UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(X)ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
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 No. 1-8847
TNP ENTERPRISES, INC.
(Exact name of registrant as specified in its charter)
TEXAS 75-1907501
(State of incorporation) (I.R.S. Employer Identification Number)
4100 International
P. O. Box 2943
Fort Worth, Texas 76113
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code 817-731-0099
Securities registered pursuant to Section 12(b) of the Act:
Shares Name of
Outstanding Each Exchange on
Title of Each Class of Securities on January 31, 1994 Which Registered
Common Stock, No Par Value 10,697,996 New York Stock Exchange
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 contained, to
the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendments to this Form 10-K. [X]
As of January 31, 1994 non-affiliates of the Registrant held 10,623,257
shares of the Common Stock having an aggregate market value of
$189,890,718.88 based on the closing price on the New York Stock Exchange of
$17.875 per share.
Documents Incorporated By Reference
Part Where
Document Incorporated
(1) Annual Report to Shareholders for the
year ended December 31, 1993 I, II
(2) Proxy Statement (distributed to
holders of common stock on or
about March 28, 1994 III
<PAGE>
TNP ENTERPRISES, INC. FORM 10-K
PART I
Item 1. Business.
General Development of Business
The Company And Its Subsidiaries
TNP Enterprises, Inc. (Company) is a Texas corporation organized in
February 1983. The Company owns all of the outstanding common stock
of its three subsidiaries: Texas-New Mexico Power Company (Utility),
its principal operating subsidiary; Bayport Cogeneration, Inc.
(Bayport); and TNP Operating Company. The Company and the Utility are
holding companies as defined in the Public Utility Holding Company Act
but each is exempt from regulation as a "registered holding company"
as defined in said act. All financial information presented herein or
incorporated by reference is on a consolidated basis and all
intercompany transactions and balances have been eliminated.
Texas-New Mexico Power Company
Texas-New Mexico Power Company is a public utility engaged in the
generation, purchase, transmission, distribution and sale of
electricity to customers within the States of Texas and New Mexico.
The Utility is qualified to do business as a foreign corporation in
the State of Arizona. Business conducted in Arizona is limited to
ownership as tenant-in-common with two other electric utility
corporations in a 345-KV electric transmission line which transmits
electrical energy into New Mexico for sale to customers in New Mexico.
The Utility is subject to regulation by the Public Utility Commission
of Texas (PUCT) and the New Mexico Public Utility Commission (NMPUC).
The Utility is subject in some of its activities, including the
issuance of securities, to the jurisdiction of the Federal Energy
Regulatory Commission (FERC), and its accounting records are
maintained in accordance with the FERC Uniform System of Accounts.
The Utility has two wholly owned subsidiaries, Texas Generating
Company (TGC), organized in 1988, and Texas Generating Company II (TGC
II), organized in 1991.
TNP One
Prior to 1990, the Utility purchased virtually all of its electric
requirements, primarily from other utilities. In an effort to
diversify its energy and fuel sources, the Utility contracted with a
consortium consisting of Westinghouse Electric Corporation, Combustion
Engineering, Inc. and H. B. Zachry Company to construct TNP One. TNP
One is a two-unit lignite-fueled, circulating fluidized bed generating
plant in Robertson County, Texas. Unit 1 and Unit 2 of TNP One
together provide, on an annualized basis, approximately 30% of the
Utility's electric capacity requirements in Texas. The Utility
acquired Unit 1 on July 20, 1990, and Unit 2 on July 26, 1991, through
TGC and TGC II, respectively. The Utility operates the two units and
sells the output of TNP One to its Texas customers. Unit 1 began
commercial operation on September 12, 1990, and Unit 2 on October 16,
1991. As of December 31, 1993, the costs of Unit 1 and Unit 2 were
approximately $357 million and approximately $282.9 million,
respectively. Portions of the costs were funded by the Utility, with
the majority of the costs borrowed by TGC and TGC II under separate
financing facilities for the two units, which are guaranteed by the
Utility.
<PAGE 2>
TNP ENTERPRISES, INC. FORM 10-K
Regulatory Proceedings
The Utility has received rate orders from the PUCT placing the
majority of the costs of each of the two units of TNP One in rate
base. The Utility and other parties to the proceedings have appealed
both orders. For a review of the history of the two rate proceedings
and the pending judicial proceedings, see Item 3, "Legal Proceedings"
and note 5 to the consolidated financial statements contained in the
Annual Report to Shareholders for the year ended December 31, 1993.
See note 2 to the consolidated financial statements contained in the
Annual Report to Shareholders for the year ended December 31, 1993 for
a discussion of the financings of the two units including, during
1993, substantial reduction of the TNP One construction indebtedness
and extension of the payment schedule for the remaining balance of the
construction debt. For a discussion of the effects of the
construction and financing of TNP One on the Utility's financial
condition, including the detrimental regulatory treatment received to
date, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" contained in the Annual Report to
Shareholders for the year ended December 31, 1993.
Business of Other Subsidiaries
TNP Operating Company and Bayport are general purpose corporations
organized under the Texas Business Corporation Act. Neither company
was materially involved in any business activities during 1993.
Financial Information About Industry Segments
This information is incorporated by reference to page 37 of the Annual
Report to Shareholders for the year ended December 31, 1993. It is
not possible to attribute operating profit or loss and identifiable
assets to each of the classes of customers listed on the page referred
to in said Annual Report.
Kilowatt-hour (KWH) sales in 1993 were assisted by more typical
weather experienced in 1993 as compared to 1992. KWH sales declined
in 1992 from 1991 due in part to milder than normal temperatures in
the Utility's service area in Texas; however, revenues were
approximately the same for the two years due primarily to an increase
in the Utility's Texas customers' rates in 1992. Also contributing to
the sales decline was the failure of new customers and revenues to
materialize as expected within the industrial class to ameliorate the
loss of KWH sales to certain industrial customers. During 1993, the
number of industrial customers decreased by 14, but that decrease
included the consolidation of 10 customers into 2 customers for
billing purposes and the reclassification of 3 customers to the
commercial class of customers.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" contained in the Annual Report to Shareholders
for the year ended December 31, 1993 for a discussion of the changes
in operating revenues, including rate increases.
Narrative Description of Business
The Company is a holding company as defined in the Public Utility
Holding Company Act of 1935, but is exempt from regulation as a
"registered holding company" under the act except with respect to the
acquisition of securities of other public utility companies. The
Company's exemption is based upon the substantially intrastate
character of the operations of the Utility, and the filing with the
Securities and Exchange Commission (SEC) of an annual exemption
statement pursuant to its Rule U-2. The Public Utility Holding
Company Act authorizes the SEC to terminate an exemption which it
determines to be detrimental to the public interest or to the interest
of investors or consumers. Therefore, the extent to which the Company
and its nonutility subsidiaries may expand or diversify and maintain
the Company's exempt status is always subject to review by the SEC.
The Company does not intend to take any action which will jeopardize
its exempt status.
<PAGE 3>
TNP ENTERPRISES, INC. FORM 10-K
The Company is not subject to regulation by the PUCT. The Company is
not generally subject to regulation by the NMPSC; the NMPSC statutes
do not regulate holding companies except under certain circumstances
of consolidation, merger, or acquisition. Both of these agencies have
regulatory authority under state laws over the activities of the
Utility. The Utility, and not the Company, is also subject to the
jurisdiction of the FERC, in certain respects, under the terms of the
Federal Power Act.
Narrative Description of Utility Business
General
The Utility purchases and generates electricity for sales to its
customers wholly within the States of Texas and New Mexico. The
Utility's purchases of electricity are primarily from other utilities
and cogenerators (see "Sources of Energy" in this section). The
Utility's current generation of electricity is from TNP One.
The Utility owns and operates electric transmission and distribution
facilities in 90 municipalities and adjacent rural areas in Texas and
New Mexico. The areas served contain a population of approximately
616,000. The Utility's service is delivered to customers in four
operating divisions in Texas and one operating division in New Mexico.
The Utility's Southeast Division, on the Texas Gulf Coast, is adjacent
to the Johnson Space Center and lies between the cities of Houston and
Galveston. The economy is supported by the oil and petrochemical
industries, agriculture and the general commercial activity of the
Houston area. This division produced 49.5% of the total operating
revenues in 1993. The Utility's Northern Division is based in
Lewisville, just north of the Dallas-Fort Worth International Airport,
and extends to include municipalities along the Red River and in the
Texas Panhandle. This division serves a variety of commercial,
agricultural and petroleum industry customers and produced 19.5% of
the Utility's revenues in 1993. The economy of the Utility's New
Mexico Division is primarily dependent upon mining and agriculture.
Copper mines are the major industrial customers in the New Mexico
Division. This division produced 16.8% of the total operating
revenues in 1993. The Utility's Central Division includes
municipalities and communities located to the south and west of Fort
Worth. This area's economy is largely dependent on agriculture and to
lesser degrees tourism and oil production. In far west Texas, between
Midland and El Paso, the Utility's Western Division serves
municipalities whose economies are primarily related to oil and gas
production, agriculture and food processing.
The Utility serves and intends to continue serving members of the
public in all of its present service areas. The Utility will
construct facilities as needed to meet increasing demand for its
service. The Utility will also extend service beyond its present
service territories to the extent permitted by law and the orders of
regulatory commissions. For a description of the properties utilized
to provide this service, see Item 2, "Properties."
Operating Revenues
Revenues contributed by the Utility's operating divisions in 1993,
1992 and 1991 and the corresponding percentages of total operating
revenues are shown below:
1993 1992 1991
Operating Revenues Revenues Revenues
Division (000's) %'s (000's) %'s (000's) %'s
Central $39,460 8.3% $ 35,421 8.0% $ 34,625 7.8%
Northern 92,265 19.5 83,626 18.9 84,227 19.1
Southeast 234,895 49.5 222,460 50.1 220,581 50.0
Western 28,084 5.9 27,193 6.1 27,487 6.2
New Mexico 79,538 16.8 75,127 16.9 74,423 16.9
Total $474,242 100.0% $443,827 100.0% $441,343 100.0%
<PAGE 4> TNP ENTERPRISES, INC. FORM 10-K
In 1993, 1992 and 1991, no single customer accounted for greater
than 10% of operating revenues, although the Utility has two
affiliated industrial customers in the New Mexico Division which,
together, contributed between 8% and 10% of the Utility's revenues
in each of these years.
Sources of Energy
Information on the "Sources of Energy" of the Utility is
incorporated herein by reference to pages 4 and 5 of the Annual
Report to Shareholders for the year ended December 31, 1993.
Recovery of Purchased Power and Fuel Costs
Purchased power cost recovery adjustment clauses in the Utility's
rate schedules have been authorized by the regulatory authorities
in Texas and New Mexico. A fixed fuel recovery factor in Texas has
also been approved. Both are of substantial benefit to the Utility
in efforts to recover timely and adequately these significant
elements of operating expenses as described in note 1(g) to the
consolidated financial statements contained in the Annual Report to
Shareholders for the year ended December 31, 1993.
