (including purchased power) ................ 1.745 1.865 1.854
Average cost of purchased power per net kwh purchased .................... 1.535 1.829 1.794
MMBtu of fuel consumed (000).............................................. 211,202 216,576 204,897
(1) Small quantities of fuel oil are burned for maintenance purposes.
(2) Includes purchased steam used at CZ-2 plant and hot nitrogen used at CZ-1 plant.
The average cost of fuel per MMBtu for fiscal 1995 decreased 5.9% to
$1.75 when compared to 1994; and for the three months ended August 31, 1995, the
average was $1.72. The average cost of fuel per net kwh generated for fiscal
1995 decreased 6.4% to 1.75 cents when compared to last year and for the three
months ended August 31, 1995 was 1.73 cents. This decrease in fuel cost per net
kwh in fiscal 1995 was primarily the result of decreased gas costs.
Fuel Cost Recovery
Fuel and purchased power costs are recoverable in Texas through a fixed
fuel factor which is a part of the Company's rates. If it appears that the
factor will materially overrecover these costs, the factor may be reduced upon
application by the Company or action by the PUCT. The rule requires refunding
overrecovered amounts when they exceed 4% of the utility's annual fuel and
purchased power cost, as allowed by the PUCT, if the overcollection is expected
to continue. The PUCT periodically examines the Company's fuel and purchased
power costs. In all other jurisdictions, the Company currently recovers
substantially all increases and refunds substantially all decreases in fuel and
purchased power costs pursuant to monthly adjustment clauses. See MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS and
Note (1) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
The Company is crediting certain wholesale customers' fuel cost with
75% of the margin from coordination energy sales to other utilities and its
Texas and New Mexico retail customers with 75% of the margin from non-firm
energy sales to other utilities (as approved by regulatory agencies in those
jurisdictions). This margin is the difference between the revenues from these
sales and incremental costs to generate the power for the sales. Continued
coordination and other non-firm energy sales would act to lower the electric
bills of these customers; however, the Company cannot predict the extent of such
sales. The PUCT staff and intervenors have raised the issue of the percent of
sharing of the margins in the current fuel reconciliation proceeding. At this
time, the Company cannot determine if the PUCT will alter the sharing
arrangement.
REGULATION
General
In fiscal 1995, 55.5% of total revenues were derived from sales subject
to the jurisdiction of the PUCT and the Texas municipalities served by the
Company. The percentages of revenue subject to the jurisdictions of the FERC,
the New Mexico Public Utility Commission (NMPUC), and the Oklahoma and Kansas
Corporation Commissions (the OCC and the KCC) were 26.9%, 16.3%, 1.1% and 0.2%,
respectively.
The PUCT has jurisdiction over the Company's Texas operations as an
electric utility, and original and appellate jurisdiction over its Texas retail
rates and services. The Texas municipalities exercise original jurisdiction over
rates within their respective city limits. The FERC has jurisdiction over the
Company's rates for sales of electricity for resale. The NMPUC, the OCC and the
KCC have jurisdiction with respect to retail rates and services in their
respective states. See MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS and Notes (1) and (9) of NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS. The NMPUC and the KCC also regulate the
Company's issuance of securities. The NMPUC also must approve any capital
investment by the Company in its subsidiaries and has limited the amount the
Company can contribute to Quixx. The amount the Company has currently been
authorized to contribute has been fully committed and the Company has an
application pending which would allow additional contributions. The OCC also
regulates the issuance of securities which are secured by a lien on Company
assets located within the State of Oklahoma. The PUCT, NMPUC and KCC must
approve the proposed merger with PSCo, and filings were made with these state
commissions on November 9, 1995. The books of the Company are kept in accordance
with the FERC's Uniform System of Accounts and all of the Company's state
jurisdictions have accepted this system.
Effective October 15, 1993, the Company implemented a Texas retail rate
reduction of 2.9%, or approximately $13 million annually. A similar retail rate
reduction of 2.9%, or approximately $4.0 million annually, was implemented in
New Mexico effective April 1, 1994. See MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Also, for a general discussion of
this and other Company rate matters see Note (9) of NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS.
Competition
The Energy Policy Act of 1992 (EPACT) significantly changed the U.S.
energy policy and, together with other changes in regulation, including
integrated resource planning, and developing technology, is effecting
substantial changes to the electric utility industry. As permitted by the EPACT,
the FERC is requiring utilities, including the Company, to provide wholesale
transmission service to others and may order electric utilities to enlarge their
transmission systems to facilitate transmission services. However, the EPACT
specifically prohibits FERC mandating transmission service to retail customers.
The EPACT has stimulated competition in the wholesale electric markets
by creating a new class of independent power producers in addition to qualifying
facilities (QFs). Revisions to the Public Utility Holding Company Act of 1935
(PUHCA) have allowed both utilities and non-utilities to form independent power
production companies called exempt wholesale generators (EWGs), which operate
without the restrictions of the PUHCA. EWGs offer alternative sources of power
supply to electric utilities across the country. Utilities are often required by
state regulation to solicit to purchase power from EWGs, QFs and other utilities
before seeking approval to construct new generation of their own. See
CONSTRUCTION PROGRAM.
Operating in this competitive environment will place pressure on
utility profit margins and credit quality. Wholesale and industrial customers in
some instances are threatening to pursue cogeneration, self-generation, retail
wheeling, municipalization, or relocation to other service territories in
attempts to obtain price concessions from utilities. Increasing competition has
recently resulted in credit rating agencies applying more stringent guidelines
when making utility credit rating determinations. However, since the Company is
a low-cost producer, competition for wholesale markets and large industrial
customers will create opportunities for the Company to compete for new customers
and revenues.
State regulatory authorities are in the process of changing utility
regulations in response to federal and state statutory changes and evolving
markets. Texas legislation enacted in 1995 recognizes the movement to a more
competitive market-place by requiring the PUCT to issue new regulations
including: allowance of less than fully costed rates in wholesale and retail
markets; recognition of and essentially waiving all Texas utility regulation of
EWGs and power marketers; and implementation of transmission access comparable
to the owning utility's use of its transmission system for non-FERC regulated
utilities. These new regulations are under consideration. The Company believes
that these statutory and conforming regulations may result in increased
wholesale competition. However, due to the Company's low cost structure,
increased wholesale competition is not expected to adversely affect it in the
near term and may favorably impact it in the long term.
The New Mexico legislature rejected retail wheeling proposals; however,
it continued post-session committee investigation of the matter. All of the
Company's jurisdictions continue to evaluate utility regulations with respect to
the competition. The Company believes it is well positioned to take advantage of
the movement towards deregulation and competition. The Company's electric rates
are among the lowest in the nation for investor-owned utilities, and its service
territory is situated at the intersection of the nation's three electrical
grids. These low rates permit the Company to compete effectively with other
utilities, EWGs and QFs for sales to wholesale customers within and outside the
Company's traditional service territory, as well as retain and develop new
retail load. Furthermore, the Company, together with its subsidiary UE, is able
to construct new generating facilities at a cost low enough to enable it to
compete with EWGs and QFs in their efforts to construct generation for sale to
wholesale customers or to self-generate their own needs. The Company is also
competing with independent power producers in markets through its subsidiary
Quixx. See NONUTILITY BUSINESSES.
In the current regulatory and competitive environments, the Company
believes that all of its costs are recoverable through rates. The Company will
assess the impact of any changes in business conditions at the time they occur.
Open Access Transmission Tariffs
FERC released an open access notice of proposed rulemaking (NOPR) in
March 1995 under which utilities will be required to adopt open-access
transmission services and affirmed that rules will be established providing for
the full-recovery of costs resulting from competitive wholesale power
transactions. On May 31, 1995, the Company filed with the FERC comparable open
access transmission service tariffs to allow other utilities use of the
Company's transmission system. On August 1, 1995, the FERC accepted the proposed
tariffs for filing, subject to hearing and refund. Major aspects of the filing
have been deferred until the FERC acts on its pending rulemaking on Promoting
Wholesale Competition Through Open Access Non-Discriminatory Transmission
Services by Public Utilities. Ratemaking issues are being addressed in the
current transmission service tariff proceeding.
Market Based Power Sales
On May 31, 1995, the Company filed with the FERC a tariff to allow the
Company to sell wholesale power at market based rates. On September 1, 1995, the
FERC accepted the Company's market based power sales tariff, subject to the
refund and the final resolution of the Company's comparable open access
transmission tariff filing of May 31, 1995. Several intervenors have sought
rehearing of the FERC's order accepting the market based power sales tariff for
filing.
ENVIRONMENTAL MATTERS
The Company's facilities are regulated by federal and state
environmental agencies. These agencies have jurisdiction over air emissions,
water quality, wastewater discharges, solid wastes and hazardous substances.
Various Company activities require registrations, permits, licenses, inspections
and approvals from these agencies. The Company has received all necessary
authorizations for the construction and continued operation of its generation,
transmission and distribution systems. Company facilities have been designed and
constructed to operate in compliance with the environmental standards.
The Clean Air Act Amendments of 1990 (CAAA) required the Company to
undertake a revised permitting program for its existing fossil-fueled plants.
Under this permitting program, the Company is paying emissions fees of
approximately $800,000 annually to the Texas and New Mexico state air quality
agencies. Beginning in the year 2000, Phase II of the CAAA will require more
stringent limits on SO2 emissions at the Company's existing fossil-fueled
plants. However, current regulations permit compliance with sulfur emissions
limitations in the year 2000 by using SO2 allowances allocated to plants by the
EPA, using allowances generated by reducing emissions at existing plants and by
using allowances purchased from other companies. Based upon information from the
Company's fuel suppliers, the SO2 allowances issued by the EPA approximate the
Company's projected SO2 emissions. The Company monitors options to insure that
allowances will be sufficient to economically operate the Company's existing
plants without significant emission reductions. The CAAA also requires the EPA
to develop new oxides of nitrogen (NOx) emission standards for existing and new
plants which may be more stringent than the current standards. The Company
anticipates being able to comply with Phase II NOx emission standards with no
additional material capital cost. The Company continues to monitor the impact
that the CAAA may have on the Company.
Capital expenditures for environmental protection facilities aggregated
approximately $4.1 million, $11.6 million, and $4.5 million for fiscal 1995,
1994 and 1993, respectively. Estimates of future capital expenditures for
environmental protection facilities are subject to change but the Company has
included $11.7 million in its construction program for these expenditures during
the five years ending August 31, 2000, of which $2.3 million is for fiscal 1996.
The Company has not developed any specific site removal and exit plans
for its fossil fuel plants or substation sites. Plant removal and exit plans are
under development, and when such plans are developed in the future, the Company
intends to treat removal and exit costs as a cost of retirement in utility plant
and include them in depreciation accruals. An estimated removal cost (based on
historical experience) is currently included in depreciation expense.
EMPLOYEE RELATIONS
The Company had approximately 2,000 utility employees at August 31,
1995. Of these, approximately 900 operating, maintenance and construction
personnel are represented by Local Union No. 602, International Brotherhood of
Electrical Workers, AFL-CIO. Pursuant to the collective bargaining agreement
with this union which expires October 31, 1996, wages increased 3% effective
November 1, 1995. The wage increase was also provided to employees not
represented by the union. A hiring freeze has been implemented during the merger
process. The Company considers its relationship with its employees to be
satisfactory.
NONUTILITY BUSINESSES
Utility Engineering Corporation
UE is a wholly owned subsidiary formed in 1986. It is engaged in
engineering, design, construction management and other miscellaneous services,
employing approximately 120 employees. UE's assets at August 31, 1995, were
approximately $42.3 million and total revenues for 1995 were $38.5 million.
Although the Company continues to be UE's major client, UE is currently involved
in a broad array of other projects for nonaffiliate customers, providing general
engineering and design services. UE also works jointly with Quixx on
cogeneration and waste-to-energy projects.
Because of the lack of major central station power plant design and
construction in the U.S. electric industry, UE is actively seeking other types
of plant engineering projects and will continue to broaden its base of customers
and diversity of projects. UE is currently the engineer for the Carolina Energy
Project near Kinston, North Carolina, in which Quixx is an equity owner, and,
during the past twelve months, has performed engineering services for combustion
turbine projects near Neuquen, Argentina and Guayaquil, Ecuador. In February
1995, it completed the second phase of a major transmission interconnection
between the Company and Cap Rock. Also, in 1995, UE completed turnkey projects
in Missouri and Kentucky, the latter being the design and installation of two
package steam generation units in which Quixx is an equity owner.
Since 1993, UE has owned a 39% convertible preferred stock interest in
S. A. Garza Engineers (SAGE), headquartered in Austin, Texas and, during the
year, purchased 12% of the common stock of SAGE. SAGE performs civil engineering
and surveying services to a variety of private and government clients in central
and south Texas. Additionally, during the year, UE purchased a 49% interest in
Vista Environmental Services, LLC, which performs environmental consulting
services for both the private and government sectors, primarily in the
southwestern United States.
Quixx Corporation
Quixx is a wholly owned subsidiary formed in 1986. Its primary business
is investing in and developing cogeneration and energy-related projects. Quixx
also holds water rights and certain other nonutility assets. Quixx employs
approximately 70 employees. Quixx's assets at August 31, 1995, were
approximately $86.4 million and total revenues for 1995 were $16.2 million.
In 1995 Quixx invested $28.3 million in independent power projects and
expects to continue to make similar investments in the future dependent upon
suitable investment opportunities and the availability of capital. The Company
currently has an application pending with the NMPUC to make additional capital
contributions to Quixx.
Quixx holds a 25% limited partnership interest in BCH Energy Limited
Partnership (BCH) which is constructing a waste-to-energy cogeneration facility
located near Fayetteville, North Carolina. The facility will provide steam to a
Du Pont De Nemours & Company (Du Pont) plant near Fayetteville and electric
power will be sold to Carolina Power & Light (CP&L). The facility will provide
17 MW of power to the CP&L grid. Commercial operation of the BCH project is
currently scheduled to begin in late calendar 1995. Quixx has invested
approximately $6.0 million in this project and has agreed to contribute
approximately $8.9 million more if additional capital is needed to complete
construction. Should additional capital be provided, Quixx's ownership position
in this project may be altered. This investment in BCH was funded with a capital
contribution from the Company. Quixx Power Services, Inc., a wholly owned
subsidiary of Quixx, will be the contract operator of the BCH project.