Franchises
The Utility holds franchises from each of the 90 municipalities in
which it renders electric service. On December 31, 1993, these
franchises had expiration dates varying from 1994 to 2039, 86
having stated terms of 25 years or more and two having stated terms
of 20 years and two having stated terms of 15 years. The Utility
also holds certificates of public convenience and necessity from
the PUCT covering all of the territories it serves in Texas. The
Utility has been issued certificates for other areas after hearings
before the PUCT. These certificates include terms which are
customary in the public utility industry. In New Mexico, the
Utility operates generally under the grandfather clause of that
state's Public Utility Act which authorizes the continuance of
existing service following the date of the adoption of such act.
Seasonality of Business
The Utility's business is seasonal in character. Summer weather
causes increased use of air-conditioning equipment which produces
higher revenues during the months of June, July, August and
September. For the year ended December 31, 1993, approximately 40%
of annual revenues were recorded in June, July, August and
September, and 60% in the other eight months.
Working Capital
The Utility's major demands on working capital are (1) the monthly
payments for purchased power costs from the Utility's suppliers,
(2) monthly and semi-annual interest payments on long-term debt and
(3) semi-monthly payments for the lignite fuel source for TNP One.
The purchased power and fuel costs are eventually recovered through
the Utility's customers' rates and the purchased power and fuel
costs recovery adjustment clauses and fixed fuel factors, more
fully described in note 1(g) to the consolidated financial
statements contained in the Annual Report to Shareholders for the
year ended December 31, 1993.
Unlike many other generating utilities, the Utility does not have
the requirement of maintaining a large fuel inventory (lignite) due
to the proximity of TNP One with the lignite mine site.
The Utility sells customer receivables, as do many other
utilities. The Utility sells its customer receivables to a
nonaffiliated company on a nonrecourse basis.
<PAGE 5> TNP ENTERPRISES, INC. FORM 10-K
Competitive Conditions
As a regulated public utility, the Utility operates with little
direct competition throughout most of its service territory.
Pursuant to the Texas Public Utility Regulatory Act, the PUCT has
issued to all electric utilities in the State certificates of
public convenience and necessity authorizing them to render elec-
tric service. Rural electric cooperatives, investor-owned electric
utilities and municipally owned electric utilities are all defined
in such act as public utilities. In 72 of the 81 Texas
municipalities served, the Utility has been the only electric
utility issued a certificate to serve customers within the
municipal limits. The Utility is also the only electric utility
authorized to serve customers in some of the rural areas where it
has electric facilities. In other rural areas served by the
Utility, other electric utilities have also been authorized to
serve customers; however, rural electric cooperatives may, under
certain circumstances, become exempt from the PUCT's rate
regulation. Where other electric utilities have also been
certificated to serve customers within the same service area, the
Utility may be subject to competition.
From time to time, industrial customers of the Utility express
interest in cogeneration as a method of reducing or eliminating
reliance upon the Utility as a source of electric service, or to
lower fuel costs and improve operating efficiency of process steam
generation. During 1993, a major industrial customer in the
Utility's Southeast Division requested proposals for a cogeneration
project for evaluation by the customer. The Utility's operating
revenues from this customer during 1993 were approximately $28
million. In January 1994, a potential developer for the proposed
project was selected by the customer. The Utility's goal is to
retain this customer and to lower overall system operating costs
through coordination with the potential developer. Although the
Utility cannot predict the ultimate outcome of the process, the
current project as proposed by the customer, and as outlined by the
potential developer, appears to present a means by which the
Utility may retain electric service to this customer, at current
levels. The Utility is actively pursuing the development of the
necessary agreements with the potential developer to further define
the degree to which electric service to this customer is retained
and overall system operating costs may be lowered.
In New Mexico, a utility subject to the jurisdiction of the NMPUC
may not extend into territory served by another utility or into
territory not contiguous to its service territory without a
certificate of public convenience and necessity from the NMPUC.
Investor-owned electric utilities and rural electric cooperatives
are subject to the jurisdiction of the NMPUC.
The Energy Policy Act of 1992, adopted in October 1992,
significantly changed the U.S. energy policy, including the
governing of the electric utility industry. Among the features of
this act is the creation of Exempt Wholesale Generators and the
authorization of the FERC to order, on a case-by-case basis,
wholesale transmission access. It appears that these particular
features will create competition for the generation and supply of
electricity. Management continues to evaluate the effects of this
act on the Utility. Although the act may not affect the Utility
directly, the Utility believes that this increased competition will
not have an unfavorable impact on it.
Environmental Requirements
Environmental requirements are not expected to materially affect
capital outlays or materially affect the Utility directly. As the
Utility's electric suppliers may be affected by environmental
requirements and resulting costs, the rates charged by them to the
Utility may be increased and thus the Utility will be affected
indirectly.
The Utility's facilities in Texas and New Mexico 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 Utility
maintains continuous procedures to insure compliance with all
applicable environmental laws, rules and regulations. Various
Utility activities require permits, licenses, registrations and
approvals from such agencies. The Utility has received all
necessary authorizations for the construction and continued
operation of its generation, transmission and distribution systems.
<PAGE 6> TNP ENTERPRISES, INC. FORM 10-K
TNP One's circulating fluidized bed technology produces "clean"
emissions, without the addition of costly scrubbers. Unit 1 and
Unit 2 meet the standards of the Clean Air Act of 1990. Under this
act, an entity will be given an allotted number of allowances which
permit emissions up to a specified level. The Utility believes the
allowances received to be sufficient for the level of emissions to
be created by TNP One.
The construction costs for TNP One included approximately $89
million for environmental protection facilities. During 1993, 1992
and 1991, as an ongoing operation of air pollution abatement,
including ash removal, TNP One incurred expenses of approximately
$2.6 million, $2.7 million and $1.9 million, respectively. The
Utility anticipates additional capital expenditures of $875,000 by
1995 for air emissions monitoring equipment for TNP One.
The operations of the Utility are subject to a number of federal,
state and local environmental laws and regulations, which govern
the storage of motor fuels, including those regulating underground
storage tanks. In September 1988, the Environmental Protection
Agency (EPA) issued regulations that required all newly installed
underground storage tanks be protected from corrosion, be equipped
with devices to prevent spills and overfills, and have a leak
detection method that meets certain minimum requirements. The
effective commencement date for newly installed tanks was December
22, 1988. Underground storage tanks in place prior to December 22,
1988, must conform to the new standards by December 1998. The
Utility currently estimates the cost over the next five years to
bring its existing underground storage tanks into compliance with
the EPA guidelines will be $100,000. The Utility also has the
option of removing any existing underground storage tanks.
During 1993, 1992, and 1991, the Utility incurred cleanup and
testing costs on both leaking and nonleaking storage tanks of
approximately $98,000, $89,000, and $84,000, respectively, in
complying with these EPA regulations. A change in the regulations
in the State of Texas permitted the Utility to collect in 1992 from
the state environmental trust fund $65,000 of expenditures paid in
prior years.
Both states in which the Utility owns or operates underground
storage tanks have state operated funds which reimburse the Utility
for certain cleanup costs and liabilities incurred as a result of
leaks in underground storage tanks. These funds, which essentially
provide insurance coverage for certain environmental liabilities,
are funded by taxes on underground storage tanks or on motor fuels
purchased within each respective state. The funds require the
Utility to pay deductibles of less than $5,000 per occurrence.
During 1992, the Texas state environmental trust fund delayed
reimbursement payments after September 30, 1992, of certain cleanup
costs due to an increase in claims. Because the state and federal
government have the right, by law, to levy additional fees on fuel
purchases, the Utility believes these cleanup costs will ultimately
be reimbursed.
Employees
The number of employees on December 31, 1993, was 1,051.
<PAGE 7> TNP ENTERPRISES, INC. FORM 10-K
Executive Officers of the Registrant
Identification of Executive Officers
Executive Officers of the Company
Positions & Offices Held Period of
with the Company Such Office
Name Age Within the Past 5 Years1 Years Months
D. R. Spurlock2 61 Interim President & Chief 0 1
Executive Officer and Director
D. R. Barnard 61 Vice President & 4 8
Chief Financial Officer
Vice President & 4 6
Treasurer
M. D. Blanchard 43 Corporate Secretary & 6 4
General Counsel
Monte W. Smith 40 Treasurer 4 8
Director - Internal Audit 2 11
Executive Officers of the Utility
Positions & Offices Held Period of
with the Utility Such Office
Name Age Within the Past 5 Years1 Years Months
D. R. Spurlock 61 Interim President & Chief 0 1
Executive Officer and Director
Sector Vice President - 2 4
Operations
Vice President - 11 1
Division Manager
D. R. Barnard 61 Sector Vice President & 3 8
Chief Financial Officer
Vice President & 1 0
Chief Financial Officer
Vice President & 17 0
Treasurer
J. V. Chambers, Jr. 44 Sector Vice President - 3 8
Revenue Production
Vice President - Contracts 3 2
& Regulation
1, 2 See respective explanation appearing on the following page.
<PAGE 8>
TNP ENTERPRISES, INC. FORM 10-K
Positions & Offices Held Period of
with the Utility Such Office
Name Age Within the Past 5 Years1 Years Months
M. C. Davie 58 Vice President - Corporate 10 11
Affairs
A. B. Davis 56 Vice President - Chief Engineer 1 8
Chief Engineer 1 4
Assistant Chief Engineer 0 1
Manager - Engineering 5 8
L.W. Dillon 39 Vice President - Operations 0 1
Division Manager 3 6
Division Engineering Manager 4 11
R. J. Wright 46 Vice President - 0 6
Corporate Services/Generation
Vice President -
Manager - Generation 4 8
M. D. Blanchard 43 Corporate Secretary & 6 4
General Counsel
Monte W. Smith 40 Treasurer 4 8
Director - Internal Audit 2 11
1 All officers are elected annually by the respective Board of Directors
for a one-year term until the next annual meeting of the Board of
Directors or until their successors shall be elected and qualified.
The term of an officer elected at any other time by the Board also will
run until the next succeeding annual meeting of the Board of Directors
or until a successor shall be elected and qualified.
2 Retired as Sector Vice President of the Utility effective December 31,
1992; named Interim President & Chief Executive Officer effective
November 9, 1993.
With the exception of D. R. Spurlock, each of the above-named officers
is a full-time employee of the Utility and has been for more than five
years prior to the date of the filing of this Form 10-K.
<PAGE 9>
TNP ENTERPRISES, INC. FORM 10-K
Item 2. Properties.
The Utility's electric properties served a total of 211,911 customers
at year-end and consisted of the installations described in the
following sections.
(1) Electric generation, transmission and distribution facilities
located in the State of Texas are as follows:
(A) Central Division. Electric transmission and distribution sys-
tems serving 25 municipalities and 18 unincorporated
communities in 17 counties to the south and west of Fort
Worth, Texas. The division is based at Clifton, Texas.