Quixx also holds a 95% interest in Vedco Louisville L.L.C., a Delaware
limited liability company, which owns a facility consisting of two gas-fired
boilers providing steam to a Du Pont plant in Louisville, Kentucky. Quixx's
investment of approximately $6.0 million in this facility was funded by a
capital contribution from the Company. Commercial operation began in December
1994.
Quixx Jamaica, Inc., a Delaware corporation and a wholly owned
subsidiary of Quixx, holds a 99% limited partnership interest in KES Jamaica,
L.P. which owns a facility consisting of two oil-fired combustion turbines
located in Montego Bay, Jamaica, W.I. The facility receives fuel from Jamaica
Public Service Company, Ltd. (JPS) and returns up to 43 MW of power to JPS's
grid. Commercial operation began in December 1994. Quixx's investment of
approximately $10.8 million in this facility was funded by a capital
contribution from the Company.
Quixx holds a 32 1/3% limited partnership interest, and through Quixx
Carolina, Inc., a Delaware corporation and a wholly owned subsidiary of Quixx, a
1% general partnership interest in Carolina Energy, Limited Partnership
(Carolina) which is constructing waste-to-energy cogeneration facilities in
Wilson and Lenoir Counties, North Carolina. The facilities will provide steam to
a DuPont plant located near Kinston, North Carolina and up to 5 MW of electric
power to the CP&L grid. Quixx's investment of approximately $13.4 million in
this facility was funded primarily by a capital contribution from the Company.
Quixx Power Services, Inc., a wholly owned subsidiary of Quixx, will be the
contract operator for the Carolina project. Commercial operation is scheduled
for July 1997.
Quixx holds a 24.67% limited liability partnership interest, and
through Quixx WPP94, Inc., a wholly owned subsidiary of Quixx, a 0.33% general
partnership interest in Windpower Partners, 1994, L.P. which constructed a 35 MW
wind generation facility in Culberson County, Texas. Electricity from the
facility is being provided to the Lower Colorado River Authority and the City of
Austin. Quixx has entered into a commitment fee agreement with Kenetech
Winpower, Inc. to provide $5.5 million for a pro rata 25% equity interest in the
project. Commercial operation began in September 1995.
Quixx owns and operates Amarillo Railcar Services, a railcar
maintenance facility which provides inspection, light and heavy maintenance and
storage for unit trains. Quixx also finances sales of heat pumps and continues
to market other nonutility goods and services. In addition Quixx has royalty
interests in coal and other minerals produced and to be produced from certain
New Mexico properties owned by the Pittsburgh and Midway Coal Mining Company.
Quixx has entered into an agreement to sell certain water rights to the Canadian
River Municipal Water Authority for $14.5 million which would result in an
after-tax gain of approximately $7.6 million. The Company expects, but can give
no assurance, that this sale would be completed in fiscal 1996.
OTHER
Golden Spread Electric Cooperative, Inc.
Golden Spread Electric Cooperative, Inc. (Golden Spread), currently a
significant full requirements customer of the Company, is investigating the
option of constructing, or purchasing from others, up to 400 MW of its peaking
power needs from sources other than the Company beginning in the summer of 1998.
The Company is negotiating with Golden Spread to continue to supply their total
power needs, resolve outstanding regulatory issues, and build a long term
alliance.
El Paso Electric Company
EPE, which filed for bankruptcy in January 1992, and Central and South
West Corporation (CSW) terminated their merger agreement in June 1995. The
Company and EPE electrical systems are interconnected and the Company currently
sells wholesale power to EPE. In November 1993, EPE and CSW filed a request with
the FERC under Section 211 of the Federal Power Act for an order requiring the
Company to transmit power and energy over its transmission system between EPE
and Public Service Company of Oklahoma (PSO), a CSW utility subsidiary. In June
1995, the Company filed a motion with the FERC requesting that the Section 211
application be dismissed as moot due to the merger termination and in September
1995 it was dismissed.
City of Las Cruces
The City of Las Cruces, New Mexico (the City) is currently seeking to
establish a municipal electric utility system by purchase or through
condemnation of the EPE facilities serving the City. The bankruptcy court has
allowed the City to proceed with the condemnation if it cannot negotiate a
purchase of the utility system from EPE.
In August 1994, the Company and the City entered into a fifteen year
contract for the Company to provide all of the wholesale electric power and
energy required by the City during the term of the contract if the City
establishes a municipal system. The City's wholesale requirements are expected
to be approximately 80 MW by 1996, the earliest it is believed service could
commence. The contract becomes effective on the acquisition of (i) a
distribution system by the City; (ii) the necessary transmission delivery and
back-up agreements by the Company; and (iii) the required regulatory approvals
by the City and the Company. If the specified events are not completed by July
1, 1998, either the Company or the City has the right to cancel the contract.
Under the contract, the rates and charges for service to the City are fixed
until January 1, 2001.
The Company and the City also entered into a System Purchase Option and
Rate Agreement in August 1994. That agreement grants the City the option to sell
to the Company the electric utility system serving the City (including
distribution, subtransmission, and transmission facilities) which the City plans
to acquire by purchase or through condemnation proceedings. The agreement has a
three-year term beginning at the time the City acquires the facilities and
ending no later than January 1, 2002. The purchase price that would be paid by
the Company would be equal to the amount required to retire all unamortized
outstanding debt incurred by the City in acquiring the facilities from EPE plus
the City's reasonable costs in acquiring the facilities. The agreement provides
that the Company will charge a total rate that shall be less than the projected
rate to be charged by EPE post-merger and the cost of fuel EPE would bill to its
customers. The Company has the right to terminate the agreement if, in the
Company's sole discretion, it deems any proposed condemnation award to be
excessive, or upon the occurrence of certain other events. The agreement further
provides, that if the City abandons or dismisses condemnation proceedings as a
consequence of the Company's termination of the agreement, the Company will
reimburse the City for one-half of its reasonable litigation expenses and for
any of EPE's damages and litigation expenses that the City is obligated to pay
by final court order.
TNP and TUCO
See Note (2) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS for
information regarding the purchase of certain Texas properties from Texas-New
Mexico Power Company and the anticipated purchase of TUCO from Cabot
Corporation.
STATISTICAL SUMMARY
Electric Revenues
Operating revenues attributable to commercial and industrial sales of
electric energy accounted for 50% of total operating revenues in fiscal 1995.
Selected operating revenues and kwh sales follow:
Fiscal year ended August 31,
1995 1994 1993
Revenue Kwh Revenue Kwh Revenue Kwh
(Dollars In Thousands _ Kwh in Millions)
Commercial and Industrial:
Oil and gas related ................................. $137,646 4,117 $146,251 4,217 $143,306 4,130
Chemical, mineral and other manufacturing ........... 47,579 1,489 49,793 1,477 51,036 1,507
Petroleum refining .................................. 35,123 978 35,273 941 33,596 905
Agricultural ........................................ 19,545 417 20,199 411 16,613 339
Feedlots and packing plants ......................... 9,592 263 9,589 258 9,590 254
Irrigation .......................................... 12,118 190 11,370 174 8,771 134
The Company's largest system customer in fiscal 1995 was Amoco
Corporation, which purchased 1.0 billion kwh resulting in approximately $31.1
million in revenues.
Electric Operating Statistics Fiscal year ended August 31,
1995 1994 1993
Energy generated and purchased (kwh-000):
Generated _ net output ....................................... 21,159,953 21,609,287 20,378,776
Purchased and other .......................................... 350,183 253,314 278,485
Net interchange .............................................. 469 53 9
Total ............................. 21,510,605 21,862,654 20,657,270
Company use, lost and unaccounted for ........................ (1,175,029) (1,459,717) (1,388,519)
Energy generated and purchased, net ........ 20,335,576 20,402,937 19,268,751
Sales (kwh-000):
Retail:
Residential ......................................... 2,709,089 2,684,365 2,578,673
Commercial .......................................... 2,809,692 2,692,848 2,601,102
Industrial .......................................... 7,685,938 7,635,066 7,420,574
Other ............................................... 548,012 533,305 519,267
Wholesale:
Rural electric cooperatives ......................... 4,682,975 4,157,209 3,680,050
Other utilities _ firm .............................. 614,609 768,850 667,804
Other utilities _ non-firm .......................... 1,285,261 1,931,294 1,801,281
Total sales ....................... 20,335,576 20,402,937 19,268,751
Electric revenues (000):
Retail:
Residential ......................................... $160,908 $163,614 $159,712
Commercial .......................................... 147,764 146,901 145,393
Industrial .......................................... 267,842 276,335 272,825
Other ............................................... 27,331 27,531 27,290
Wholesale:
Rural electric cooperatives ......................... 165,930 147,010 129,069
Other utilities _ firm .............................. 29,494 31,644 26,154
Other utilities _ non-firm .......................... 31,351 47,150 46,642
Miscellaneous* ............................................... 4,194 3,956 3,431
Total electric revenues* .......... $834,814 $844,141 $810,516
*Includes intercompany revenues
Customers (end of period):
Retail:
Residential ......................................... 300,459 297,853 294,970
Commercial .......................................... 54,330 53,489 52,467
Industrial .......................................... 11,896 11,422 11,031
Other ............................................... 665 656 624
Wholesale:
Rural electric cooperatives ......................... 17 17 16
Other utilities ..................................... 157 128 107
Total customers ................... 367,524 363,565 359,215
Cost per net kwh generated (in cents):
Operation .................................................... 2.26 2.36 2.36
Maintenance .................................................. .14 .13 .13
Average revenue per kwh sold (in cents):
Residential .................................................. 5.94 6.10 6.19
Commercial ................................................... 5.26 5.46 5.59
Industrial ................................................... 3.48 3.62 3.68
Wholesale excluding non-firm sales to other utilities ........ 3.69 3.63 3.57
Total sales .................................................. 4.11 4.14 4.21
EXECUTIVE OFFICERS OF THE REGISTRANT
Years
Continuous
Present office, date elected thereto, and Age at Service with
Name previous title if in current office less than 5 years 11-1-95 Company
Bill D. Helton Chairman of the Board and Chief Executive Officer since 3-1-91; 57 31
President and Chief Executive Officer, 10-23-90 to 3-1-91
*Coyt Webb President and Chief Operating Officer, 3-1-91 to 8-31-95; 59 31
Senior Vice President and Chief Operating Officer, 1-9-91 to 3-1-91;
Senior Vice President, Controller and Chief Operating Officer, 10-23-90
to 1-9-91
David M. Wilks President and Chief Operating Officer since 9-1-95; 48 18
Senior Vice President, 1-9-91 to 9-1-95;
Vice President, Engineering and Operations, 7-25-89 to 1-9-91
Doyle R. Bunch II Executive Vice President, Accounting and Corporate Development 49 19
since 9-25-92;
Executive Vice President and Chief Financial Officer, 10-23-90 to 9-25-92
Kenneth L. Ladd, Jr Senior Vice President since 1-9-91; 56 34
Vice President, Energy and Environment, 1-1-88 to 1-9-91
John L. Anderson Vice President, Personnel since 1-11-89 61 36
Robert D. Dickerson Secretary and Treasurer since 1-13-88 46 20
Gerald J. Diller Vice President, Rates and Regulation since 7-27-93; 61 29
Group Manager, Rates and Regulation, 2-1-89 to 7-27-93
Gary L. Gibson Vice President, Marketing since 1-1-85 53 31
Henry H. Hamilton Vice President, Production since 1-14-87 57 31
Carl E. Jeans Vice President, Management Systems since 1-9-85 54 29
John McAfee Vice President, Engineering and Operations since 9-1-95; 50 22
Vice President, Panhandle Division and Corporate Communication,
2-1-95 to 9-1-95;
Vice President, Corporate Services, 7-25-89 to 2-1-95
*Retired effective August 31, 1995
None of the above executive officers of the Company are family related.
Officers of the Registrant are elected by, and hold office at the will of, the
Board of Directors and do not serve a "term of office" as such.
There is no arrangement or understanding between any officer and any
other person pursuant to which the officer was selected.
ITEM 2. PROPERTIES.
ELECTRIC GENERATING STATIONS
at August 31, 1995
Maximum Station Totals
Generator Maximum Net
Name-plate Generator Net Generation
Rating Name-plate Capability (Mwh) Fiscal
Year (Kilowatts) Principal Rating (Kilowatts) Year Ended
Generating Station Location New (A) Fuel (Kilowatts) (B) August 31, 1995
Steam
Harrington Near Amarillo, TX 1976 360,000 Coal
1978 360,000
1980 360,000 1,080,000 1,066,000 7,583,071
Tolk Near Muleshoe, TX 1982 568,000 Coal
1985 568,000 1,136,000 1,080,000 6,380,334
Jones Near Lubbock, TX 1971 247,500 Natural gas
1974 247,500 495,000 486,000 2,565,626
Plant X Near Earth, TX 1952 48,000 Natural gas
1953 98,000
1955 98,000
1964 190,400 434,400 442,000 747,169
Nichols Near Amarillo, TX 1960 113,635 Natural gas
1962 113,635
1968 247,500 474,770 457,000 1,459,737
Cunningham Near Hobbs, NM 1957 75,000 Natural gas
1965 190,400 265,400 267,000 1,475,139
Maddox Near Hobbs, NM 1967 113,636 Natural gas 113,636 118,000 590,305
CZ-2 Near Pampa, TX 1979 37,440 Purchased steam 37,440 26,000 210,644
Moore County Near Sunray, TX 1954 49,000 Natural gas 49,000 48,000 1,885
Subtotal, steam ................................................. 4,085,646 3,990,000 21,013,910
Other
Gas Turbine
Carlsbad Carlsbad, NM 1968 16,320 Natural gas 16,320 16,000 5,936
CZ-1 Near Pampa, TX 1964 13,281 Hot nitrogen 13,281 13,000 99,836
Maddox Near Hobbs, NM 1976 86,850 Natural gas
1963 11,500 98,350 76,000 34,468
Riverview Near Borger, TX 1916 25,000 Natural gas 25,000 25,000 4,356
Diesel Engines
Tucumcari Tucumcari, NM 1975 1,000 Diesel
1959 2,250
1963 1,000
1964 3,000
1968 4,100
1977 4,800 16,150 15,000 1,447
Subtotal, other.................................................. 169,101 145,000 146,043
Total, all generating stations................................ 4,254,747 4,135,000 21,159,953
(A) Pursuant to FERC instructions, name-plate ratings show the manufacturer's maximum
generator rating of each unit.