(B) Northern Division. Electric transmission and distribution
systems serving 36 municipalities and 19 unincorporated
communities in 14 North Texas counties and 3 counties in the
Texas Panhandle. The division is based at Lewisville, Texas.
(C) Southeast Division. Electric transmission and distribution
systems serving 14 municipalities and 2 unincorporated
communities in 3 counties on the Texas Gulf Coast. The
division is based at Texas City, Texas.
(D) Western Division. Electric transmission and distribution sys-
tems serving 6 municipalities and 1 unincorporated community
in 5 counties in West Texas. The division is based at Pecos,
Texas.
(E) Robertson County, Texas. Two 150-megawatt lignite-fueled
generating units (Unit 1 and Unit 2, collectively referred to
as TNP One) using circulating fluidized bed technology. The
Utility also has an 18-mile long transmission line to connect
TNP One to a major transmission grid in Texas.
(2) Electric generation, transmission and distribution facilities in
the State of New Mexico serve 5 municipalities and 5
unincorporated communities in Grant and Hidalgo Counties, and 4
municipalities and 1 unincorporated community in Otero and Lincoln
Counties. The New Mexico Division is based at Silver City, New
Mexico.
(3) The facilities owned by the Utility include those normally used in
the electric utility business. The facilities are of sufficient
capacity to adequately serve existing customers, and such
facilities may be extended and expanded to serve future customer
growth of the Utility in existing service areas. The Utility
generally constructs its transmission and distribution facilities
upon real property held pursuant to easements or public rights of
way and not upon real property held in fee simple by the Utility.
(4) All real and personal property of the Utility, with certain
exceptions such as much of TNP One, is subject to the lien of the
Indenture of Mortgage and Deed of Trust (Bond Indenture) under
which the Utility's First Mortgage Bonds are issued. Certain
exceptions are set forth in the Bond Indenture. The lenders in
the Unit 2 financing facility and the holders of all secured
debentures hold a second lien on all real and personal Texas
property of the Utility.
Holders of the Utility's Secured Debentures, due 1999 and Series
A, Secured Debentures, due 2003 equally and ratably hold first
liens on approximately 59% of Unit 1. The remaining amount of
Unit 1 property is subject to a first lien under the Utility's
Bond Indenture and a second lien under the secured debentures'
indentures.
The lenders under the Unit 2 financing facility and the Utility's
Secured Debentures, due 1999, equally and ratably hold first liens
on approximately 74% of Unit 2. The remaining amount of Unit 2
property is subject to a first lien under the Utility's Bond
Indenture and a second lien under the secured debentures'
indentures.
Under certain conditions, upon repayment of portions of the loans
or secured debentures under the financing facilities, the Utility
may purchase undivided interests in Unit 1 or Unit 2 from TGC or
TGC II, respectively, whereupon such undivided interests become
subject to the first lien of the Utility's Bond Indenture. See
note 2 to the consolidated financial statements contained in the
Annual Report to Shareholders for the year ended December 31, 1993
for additional information.
<PAGE 10>
TNP ENTERPRISES, INC. FORM 10-K
Item 3. Legal Proceedings.
Appeals of Regulatory Orders
The following summary discusses the Utility's most recent regulatory
proceedings before the PUCT and the judicial appeals. While the
ultimate outcome of these cases and of other matters discussed below
cannot be predicted, the Utility is vigorously pursuing their favorable
conclusion. Material adverse resolution of certain of the matters
discussed below would have a material adverse impact on earnings in the
period of resolution. More detailed discussions of the proceedings and
related impacts are included in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and note 5 to the
consolidated financial statements contained in the Annual Report to
Shareholders for the year ended December 31, 1993.
PUCT Docket No. 9491
On April 11, 1990, the Utility filed a rate application, Docket No.
9491, with the PUCT for inclusion of the costs of Unit 1 in the
Utility's rate base and for the setting of rates to recover the costs
of that unit. On February 7, 1991, the Utility received a final order
which allowed $298.5 million of the costs of Unit 1 in rate base;
however, the PUCT disallowed from rate base $39.5 million of the
requested investment costs of $338 million for that unit. The PUCT
approved an increase in annualized revenues of approximately $36.7
million, or 67% of the Utility's original $54.9 million rate request.
The PUCT also found that the Utility failed to prove that its decision
to start construction of Unit 2 was prudent. Nevertheless, the PUCT
granted rate base treatment for Unit 2 in Docket No. 10200, as
discussed below.
On appeal by the Utility of the PUCT's order in Docket No. 9491, a
State district court in Travis County, Texas, ruled that the PUCT's
disallowance of rate base treatment for certain costs of Unit 1 was in
error and that the PUCT's "decision to deny $39,508,409 in capital
costs for TNP One Unit 1 is not supported by substantial evidence and
is arbitrary and capricious."
On appeal of the State district court's order by the Utility, the PUCT
and certain of the intervenor cities (the Cities), a Third District
Court of Appeals in Austin, Texas, rendered a judgment partially
reversing the State district court and affirming the PUCT's
disallowances for $30.4 million of the total $39.5 million. The Court
of Appeals remanded the cause to the district court with instructions
that the cause be remanded to the PUCT for proceedings not inconsistent
with the appellate opinion.
On September 9, 1993, the Utility, the Cities and the PUCT filed
motions for rehearing with the Court of Appeals. The Utility's
opponents are seeking, among other things, lower rates and greater
disallowances, and the Utility is seeking higher rates and no
disallowances. The PUCT is not expected to act upon the district
court's ordered remand, discussed above, until the appellate process,
including appeals to the Texas Supreme Court, has been completed.
Based upon the opinions of the Utility's Texas regulatory counsel,
Johnson & Gibbs, a Professional Corporation, management believes that
it will prevail in obtaining a remand of a significant portion of the
disallowances in Docket No. 9491; however, the ultimate disposition and
quantification of these items cannot presently be determined.
Accordingly, no provision for any loss that may ultimately be required
upon resolution of these matters has been made in the consolidated
financial statements.
If the Utility is not successful in obtaining a final favorable
disposition in the appellate proceedings relating to the disallowances
in Docket No. 9491, a write-off of some portion of the $39.5 million
disallowances would be required, which could result in a significant
negative impact on earnings in the period of final resolution.
PUCT Docket No. 10200
On April 11, 1991, the Utility filed a rate application, Docket
No. 10200, with the PUCT for inclusion of $275.2 million of capital
costs of Unit 2 in the Utility's rate base and for the setting of rates
to recover the costs of that unit.
<PAGE 11>
TNP ENTERPRISES, INC. FORM 10-K
On March 18, 1993, the Utility received a final order which allowed
$250.7 million of the Unit 2 costs in rate base; however, the PUCT
disallowed from rate base $21.1 million associated with Unit 2 and $0.8
million additional costs requested for Unit 1. The PUCT also
determined that $11.1 million of Unit 2 costs would be addressed in a
future Texas rate application. The PUCT approved an increase in
annualized revenues of approximately $19 million, or 53%, of the
Utility's original $35.8 million rate request.
The order in Docket No. 10200 also reflects application to the Utility
of a new method for calculating the amount of Federal income tax
expense allowed in cost of service, which significantly reduced the
Utility's level of annualized revenue increase from $26 million to $19
million.
The Docket No. 10200 rate order has been appealed to a Texas district
court by the Utility and other parties. Because of the Court of
Appeals judgment relating to the prudence of starting construction of
Unit 2 (FF No. 84 in the docket No. 9491), the presiding judge in the
Texas district court for the Docket No. 10200 appeal has ordered that
the procedural schedule in this appeal be abated until final resolution
of the FF No. 84 issue in Docket No. 9491. The Utility will vigorously
pursue reversal of the PUCT's new position regarding Federal income tax
expenses, in addition to seeking judicial relief from the disallowances
and certain other rulings by the PUCT in Docket No. 10200. The
opposing parties are seeking a variety of relief to obtain lower rates
and greater disallowances, including overturning the basis of the
Utility's case as presented to the PUCT and sustaining the PUCT's
adverse Federal income tax position without regard to any IRS ruling
on the normalization issue.
Based upon the opinions of the Utility's Texas regulatory counsel,
Johnson & Gibbs, a Professional Corporation, management believes that
it will prevail in obtaining a remand of a significant portion of the
disallowances in Docket No. 10200; however, the ultimate disposition
and quantification of these items cannot presently be determined.
Accordingly, no provision for any loss that may ultimately be required
upon resolution of these matters has been made in the consolidated
financial statements.
If the Utility is not successful in obtaining a final favorable
disposition in the appellate proceedings relating to the disallowances
in Docket No. 10200, a write-off of some portion of the $21.9 million
disallowances would be required, which could result in a significant
negative impact on earnings in the period of final resolution.
Other Legal Matters
The Utility is involved in various claims and other legal actions
arising in the ordinary course of business. In the opinion of
management, the ultimate disposition of these matters will not have a
material adverse effect on the Utility's consolidated financial
position.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders in the
fourth quarter of 1993.
PART II
Item 5. Market For The Registrant's Common Equity and Related Shareholder
Matters.
This information is incorporated by reference to "Common Stock
Information" on page 38 of the Annual Report to Shareholders for the
year ended December 31, 1993.
For the years ended December 31, 1993 and 1992, the Company paid
$17,344,000, and $13,780,000, respectively, in common dividends.
Dividends were paid on a quarterly basis. Since most of the assets,
liabilities and earnings capability of the Company are those of the
Utility, the ability of the Company to pay dividends will be largely
dependent upon the Utility's operations and the Utility's restrictions
regarding payment of its dividends as discussed in notes 2 and 3 to the
consolidated financial statements contained in the Annual Report to
Shareholders for the year ended December 31, 1993.
<PAGE 12>
TNP ENTERPRISES 10-K
Item 6. Selected Consolidated Financial Data.
This information is incorporated by reference to "Selected Annual
Consolidated Financial Data" on page 36 of the Annual Report to
Shareholders for the year ended December 31, 1993.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and note 5 to the consolidated financial
statements contained in the Annual Report to Shareholders for the year
ended December 31, 1993 for discussion of material uncertainties which
might cause the information incorporated by reference above not to be
indicative of future financial condition or results of operations.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
This information is incorporated by reference to "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" on pages 6 through 16 of the Annual Report to Shareholders
for the year ended December 31, 1993.
Item 8. Financial Statements and Supplementary Data.
This information is incorporated by reference to the appropriate
sections on pages 17 through 35 of the Annual Report to Shareholders
for the year ended December 31, 1993.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant.
Identification of Directors and Directorships
The information required by this item is incorporated by reference
from "The Nominees and Continuing Directors" of the definitive Proxy
Statement relating to the annual meeting of holders of common stock
of the Company, pursuant to Regulation 14A, filed with the SEC and
mailed on or about March 28, 1994 to the holders of common stock of
the Company.
Identification of Executive Officers
The information required by this item with respect to executive
officers is set forth in Item 1 of Part I of this Form 10-K under
"Executive Officers of the Registrant, " pursuant to instruction 3
of paragraph (b) of Item 401 of Regulation S-K.
Item 11. Executive Compensation.*
Item 12. Security Ownership of Certain Beneficial Owners and Management.*
Item 13. Certain Relationships and Related Transactions.*
* The information required by Items 11, 12, and 13 is incorporated
by reference from the definitive Proxy Statement relating to the
Annual Meeting of holders of common stock of the Company, pursuant
to Regulation 14A, filed with the SEC and mailed on or about
March 28, 1994 to the holders of common stock of the Company.
<PAGE 13>
TNP ENTERPRISES, INC. FORM 10-K
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) Items Filed as Part of This Report
Financial Statements and Supplementary Data
The following information is incorporated by reference to pages 17
through 35 of the Annual Report to Shareholders for the year ended
December 31, 1993:
Independent Auditors' Report
Consolidated Statements of Earnings, Three Years Ended December 31,
1993
Consolidated Balance Sheets, December 31, 1993 and 1992
Consolidated Statements of Common Stock Equity and Redeemable
Cumulative Preferred Stocks, Three Years Ended December 31, 1993
Consolidated Statements of Cash Flows, Three Years Ended December 31,
1993
Notes to Consolidated Financial Statements, December 31, 1993, 1992
and 1991
Selected Quarterly Consolidated Financial Data (Unaudited), Quarters
ended March 31, June 30, September 30, and December 31, 1993 and 1992
Financial Statement Schedules Page
Independent Auditors' Report. . . . . . . . . . . . . . 17
V - Utility Plant, Three Years Ended December 31, 1993 . . . . . 18
VI - Accumulated Depreciation of Utility Plant, Three Years
Ended December 31, 1993 . . . . . . . . . . . . . . 19
IX - Short-term Borrowings, Three Years Ended December 31, 1993 20
X - Supplementary Consolidated Earnings Statement Information,
Three Years Ended December 31, 1993 . . . . . 21
All other schedules are omitted, as the required information is
inapplicable or the information is presented in the consolidated
financial statements or related notes contained in the Annual Report
to Shareholders for the year ended December 31, 1993.
Exhibits.
See Exhibit Index, Pages 22 through 33.
(b) Reports on Form 8-K
None during the last quarter covered by this report.
<PAGE 14>
TNP ENTERPRISES, INC. FORM 10-K
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.
(Registrant) TNP ENTERPRISES, INC.
By /s/ D. R. Barnard
D. R. Barnard, Vice President &
Chief Financial Officer
Date: March 22, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Title Date
By /s/ R. D. Woofter Chairman 3-22-94
R. D. Woofter
By /s/ Dwight R. Spurlock Interim President & 3-22-94
D. R. Spurlock Chief Executive Officer
By /s/ D. R. Barnard Vice President & 3-22-94
D. R. Barnard Chief Financial Officer
By /s/ Monte W. Smith Treasurer (Principal 3-22-94
Monte W. Smith Accounting Officer)
By /s/ R. Denny Alexander Director 3-22-94
R. Denny Alexander
By /s/ Cass O. Edwards, II Director 3-22-94
Cass O. Edwards, II
By /s/ John A. Fanning Director 3-22-94
John A. Fanning
By /s/ Harris L. Kempner, Jr. Director 3-22-94
Harris L. Kempner, Jr.
<PAGE 15>
TNP ENTERPRISES, INC. FORM 10-K
Index to Financial Statement Schedules
Independent Auditors' Report
Schedules:
V - Utility Plant, Three Years Ended December 31, 1993
VI - Accumulated Depreciation of Utility Plant, Three Years Ended
December 31, 1993
IX - Short-term Borrowings, Three Years Ended December 31, 1993
X - Supplementary Consolidated Earnings Statement Information, Three
Years Ended December 31, 1993
All other schedules are omitted, as the required information is inapplicable
or the information is presented in the consolidated financial statements or
related notes.
The consolidated balance sheets of the Company and subsidiaries as of
December 31, 1993 and 1992, and the related consolidated statements of
earnings, common stock equity and redeemable cumulative preferred stocks, and
cash flows for each of the years in the three-year period ended December 31,
1993, together with the related notes and the report of KPMG Peat Marwick,
independent certified public accountants, all contained in the Annual Report
to Shareholders for the year ended December 31, 1993, are incorporated herein
by reference.
<PAGE 16>
TNP ENTERPRISES, INC. FORM 10-K
Independent Auditors' Report
The Shareholders and Board of Directors
TNP Enterprises, Inc.:
Under date of January 28, 1994, we reported on the consolidated balance
sheets of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993 and
1992, and the related consolidated statements of earnings, common stock
equity and redeemable cumulative preferred stocks, and cash flows for each of
the years in the three-year period ended December 31, 1993, as contained in
the 1993 annual report to shareholders. These consolidated financial
statements and our report thereon are incorporated by reference in the annual
report on Form 10-K for the year 1993. In connection with our audits of the
aforementioned consolidated financial statements, we also have audited the
related financial statement schedules as listed in the accompanying index.
These financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statement schedules based on our audits.
In our opinion, such financial statement schedules, when considered in
relation to the basic consolidated financial statements taken as a whole,
present fairly, in all material respects, the information set forth therein.
The report includes an explanatory paragraph that states that uncertainties
exist with respect to the outcome of certain regulatory matters as discussed
in note 5 to the consolidated financial statements. The ultimate outcome of
these matters cannot presently be determined. Accordingly, no provision for
any loss that may ultimately be required upon resolution of these matters has
been made in the above consolidated financial statements and financial
statement schedules.
As discussed in note 4 to the consolidated financial statements, the Company
changed its method of accounting for income taxes in 1993 to adopt the
provisions of the Financial Accounting Standards Board's Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes.
As discussed in note 1(j), the Company also adopted the provisions of the
Financial Accounting Standards Board's SFAS No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions in 1993.
KPMG PEAT MARWICK
Fort Worth, Texas
January 28, 1994
<PAGE 17>
TNP ENTERPRISES, INC. FORM 10-K
Utility Plant Schedule V
<TABLE>
<CAPTION>
Three Years Ended December 31, 1993
(In Thousands)
Other
Balance at changes: Balance at
beginning Additions add end of
Classification of period at cost(1) Retirements (deduct) period
<S> <C> <C> <C> <C>
Year ended
December 31, 1993:
Electric plant $1,184,635 17,587 5,436 6,850 1,203,636
Construction work
in progress 3,922 8,210 - (6,850) 5,282
$1,188,557 25,797 5,436 - 1,208,918
Year ended
December 31, 1992:
Electric plant $1,159,511 30,365 (6,683) 1,442 1,184,635
Construction work
in progress 2,279 3,085 - (1,442) 3,922
$1,161,790 33,450 (6,683) - 1,188,557
Year ended
December 31, 1991:
Electric plant $850,160 313,259 (6,650) 2,742 1,159,511
Construction work
in progress 2,844 2,177 - (2,742) 2,279
$853,004 315,436 (6,650) - 1,161,790
<FN>
Note: See note 1(c) to the consolidated financial statements contained in the
Annual Report to Shareholders for the year ended December 31, 1993 for
disclosure of depreciation method.
(1) On July 26, 1991, the Utility's wholly owned subsidiary, TGCII, assumed
ownership of TNP One, Unit 2 and assumed the related liabilities
totaling approximately $269 million. In addition, approximately $12
million of deferred charges related to TNP One, Unit 2 were
reclassified to utility plant. These amounts are included in the 1991
additions above. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and note 5 to the
consolidated financial statements contained in the Annual Report to
Shareholders for the year ended December 31, 1993, and Items 1 and 2,
for more information about Unit 2.
During 1992, the Utility reclassified approximately $12 million of
deferred charges to utility plant.
</TABLE>
<PAGE 18>
TNP ENTERPRISES, INC. FORM 10-K
Accumulated Depreciation of Utility Plant Schedule VI
Three Years Ended December 31, 1993
(In Thousands)
<TABLE>
<CAPTION>
Other
Additions changes:
Balance at charged to add Balance at
beginning costs and Net (deduct) end of
Description of period expenses retirements (See Notes) period
<S> <C> <C> <C> <C> <C>
Year ended
December 31, 1993:
Electric plant $172,848 36,015 (6,268) 328 202,923
Year ended
December 31, 1992:
Electric plant $145,188 35,098 (7,687) 249 172,848
Year ended
December 31, 1991:
Electric plant $124,015 28,027 (7,444) 590 145,188
<FN>
Notes: Other additions represent depreciation of transportation equipment
charged to property accounts in accordance with the equipment's use.
See note 1(c) to the consolidated financial statements contained in
the Annual Report to Shareholders for the year ended December 31,
1993 for disclosure of depreciation method.
</TABLE>
<PAGE 19>
TNP ENTERPRISES, INC. FORM 10-K
Short-term Borrowings (1) Schedule IX
Three Years Ended December 31, 1993
(Dollars in Thousands)
<TABLE>
<CAPTION>
Weighted Maximum Average Weighted
Category of average amount amount average
aggregate Balance interest rateout standing outstandinginterest rate
short-term at end at end during the during the during the
Period borrowings of period of period period(3) period(2) period (2)
<S> <C> <C> <C> <C> <C> <C>
1993 Unsecured Notes
Payable to Banks $ -0- N/A $-0- -0- N/A
1992 Unsecured Notes
Payable to Banks $ -0- N/A(2) $36,000 13,004 5.70%
1991 Unsecured Notes
Payable to Banks $ 36,000 7.10% $60,000 36,698 7.70%
<FN>
Notes:
(1) Unsecured notes payable to banks were issued under revolving lines of
credit. Under the terms of the revolving lines of credit, the interest
rates were determined under several alternative methods. All rates at
the time of issuance were the prime lending rate plus 1/2% or lower.
A fee of 1/4 of 1% per annum of the average unused commitments was
payable quarterly, with no compensating bank balance requirements.
(2) For 1991, computation was based on days outstanding for the year. For
1992, computation was based on the period of January 1, 1992 to August
12, 1992 when all outstanding unsecured notes payable to banks were
retired.
(3) For 1991, represents the maximum amount outstanding at any month end.
For 1992, represents the balance outstanding at January 1, 1992.
</TABLE>
<PAGE 20>
TNP ENTERPRISES, INC. FORM 10-K
Supplementary Consolidated Earnings Statement InformationSchedule X
Three Years Ended December 31, 1993
(In Thousands)
Charged to costs and expenses
Item 1993 1992 1991
Taxes, other than payroll and income taxes:
Gross receipts and street rentals $11,387 10,064 9,484
Property 14,132 14,272 10,302
Other 2,613 2,431 1,689
$28,132 26,767 21,475
<PAGE 21>
TNP ENTERPRISES, INC. FORM 10-K
EXHIBIT INDEX
Exhibits filed herewith are denoted by "*." The other exhibits have
heretofore been filed with the Commission and are incorporated herein by
reference.