(B) Capability as used herein represents the demonstrated dependable carrying abilities
of the respective stationsduring peak periods as proven under actual operating conditions.
WATER SUPPLY
The Company has an adequate supply of water for condensing and other
purposes at its principal generating stations for the design life of the
stations. To ensure future flexibility in the use of these stations beyond their
original design lives, the Company is negotiating additional water supplies for
certain generating stations. In an effort to conserve the fresh, potable water
of the area, the Company purchases for its Harrington and Nichols Stations
located near Amarillo, Texas, and its Jones Station located near Lubbock, Texas,
an aggregate of approximately 15,000,000 gallons of water per day from sewage
treatment plants owned by the respective cities, which it processes to a point
which permits its use as cooling tower water. The water is subsequently used for
irrigation.
ITEM 3. LEGAL PROCEEDINGS.
The Company has been named as a defendant in a case entitled Thunder
Basin Coal Co. v. Southwestern Public Service Co., No. 93-CV-304B (D. Wyo.). The
action was served on the Company on February 14, 1994 and it involves a dispute
over the interpretation of a clause in a contract between Thunder Basin and TUCO
for the supply of coal for use by the Company. The suit sought a determination
that there has been a partial repudiation of the agreement by TUCO which has
damaged Thunder Basin, and that the Company is liable for that damage as a
result of its guarantee of TUCO's performance. Thunder Basin also claimed that
the Company interfered with the contract between Thunder Basin and TUCO, causing
Thunder Basin damage. The total alleged damages sought by Thunder Basin was in
excess of $20 million. The Company denied any liability, and asked the court to
determine that its interpretation of the contract was correct.
Thunder Basin's Wyoming lawsuit in federal court went to trial in late
October 1994. On November 1, 1994 the jury returned a verdict in favor of
Thunder Basin and against the Company finding that there had been a partial
repudiation of the contract and that the Company had interfered with Thunder
Basin's contract with TUCO. The jury awarded damages to Thunder Basin of
approximately $18.8 million. The Company has appealed the judgement to the Tenth
Circuit Court of Appeals and the appeal is progressing.
The Company, in conjunction with TUCO, has commenced a related case
against Thunder Basin and its parent ARCO in state court in Amarillo, Texas (No.
80,280-E, TUCO, Inc. v. Thunder Basin Coal Company). This suit involves some of
the same issues of contract interpretation raised in the Thunder Basin Wyoming
suit, as well as the Company's claims that it has been overcharged approximately
$40 million for coal during the course of the contract. This litigation is
proceeding.
TUCO requested an audit of Thunder Basin's and ARCO's costs and
expenses used to calculate the cost escalation under the contracts which supply
coal for the Company. Thunder Basin and ARCO filed suit in Wyoming state court
(No. 20041, Thunder Basin Coal Company v. TUCO, Inc. and Southwestern Public
Service Company) on June 26, 1995, seeking a declaratory judgment of the extent
of the information which must be revealed to TUCO under the coal supply
contracts. That suit was amended in September 1995 to request a declaratory
judgment of the issues pending in the Texas state court litigation.
Management believes that if a payment must ultimately be made to
Thunder Basin it would be recoverable from ratepayers, although any such
recovery would be subject to regulatory review. The Company has applied to the
FERC for approval to recover, subject to refund, the $18.8 million in potential
damages. Intervention has been filed and the matter is pending before the FERC.
Management believes that ultimate resolution will not have a material adverse
effect on the Company's consolidated financial statements.
The Company is involved in ordinary routine litigation incidental to
the business which litigation is not considered material. See REGULATION,
ENVIRONMENTAL MATTERS and Notes (6), (8) and (9) of NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS for information on regulation, environmental and rate
matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matter was submitted during the fourth quarter of the Company's 1995
fiscal year to a vote of its security holders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The principal markets on which the Company's common stock is traded are
the New York, Chicago and Pacific Stock Exchanges. The common stock has unlisted
trading privileges on the Boston and Philadelphia Stock Exchanges. The table
below presents the high and low market prices as reported by the National
Quotations Bureau, Inc., and dividend information for the Company's common
stock.
Market Price Dividends
High Low Declared
1995 - Fiscal Quarter Ended:
November 30, 1994 $27 $25-1/8 $0.55
February 28, 1995 29-3/8 25-7/8 0.55
May 31, 1995 29 27-1/4 0.55
August 31, 1995 30-3/4 28-5/8 0.55
1994 - Fiscal Quarter Ended:
November 30, 1993 $32-1/2 $29-3/4 $0.55
February 28, 1994 31-1/8 27-5/8 0.55
May 31, 1994 29-1/4 23-3/4 0.55
August 31, 1994 27-1/4 24-1/8 0.55
The Company declared dividends on its common stock of $2.20 in 1995 and
1994. The Company has agreed with PSCo in the merger agreement that it will not
raise its common stock dividend rate without the consent of PSCo. The Company's
dividend payout on its common stock was 79% in 1995 and 93% in 1994. At August
31, 1995, the number of holders of record of the Company's common stock was
30,496.
The Company's Restated Articles of Incorporation (Articles) provide
that the Company may not, without the consent of two-thirds in aggregate par
value of the preferred stock outstanding, (1) declare any dividends (other than
dividends payable in stock junior to the preferred stock) on, or acquire shares
of such junior stock unless, after giving effect thereto, the common stock
equity, as defined, is at least equal to the involuntary liquidation value of
the preferred stock and any stock ranking on a parity therewith or prior
thereto; or (2) make any distribution out of capital or capital surplus (other
than dividends payable in junior stock) to holders of junior stock, or purchase
any junior stock, if thereupon the common stock equity would be below 22% of
total capitalization, as defined. If the common stock equity at the end of any
fiscal year is less than 25% of total capitalization, the Company must, during
the ensuing fiscal year, redeem shares of preferred stock of certain series
having an aggregate par value equal to one-quarter of the amount of such
deficiency. Dividends on and acquisition of common stock are prohibited during a
failure to comply with such obligation. At August 31, 1995, the common stock
equity represented approximately 52% of total capitalization.
The Company has called for redemption and is purchasing all of its
currently outstanding Preferred Stock. The Company will seek approval of its
Common Shareholders at the Annual Meeting scheduled for January 31, 1996, to
amend its Articles to eliminate the current provisions with respect to Preferred
Stock, including those described above, and adopt modern, flexible provisions
pursuant to which new series would be issued. See MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Liquidity and Capital
Resources.
The Company covenants, in the Mortgage pursuant to which First Mortgage
Bonds are issued, that it will not declare any dividends (other than dividends
payable in its stock) upon its common stock, or make any payment on account of
the purchase, redemption or other retirement of, or make any distribution in
respect of, any shares of its stock except to the extent that the sum of (1)
$1,278,243.59, (2) net income of the Company, as defined, since June 1, 1946,
and (3) net proceeds received by the Company from the issue since such date of
any shares of its stock (but only up to an amount equal to the aggregate amount
of all payments since such date on account of the acquisition of any shares of
its stock) shall be (after giving effect to such dividends or distributions)
greater than the aggregate amount of dividends declared on all classes of the
Company's stock and of all payments made on account of the acquisition of, or
distribution in respect of, any shares of its stock since such date. See Note
(4) of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
In 1991 the Company adopted a Shareholder Rights Plan, which has been
amended so that it is not applicable to the merger with PSCo. See Note (1) of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 6. SELECTED FINANCIAL DATA.
Fiscal year ended August 31,
1995 1994 1993 1992 1991
(Dollars In Thousands Except Per Share Amounts)
Operating revenues $ 834,083 $ 843,448 $ 809,753 $ 749,154 $ 724,825
Operating income $ 154,211 $ 139,719 $ 140,684 $ 137,755 $ 149,966
Net earnings $ 119,477 $ 102,168 $ 105,254 $ 102,987 $ 114,836
Earnings per weighted average common
share outstanding $2.80* $2.38 $2.43 $2.34 $2.63**
Dividends per share $2.20 $2.20 $2.20 $2.20 $2.20
Ratio of earnings to fixed charges 5.10 4.76 4.82 4.53 4.67
Ratio of earnings to fixed charges and
preferred dividend requirements combined 4.37 4.04 4.01 3.63 3.79
Return on average common equity 16.2% 14.1% 14.5% 14.2% 16.2%
Operating income as a percent of
operating revenue 18.5% 16.6% 17.4% 18.4% 20.7%
Total assets $1,909,005 $1,821,235 $1,718,546 $1,705,734 $1,680,709
Long-term debt and redeemable
preferred stock*** $ 582,552 $ 523,228 $ 548,772 $ 554,117 $ 547,825
Weighted average common stock outstanding 40,917,908 40,917,908 40,917,908 40,917,908 40,917,908
Book value per common share $17.61 $17.01 $16.84 $16.61 $16.47
*Includes a $0.13 increase in earnings per share attributable to a change in the
estimated delivered not billed kwh sales and an $0.11 increase in earnings per share attributable to a one-time
adjustment resulting from settlement of the 1985 FERC rate case with New Mexico wholesale customers.
**Includes an increase of $0.09 per share attributable to a one-time adjustment resulting from the 1985 FERC rate case.
***Includes current maturities of long-term debt.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
References to "years" in this discussion pertain to the Company's
fiscal years which begin September 1 and end August 31. References to "Notes"
pertain to the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
Operating Revenues and Kilowatt-Hour Sales
Substantially all of the Company's operating revenues result from the
sale of electric energy. The principal factors determining revenues are the
amount and price per unit of energy sold. The following table describes the
principal components of changes in revenues.
Increase (Decrease) From Prior Year
1995 1994
(Dollars In Thousands)
Estimated effect on revenues of:
Variations in kilowatt-hour (kwh) sales* $ 19,943 $ 41,537
Variations in rates 9,110 (13,994)
Variations in fuel and purchased power cost recovery (22,583) 5,509
Subtotal 6,470 33,052
Variations in non-firm kwh sales (15,835) 643
Total revenue increase (decrease) $ (9,365) $ 33,695
Increase in kwh sales* (in millions) 579 1,004
Increase (decrease) in non-firm kwh sales (in millions) (646) 130
*Comprised of retail and wholesale sales excluding economy and
interruptible wholesale (non-firm) kwh sales.
Variations in Kwh Sales. The revenue increases in 1995 were due
primarily to increased kwh sales to rural electric cooperatives (RECs) and
retail (ultimate) customers. The increase in REC sales was due primarily to Cap
Rock Electric Cooperative (Cap Rock). Sales began in February 1994 and increased
to 100% of Cap Rock's West Texas requirements in February 1995. Accounting
adjustments to the estimate of delivered not billed kwh sales also increased kwh
revenues by approximately $8.3 million. These estimated kwh sales relate to
energy used by customers but not billed until the subsequent month. Increases in
1994 were due largely to increased sales to all classes of customers, but
principally RECs. These increases were due in large part to dry, hot weather
that favorably impacted agriculture-related sales. The Company expects modest
growth in kwh sales (excluding non-firm sales) in 1996, given normal weather
conditions. Current estimates of the compound annual growth rates in kwh sales
for the five-year period 1996-2000 are 2.5% for wholesale sales (excluding
non-firm sales) and 2.0% for retail sales. Last year the Company estimated for
the period 1995-1999 that its wholesale sales growth rate would be 3.9% and the
retail sales growth rate would be 1.6%. Last year's wholesale growth rate
estimate was higher because it included the increase in the Cap Rock load.
Actual kwh sales by class of customer are shown in the following table:
1995 1994 1993
(Kwh In Millions)
Retail Sales:
Residential 2,709 2,685 2,579
Commercial 2,810 2,693 2,601
Industrial 7,686 7,635 7,421
Other 548 533 519
Total Retail Sales 13,753 13,546 13,120
Wholesale Sales:
Rural electric cooperatives 4,683 4,157 3,680
Other utilities:
Firm 615 769 668
Non-firm* 1,285 1,931 1,801
Total Wholesale Sales 6,583 6,857 6,149
Total Sales 20,336 20,403 19,269
*Comprised of economy and interruptible sales.
Variations in Rates. Increased revenues for 1995 resulted primarily
from additional demand charge revenues paid by certain wholesale customers.
Additionally, a settlement of the 1985 Federal Energy Regulatory Commission
(FERC) rate case with the Company's New Mexico wholesale REC customers
contributed increased revenues of approximately $4.0 million (and interest of
$3.0 million which is included in other income) (see Note 9). Revenues
attributable to rate changes decreased for 1994 because of the effects of the
retail rate reductions in Texas and New Mexico. In Texas reduced rates totaling
approximately $13 million annually were implemented October 15, 1993. In New
Mexico an approximate $4 million annual reduction, approved in September 1994,
became effective April 1, 1994.
Variations in Fuel and Purchased Power Cost Recovery. Revenues
decreased in 1995 due to substantially lower natural gas prices. These revenues
increased in 1994 due to greater per unit fuel cost as a result of higher coal
costs.
Fuel and purchased power costs are recoverable in Texas under a Public
Utility Commission of Texas (PUCT) rule that provides for a fixed factor (based
on known or reasonably measurable fuel costs) to be used for fuel cost
collection with final approval of the amount of recoverable fuel cost being
determined at the time of a utility's fuel reconciliation proceeding. If
reasonably unforeseeable circumstances result in a material under-recovery of
fuel costs, the utility may file a petition with PUCT requesting an emergency
interim fuel factor. The Company's current fixed factor, set by the PUCT in
April 1990, is based on then reasonably predictable fuel and purchased power
costs. In all other jurisdictions, the Company currently recovers substantially
all increases and refunds substantially all decreases in fuel and purchased
power costs pursuant to monthly adjustment clauses. Currently the Company has
$5.5 million in total overrecovered costs that are comprised of fuel costs
totaling $3.7 million and off-system sales margin credits totaling $1.8 million.
The Company refunded to its Texas retail customers margin credits on non-firm
sales totaling $4.6 million in 1995. The Company is currently in a fuel
reconciliation with the PUCT (see Note 9).
Variations in Non-Firm Kwh Sales. The amount of revenues arising from
non-firm sales is dependent, in large part, upon the amount and cost of power
available to the Company for sale, the demand for power, the availability of
competing hydro-electric power from the Northwest and generation from major
plants in the West. The decline in non-firm sales in 1995 was due primarily to
available power from major western plants and excess hydroelectric power in the
Northwest. Mild weather throughout the region, particularly in the winter, also
contributed to the decline for the year. Greater non-firm sales in 1994 were due
primarily to increased sales to other regional utilities. These sales were
curtailed somewhat in the last quarter of 1994 and 1995 because hot weather in
the Company's service territory limited the amount of power the Company had
available for such sales.
Operating Expenses and Other Income
Operating Expenses. Fuel and purchased power expense comprised 55.2% of
total operating expenses in 1995 and 58.0% in 1994. Such expenses, when compared
to prior years, decreased 8.0% in 1995 and increased 6.5% in 1994. The decrease
in 1995 is due primarily to decreased natural gas prices and decreased kwh
generation. The primary reason for the rise in 1994 was increased kwh
generation. The fuel cost per net kwh generated was 1.75 cents, 1.87 cents and
1.85 cents in 1995, 1994 and 1993, respectively. The decline in 1995 was due to
decreased natural gas prices. The increase in 1994 was due to increased coal
costs. Although fuel costs are expected to rise marginally throughout 1996, the
Company plans to mitigate any such increases through the purchase of
lower-priced gas on the open market and under short-term contracts, as well as
using low-priced coal purchased on the spot market for generation of off-system
sales.
Operating expenses, excluding fuel and purchased power, increased 2.9%
in 1995 and 3.4% in 1994. The increase in 1995 was due primarily to increased
federal income taxes as a result of larger taxable income. The increase in 1994
was due primarily to the adoption of Statement of Financial Accounting Standards
No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
(see Note 7). Additionally, "Taxes other than property and income taxes" were
higher in 1994 because a one-time Texas franchise tax refund lowered such taxes
in 1993. This refund was a result of the Company amending its returns for 1988
through 1991 to utilize accelerated instead of straight-line depreciation to
determine taxable capital. In 1995 and 1994 cost-reduction and cost-control
measures were implemented throughout the Company in an effort to mitigate the
financial impact of retail rate reductions that resulted in lowering the level
of increases in certain operating expenses. Additionally, lower depreciation
rates, approved in Texas and New Mexico retail jurisdictions in conjunction with
the rate cases to lower base rates, caused depreciation expense to be
approximately $2.9 million lower in 1994 than it would have been under the
previous rates. Property additions caused increased property taxes in 1995 and
school finance reform in Texas resulted in property tax increases in 1994.
Although property taxes are expected to continue to increase in 1996, the rate
of increase is expected to decline. The Company has a hiring freeze in effect
during the merger process (see Note 2). The Company's expenses in 1995 and 1994
were not significantly impacted by inflation.
Other Income. Other income increased 150.7% in 1995 and decreased 45.1%
in 1994. The $4.3 million increase in 1995 is due primarily to approximately
$3.0 million of interest on the rate case settlement with New Mexico wholesale
customers and greater subsidiary earnings. The write-off in 1994 of nonrecurring
items caused the decline in such income in 1994. These nonrecurring items
included $2.8 million of engineering and design costs of a previously planned
generating facility and contractual costs associated with other generation
studies. Also included was $0.6 million of business development costs related to
a generation project in the state of Missouri. Also contributing to the decrease
in 1994 was a $1.4 million reduction in the equity portion of allowance for
funds used during construction (AFUDC) due to reduced rates. Somewhat offsetting
the effects of the nonrecurring expenses and lower AFUDC was a $1.5 million
increase in subsidiary income. Subsidiary operations contributed approximately
13 cents per share to earnings in 1995 and 8 cents in 1994.
Earnings
Operating income and earnings applicable to common stock increased in
1995 due primarily to greater sales to RECs, the change in estimate of delivered
not billed kwh ($5.4 million or 13 cents per share) and the rate settlement with
wholesale customers in New Mexico ($4.5 million or 11 cents per share).
Operating income and earnings declined in 1994 due to increased operating
expenses. In 1994 the favorable effects of increased kwh sales and lower
preferred stock dividends were mitigated by retail rate reductions, nonrecurring
expenses, and lower AFUDC. Assuming normal weather conditions, earnings for the
1996 fiscal year are expected to remain relatively level. A favorable resolution
of the 1985 FERC rate case with Texas wholesale REC customers could materially
improve 1996 earnings. Quixx has entered into an agreement to sell certain water
rights to the Canadian River Municipal Water Authority for $14.5 million which
would result in an after-tax gain of approximately $7.6 million. The Company
expects, but can give no assurance, that this sale would be completed in fiscal
1996.
The Company's average common equity for the years 1995, 1994 and 1993
was $708.5 million, $692.5 million and $684.2 million, respectively. The rate of
return on average common equity for these years was 16.2%, 14.1% and 14.5%,
respectively. The components of such return are presented as follows:
1995 1994 1993
Components of Return on Average Common Equity:
Rate-related income 13.5% 13.5% 13.6%
Subsidiary and other income 1.0 .4 .5
Allowance for funds used during construction .3 .2 .4
New Mexico wholesale settlement .6 - -
Delivered not billed adjustment .8 - -
Total 16.2% 14.1% 14.5%
LIQUIDITY AND CAPITAL RESOURCES
The Company's demand for capital is normally related to the
construction of utility plant and equipment. Cash construction expenditures
excluding AFUDC were $94.7 million, $91.8 million and $92.3 million in 1995,
1994 and 1993, respectively. During 1995 the Company generated substantially all
of its capital requirements for such purposes internally. Also in 1995, Quixx
invested $28.3 million in independent power projects and expects to continue to
make such investments in the future dependent upon suitable investment
opportunities and the availability of capital. Estimated construction
expenditures excluding AFUDC are $112.9 million for 1996 and $665 million for
the five-year period 1996-2000. In 1996 the anticipated purchase of TUCO, Inc.
(TUCO) from Cabot Corporation and certain Texas properties purchased from Texas
New Mexico Power Company (TNP) will result in additional cash requirements of
approximately $106 million (see Note 2). The portion of cash requirements to be
provided by internally generated funds cannot be accurately forecast, but the
Company expects that it will be approximately 40% in 1996 (including TNP and
TUCO), and approximately 55% for the five-year period 1996-2000. The Company's
estimates of capital needs, particularly those related to construction, and
generation of internal funds are subject to review and revision, and may vary
substantially from the foregoing. During the period 1996-2000, the Company will
be required to retire $105 million of long-term debt, comprised of $15 million
First Mortgage Bonds (Bonds), 5.70% Series due 1997 and $90 million Bonds 6.875%
Series due 1999.
In addition, as discussed under BUSINESS-General, the Company has
called for redemption as of December 27, 1995, all of its outstanding Preferred
Stock which is redeemable by its terms and will purchase all of the outstanding
2,600 shares of its 14.50% Cumulative Preferred Stock which is not redeemable by
its terms. As a consequence, following the redemptions and purchase, there will
be no shares of Preferred Stock outstanding. The Company will seek approval of
the holders of its Common Stock at its Annual Meeting to be held on January 31,
1996, to amend its Articles relating to the Preferred Stock in order to provide
for updated provisions and eliminate covenants imposed by the current
provisions. The aggregate redemption price of the outstanding shares of stock
which are to be redeemed is approximately $75 million, including accrued
dividends. The purchase price of the non-redeemable 14.50% Cumulative Preferred
Stock is being negotiated. The Company plans to finance the redemption and
purchase of the Preferred Stock with the use of short-term borrowings, which
would be repaid subject to market conditions with the issuance of new Preferred
Stock following the Annual Meeting in January 1996 or with the issuance of Bonds
during 1996. The estimates set forth in the preceding paragraph do not include
the issuance of securities to obtain the funds required for the Preferred Stock
redemptions and purchase. The Company currently contemplates the sale of other
Preferred Stock, Common Stock and Bonds during the five-year period 1996-2000 in
connection with the financing of its construction program and retirement of
Bonds.
In August 1994 the Company entered into a forward interest rate swap
agreement in anticipation of redeeming its $25 million principal amount of
13-1/2% pollution control revenue bonds with a new issuance of variable rate
pollution control revenue bonds. Such bonds are not redeemable until October 1,
1996 (see Note 4).
The Company has effective a shelf registration under which a remaining
aggregate of $130 million of First Mortgage Bonds and Cumulative Preferred Stock
may be issued (a maximum of $40 million of Preferred Stock is issuable
thereunder). At August 31, 1995, the Company maintained committed bank lines of
credit aggregating $128 million, of which the Company had no borrowings
outstanding at fiscal year-end.
OTHER MATTERS
Electric utilities have historically operated in a highly regulated
environment in which they have an obligation to provide electric service to
their customers in return for an exclusive franchise within their service
territory with an opportunity to earn a regulated rate of return. This
regulatory environment is changing. The generation sector has experienced
competition from nonutility power producers, and the FERC is requiring
utilities, including the Company, to provide wholesale transmission service to
others and may order electric utilities to enlarge their transmission systems to
facilitate transmission services. Some state regulatory authorities are in the
process of changing utility regulations in response to federal and state
statutory changes and evolving markets (see Note 8). In partial response to
these changing conditions, the Company has entered into a definitive merger
agreement with Public Service Company of Colorado (the Merger). Consummation of
the Merger is subject to customary conditions including receiving shareholder
and regulatory authority approvals. The two utilities are working toward a
completion date in the fall of 1996 (see Item 1. BUSINESS-General and Note 2).
The foregoing discussions of the Company's results of operations and liquidity
and capital resources do not take into account any changes that could arise as a
result of the Merger.
The foregoing discussion and analysis by management is intended to
provide a summary of information relevant to an assessment of the financial
condition and results of operations of the Company and should be read together
with the Consolidated Financial Statements and Notes to Consolidated Financial
Statements in order to arrive at a more complete understanding of such matters.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Southwestern Public Service Company:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of Southwestern Public Service Company and
subsidiaries as of August 31, 1995 and 1994, and the related consolidated
statements of earnings, common shareholders' equity and cash flows for the years
then ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements 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 Southwestern Public Service
Company and subsidiaries as of August 31, 1995 and 1994, and the results of
their operations and their cash flows for the years then ended, in conformity
with generally accepted accounting principles.
As discussed in Notes 1 and 7 to the consolidated financial statements,
in 1994, the Company changed its method 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.
DELOITTE & TOUCHE LLP
Dallas, Texas
October 10, 1995
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Southwestern Public Service Company:
We have audited the accompanying consolidated statements of earnings,
common shareholders' equity and cash flows of Southwestern Public Service
Company and subsidiaries for the year ended August 31, 1993. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the results of operations and cash
flows of Southwestern Public Service Company and subsidiaries for the year ended
August 31, 1993, in conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Amarillo, Texas
October 8, 1993
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Balance Sheets
August 31, 1995 and 1994
1995 1994
(In Thousands)
Assets
Utility Plant:
Utility plant in service $ 2,366,435 $ 2,280,126
Accumulated depreciation (854,015 (794,102)
Net plant in service 1,512,420 1,486,024
Construction work in progress 31,026 22,590
Net utility plant 1,543,446 1,508,614
Nonutility Property and Investments 70,087 41,868
Current Assets:
Cash and temporary investments 36,860 20,782
Accounts receivable, net 73,262 69,357
Accrual for unbilled revenues 28,626 21,318
Materials and supplies, at average cost 21,647 18,238
Prepayments and other current assets 10,734 8,555
Total current assets 171,129 138,250
Deferred Debits 124,343 132,503
Total Assets $ 1,909,005 $ 1,821,235
Capitalization and Liabilities
Capitalization (See Consolidated Statements of Capitalization):
Common shareholders' equity $ 720,752 $ 696,172
Preferred stock 72,680 72,680
Long-term debt 582,276 506,487
Total capitalization 1,375,708 1,275,339
Current Liabilities:
Short-term debt - 14,994
Current maturities of long-term debt 276 16,741
Accounts payable 12,187 12,301
Liability for refunds to customers 5,969 3,804
Interest accrued 9,067 8,799
Fuel and purchased power expense accrued 40,164 40,884
Taxes accrued 39,757 30,359
Dividends payable on common stock 22,505 22,505
Other current liabilities 39,843 35,092
Total current liabilities 169,768 185,479
Deferred Credits:
Deferred income taxes 344,794 339,456
Unamortized investment tax credits 6,053 6,303
Other 12,682 14,658
Total deferred credits 363,529 360,417
Commitments and Contingencies
Total Capitalization and Liabilities $ 1,909,005 $ 1,821,235
See accompanying notes to consolidated financial statements.
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Statements of Capitalization
August 31, 1995 and 1994
1995 1994
(In Thousands)
Common Shareholders' Equity:
Common stock, $1 par value, authorized 100,000,000 shares in 1995 and
1994; outstanding 40,917,908 shares in 1995 and 1994 $ 40,918 $ 40,918
Premium on capital stock 306,376 306,376
Retained earnings 373,458 348,878
Total common shareholders' equity $720,752 $696,172
Cumulative Preferred Stock:
Preferred stock, $25 par value, authorized 3,000,000 shares;
outstanding 920,000 shares in 1995 and 1994
Preferred stock, $100 par value, authorized 2,000,000 shares;
outstanding 496,800 shares in 1995 and 1994
Par Shares Redemption
Series Value Outstanding Price
Redemption not required:
4.36% $ 25 80,000 $ 25.50 $ 2,000 $ 2,000
4.40 25 120,000 25.50 3,000 3,000
5.00 25 120,000 25.50 3,000 3,000
8.88 25 600,000 26.05 15,000 15,000
3.70 100 22,410 104.50 2,241 2,241
4.15 100 42,590 116.50 4,259 4,259
3.90 100 20,000 103.50 2,000 2,000
4.40 100 9,200 102.00 920 920
4.25 100 10,000 101.00 1,000 1,000
4.60 100 20,000 101.00 2,000 2,000
4.75 100 20,000 102.00 2,000 2,000
5-5/8 100 50,000 103.00 5,000 5,000
6.50 100 100,000 101.50 10,000 10,000
8.00 100 200,000 101.00 20,000 20,000
14.50 100 2,600 Not redeemable 260 260
Total preferred stock $ 72,680 $ 72,680
See accompanying notes to consolidated financial statements. Continued . . .