Exhibit
No. Description
3(a) - Articles of Incorporation and Amendments through March 6, 1984
(Exhibit 3(a), File No. 2-89800).
3(b) - Amendment to Articles of Incorporation filed September 25, 1984.
(Exhibit 3(b) to Form 10-K for the year ended December 31, 1987,
File No. 1-8847).
3(c) - Amendment to Articles of Incorporation filed August 29, 1985
(Exhibit 3(a) to Form 10-K for the year ended December 31, 1985,
File No. 1-8847).
3(d) - Amendment to Articles of Incorporation filed June 2, 1986
(Exhibit 3(a) to Form 10-K for the year ended December 31, 1986,
File No. 1-8847).
3(e) - Amendment to Articles of Incorporation filed May 10, 1988
(Exhibit 3(e) to Form 10-K for the year ended December 31, 1988,
File No. 1-8847).
3(f) - Amendment to Articles of Incorporation filed May 10, 1988
(Exhibit 3(f) to Form 10-K for the year ended December 31, 1988,
File No. 1-8847).
3(g) - Amendment to Articles of Incorporation filed December 27, 1988
(Exhibit 3(g) to Form 10-K for the year ended December 31, 1988,
File No. 1-8847).
3(h) - Bylaws of the Company, as amended February 18, 1992 (Exhibit
4(h), File No. 33-53918).
4(a) - Indenture of Mortgage and Deed of Trust of the Utility dated as
of November 1, 1944 (Exhibit 2(d), File No. 2-61323).
4(b) - Seventh Supplemental Indenture dated as of May 1, 1963 (Exhibit
2(k), File No. 2-61323).
4(c) - Eighth Supplemental Indenture dated as of July 1, 1963 (Exhibit
2(1), File No. 2-61323).
<PAGE 22>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit Description
No.
4(d) - Ninth Supplemental Indenture dated as of August 1, 1965 (Exhibit
2(m), File No. 2-61323).
4(e) - Tenth Supplemental Indenture dated as of May 1, 1966 (Exhibit
2(n), File No. 2-61323).
4(f) - Eleventh Supplemental Indenture dated as of October 1, 1969
(Exhibit 2(o), File No. 2-61323).
4(g) - Twelfth Supplemental Indenture dated as of May 1, 1971 (Exhibit
2(p), File No. 2-61323).
4(h) - Thirteenth Supplemental Indenture dated as of July 1, 1974
(Exhibit 2(q), File No. 2-61323).
4(i) - Fourteenth Supplemental Indenture dated as of March 1, 1975
(Exhibit 2(r), File No. 2-61323).
4(j) - Fifteenth Supplemental Indenture dated as of September 1, 1976
(Exhibit 2(e), File No. 2-57034).
4(k) - Sixteenth Supplemental Indenture dated as of November 1, 1981
(Exhibit 4(x), File No. 2-74332).
4(l) - Seventeenth Supplemental Indenture dated as of December 1, 1982
(Exhibit 4(cc), File No. 2-80407).
4(m) - Eighteenth Supplemental Indenture dated as of September 1, 1983
(Exhibit (a) to Form 10-Q of Texas-New Mexico Power Company for
the quarter ended September 30, 1983, File No. 1-4756).
4(n) - Nineteenth Supplemental Indenture dated as of May 1, 1985
(Exhibit 4(v), File No. 2-97230).
4(o) - Twentieth Supplemental Indenture dated as of July 1, 1987
(Exhibit 4(o) to Form 10-K of Texas-New Mexico Power Company for
the year ended December 31, 1987, File No. 2-97230).
4(p) - Twenty-First Supplemental Indenture dated as of July 1, 1989
(Exhibit 4(p) to Form 10-Q of Texas-New Mexico Power Company for
the quarter ended June 30, 1989, File No. 2-97230).
4(q) - Twenty-Second Supplemental Indenture dated as of January 15,
1992 (Exhibit 4(q) to Form 10-K of the Utility for the year
ended December 31, 1991, File No. 2-97230).
<PAGE 23>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
4(r) - Twenty-Third Supplemental Indenture dated as of September 15,
1993 (Exhibit 4(r) to Form 10-K of the Utility for the year
ended December 31, 1993, File No. 2-97230).
4(s) - Indenture and Security Agreement for Secured Debentures dated
as of January 15, 1992 (Exhibit 4(r) to Form 10-K of the Utility
for the year ended December 31, 1991, File No. 2-97230).
4(t) - Indenture and Security Agreement for Secured Debentures dated
as of September 15, 1993 (Exhibit 4(t) to Form 10-K of the
Utility for the year ended December 31, 1993, File No. 2-97230).
4(u) - Rights Agreement and Form of Right Certificate, as amended,
effective November 13, 1990 (Exhibit 2.1 to Form 8-A, File No.
1-8847).
Material Contracts Relating to TNP One
10(a) - Fuel Supply Agreement, dated November 18, 1987, between Phillips
Coal Company and the Utility (Exhibit 10(j) to Form 10-K of the
Utility for the year ended December 31, 1987, File No. 2-97230).
10(b) - Unit 1 First Amended and Restated Project Loan and Credit
Agreement, dated as of January 8, 1992 (the "Unit 1 Credit
Agreement"), among the Utility, Texas Generating Company
("TGC"), the banks named therein as Banks (the "Unit 1 Banks")
and The Chase Manhattan Bank (National Association), as Agent
for the Unit 1 Banks (the "Unit 1 Agent"), amending and
restating the Project Loan and Credit Agreement among such
parties dated as of December 1, 1987 (Exhibit 10(c) to Form 10-K
of the Utility for the year ended December 31, 1991, File No.
2-97230).
10(b)1 - Participation Agreement, dated as of January 8, 1992, among the
banks named therein as Banks, the parties named therein as
Participants and the Unit 1 Agent (Exhibit 10(c)1) to Form 10-K
of the Utility for the year ended December 31, 1991, File No.
2-97230).
10(b)2 - Amendment No. 1, dated as of September 21, 1993, to the Unit 1
Credit Agreement (Exhibit 10(b)2 to Form 10-K of the Utility for
the year ended December 31, 1993, File No. 2-97230).
10(c) - Assignment and Security Agreement, dated as of January 8, 1992,
among TGC and the Unit 1 Agent, for the benefit of the Secured
Parties, as defined in the Unit 1 Credit Agreement, amending and
restating the Assignment and Security Agreement among such
parties dated as of December 1, 1987 (Exhibit 10(d) to Form 10-K
of the Utility for the year ended December 31, 1991, File No.
2-97230).
<PAGE 24>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(d) - Assignment and Security Agreement, dated December 1, 1987,
executed by the Utility in favor of the Unit 1 Agent for the
benefit of the Secured Parties, as defined therein (Exhibit
10(u) to Form 10-K of the Utility for the year ended December
31, 1987, File No. 2-97230).
10(e) - Amended and Restated Subordination Agreement, dated as of
October 1, 1988, among the Utility, Continental Illinois
National Bank and Trust Company of Chicago and the Unit 1 Agent,
amending and restating the Subordination Agreement among such
parties dated as of December 1, 1987 (Exhibit 10(uu) to Form 10-
K of the Utility for the year ended December 31, 1988, File No.
2-97230).
10(f) - Mortgage and Deed of Trust (With Security Agreement and UCC
Financing Statement for Fixture Filing), dated to be effective
as of December 1, 1987, and executed by Project Funding
Corporation ("PFC"), as Mortgagor, to Donald H. Snell, as
Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(ee) to Form 10-K of the Utility for
the year ended December 31, 1987, File No. 2-97230).
10(f)1 - Supplemental Mortgage and Deed of Trust (With Security Agreement
and UCC Financing Statement for Fixture Filing), executed by
TGC, as Mortgagor, on January 27, 1992, to be effective as of
December 1, 1987, to Donald H. Snell, as Mortgage Trustee, for
the benefit of the Secured Parties, as defined therein (Exhibit
10(g)4) to Form 10-K of the Utility for the year ended
December 31, 1991, File No. 2-97230).
10(f)2 - First TGC Modification and Extension Agreement, dated as of
January 24, 1992, among the Unit 1 Banks, the Unit 1 Agent, the
Utility and TGC (Exhibit 10(g)1) to Form 10-K of the Utility for
the year ended December 31, 1991, File No. 2-97230).
10(f)3 - Second TGC Modification and Extension Agreement, dated as of
January 27, 1992, among the Unit 1 Banks, the Unit 1 Agent, the
Utility and TGC (Exhibit 10(g)2) to Form 10-K of the Utility for
the year ended December 31, 1991, File No. 2-97230).
10(f)4 - Third TGC Modification and Extension Agreement, dated as of
January 27, 1992, among the Unit 1 Banks, the Unit 1 Agent, the
Utility and TGC (Exhibit 10(g)3) to Form 10-K of the Utility for
the year ended December 31, 1991, File No. 2-97230).
10(f)5 - Fourth TGC Modification and Extension Agreement, dated as of
September 29, 1993, among the Unit 1 Banks, the Unit 1 Agent,
the Utility and TGC (Exhibit 10(f)5 to Form 10-K of the Utility
for the year ended December 31, 1993, File No. 2-97230).
<PAGE 25>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(f)6 - Fifth TGC Modification and Extension Agreement, dated as of
September 29, 1993, among the Unit 1 Banks, the Unit 1 Agent,
the Utility and TGC (Exhibit 10(f)6 to Form 10-K of the Utility
for the year ended December 31, 1993, File No. 2-97230).
10(g) - Indemnity Agreement, made as of the 1st day of December, 1987,
by Westinghouse, CE and Zachry, as Indemnitors, for the benefit
of the Secured Parties, as defined therein (Exhibit 10(ff) to
Form 10-K of the Utility for the year ended December 31, 1987,
File No. 2-97230).
10(h) - Second Lien Mortgage and Deed of Trust (With Security Agreement)
executed by the Utility, as Mortgagor, to Donald H. Snell, as
Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(jj) to Form 10-K of the Utility for
the year ended December 31, 1987, File No. 2-97230).
10(h)1 - Correction Second Lien Mortgage and Deed of Trust (with Security
Agreement), dated as of December 1, 1987, executed by the
Utility, as Mortgagor, to Donald H. Snell, as Mortgage Trustee,
for the benefit of the Secured Parties, as defined therein
(Exhibit 10(vv) to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
10(h)2 - Second Lien Mortgage and Deed of Trust (with Security Agreement)
Modification, Extension and Amendment Agreement, dated as of
January 8, 1992, executed by the Utility to Donald H. Snell, as
Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(i)2) to Form 10-K of the Utility for
the year ended December 31, 1991, File No. 2-97230).
10(h)3 - TNP Second Lien Mortgage Modification No. 2, dated as of
September 21, 1993, executed by the Utility to Donald H. Snell,
as Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(h)3 to Form 10-K of the Utility for
the year ended December 31, 1993, File No. 2-97230).
10(i) - Agreement for Conveyance and Partial Release of Liens, made as
of the 1st day of December, 1987, by PFC and the Unit 1 Agent
for the benefit of the Utility (Exhibit 10(kk) to Form 10-K of
the Utility for the year ended December 31, 1987, File No.
2-97230).
10(j) - Inducement and Consent Agreement, dated as of June 15, 1988,
between Phillips Coal Company, Kiewit Texas Mining Company, the
Utility, Phillips Petroleum Company and Peter Kiewit Son's, Inc.
(Exhibit 10(nn) to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
10(k) - Assumption Agreement, dated as of October 1, 1988, executed by
TGC, in favor of the Issuing Bank, as defined therein, the Unit
1 Banks, the Unit 1 Agent and the Depositary, as defined therein
(Exhibit 10(ww) to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
<PAGE 26>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(l) - Guaranty, dated as of October 1, 1988, executed by the Utility
and given in respect of the TGC obligations under the Unit 1
Credit Agreement (Exhibit 10(xx) to Form 10-K of the Utility for
the year ended December 31, 1988, File No. 2-97230).
10(m) - First Amended and Restated Facility Purchase Agreement, dated
as of January 8, 1992, among the Utility, as the Purchaser, and
TGC, as the Seller, amending and restating the Facility Purchase
Agreement among such parties dated as of October 1, 1988
(Exhibit 10(n) to Form 10-K of the Utility for the year ended
December 31, 1991, File No. 2-97230).
10(n) - Operating Agreement, dated as of October 1, 1988, among the
Utility and TGC (Exhibit 10(zz) to Form 10-K of the Utility for
the year ended December 31, 1988, File No. 2-97230).
10(o) - Unit 2 First Amended and Restated Project Loan and Credit
Agreement, dated as of January 8, 1992 (the "Unit 2 Credit
Agreement"), among the Utility, Texas Generating Company II
("TGCII"), the banks named therein as Banks (the "Unit 2 Banks")
and The Chase Manhattan Bank (National Association), as Agent
for the Unit 2 Banks (the "Unit 2 Agent"), amending and
restating the Project Loan and Credit Agreement among such
parties dated as of October 1, 1988 (Exhibit 10(q) to Form 10-K
of the Utility for the year ended December 31, 1991, File No.
2-97230).
10(o)1 - Amendment No. 1, dated as of September 21, 1993, to the Unit 2
Credit Agreement (Exhibit 10(o)1 to Form 10-K of the Utility for
the year ended December 31, 1993, File No. 2-97230).
10(p) - Assignment and Security Agreement, dated as of January 8, 1992,
among TGCII and the Unit 2 Agent, for the benefit of the Secured
Parties, as defined in the Unit 2 Credit Agreement, amending and
restating the Assignment and Security Agreement among such
parties dated as of October 1, 1988 (Exhibit 10(r) to Form 10-K
of the Utility for the year ended December 31, 1991, File No.
2-97230).
10(q) - Assignment and Security Agreement, dated as of October 1, 1988,
executed by the Utility in favor of the Unit 2 Agent for the
benefit of the Secured Parties, as defined therein (Exhibit
10(jjj) to Form 10-K of the Utility for the year ended December
31, 1988, File No. 2-97230).
10(r) - Subordination Agreement, dated as of October 1, 1988, among the
Utility, Continental Illinois National Bank and Trust Company
of Chicago and the Unit 2 Agent (Exhibit 10(mmm) to Form 10-K
of the Utility for the year ended December 31, 1988, File No.
2-97230).
<PAGE 27>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(s) - Mortgage and Deed of Trust (With Security Agreement and UCC
Financing Statement for Fixture Filing), dated to be effective
as of October 1, 1988, and executed by Texas PFC, Inc., as
Mortgagor, to Donald H. Snell, as Mortgage Trustee, for the
benefit of the Secured Parties, as defined therein (Exhibit
10(uuu) to Form 10-K of the Utility for the year ended December
31, 1988, File No. 2-97230).
10(s)1 - First TGCII Modification and Extension Agreement, dated as of
January 24, 1992, among the Unit 2 Banks, the Unit 2 Agent, the
Utility and TGCII (Exhibit 10(u)1) to Form 10-K of the Utility
for the year ended December 31, 1991, File No. 2-97230).
10(s)2 - Second TGCII Modification and Extension Agreement, dated as of
January 27, 1992, among the Unit 2 Banks, the Unit 2 Agent, the
Utility and TGCII (Exhibit 10(u)2) to Form 10-K of the Utility
for the year ended December 31, 1991, File No. 2-97230).
10(s)3 - Third TGCII Modification and Extension Agreement, dated as of
January 27, 1992, among the Unit 2 Banks, the Unit 2 Agent, the
Utility and TGCII (Exhibit 10(u)3) to Form 10-K of the Utility
for the year ended December 31, 1991, File No. 2-97230).
10(s)4 - Fourth TGCII Modification and Extension Agreement, dated as of
September 29, 1993, among the Unit 2 Banks, the Unit 2 Agent,
the Utility and TGCII (Exhibit 10(s)4 to Form 10-K of the
Utility for the year ended December 31, 1993, File No. 2-97230).
10(t) - Release and Waiver of Liens and Indemnity Agreement, made
effective as of the 1st day of October, 1988, by a consortium
composed of Westinghouse, CE, and Zachry (Exhibit 10(vvv) to
Form 10-K of the Utility for the year ended December 31, 1988,
File No. 2-97230).
10(u) - Second Lien Mortgage and Deed of Trust (With Security
Agreement), dated as of October 1, 1988, and executed by the
Utility, as Mortgagor, to Donald H. Snell, as Mortgage Trustee,
for the benefit of the Secured Parties, as defined therein
(Exhibit 10(www) to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
10(u)1 - Second Lien Mortgage and Deed of Trust (with Security Agreement)
Modification, Extension and Amendment Agreement, dated as of
January 8, 1992, executed by the Utility to Donald H. Snell, as
Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(w)1) to Form 10-K of the Utility for
the year ended December 31, 1991, File No. 2-97230).
<PAGE 28>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(u)2 - TNP Second Lien Mortgage Modification No. 2, dated as of
September 21, 1993, executed by the Utility to Donald H. Snell,
as Mortgage Trustee, for the benefit of the Secured Parties, as
defined therein (Exhibit 10(u)2 to Form 10-K of the Utility for
the year ended December 31, 1993, File No. 2-97230).
10(v) - Intercreditor and Nondisturbance Agreement, dated as of October
1, 1988, among PFC, Texas PFC, Inc., the Utility, the Project
Creditors, as defined therein, and the Collateral Agent, as
defined therein (Exhibit 10(xxx) to Form 10-K of the Utility for
the year ended December 31, 1988, File No. 2-97230).
10(v)1 - Amendment #1, dated as of January 8, 1992, to the Intercreditor
and Nondisturbance Agreement, dated as of October 1, 1988, among
TGC, TGCII, the Utility, the Unit 1 Banks, the Unit 2 Banks and
The Chase Manhattan Bank (National Association) in its capacity
as collateral agent for the Unit 1 Banks and the Unit 2 Banks
(Exhibit 10(x)1) to Form 10-K of the Utility for the year ended
December 31, 1991, File No. 2-97230).
10(v)2 - Amendment No. 2, dated as of September 21, 1993, to the
Intercreditor and Nondisturbance Agreement among TGC, TGCII, the
Utility, the Unit 1 Banks, the Unit 2 Banks and The Chase
Manhattan Bank (National Association) in its capacity as
collateral agent for the Unit 1 Banks and the Unit 2 Banks
(Exhibit 10(v)2 to Form 10-K of the Utility for the year ended
December 31, 1993, File No. 2-97230).
10(w) - Grant of Reciprocal Easements and Declaration of Covenants
Running with the Land, dated as of the 1st day of October, 1988
between PFC and Texas PFC, Inc. (Exhibit 10(yyy) to Form 10-K
of the Utility for the year ended December 31, 1988, File No.
2-97230).
10(x) - Non-Partition Agreement, dated as of May 30, 1990, among the
Utility, TGC and The Chase Manhattan Bank (National
Association), as Agent for the Banks which are parties to the
Unit 1 Credit Agreement (Exhibit 10(ss) to Form 10-K for the
year ended December 31, 1990, File No. 1-8847).
10(y) - Assumption Agreement, dated July 26, 1991, to be effective as
of May 31, 1991, by TGCII in favor of the Issuing Bank, the Unit
2 Banks, the Unit 2 Agent and the Depositary, as defined therein
(Exhibit 10(kkk) to Amendment No. 1 to File No. 33-41903).
10(z) - Guaranty, dated July 26, 1991, to be effective as of May 31,
1991, by the Utility and given in respect of the TGCII
obligations under the Unit 2 Credit Agreement (Exhibit 10(lll)
to Amendment No. 1 to File No. 33-41903).
<PAGE 29>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(aa) - First Amended and Restated Facility Purchase Agreement, dated
as of January 8, 1992, among the Utility, as the Purchaser, and
TGCII, as the Seller, amending and restating the Facility
Purchase Agreement among such parties dated July 26, 1991, to
be effective as of May 31, 1991 (Exhibit 10(dd) to Form 10-K of
the Utility for the year ended December 31, 1991, File No. 2-
97230).
10(aa)1 - Amendment No. 1 to the Unit 2 First Amended
and Restated Facility Purchase Agreement,
dated as of September 21, 1993, among the
Utility, as the Purchaser, and TGCII, as the
Seller (Exhibit 10(aa)1 to Form 10-K of the
Utility for the year ended December 31, 1993,
File No. 2-97230).
10(bb) - Operating Agreement, dated July 26, 1991, to be effective as of
May 31, 1991, between the Utility and TGCII (Exhibit 10(nnn) to
Amendment No. 1 to File No. 33-41903).
10(cc) - Non-Partition Agreement, executed July 26, 1991, to be effective
as of May 31, 1991, among the Utility, TGCII and The Chase
Manhattan Bank (National Association) (Exhibit 10(ppp) to
Amendment No. 1 to File No. 33-41903).
Power Supply Contracts
10(dd) - Contract dated May 12, 1976 between the Utility and Houston
Lighting & Power Company (Exhibit 5(a), File No. 2-69353).
10(dd)1 - Amendment, dated January 4, 1989, to the
Contract dated May 12, 1976 between the
Utility and Houston Lighting & Power Company
(Exhibit 10(cccc) to Form 10-K of the Utility
for the year ended December 31, 1988, File No.
2-97230).
10(ee) - Contract dated May 1, 1986 between the Utility and Texas
Electric Utilities Company, amended September 29, 1986, October
24, 1986 and February 21, 1987 (Exhibit 10(c) of Form 8
applicable to Form 10-K of the Utility for the year ended
December 31, 1986, File No. 2-97230).