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Statements of Capitalization, Continued
August 31, 1995 and 1994
1995 1994
(In Thousands)
Long-Term Debt:
First Mortgage Bonds:
Rate Maturity
4-5/8% February 1995 - $ 16,000
5.70 February 1997 $ 15,000 15,000
7-1/4 July 2004 135,000 135,000
8-1/4 July 2022 40,000 40,000
6.875 December 1999 90,000 90,000
8.20 December 2022 100,000 100,000
8.50 February 2025 70,000 -
Unamortized debt discount, net (1,418) (1,510)
Total first mortgage bonds 448,582 394,490
Pollution control obligations, securing Red River Authority Pollution
Control Revenue Bonds, net:
Series Rate Maturity
Not collateralized by First Mortgage Bonds:
1991 adjustable July 2011 44,500 44,500
Collateralized by First Mortgage Bonds:
1979 6-1/2% March 2004 25,000 25,000
1979 6-5/8 March 2009 32,300 32,300
1981 13-1/2 October 2001 25,000 25,000
Funds held and invested by Trustee (55) (98)
Total pollution control obligations, net 126,745 126,702
Other long-term debt 7,225 2,036
Total long-term debt, including current maturities 582,552 523,228
Current maturities (276) (16,741)
Total long-term debt $ 582,276 $ 506,487
Total Capitalization $1,375,708 $1,275,339
See accompanying notes to consolidated financial statements.
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Statements of Earnings
For the years ended August 31, 1995, 1994 and 1993
1995 1994 1993
(In Thousands, Except Per Share Amounts)
Operating Revenues $834,083 $843,448 $809,753
Operating Expenses:
Operation:
Fuel 370,052 403,207 377,919
Purchased power 5,241 4,604 4,969
Other 107,467 107,295 103,401
Maintenance 29,039 28,276 27,392
Depreciation and amortization 61,069 60,551 61,348
Taxes other than property and income taxes 19,122 19,471 15,828
Property taxes 24,009 22,468 21,548
Income taxes 63,873 57,857 56,664
Total operating expenses 679,872 703,729 669,069
Operating Income 154,211 139,719 140,684
Other Income, Net:
Allowance for equity funds used during construction 229 559 1,923
Income taxes (3,775) (531) (1,004)
Other, net 10,746 2,844 4,312
Total other income, net 7,200 2,872 5,231
Interest Charges:
Interest on long-term debt 40,644 37,881 38,992
Allowance for borrowed funds used during construction (2,463) (1,044) (876)
Other interest 3,753 3,586 2,545
Total interest charges 41,934 40,423 40,661
Net Earnings 119,477 102,168 105,254
Dividends and premiums on cumulative preferred stock 4,878 4,878 6,009
Earnings Applicable to Common Stock $114,599 $ 97,290 $ 99,245
Weighted Average Shares Outstanding 40,918 40,918 40,918
Earnings per Common Share $2.80 $2.38 $2.43
Dividends Declared per Common Share $2.20 $2.20 $2.20
See accompanying notes to consolidated financial statements.
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Statements of Common Shareholders' Equity For the years ended
August 31, 1995, 1994 and 1993
Shares of Amount of Premium
Common Common on Capital Retained
Stock Stock Stock Earnings Total
(In Thousands)
Balance at August 31, 1992 40,918 $ 40,918 $306,172 $332,383 $679,473
Net earnings - - - 105,254 105,254
Redemption of cumulative preferred stock - - 204 (383) (179)
Dividends declared:
Cumulative preferred stock - - - (5,626) (5,626)
Common stock, $2.20 per share - - - (90,020) (90,020)
Balance at August 31, 1993 40,918 40,918 306,376 341,608 688,902
Net earnings - - - 102,168 102,168
Dividends declared:
Cumulative preferred stock - - - (4,878) (4,878)
Common stock, $2.20 per share - - - (90,020) (90,020)
Balance at August 31, 1994 40,918 40,918 306,376 348,878 696,172
Net earnings - - - 119,477 119,477
Dividends declared:
Cumulative preferred stock - - - (4,878) (4,878)
Common stock, $2.20 per share - - - (90,019) (90,019)
Balance at August 31, 1995 40,918 $ 40,918 $ 306,376 $373,458 $720,752
See accompanying notes to consolidated financial statements.
SOUTHWESTERN PUBLIC SERVICE COMPANY
Consolidated Statements of Cash Flows
For the years ended August 31, 1995, 1994 and 1993
1995 1994 1993
(In Thousands)
Operating Activities:
Cash received from customers $ 824,103 $ 851,602 $ 782,358
Cash paid to suppliers and employees (510,319) (536,618) (499,964)
Interest paid (42,090) (39,569) (42,742)
Income taxes paid (50,088) (47,126) (41,614)
Taxes other than income taxes paid (41,898) (41,388) (39,156)
Other operating cash receipts and payments, net 9,819 12,751 8,224
Net cash provided by operating activities 189,527 199,652 167,106
Investing Activities:
Construction expenditures (94,662) (91,788) (92,315)
Nonutility property and investments (28,219) (12,763) (3,429)
Net cash used in investing activities (122,881) (104,551) (95,744)
Financing Activities:
Issuance of long-term debt 76,204 _ 190,000
Retirement of long-term debt (16,880) (25,544) (177,315)
Change in short-term debt (14,994) 14,994 _
Redemption of cumulative preferred stock _ _ (27,345)
Dividends paid (common and preferred) (94,898) (94,898) (95,645)
Net cash used in financing activities (50,568) (105,448) (110,305)
Net Increase (Decrease) in Cash and Temporary Investments 16,078 (10,347) (38,943)
Cash and Temporary Investments at Beginning of Year 20,782 31,129 70,072
Cash and Temporary Investments at End of Year $ 36,860 $ 20,782 $ 31,129
Reconciliation of Net Earnings to Net Cash Provided by Operating Activities:
Net earnings $119,477 $102,168 $105,254
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization 61,069 60,551 61,348
Deferred income taxes and investment tax credits 9,467 11,314 13,633
Allowance for equity funds used during construction (229) (559) (1,923)
Cash flows impacted by changes in:
Accounts receivable (3,905) 4,080 (14,273)
Accrual for unbilled revenues (7,308) 2,304 161
Materials and supplies (3,409) (1,495) (167)
Accounts payable (114) 1,071 854
Fuel and purchased power expense accrued (720) (306) 8,748
Taxes accrued 9,398 4,612 3,833
Liability for refunds to customers 2,165 2,768 (12,380)
Other, net 3,636 13,144 2,018
Net cash provided by operating activities $189,527 $199,652 $167,106
See accompanying notes to consolidated financial statements.
SOUTHWESTERN PUBLIC SERVICE COMPANY
Notes To Consolidated Financial Statements
August 31, 1995
(1) Nature of Operations and Summary of Significant Accounting Policies
GENERAL
Southwestern Public Service Company (the Company) is principally
engaged in the generation, transmission, distribution and sale of electric
energy. The Company maintains its accounts in accordance with the Uniform System
of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as
adopted by the Public Utility Commission of Texas (PUCT), the New Mexico Public
Utility Commission (NMPUC), the Oklahoma Corporation Commission and the Kansas
Corporation Commission.
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries, Utility Engineering Corporation (UE)
and Quixx Corporation and subsidiaries (Quixx). UE is primarily engaged in
engineering, design and construction management. Quixx invests in cogeneration
projects and holds water rights and certain other nonutility assets. The
aggregate net earnings of UE and Quixx of $5,216,000, $3,335,000 and $1,868,000
in 1995, 1994 and 1993, respectively, are included in net other income in the
Consolidated Statements of Earnings. All significant intercompany transactions
and balances are eliminated in consolidation.
UTILITY PLANT
Utility plant is stated at the historical cost of construction, which
includes labor, materials, an allowance for funds used during construction and
indirect charges for such items as engineering, supervision and general
administrative costs. Maintenance, repairs and minor replacements are charged to
operating expense; major replacements and betterments are capitalized.
The cost of depreciable units of utility plant retired or disposed of
in the normal course of business is eliminated from utility plant accounts and
such cost plus removal expenses and less salvage value is charged to accumulated
depreciation. When complete operating units are disposed of, appropriate
adjustments are made to accumulated depreciation, and the resulting gains or
losses, if any, are recognized.
The provision for depreciation is computed on a straight-line method at
rates based on the estimated service lives and salvage values of the several
classes of depreciable property as indicated by periodic depreciation studies.
Depreciation as a percentage of average depreciable cost was 2.86% in 1995,
2.83% in 1994 and 2.96% in 1993.
OPERATING REVENUES
Electric rates include estimates of fuel costs incurred by the Company
in the generation or purchase of electricity. Differences between amounts
collected and allowable costs are recorded as over/underrecovered fuel and
purchased power costs in accordance with ratemaking policies of regulatory
authorities. Such overrecovered fuel and purchased power costs are reflected as
liability for refunds to customers in the accompanying consolidated financial
statements.
Included in operating revenues is an estimate of revenues for electric
services provided but not billed. In 1995 the Company made accounting
adjustments to the estimate of delivered not billed kwh sales which increased
operating revenues by approximately $8,300,000 and net income by approximately
$5,400,000, or 13 cents per share.
DEFERRED DEBITS
Losses on Early Retirements of Debt
Losses on early retirements of debt refinanced by new lower coupon debt
issues are amortized on a straight-line basis over the lives of the new issues.
Losses on early debt retirements not refinanced by new issues are amortized on a
straight-line basis over the remaining original lives of the retired debt.
Amortization of such amounts is included in other interest charges in the
Consolidated Statements of Earnings. The unamortized balances of losses on early
retirements of debt are approximately $21,262,000 and $22,766,000 as of August
31, 1995 and 1994, respectively (see Note 4).
Debt Premium, Discount and Expense
Expenses incurred in connection with the issuance of long-term debt,
and premiums and discounts relating to such debt, are being amortized or
accreted on a straight-line basis over the lives of the respective issues.
Other Assets
Included in deferred debits are other assets that are expected to
benefit future periods and certain costs that, for rate making purposes, are
recorded as deferred charges and amortized over periods allowed by regulatory
authorities.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The allowance for funds used during construction (AFUDC) is designed to
allow the Company to capitalize the net composite interest and equity costs of
capital funds used to finance plant additions during construction periods and
does not represent current cash income. Established regulatory rate practices
permit the Company to recover these costs in future periods by fixing rates to
include a fair return on, and a recovery of, these capital costs through their
inclusion in the rate base and cost of service. The composite rates used for
AFUDC were 6.5% in 1995, 6.2% in 1994 and 9.9% in 1993. Such rates reflect
semiannual compounding.
INCOME TAXES
On September 1, 1993, the Company adopted, on a prospective basis, as
required by the FERC, Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" (Statement 109). Statement 109 requires a change
from the deferred method to the asset and liability method of accounting for
income taxes. Under the asset and liability method, deferred income taxes are
recognized for the tax consequences of "temporary differences" by applying
enacted tax rates applicable to the differences between the financial statement
amounts and the tax bases of existing assets and liabilities.
Statement 109 requires the Company to recognize deferred income tax
liabilities for the temporary differences including cumulative unrecognized
timing differences as well as certain new items such as the equity portion of
AFUDC and unamortized investment tax credits. Certain provisions of Statement
109 provide that regulated enterprises are permitted to recognize adjustments
resulting from the adoption of Statement 109 as regulatory assets or liabilities
if it is probable that such amounts will be recovered from or returned to
customers through future rates. Accordingly, the Company recorded additional
deferred income tax liabilities and corresponding regulatory assets of
approximately $78,000,000 in 1994. The adoption of Statement 109 did not have a
material effect on results of operations.
Investment tax credits have been deferred and are being amortized to
income over the life of the related property.
CASH FLOWS
The Company uses the direct method of presentation for cash flows from
operating activities. For purposes of the Consolidated Statements of Cash Flows,
the Company considers all highly liquid investments purchased with a maturity of
three months or less to be cash equivalents. The Company records such
investments at cost which approximates market value.
EARNINGS PER COMMON SHARE
Earnings per share of common stock is computed for each year based upon
the weighted average number of common shares outstanding. The effect of stock
awards and options outstanding under the Company's 1989 Stock Incentive Plan is
not significant (see Note 7).
The Company has a Shareholder Rights Plan (the Rights Plan) designed to
ensure that all shareholders receive fair and equal treatment in the event of
any proposal to acquire control of the Company. Under the Rights Plan, each
shareholder holds one right for each share of the Company's common stock held of
record. Each right entitles the holder to purchase one share of the Company's
common stock for $70 in the event a person or group acquires 10% or more of the
Company's common stock. Under certain circumstances, the holders of the rights
will be entitled to purchase common shares of the Company at one half of the
current market price. In addition, any time after a person or group acquires 10%
or more of the Company's outstanding common shares, the board of directors may,
at its option, exchange part or all of the rights for shares of common stock of
the Company. The Company will be entitled to redeem the rights for $0.01 per
right at any time until the tenth day following a public announcement of the
acquisition of 10% of its common shares. The rights expire in 2001, unless
earlier redeemed or exchanged by the Company, and have no effect on operating
results or earnings per share. This Rights Plan has been amended to provide that
the merger agreement with Public Service Company of Colorado (PSCo) will not
trigger the provisions of the Rights Plan.
FAIR VALUES OF FINANCIAL INSTRUMENTS
The fair value amounts of certain financial instruments included in the
accompanying Consolidated Balance Sheets as of August 31, 1995 and 1994 are as
follows:
The fair values of cash and temporary investments approximate
the carrying amount because of the short maturity of those instruments.