10(ff) - Amended and Restated Agreement for Electric Service dated May
14, 1990 between the Utility and Texas Utilities Electric
Company (Exhibit 10(vv) to Form 10-K for the year ended December
31, 1990, File No. 1-8847).
10(ff)1 - Amendment, dated April 19, 1993, to Amended
and Restated Agreement for Electric Service,
dated May 14, 1990, As Amended between the
Utility and Texas Utilities Electric Company
(Exhibit 10(ii)1 to Form S-2 Registration
Statement, filed on July 19, 1993, File No.
33-66232).
10(gg) - Contract dated June 11, 1984 between the Utility and
Southwestern Public Service Company (Exhibit 10(d) of Form 8
applicable to Form 10-K of the Utility for the year ended
December 31, 1986, File No. 2-97230).
<PAGE 30>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(hh) - Contract dated April 27, 1977 between the Utility and West Texas
Utilities Company amended April 14, 1982, April 19, 1983, May
18, 1984 and October 21, 1985 (Exhibit 10(e) of Form 8
applicable to Form 10-K of the Utility for the year ended
December 31, 1986, File No. 2-97230).
10(ii) - Contract dated April 29, 1987 between the Utility and El Paso
Electric Company (Exhibit 10(f) of Form 8 applicable to Form 10-
K of the Utility for the year ended December 31, 1986, File No.
2-97230).
10(jj) - Contract dated February 28, 1974, amended May 13, 1974, November
26, 1975, August 26, 1976 and October 7, 1980 between the
Utility and Public Service Company of New Mexico (Exhibit 10(g)
of Form 8 applicable to Form 10-K of the Utility for the year
ended December 31, 1986, File No. 2-97230).
10(jj)1 - Amendment, dated February 22, 1982, to the
Contract dated February 28, 1974, amended May
13, 1974, November 26, 1975, August 26, 1976,
and October 7, 1980 between the Utility and
Public Service Company of New Mexico (Exhibit
10(iiii) to Form 10-K of the Utility for the
year ended December 31, 1988, File No. 2-
97230).
10(jj)2 - Amendment, dated February 8, 1988, to the
Contract dated February 28, 1974, amended May
13, 1974, November 26, 1975, August 26, 1976,
and October 7, 1980 between the Utility and
Public Service Company of New Mexico (Exhibit
10(jjjj) to Form 10-K of the Utility for the
year ended December 31, 1988, File No. 2-
97230).
10(jj)3 - Amended and Restated Contract for Electric
Service, dated April 29, 1988, between the
Utility and Public Service Company of New
Mexico (Exhibit 10(zz)3 to Amendment No. 1 to
File No. 33-41903).
10(kk) - Contract dated December 8, 1981 between the Utility and
Southwestern Public Service Company amended December 12, 1984,
December 2, 1985 and December 19, 1986 (Exhibit 10(h) of Form
8 applicable to Form 10-K of the Utility for the year ended
December 31, 1986, File No. 2-97230).
10(kk)1 - Amendment, dated December 12, 1988, to the
Contract dated December 8, 1981 between the
Utility and Southwestern Public Service
Company amended December 12, 1984, December 2,
1985 and December 19, 1986 (Exhibit 10(llll)
to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
10(kk)2 - Amendment, dated December 12, 1990, to the
Contract dated December 8, 1981 between the
Utility and Southwestern Public Service
Company (Exhibit 19(t) to Form 10-K of the
Utility for the year ended December 31, 1990,
File No. 2-97230).
<PAGE 31>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(ll) - Contract dated August 31, 1983, between the Utility and Capitol
Cogeneration Company, Ltd. (including letter agreement dated
August 14, 1986) (Exhibit 10(i) of Form 8 applicable to Form
10-K of the Utility for the year ended December 31, 1986, File
No. 2-97230).
10(ll)1 - Agreement Substituting a Party, dated May 3,
1988, among Capitol Cogeneration Company,
Ltd., Clear Lake Cogeneration Limited
Partnership and the Utility (Exhibit 10(nnnn)
to Form 10-K of the Utility for the year ended
December 31, 1988, File No. 2-97230).
10(ll)2 - Letter Agreements, dated May 30, 1990 and
August 28, 1991, between Clear Lake
Cogeneration Limited Partnership and the
Utility (Exhibit 10(oo)2 to Form 10-K of the
Utility for the year ended December 31, 1992,
File No. 2-97230).
10(ll)3 - Notice of Extension Letter, dated August 31,
1992, between Clear Lake Cogeneration Limited
Partnership and the Utility (Exhibit 10(oo)3
to Form 10-K of the Utility for the year ended
December 31, 1992, File No. 2-97230).
10(ll)4 - Scheduling Agreement, dated September 15,
1992, between Clear Lake Cogeneration Limited
Partnership and the Utility (Exhibit 10(oo)4
to Form 10-K of the Utility for the year ended
December 31, 1992, File No. 2-97230).
10(mm) - Interconnection Agreement between the Utility and Plains
Electric Generation and Transmission Cooperative, Inc. dated
July 19, 1984 (Exhibit 10(j) of Form 8 applicable to Form 10-K
of the Utility for the year ended December 31, 1986, File No.
2-97230).
10(nn) - Interchange Agreement between the Utility and El Paso Electric
Company dated April 29, 1987 (Exhibit 10(l) of Form 8 applicable
to Form 10-K of the Utility for the year ended December 31,
1986, File No. 2-97230).
10(oo) - DC Terminal Participation Agreement between the Utility and El
Paso Electric Company dated December 8, 1981 amended April 29,
1987 (Exhibit 10(m) of Form 8 applicable to Form 10-K of the
Utility for the year ended December 31, 1986, File No. 2-97230).
Employment Contracts
10(pp) - Texas-New Mexico Power Company Executive Agreement for Severance
Compensation Upon Change in Control, executed November 11, 1993,
between Sector Vice President and Chief Financial Officer and
the Utility (Pursuant to Instruction 2 of Reg. 229.601(a),
accompanying this document is a schedule: (i) identifying
documents substantially identical to the document which have
been omitted from the Exhibits; and (ii) setting forth the
material details in which such omitted documents differ from the
document) (Exhibit 10(pp) to Form 10-K of the Utility for the
year ended December 31, 1993, File No. 2-97230).
<PAGE 32>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit
No. Description
10(qq) - Texas-New Mexico Power Company Key Employee Agreement for
Severance Compensation Upon Change in Control, executed November
11, 1993, between Assistant Treasurer and the Utility (Pursuant
to Instruction 2 of Reg. 229.601(a), accompanying this document
is a schedule: (i) identifying documents substantially identical
to the document which have been omitted from the Exhibits; and
(ii) setting forth the material details in which such omitted
documents differ from the document) (Exhibit 10(qq) to Form 10-K
of the Utility for the year ended December 31, 1993, File No.
2-97230).
10(rr) - Agreement between James M. Tarpley and the Company and the
Utility, effective January 1, 1994 (Exhibit 10(rr) to Form 10-K
of the Utility for the year ended December 31, 1993, File No.
2-97230).
10(ss) - Agreement between Dwight R. Spurlock and the Company and the
Utility, effective November 9, 1993 (Exhibit 10(ss) to Form 10-K
of the Utility for the year ended December 31, 1993, File No.
2-97230).
*13 - Annual Report to Shareholders for the year ended December 31,
1993.
*21 - Subsidiaries of the Registrant.
*23 - Independent Auditors' Consent - KPMG Peat Marwick.
<PAGE 33>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit 21
SUBSIDIARIES OF THE REGISTRANT
Name State of Incorporation
Texas-New Mexico Power Company Texas
Bayport Cogeneration, Inc. Texas
TNP Operating Company Texas
Each subsidiary of the Company conducts its business under its own name.
Texas-New Mexico Power Company has two wholly owned subsidiaries, Texas
Generating Company and Texas Generating Company II, each incorporated in
Texas.
<PAGE>
TNP ENTERPRISES, INC. FORM 10-K
Exhibit 23
Independent Auditors' Consent
The Board of Directors
TNP Enterprises, Inc.:
We consent to incorporation by reference in the Registration Statement (No.
2-93266) on Form S-3 and in the Registration Statement (No. 2-93265) on Form
S-8 of TNP Enterprises, Inc. of our report dated January 28, 1994, relating
to the consolidated balance sheets of TNP Enterprises, Inc. and subsidiaries
as of December 31, 1993 and 1992, and the related consolidated statements of
earnings, common stock equity and redeemable cumulative preferred stocks, and
cash flows and related schedules for each of the years in the three-year
period ended December 31, 1993, which report is incorporated by reference in
the December 31, 1993 annual report on Form 10-K of TNP Enterprises, Inc.
Our report includes an explanatory paragraph that states that uncertainties
exist with respect to the outcome of certain regulatory matters as discussed
in note 5 to the consolidated financial statements. The ultimate outcome of
these matters cannot presently be determined. Accordingly, no provision for
any loss that may ultimately be required upon resolution of these matters has
been made in the above consolidated financial statements.
As discussed in note 4 to the consolidated financial statements, the Company
changed its method of accounting for income taxes in 1993 to adopt the
provisions of the Financial Accounting Standards Board's Statement of
Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes.
As discussed in note 1(j), the Company also adopted the provisions of the
Financial Accounting Standards Board's SFAS No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions in 1993.
KPMG PEAT MARWICK
Fort Worth, Texas
March 22, 1994
TNP ENTERPRISES, INC. & SUBSIDIARIES
1993 ANNUAL REPORT
CONTENTS
To the Shareholders 2
Sources of Energy 4
Management's Discussion and Analysis of
Financial Condition and Results of Operations 6
Independent Audirots' Report 17
Consolidated Financial Statements 18
Selected Electric Operating Statistics 37
Common Stock Information 38
Directors and Officers 39
Shareholder Information 40
HIGHLIGHTS
<TABLE>
<CAPTION>
(Amounts in thousands - except as noted by *)
1993 1992 % Change
<S> <C> <C> <C>
Total operating revenues $ 474,242 443,827 6.9
Net earnings $ 11,605 10,930 6.2
Earnings available for common
stock $ 10,726 9,962 7.7
Weighted average number of
common shares outstanding 10,641 8,545 24.5
Earnings per share of
common stock* $ 1.01 1.17 (13.7)
Dividends per share of
common stock* $ 1.63 1.63 0.0
Net book value of
utility plant $1,005,995 1,015,709 (1.0)
Kilowatt-hour (KWH) sales 6,286,877 6,066,311 3.6
Average annual KWH sales per
residential customer* 11,362 11,003 3.3
Electric customers served
(year-end)* 211,911 208,897 1.4
Number of employees* 1,051 1,086 (3.2)
</TABLE>
CORPORATE PROFILE
TNP Enterprises, Inc. (Company), based in Fort Worth, Texas, is
the parent company of Texas-New Mexico Power Company (Utility).