The estimated fair values of long-term debt and preferred
stock are based on quoted market prices of the same or similar issues. The
estimated fair values of long-term debt and preferred stock are as follows:
1995 1994
Carrying Amount Fair Value Carrying Amount Fair Value
(In Thousands)
Long-term debt $582,276 $579,924 $506,487 $518,290
Preferred stock $ 72,680 $ 61,382 $ 72,680 $ 56,970
The fair values of other financial instruments for which estimated fair
values have not been presented are not materially different than the related
book values.
The fair value estimates presented herein are based on pertinent
information available to management as of August 31, 1995 and 1994. These fair
value estimates have not been comprehensively revalued for purposes of these
financial statements since that date, and current estimates of fair values may
differ significantly from the amounts presented herein.
NEW ACCOUNTING STANDARDS
In March 1995 the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (Statement 121).
Statement 121 requires that long lived assets and certain identifiable
intangibles to be held and used by an entity be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. The statement also requires that rate-regulated
enterprises recognize an impairment for the amount of costs excluded when a
regulator excludes all or part of a cost from the enterprise's rate base. The
adoption of Statement 121, which will be required in 1997, is not expected to
have a material effect on the Company's consolidated financial position or
results of operations.
(2) Merger and Acquisitions
MERGER WITH PUBLIC SERVICE COMPANY OF COLORADO
The Company and Denver-based PSCo entered into a definitive merger
agreement (the Merger) on August 22, 1995, to form a registered public utility
holding company, which will be the parent company for the Company and PSCo. The
transaction is subject to various conditions, including receipt of the approval
of the shareholders of the Company and PSCo, as well as the approval of or the
taking of other action by the Securities and Exchange Commission, the Federal
Trade Commission, the Department of Justice, the Nuclear Regulatory Commission,
the Federal Energy Regulatory Commission, and the state public utility
commissions in Texas, Colorado, New Mexico, Wyoming, and Kansas.
The Merger, with a targeted completion date in the fall of 1996, is
conditioned on qualifying as a tax-free reorganization and being accounted for
as a pooling of interests.
Upon completion of the Merger, holders of the Company and PSCo common
stock will receive 0.95 of one share and one share of the new holding company
common stock, respectively, for each share of stock held. As of August 4, 1995,
the Company and PSCo had 40,917,908 and 63,109,140 shares, respectively, of
common stock outstanding. Based on that number of shares outstanding and the
conversion ratios, the Company and PSCo shareholders would own 38.1 percent and
61.9 percent, respectively, of the common equity of the new holding company. The
debt (including mortgage bonds) and preferred stock outstanding at the time of
the effectiveness of the Merger will remain outstanding debt and preferred stock
of the Company.
The board of directors of the new holding company will consist of six
and eight current directors of the Company and PSCo, respectively.
ACQUISITION OF TNP PROPERTIES
On December 6, 1994, the Company signed a definitive agreement with
Texas-New Mexico Power Company (TNP) for the purchase of certain Texas
properties located in the Panhandle area for $29.2 million. These Panhandle area
properties are located in the cities of Spearman, Perryton, Booker, Follett,
Higgins and Darrouzett located in Hansford, Ochiltree and Lipscomb counties. The
purchase was completed September 15, 1995, and added approximately 7,300
customers. Rates in the affected communities were immediately reduced by 10% and
other rate decreases will follow over a ten-year period until the new customers
are at the same rates as the Company's other customers in its Texas service
area. In June 1995 the Company received approval from the PUCT to commence
retail electric service to the Panhandle area properties. Cost recovery of the
purchase amount in excess of book value of approximately $14,000,000 was allowed
by FERC and the PUCT through a rate surcharge over a ten-year period. This
purchase will not have a significant impact on results of operations of the
Company.
ACQUISITION OF TUCO, INC.
The Company has agreed to purchase TUCO, Inc. (TUCO), a wholly owned
subsidiary of Cabot Corporation, for $77,000,000 subject to regulatory approval
and other conditions. TUCO owns the coal inventory maintained at the Company's
Harrington and Tolk generating stations. It also administers contracts with coal
mines, railroads and the coal-handling operator at the two coal-fueled power
plants. This purchase is expected to lower fuel costs. Regulatory approval is
expected in 1996.
(3) Short-Term Debt
Weighted Weighted
Category of Balance at Average Maximum Amount Average Amount Average
Short-term End of Interest Outstanding Outstanding Interest Rate
Borrowings Year Rate During the Year (A) During the Year (B) For the Year (C)
(Dollars In Thousands)
1995:
Notes payable to banks - - $ 8,000 $ 679 6.25%
Commercial paper - - 66,826 16,548 5.78
1994:
Notes payable to banks - - $59,000 $21,025 4.15%
Commercial paper $14,994 4.79% 29,886 5,021 4.49
(A) Maximum amount outstanding at any month-end for the year.
(B) The average amount outstanding for the period was computed by
dividing the total of daily outstanding principal balances by 365.
(C) The weighted average interest rate during the period was computed by
dividing actual interest expense by the average short-term debt outstanding
for the period.
Unsecured borrowings permitted under bank lines of credit were
$128,000,000 in 1995 and $70,000,000 in 1994.
(4) Capitalization
CUMULATIVE PREFERRED STOCK
The Company is limited in the amount of preferred stock that it can
issue by certain restrictions contained in the Restated Articles of
Incorporation (Articles). As a condition to the issuance of additional shares of
preferred stock, the Articles require that net earnings, as defined, for 12
consecutive calendar months within the 15 immediately preceding calendar months,
must be at least 1.5 times the annual interest requirements on funded debt, as
defined, plus annual dividend requirements on preferred stock (or any stock
ranking on a parity). Such ratio for the year ended August 31, 1995, was 3.34.
The Articles also limit the amount of restricted indebtedness, as defined, that
may be issued or assumed by the Company without the consent of the holders of
two-thirds of the aggregate par value of the preferred stock outstanding. Under
this limitation approximately $379,000,000 of additional restricted indebtedness
could have been issued or assumed as of August 31, 1995. Such limitation would
also prevent the issuance of bonds against property additions unless, after
giving effect to the use of the proceeds from such issuance, such restricted
indebtedness limitation is met.
In the event of voluntary liquidation of the Company, holders of the
cumulative preferred stock have a preference to the extent of amounts payable on
redemption plus accrued dividends, and in the event of involuntary liquidation,
to the extent of par value plus accrued dividends.
The 7-5/8% and 9.68% series cumulative preferred stock were redeemed
from the proceeds of the December 1992 issuance of First Mortgage Bonds (see
LONG-TERM DEBT below).
LONG-TERM DEBT
First Mortgage Bonds (Bonds) issued under the Indenture of Mortgage and
Deed of Trust dated August 1, 1946, as supplemented and amended (Mortgage), are
secured by substantially all of the Company's utility plant. The Mortgage limits
the maximum principal amount of Bonds that may be outstanding thereunder to
$3,000,000,000 and contains provisions relating to the restriction of the
payment of dividends on common stock. At August 31, 1995, approximately $949,000
of total retained earnings of $373,458,000 was so restricted.
The Company is limited in the amount of Bonds that it can issue by
certain restrictions contained in the Mortgage. The Mortgage permits the
issuance of Bonds against 60% of certain property additions, against certain
retired Bonds or against deposited cash. Property additions and retired Bonds
available for the issuance of Bonds were approximately $335,000,000 and
$115,300,000, respectively, at August 31, 1995, which would permit issuance of
$316,300,000 of additional Bonds. Substantial amounts of property additions are
used by the Company to satisfy a maintenance fund covenant and improvement fund
obligations under the Mortgage. The Mortgage also provides that, with certain
exceptions, additional Bonds may not be issued unless net earnings, as defined,
are at least twice the annual interest requirements on all Bonds outstanding and
then to be issued and on all prior lien indebtedness. Such ratio for the year
ended August 31, 1995, was 5.53.
In February 1995 the Company retired $16,000,000 of Bonds, 4-5/8%
Series due 1995 and in February 1994 retired $25,000,000 of Bonds, 4-1/2% Series
due 1994.
In February 1995 the Company issued $70,000,000 of additional Bonds of
8.50% Series due 2025. The proceeds from these Bonds were applied primarily to
the retirement of short-term debt.
In December 1992 the Company issued $190,000,000 of additional Bonds
consisting of $90,000,000 of 6.875% Series due 1999 and $100,000,000 of 8.20%
Series due 2022. The proceeds from these Bonds were applied to the redemption of
outstanding Bonds as follows: (i) 8.45% Series due 2001, (ii) 7-5/8% Series due
2002, (iii) 8-3/8% Series due 2007, and (iv) 9-1/8% Series due 2016, and also
cumulative preferred stock as follows: (i) 82,960 shares of 7-5/8% preferred
stock and (ii) 170,000 shares of 9.68% preferred stock. In connection with this
redemption, the Company incurred a loss of approximately $10,575,000, including
redemption premiums of $9,315,000; $10,192,000 of such loss was deferred and is
being amortized over the lives of the new issues and $383,000 relating to the
preferred stock was charged to retained earnings (see Note 1).
The Red River Authority of Texas has issued certain obligations, based
on long-term installment sale agreements executed by the Company, that relate to
the pollution control facilities installed at the Company's coal-fueled
generating units. The Company's payments under the pollution control obligations
are pledged to secure the Red River Authority Pollution Control Revenue Bonds.
In August 1994 the Company entered into a forward interest rate swap
agreement in anticipation of redeeming its $25,000,000 principal amount of
13-1/2% pollution control revenue bonds with a new issuance of variable rate
pollution control revenue bonds. The 13-1/2% bonds are not redeemable until
October 1, 1996. The interest rate swap will commence in September 1996 on a
$25,000,000 notional amount which, in effect, fixes the interest rate on the
bonds to be issued at 6.435%. The swap agreement may be terminated by the
Company at any time or by the other party, upon the occurrence of specified
events. If terminated, the Company may be required to make a payment or may
receive a payment to settle any gains or losses resulting from the termination.
The amount of any settlement, which could be substantial, is dependent upon
market interest rates at the time of settlement. If the forward interest rate
agreement had been terminated at August 31, 1995, the Company would have been
required to pay approximately $3,765,000; however, the Company would then have
received the benefit of an interest rate lower than 6.435% on the bonds to be
issued. The Company is exposed to interest rate risk in the event of
nonperformance by the other party to the swap agreement; however, the Company
does not anticipate nonperformance by the counter party.
The trust indenture for the 1991 Series of pollution control
obligations permits the Company to choose between various interest rate options,
including the option to convert to a fixed rate. Currently, the interest rate is
adjusted weekly and as of August 31, 1995 and 1994, the interest rate was 3.45%
and 3.15%, respectively.
The 1991 Series may be subject to tender for purchase at the option of
the holder and will be subject to mandatory tender at certain times. The Company
entered into a credit agreement with a bank to provide liquidity support in
connection with the optional and mandatory tenders. The Company has also entered
into a remarketing agreement to provide for the remarketing of any tendered
bonds. The credit agreement is scheduled to expire on July 1, 1997. Based upon
the Company's intent and ability to remarket such obligations, the 1991 Series
obligations have been classified as long-term debt.
Aggregate maturities of long-term debt for each of the years in the
five-year period subsequent to August 31, 1995, are as follows: 1996, $276,000;
1997, $15,176,000; 1998, $229,000; 1999, $0; and 2000, $90,000,000. Sinking fund
and improvement fund requirements are not significant.
(5) Income Taxes
The components of income tax expense (benefit) for the years ended
August 31, 1995, 1994 and 1993 are as follows:
1995 1994 1993
(In Thousands)
Taxes on operating income:
Federal - current $ 51,594 $ 43,878 $ 41,385
Federal - deferred 10,671 12,387 13,766
Investment tax credits (250) (250) (250)
State - current 1,858 1,842 1,763
63,873 57,857 56,664
Taxes on other income:
Federal - current 4,703 1,354 887
Federal - deferred (954) (823) 117
State - current 26 - -
3,775 531 1,004
Total income taxes $ 67,648 $ 58,388 $ 57,668
The provisions (credits) for deferred income taxes that arise from
temporary differences between financial and tax reporting for the years ended
August 31, 1995, 1994 and 1993, are as follows:
1995 1994 1993
(In Thousands)
Deferred income taxes on operating income:
Depreciation differences $ 12,205 $ 10,856 $ 9,650
Liability for refunds to customers (1,848) (186) 4,257
Losses on reacquisition of long-term debt (439) (439) 2,125
Postretirement benefits other than pensions (2) (761) -
Other 755 2,917 (2,266)
Subtotal 10,671 12,387 13,766
Deferred taxes on other income (954) (823) 117
Total deferred income taxes $ 9,717 $ 11,564 $ 13,883
Total income tax expense for the years ended August 31, 1995, 1994, and
1993 differs from the amounts computed by applying the statutory federal tax
rates (35% in 1995 and 1994, 34.67% in 1993) to earnings before income taxes for
the following reasons:
1995 1994 1993
(In Thousands)
Statutory federal income tax expense $ 65,494 $ 56,194 $ 56,485
Increase (decrease) due to:
State income taxes 1,225 1,197 1,146
Tax exempt interest and dividends (93) (83) (148)
Amortization of investment tax credits (250) (250) (250)
Property-related differences 2,602 2,562 2,274
Dividends paid on EIP shares (1,118) (640) (655)
Other (212) (592) (1,184)
Actual income tax expense $ 67,648 $ 58,388 $ 57,668
Effective tax rate 36.2% 36.4% 35.4%
Property-related differences increase income tax expense due primarily
to the reversal of depreciation and basis differences.
The significant components of the Company's deferred tax assets and
liabilities, which are reflected net in the accompanying Consolidated Balance
Sheets at August 31, 1995 and 1994, are as follows:
1995 1994
(In Thousands)
Deferred Tax Assets:
Current:
Over (under) recovered fuel revenue $ 2,365 $ 517
Liability for refunds to customers - 672
Total current assets 2,365 1,189
Noncurrent:
Employee benefit plans 3,068 1,344
Interest on pollution control obligations 1,812 1,821
Avoided cost method of capitalized interest 1,942 1,942
Contributions in aid of construction 2,172 2,172
Deferred compensation 3,578 2,941
Unamortized investment tax credits 3,398 3,541
Deferred promotional cost 4,624 4,397
Other 2,880 4,424
Total noncurrent assets 23,474 22,582
Total deferred tax assets $ 25,839 $ 23,771
Deferred Tax Liabilities:
Differences related to depreciation $260,744 $248,606
Capitalized construction costs 28,954 36,015
Previously unrecognized temporary differences
net of the tax rate adjustment of previously
normalized temporary differences 51,581 50,925
Losses on reacquisition of long-term debt 6,345 6,784
Other 20,644 19,708
Total deferred tax liabilities $368,268 $362,038
(6) Commitments, Contingencies and Financial Guarantees
SYSTEM PURCHASE OPTION
The Company and the City of Las Cruces, New Mexico (the City) entered
into a System Purchase Option and Rate Agreement in August 1994, which grants
the City the option to sell to the Company the electric utility system serving
the City (including distribution, subtransmission, and transmission facilities),
which the City plans to acquire from El Paso Electric Company (EPE) by purchase
or through condemnation proceedings. The agreement has a three-year term
beginning at the time the City acquires the facilities and ending no later than
January 1, 2002. The purchase price which would be paid by the Company would be
equal to the amount required to retire all outstanding debt incurred by the City
in acquiring the facilities plus the city's reasonable costs in acquiring the
facilities. The Company has the right to terminate the agreement if, in the
Company's sole discretion, it determines that any proposed condemnation award is
excessive or upon the occurrence of certain other events. The agreement also
provides that, if the City abandons or dismisses condemnation proceedings as a
consequence of the Company's termination of the agreement, the Company will
reimburse the City for one-half of its reasonable litigation expenses and for
any of EPE's damages and litigation expenses that the City is obligated to pay
by final court order.
FUEL PURCHASE COMMITMENTS
In the ordinary course of business, the Company has made substantial
commitments with respect to the purchase of coal and natural gas for use as fuel
in its generating units. To provide fuel for its coal-fueled generating units,
the Company has various long-term commitments with TUCO for the purchasing and
processing of coal which is delivered to the Company's coal bunkers in the form
of crushed, ready-to-burn coal. The commitments include the use of rail coal
cars, unloading facilities and related services. Such commitments in 1995
dollars for the remaining term of the contract are approximately $1,756,000,000.
The contracts for coal supply, transportation and other services expire in 2001,
2002 and 2016, respectively.
In May 1995 the Company agreed to purchase TUCO from Cabot Corporation
for $77,000,000 (see Note 2).
FINANCIAL GUARANTEES
In connection with an agreement for the sale of electric power, the
Company guaranteed certain obligations of a customer totaling $48,000,000. These
obligations relate to the construction of certain utility property, that in the
event of default by the customer, would revert to the Company. In connection
with a Quixx investment, Quixx has provided a financial guarantee totaling
$8,900,000 to fund any construction cost overruns and other project
contingencies. Should additional funds be provided, Quixx's ownership position
in that project may be altered.
ENVIRONMENTAL MATTERS
The Company's facilities are regulated by federal and state
environmental agencies. These agencies have jurisdiction over air emissions,
water quality, wastewater discharges, solid wastes and hazardous substances. The
Company has received all necessary authorizations for the construction and
continued operation of its generation, transmission and distribution systems.
Company facilities have been designed and constructed to operate in compliance
with environmental standards.
Beginning in the year 2000, the Clean Air Act Amendments of 1990 (CAAA)
Phase II will require more stringent limits on SO2 emissions at the Company's
existing fossil-fueled plants. However, current regulations permit compliance
with sulfur emissions limitations in the year 2000 by using SO2 allowances
allocated to plants by the Environmental Protection Agency (EPA), using
allowances generated by reducing emissions at existing plants and by using
allowances purchased from other companies. Based upon information from the
Company's fuel suppliers, the SO2 allowances issued by the EPA approximate the
Company's projected SO2 emissions. The Company monitors options to ensure that
allowances will be sufficient to economically operate the Company's existing
plants without significant emission reductions. The CAAA also requires the EPA
to develop new oxides of nitrogen (NOx) emission standards for existing and new
plants which may be more stringent than the current standards. The Company
anticipates being able to comply with Phase II NOx emission standards with no
additional material capital cost. The Company continues to monitor the impact
that the CAAA may have on the Company.
Capital expenditures for environmental protection facilities aggregated
approximately $4,100,000, $11,600,000, and $4,500,000 for 1995, 1994 and 1993,
respectively. Estimates of future capital expenditures for environmental
protection facilities are subject to change but the Company has included
approximately $11,700,000 in its construction program for these expenditures
during the five years ending August 31, 2000, of which approximately $2,300,000
is for 1996.
The Company has not developed any specific site removal and exit plans
for its fossil fuel plants or substation sites. Plant removal and exit plans are
under development, and when such plans are developed in the future, the Company
intends to treat removal and exit costs as a cost of retirement in utility plant
and include them in depreciation accruals. An estimated removal cost (based on
historical experience) is currently included in depreciation expense.
THUNDER BASIN LAWSUIT
The Company was named as a defendant in a case entitled Thunder Basin
Coal Co. v. Southwestern Public Service Co., No. 93-CV-304B (D. Wyo.). Thunder
Basin's Wyoming lawsuit in federal court went to trial in late October 1994. On
November 1, 1994 the jury returned a verdict in favor of Thunder Basin and
against the Company finding that there had been a partial repudiation of the
contract and that the Company had interfered with Thunder Basin's contract with
TUCO. The jury awarded damages to Thunder Basin of approximately $18,800,000.
The Company has appealed the judgment to the Tenth Circuit Court of Appeals and
the appeal is progressing.
Management believes that in the event a payment is ultimately required
to be made to Thunder Basin it would be recoverable from ratepayers, although
any such recovery would be subject to regulatory review. Management believes
that the ultimate resolution will not have a material adverse effect on the
Company's consolidated financial statements.
OTHER
The Company is a defendant in various claims and legal actions,
primarily workers' compensation, contractual matters and general liability
lawsuits, all arising in the normal course of business. In the opinion of
management, the ultimate disposition of these matters will not have a material
adverse effect on the Company's consolidated financial statements.
(7) Employee Benefit Plans
DEFINED BENEFIT PLANS
The Company has a noncontributory defined benefit retirement plan (the
Retirement Plan) which provides retirement and certain other benefits to its
officers and employees. The Company's policy is to fund the accrued costs of the
Retirement Plan. Assets of the Retirement Plan consist primarily of U.S.
government and agency obligations, bonds and common stocks (including 586,236
shares of common stock of the Company with an estimated fair market value of
$17,587,080 as of August 31, 1995).
Additionally, the Company has a noncontributory defined benefit
supplemental retirement income plan (the Supplemental Plan) for qualifying
executive personnel. The Supplemental Plan is unfunded, and benefits due under
the plan are paid out of the Company's general funds.
Net periodic pension cost for the Retirement and Supplemental Plans, as
determined using the projected unit credit actuarial cost method for the years
ended August 31, 1995, 1994 and 1993, is presented below:
1995 1994 1993
(In Thousands)
Net periodic pension cost:
Service cost for benefits earned during the period $ 6,606 $ 6,394 $ 5,863
Interest cost on projected benefit obligation 19,563 18,444 17,958
Actual return on plan assets (37,912) 2,729 (39,868)
Net amortization and deferral 12,840 (26,806) 17,401
Net periodic pension cost $ 1,097 $ 761 $ 1,354
The funded status of the Retirement and Supplemental Plans and amounts
recognized in the Company's Consolidated Balance Sheets as of August 31, 1995
and 1994 is presented below:
1995 1994
Supplemental Supplemental
Retirement Retirement Retirement Retirement
Plan Plan Plan Plan
(In Thousands)
Actuarial present value of benefit obligations:
Vested benefit obligation $ 190,848 $ 5,749 $ 185,267 $ 5,207
Nonvested benefit obligation 13,139 1,255 12,406 1,357
Accumulated benefit obligation $ 203,987 $ 7,004 $ 197,673 $ 6,564
Plan assets at fair value $ 306,783 - $ 283,408 -
Projected benefit obligation (253,793) $(7,421) (245,028) $(7,276)
Plan assets in excess of (less than) projected
benefit obligation 52,990 (7,421) 38,380 (7,276)
Unrecognized prior service costs 1,320 330 1,455 372
Unrecognized net loss (gain) from past experience (36,847) 1,520 (18,803) 2,270
Additional minimum liability - (2,112) - (2,867)
Unrecognized transition obligation (asset) (24,508) 679 (28,071) 938
Accrued pension liability $ (7,045) $(7,004) $ (7,039) $(6,563)
The current and noncurrent portions of the accrued pension liability
are included in other current liabilities and other deferred credits,
respectively, in the accompanying Consolidated Balance Sheets.
The assumed discount rate and the rate of increase in compensation
levels used in determining the actuarial present value of the projected benefit
obligations were 8% and 6%, respectively. The expected long-term rate of return
on plan assets was 8%. Plan assets and liabilities are valued each year using a
measurement date of June 30.
HEALTH AND WELFARE BENEFIT PLANS
The Company provides health care and life insurance benefits to its
active and retired employees through various health and welfare benefit plans.
In 1994 the Company adopted Statement of Financial Accounting Standards No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions"
(Statement 106). Statement 106 requires accrual of postretirement benefits other
than pensions (primarily group term life insurance, medical and dental benefits
provided to retired employees) during the years an employee provides services.
Statement 106 also requires employers to recognize the costs of benefits already
earned by active employees as of the date of adoption of Statement 106 (the
Transition Obligation).
The accrual of postretirement costs was comprised of: (1) the portion
of the expected postretirement benefit obligation attributable to employee
service during the period, (2) amortization of the Transition Obligation and (3)
interest costs associated with the unfunded accumulated obligation for future
benefits. An assumed discount rate of 8% was used to develop the associated
interest costs. The assumed health care cost trend rate used to measure the
expected cost of benefits was 12% for 1995 and was assumed to diminish to a
level of 5.5% in 2007 and thereafter. The Transition Obligation of approximately
$58,000,000 is being amortized over a 20-year period. A one percentage point
increase in the assumed health care cost trend rate in each future year would
increase the accumulated postretirement benefit obligation (APBO) at August 31,
1995, by approximately $8,000,000 and other postretirement benefits cost for
1995 by approximately $900,000.
These postretirement costs have historically been included in rates
when paid. Federal and state agencies that regulate the Company have issued
guidelines permitting recovery of such additional costs on an accrual basis. In
Texas and New Mexico, which represent approximately 72% of the Company's
revenues, the Company was permitted in its rate settlements to recover the
additional costs. The Company is required to deposit the amounts included in
Texas and New Mexico rates in an irrevocable external trust dedicated to the
payment of these postretirement benefits. In remaining jurisdictions, the
Company is permitted to recognize regulatory assets for the difference between
any amounts recorded currently and those required under Statement 106. At August
31, 1995 and 1994, deferred debits in the Consolidated Balance Sheets include
$2,500,000 and $1,700,000, respectively, that represent the future revenues
expected to be realized at the time the additional postretirement benefits are
included in the Company's rates.
The Company's net periodic postretirement benefits cost other than
pensions for the years ended August 31, 1995 and 1994, including amounts
capitalized, were comprised of the following components:
1995 1994
(In Thousands)
Service cost for benefits earned during the period $ 1,213 $ 1,280
Interest cost on the APBO 4,843 4,715
Actual return on plan assets (723) (134)
Net amortization and deferral 2,476 2,138
Net postretirement benefits cost $ 7,809 $ 7,999
The funded status for other postretirement benefits and amounts
recognized by the Company at August 31, 1995 and 1994, is presented below:
1995 1994
(In Thousands)
APBO:
Retirees $ 40,210 $ 38,721
Fully eligible active employees 2,307 2,619
Other active employees 22,753 22,139
Total APBO $ 65,270 $ 63,479
Plan assets at fair value $ 17,129 $ 10,342
APBO (65,270) (63,479)
APBO in excess of plan assets (48,141) (53,137)
Unrecognized net loss (2,671) (374)
Unrecognized Transition Obligation 48,138 50,812
Accrued postretirement benefits cost $ (2,674) $ (2,699)
The Company's cost of providing other postretirement benefits in 1993,
which was recognized on a "pay-as-you-go" basis, was approximately $2,280,000.
DEFINED CONTRIBUTION PLANS
The Company has an Employee Stock Ownership Plan and a 401(k) plan.
Total contributions to the plans by the Company for the years ended August 31,
1995, 1994 and 1993 were approximately $1,469,000, $983,000 and $993,000,
respectively. Effective March 1, 1995, the plan assets of the Employee Stock
Ownership Plan and 401(k) plan were combined into one plan called the Employee
Investment Plan.
OTHER BENEFIT PLANS
The Company's 1989 Stock Incentive Plan provides for awards of share
options and restricted shares, and delivery of shares in certain cases. The
number of shares of common stock of the Company registered in connection with
this plan is 800,000, the maximum amount that may be awarded prior to July 25,
1998.
Stock options have been awarded to key employees under the 1989 Stock
Incentive Plan. Options granted under the plan have an exercise price equal to
the fair market value of the common stock on its award date. At August 31, 1995,
there were 22 participants in the plan. Options generally become exercisable
evenly over nine years and expire ten years after the date of the grant.
Number of Options
1995 Price Range 1995 1994 1993
Summary of stock option activity:
Outstanding - beginning of year $28.63-$33.31 70,724 74,816 -
Granted - - 5,645 74,816
Exercised* $ 33.31 (245) (6,581) -
Canceled or expired $ 30.81 (2,720) (3,156) -
Outstanding - end of year $28.63-$33.31 67,759 70,724 74,816
Exercisable $28.63-$33.31 9,345 1,348 -
*The price of options exercised in 1994 was $30.81.
At August 31, 1995, approximately 81,200 restricted shares of common
stock have been awarded to employees, generally subject to a ten-year vesting
requirement. The cost of shares awarded are charged to expense over a ten-year
period based on the fair market value at date of award.
The Company has a Directors' Deferred Compensation Plan under which
directors of the Company or its subsidiaries may elect to defer the distribution
of all or a percentage of the annual retainer or meeting fees, or both,
otherwise currently payable to such directors.
(8) Competitive Environment and Regulatory Assets and Liabilities
Electric utilities have historically operated in a highly regulated
environment in which they have an obligation to provide electric service to
their customers in return for an exclusive franchise within their service
territory with an opportunity to earn a regulated rate of return. This
regulatory environment is changing. The generation sector has experienced
competition from nonutility power producers, and the FERC is requiring
utilities, including the Company, to provide wholesale transmission service to
others and may order electric utilities to enlarge their transmission systems to
facilitate transmission services.
The changing regulatory environment has stimulated competition in the
wholesale electric markets by creating a new class of independent power
producers. Revisions to the Public Utility Holding Company Act of 1935 (PUHCA)
have allowed both utilities and non-utilities to form independent power
production companies called exempt wholesale generators (EWGs), which operate
without the restrictions of the PUHCA. EWGs offer alternative sources of power
supply to electric utilities across the country. Utilities are often required by
state regulation to solicit to purchase power from nonutility power producers
and other utilities before seeking approval to construct new generation of their
own.
Some state regulatory authorities are in the process of changing
utility regulations in response to federal and state statutory changes and
evolving markets. Texas legislation enacted in 1995 recognizes the movement to a
more competitive marketplace by requiring the PUCT to issue new regulations
including: allowance of less than fully costed rates in wholesale and retail
markets; recognition of and essentially waiving all Texas utility regulation of
EWGs and power marketers; and implementation of transmission access comparable
to the owning utility's use of its transmission system for non-FERC regulated
utilities. The Company believes that these statutory and conforming regulations
may result in increased wholesale competition. However, due to the Company's low
cost structure, increased wholesale competition is not expected to adversely
affect it in the near term and may favorably impact it in the long term.
The New Mexico legislature rejected retail wheeling proposals; however,
it continued post-session committee investigation of the matter. All of the
Company's jurisdictions continue to evaluate utility regulations with respect to
competition.
The Company currently applies accounting standards that recognize the
economic effects of rate regulation. Regulatory assets represent probable future
revenue associated with certain costs which will be recovered from customers
through the ratemaking process. Regulatory liabilities represent costs
previously collected that are refundable in future rates. If rate recovery of
generation-related and other costs becomes unlikely or uncertain, whether due to
competition or regulatory action, these accounting standards may no longer apply
to the Company.
Regulatory assets and liabilities reflected in the Consolidated Balance
Sheets as of August 31, 1995 and 1994, are as follows:
1995 1994
(In Thousands)
Regulatory assets:
Income taxes $ 83,286 $ 89,114
Deferred refinancing costs 21,262 22,766
Deferred costs related to a development project 4,921 6,038
Deferred employee benefit costs 4,310 4,325
Other 4,110 5,720
Total $117,889 $127,963
Regulatory liabilities:
Deferred investment tax credits $ 6,053 $ 6,303
Deferred fuel revenue 5,969 1,961
Rate case refund - 1,844
Total $ 12,022 $ 10,108
As of August 31, 1995, the Company's regulatory assets are being
recovered through rates charged to customers over periods ranging from ten to
thirty years. Under current rates, the Company is recovering approximately
$8,000,000 of regulatory costs per year. Based on prior and current rate
treatment of such costs, management believes it is probable that the Company
will continue to recover from ratepayers the regulatory assets described above.
In July 1995 the Company negotiated a settlement with the PUCT and
various intervenors. As part of this agreement, the Company is required to
perform certain demand side management activities and is allowed to defer the
costs of these activities and include them in rate base and cost of service in
future PUCT proceedings.
(9) Rate Matters
The Company may effect changes in its rates only as approved by the
regulatory authorities governing its jurisdictions. Amounts ultimately realized
will differ from amounts approved because kilowatt-hour sales and other factors
will vary from those approved in the rate proceedings.
A PUCT substantive rule requires periodic examination of the Company's
fuel and purchased power costs, the efficiency of the use of such fuel and
purchased power, fuel acquisition and management policies and purchase power
commitments (see Item 1. Business Fuel Supply and Purchased Power). On May 1,
1995, the Company filed with the PUCT a petition for a fuel reconciliation for
the months of January 1992 through December 1994. A hearing was held in
September 1995 and the Commission staff has recommended some disallowances which
the Company opposes and which are subject to final ruling by the PUCT. The
Company's management is unable to predict the ultimate outcome; however, they
believe the final determination of this matter will not significantly affect
consolidated financial results.
On December 19, 1989, the FERC issued its final order regarding the
1985 rate case. The Company appealed certain portions of the order that related
to recognition in rates of the reduction of the federal income tax rate from 46%
to 34%. The United States Court of Appeals for the District of Columbia Circuit
remanded the case, directing the FERC to reconsider the Company's claim of an
offsetting cost and limiting the FERC's actions. The FERC issued its Order on
Remand in July 1992, required filings were made and a hearing was completed in
February 1994. In October 1994 the administrative law judge issued a favorable
initial decision that, if approved by the FERC, would result in a substantial
recovery by the Company. Negotiated settlements with the Company's partial
requirements customers and Texas- New Mexico Power Company were approved by the
FERC in July 1993 and September 1993, respectively, and the Company received
approximately $2,800,000. In a settlement with the Company's New Mexico
cooperative customers the Company received approximately $7,000,000, including
interest. The FERC approved this settlement in July 1995. Resolutions with the
remaining wholesale customers, Golden Spread member cooperatives and Lyntegar
Electric Cooperative have not been reached. The Company cannot reasonably
estimate the remaining amount recoverable from these proceedings; however, a
favorable resolution could materially improve 1996 consolidated earnings.
10) Quarterly Operating Results (Unaudited)
The following quarterly operating results are unaudited, but, in the
opinion of management, include all adjustments (consisting of normal recurring
accruals) necessary for a fair presentation of the Company's operating results
for the periods indicated.
Quarter Ended
11-30-94 2-28-95 5-31-95 8-31-95
(In Thousands, Except Per Share Amounts)
1995
Total kilowatt-hours sold 4,732,246 4,467,149 5,035,896 6,100,285
Operating revenues $ 187,216 $ 181,848 $ 205,187 $ 259,832
Operating income 30,088 27,785 36,037 60,301
Net earnings 21,169 18,677 26,429 53,202
Earnings applicable to common stock 19,950 17,457 25,210 51,982
Earnings per common share .49 .43 .62 1.26*
11-30-93 2-28-94 5-31-94 8-31-94
(In Thousands, Except Per Share Amounts)
1994
Total kilowatt-hours sold 4,855,254 4,672,110 4,747,315 6,128,258
Operating revenues $ 203,071 $ 189,392 $ 196,173 $ 254,812
Operating income 33,857 26,369 29,054 50,439
Net earnings 26,045 17,371 19,779 38,973
Earnings applicable to common stock 24,826 16,151 18,560 37,753
Earnings per common share .61 .39 .45 .93
*Includes an increase of $0.13 attributable to a change in the
estimated delivered not billed kwh sales (see Note 1) and an increase of $0.11
attributable to a one-time adjustment resulting from the 1985 FERC rate case
(see Note 9).
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
As previously reported on Form 8-K dated April 27, 1993, the Company
notified its certifying accountants, KPMG Peat Marwick LLP (KPMG), that the
client-auditor relationship between the Company and KPMG was terminated
effective with the completion of the 1993 financial audit. Additionally, the
Company announced its new certifying accountants, DELOITTE & TOUCHE LLP, to
serve as independent accountants for the fiscal year 1994 and 1995. The decision
to change accountants was recommended by the Audit Committee and approved by the
Board of Directors.
KPMG's report on the Company's financial statements for the 1993 fiscal
year contained no adverse opinion or disclaimer of opinion, and was not
qualified or modified as to uncertainty, audit scope, or accounting principles.
During the 1993 fiscal year and up to the audit completion date, there
were no disagreements between the Company and KPMG on any matters of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, which disagreements, if not resolved to the satisfaction of KPMG,
would have caused KPMG to make a reference to the subject matter of the
disagreements in connection with its reports.
None of the "reportable events" described under Regulation S-K, Item
304(a)(1)(v), occurred within the Company's two most recent fiscal years.
During the 1993 fiscal year, prior to their appointment as certifying
accountants, the Company did not consult DELOITTE & TOUCHE LLP regarding any of
the matters or events set forth in Item 304(a)(2)(i) and (ii) of Regulation S-K.
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.*
To the knowledge of the Company, no person is the beneficial owner of
more than 5% of any class of the Company's voting
securities.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.*
*The information required by Items 10, 11, 12 and 13 with respect to
directors and officers to the extent not set forth under Item 1 of Part I in
this Form 10-K (pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K) under "Executive Officers of the Registrant," is set forth in
the Company's proxy statement for its Annual Meeting of Shareholders to be held
January 31, 1996, which is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
FINANCIAL STATEMENTS
Independent Auditors' Reports
Consolidated Balance Sheets as of August 31, 1995 and 1994
Consolidated Statements of Capitalization as of August 31, 1995 and 1994
Consolidated Statements of Earnings for the years ended August 31, 1995,
1994 and 1993
Consolidated Statements of Common Shareholders' Equity for the years
ended August 31, 1995, 1994 and 1993
Consolidated Statements of Cash Flows for the years ended August 31, 1995,
1994 and 1993
Notes to Consolidated Financial Statements
FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because of the absence of conditions
under which they are required or because the required information is included in
the Consolidated Financial Statements or notes thereto.
REPORTS ON FORM 8-K
Items reported - Item 5. Other Events
Financial Statements filed - None
Dates of reports filed - August 22, 1995 and August 30, 1995
EXHIBITS
Filed with this Form 10-K:
10a Form of Executive Employment Agreement, as amended
10b System Purchase Option and Rate Agreement with the City of
Las Cruces
12 Statements re computation of ratio of earnings
21 Subsidiaries of the registrant
23a Consent of DELOITTE & TOUCHE LLP
23b Consent of KPMG Peat Marwick LLP
24 Power of attorney
27 Financial Data Schedule
Incorporated in this Form 10-K by reference:
2 Agreement and Plan of Reorganization dated as of August 22,
1995, among Southwestern Public Service Company, M-P New Co.
and Public Service Company of Colorado, filed as exhibit 2,
Form 8-K dated August 22, 1995.
3(a) Restated Articles of Incorporation as amended through April
27, 1990, filed as exhibit 3, Form 10-Q for the quarter ended
May 31, 1990.
(b) Restated Bylaws as amended through July 23, 1991, filed as
exhibit 3, Form 10-K for the fiscal year ended August 31,1991.
4(a) First Mortgage Indenture dated August 1, 1946, filed as
exhibit 7-A, Registration No. 2-6910.
(b) Supplemental Indentures to the First Mortgage Indenture:
Dated File Reference Exhibit
February 1, 1967 2-25983 2-S
October 1, 1970 2-38566 2-T
February 9, 1977 2-58209 2-Y
March 1, 1979 2-64022 b(28)
April 1, 1983 (two) Form 10-Q, May 1983 4(a)
February 1, 1985 Form 10-K, August 1985 4(c)
July 15, 1992 (two) Form 10-K, August 1992 4(a)
December 1, 1992 (two) Form 10-Q, February 1993 4
February 15, 1995 Form 10-Q, May 1995 4
(c) Standby Credit Agreement with Union Bank of Switzerland (Houston
Agency) dated July 1, 1991, filed as exhibit 4(a), Form 10-K for
the fiscal year ended August 31, 1991.
(d) Red River Authority for Texas Indenture of Trust dated July 1,
1991, filed as exhibit 4(b), Form 10-K for the fiscal year ended
August 31, 1991.
(e) Rights Agreement between the Company and Society National Bank,
dated July 23, 1991, filed as exhibit 2, Form 8-A dated July 23,
1991.
(f) Amendment No. 1 dated August 22, 1995, to the Rights Agreement
between the Company and Society National Bank, filed as exhibit
4, Form 8-K dated August 30, 1995.
10(a) Coal Supply Agreement (Harrington Station) between Southwestern
Public Service Company and TUCO, Inc., dated May 1, 1979, filed
as exhibit 3, Form 8-K dated May 14, 1979.
(b) Master Coal Service Agreement between Swindell-Dressler Energy
Supply Company and TUCO, Inc., dated July 1, 1978, filed as
exhibit 5A, Form 8-K dated May 14, 1979.
(c) Guaranty of Master Coal Service Agreement between
Swindell-Dressler Energy Supply Company and TUCO, Inc., filed
as exhibit 5B, Form 8-K dated May 14, 1979.
(d) Coal Supply Agreement (Tolk Station) between Southwestern Public
Service Company and TUCO, Inc., dated April 30, 1979, as
amended November 1, 1979 and December 30, 1981, filed as exhibit
10(b), Form 10-Q for the quarter ended February 28, 1982.
(e) Master Coal Service Agreement between Wheelabrator Coal Services
Co. and TUCO, Inc., dated December 30, 1981, filed as exhibit
10(c), Form 10-Q for the quarter ended February 28, 1982.
(f) 1989 Stock Incentive Plan for Executive Management, filed as
Exhibit A to the Company's Proxy Statement dated December 1,1988.
(g) Directors' Plan for members of the Company's Board of Directors,
filed as Exhibit B to the Company's Proxy Statement dated
December 1, 1988.
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.
SOUTHWESTERN PUBLIC SERVICE COMPANY
By Bill D. Helton
Chairman and Chief Executive Officer
DATE: November 20, 1995
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 on the date indicated:
Signature Title Date
Bill D. Helton Chairman and Chief November 20, 1995
Executive Officer
(Principal Executive & Financial
Officer & Director)
Doyle R. Bunch II Executive Vice President,
Accounting & Corporate Development
(Principal Accounting Officer)
C. Coney Burgess* Directors
J. C. Chambers*
Danny H. Conklin*
Giles M. Forbess*
Shirley Bird Perry*
David M. Wilks*
By Doyle R. Bunch II*
(Attorney-in-fact)