Through the Utility, the Company's principal subsidiary, the
Company engages in the production, transmission and distribution
of electricity to residential, commercial and industrial
customers.
The Utility serves approximately 212,000 customers in its
four Texas divisions and its New Mexico division. Its service
areas are located in southeast Texas near Houston, north central
Texas in areas surrounding the Dallas-Fort Worth metroplex, the
northeast corner of the Texas Panhandle, west Texas in the
trans-Pecos region, and in southwest and south central New
Mexico.
[CENTERED IN PAGE ONE IS A TNP SERVICE AREA GRAPHIC MAP
COVERING THE STATES OF NEW MEXICO AND TEXAS]
Prior to 1990, the Utility purchased virtually all of its
energy requirements from wholesale third party generators. The
Utility reduced its dependence on such third party generators
when it acquired, through its subsidiaries, a two-unit,
300-megawatt, lignite-fired power plant in Robertson County,
Texas, in 1990 and 1991.
The plant, called TNP One, uses the circulating fluidized bed
technology to produce electricity. This environmentally superior
technology allows TNP One to burn Texas lignite, its primary
fuel, as well as Western coal, natural gas and petroleum coke.
The plant's clean-fuel technology and fuel flexibility will
provide benefits to the Utility's customers and the environment
for years to come.
At present, the Company's other two subsidiaries, Bayport
Cogeneration, Inc. and TNP Operating Company, are not involved in
any business activities.
<PAGE 1>
TO THE SHAREHOLDERS
1993 was a year of tough decisions, decisions requiring
management to concentrate on the requirements of our customers
while assuring the integrity of the Company for our shareholders.
For our customers, we took direct steps to add value to the
service we provide. For our shareholders, we executed a strategy
to stabilize the financing requirements and, for the long-term,
to improve the financial performance of TNP Enterprises, Inc.
(Company) and its principal subsidiary, Texas-New Mexico Power
Company (Utility).
Financial efforts influenced by regulatory actions
Our efforts to jointly address the interests of shareholders
and of customers continued to be negatively affected by
regulatory actions in Texas. During 1993, the Public Utility
Commission of Texas (PUCT) completed its Final Order proceedings
on the Utility's request to include the second unit of its
two-unit power plant, TNP One, in base rates. The PUCT granted a
rate increase of approximately $19 million, or 53% of the $35.8
million we had requested. We have appealed this decision to a
Texas district court.
The principal adverse effect of the PUCT's actions resulted
from its decision to abandon its long-standing method for
calculating the amount allowed in cost of service for Federal
income tax expense. The effect of this decision was a reduction
of approximately $7 million in annualized revenues. The PUCT
finally granted, subject to refund, $1.6 million of additional
annualized revenues, conditioned upon the Utility obtaining a
private letter ruling from the Internal Revenue Service
supporting the Utility's position on certain related tax
consequences. This issue is reviewed extensively in the notes to
consolidated financial statements in this report and is addressed
in Management's Discussion and Analysis of Financial Condition
and Results of Operations.
Despite adverse regulatory actions, we were able to improve
the debt structure of the Utility. We accomplished this by
issuing $240 million in new debt securities last September. The
proceeds were used primarily to discharge substantial portions of
the indebtedness incurred for the construction of each unit of
TNP One and, together with proceeds applied from prior securities
offerings, reduced to $147.75 million the original $633.5 million
amount of construction debt. This reduction, including a
significant prepayment of outstanding indebtedness under the Unit
2 financing facility, was an integral part of an agreement with
the lenders to extend the payment schedule for the remaining
balance of the construction debt. The extension allows
additional time for overall financial improvement, including
additional rate relief. We believe the end result was the
stabilizing of the financing requirements of the Utility for the
balance of the 1990s.
Earnings increase slightly
For 1993, earnings available for common stock increased 7.7%;
however, based upon the 24.5% increase of the weighted average
number of common shares outstanding for 1993, earnings per share
decreased to $1.01 in 1993 from $1.17 in 1992.
Total revenues for the year increased (6.9%), as did
kilowatt-hour sales (3.6%) and the number of customers served
(1.4%). These results were assisted by more typical weather
experienced in 1993 as compared to 1992.
Definition of "service" evolving
Our customer base has grown, and so have customer
expectations. To meet these expectations, our employees have
made a dedicated effort to go beyond the basic requirement of
providing a reliable source of electricity to our customers. An
example is our personalized energy service program directed to
assist customers in their more economical use of energy. During
the past year, this program involved our employees in
approximately 750 on-site audits for customers and over 6,000
direct mail energy audits.
During the past three years, several of our local billing
offices have been consolidated to increase operating efficiency,
but our local employee base remains a central part of our
commitment to customers. By our reliance upon employees who are
themselves part of the communities we serve, we believe we are in
a position to be more aware of our customers' expectations and to
more rapidly respond to their needs on a true neighbor-to-
neighbor basis. This is that "little bit extra" to which we
believe the customer is entitled, in addition to our creating
jobs and contributing to the tax revenues of our service areas.
<page 2>
We will continue to look at the dynamics of different
population centers for consolidation opportunities, but always
with the commitment of the Utility and our employees to remain a
meaningful part of the communities we serve.
TNP One reflects commitment to customers
The TNP One power plant is another example of our efforts to
exceed customer expectations. Recognizing that customers want
environmental accountability, we selected an innovative clean
fuel technology for the Utility's 300-megawatt lignite-fired
plant. In June, the National Environmental Development
Association awarded the plant its 1993 Honor Roll Award for the
selection and successful implementation of circulating-fluidized
bed technology. In 1993 TNP One was also honored to be among the
superior plants in the State based on nitrous oxide emissions.
The first unit of TNP One began commercial operation in
September 1990, and the second unit began commercial operation in
October 1991. Both units have exceeded their output
specifications. The two units produce approximately 30% of the
Utility's capacity requirements in Texas. The balance of our
customers' requirements are purchased pursuant to negotiated
contractual arrangements with third party generators.
Parties reach agreement in New Mexico rate application
In August 1993, the Utility filed an application to increase
its base rate revenues in New Mexico by $1.95 million, or 2.87%,
while being able to allow a decrease in overall annualized
revenues by $5.13 million for the ultimate benefit to its
customers.
In January 1994, a unanimous settlement was agreed upon by
all parties involved in the rate proceeding. Approval of the
settlement by the New Mexico Public Utility Commission would
effect an increase in the Utility's annual base rate revenues in
New Mexico by approximately $400,000, or 0.57%. In addition, as
a result of a scheduled decrease of approximately $7.1 million in
firm purchased power costs, New Mexico customers will receive a
net decrease in their overall rates. Because such a large part
of the total revenue requirements in the Utility's New Mexico
operations is related to the cost of purchased power, the
Utility's effort in contracting for lower costs of power is a
principal reason for the positive result for our customers.
Lowering of overall rates for customers while allowing the
Utility to recover its reasonable costs of providing service is a
prime example of the results we are striving to achieve for the
benefit of both our customers and our shareholders.
Pending approval of the settlement by the New Mexico Public
Utility Commission, the rates are expected to become effective
this spring.
Quarterly dividends paid to shareholders
Despite earnings that were not as high as we would have
preferred, the Company continued to pay quarterly dividends of
$0.4075 per share of common stock during 1993.
Employees' commitment
Your Company is committed to addressing the interests of both
customers and shareholders. We rely upon our employees as our
major resource to achieve this goal, and they continued to meet
these challenges with excellence during 1993, although with our
labor force reduced 3.2% from 1992 and without cost-of-living
wage increases in 1992 or 1993.
To our employees, our grateful acknowledgement of your
loyalty and achievements. And to our shareholders, our
appreciation for your support as we address the tasks at hand.
By Order of the Board of Directors
March 11, 1994
\s\ Dwight R. Spurlock
DWIGHT R. SPURLOCK
Interim President and
Chief Executive Officer
\s\ R. D. Woofter
R. D. WOOFTER
Chairman of the Board
<page 3>
SOURCES OF ENERGY
The Utility obtained its electric energy requirements during
the year ended December 31, 1993, from sources shown in the table
on the next page.
The Utility's future load growth is considered by the Utility
and its suppliers in planning their future construction
expenditures based on projections or official contract
notifications furnished to its suppliers by the Utility.
Currently the resources of TNP One and the suppliers
availability of lignite-, coal-, nuclear-, and gas-fired units
are adequate to assure projected requirements for power.
To the extent the Utility's suppliers experience delays or
increases in the costs of construction of new generating
facilities, additional costs of complying with regulatory and
environmental laws, or increases in the cost of fuel or shortages
in fuel supplies, the availability and cost of energy to the
Utility will likewise be affected for that portion of supply
purchased by the Utility. The Utility does not expect that the
factors discussed in this section will result in the inability of
its suppliers to provide the portions of power requirements to be
purchased by the Utility. The Utility expects to refund or
collect within two months or less those amounts of total
purchased power costs (including supplier fuel costs) billed to
the Utility from suppliers that are over- or under-collected in
the current month.
Terminations of service by those suppliers regulated by the
Federal Energy Regulatory Commission (El Paso Electric Company,
Southwestern Public Service Company, West Texas Utilities Company
and Public Service Company of New Mexico) would require
authorization by that commission. The Utility anticipates
renewing and amending its purchased power contracts with its
suppliers as necessary. As a result of the Utility's efforts in
contracting for lower costs of purchased power, the Utility's New
Mexico customers are expected to benefit from a scheduled
decrease of approximately $7.1 million in annualized firm
purchased power costs in 1994, the effect of which will be
reduced by a $400,000 increase in base rates.
In 1990 and 1991, the Utility commenced replacing portions of
its Texas purchased power requirements when Unit 1 and Unit 2,
respectively, became operational. Beginning in 1992, the full
effect of the electric generation of both units was realized.
Provisions in the contracts with Texas Utilities Electric Company
and Houston Lighting & Power Company allow for reductions in
future purchased power commitments.
Power generated at TNP One is transmitted over the Utility's
own transmission line to other utilities' transmission systems
for delivery to the Utility's Texas service area systems. To aid
in maintaining a reliable supply of power for its customers and
to coordinate interconnected operations, the Utility is a member
of the Electric Reliability Council of Texas (ERCOT), the Inland
Power Pool and the New Mexico Power Pool. See Management's
Discussion and Analysis of Financial Condition and Results of
Operations and notes 2 and 5 to the consolidated financial
statements for additional information about TNP One.
<page 4>
Sources of Energy
<TABLE>
<CAPTION>
Year of Percent
Contract of Energy Fuel
Sources* Area Served Expiration Required Source<S> <C>
TEXAS
Generation
TNP One Texas Gulf Coast, - 45.2% Texas Lignite
Central & (Western Coal,
Northern Texas Petroleum Coke &
Natural Gas Capabilities)
Purchased Power
Clear Lake Cogeneration Texas Gulf Coast 2004 23.5 Natural Gas
Limited Partnership (Oil Standby)
Texas Utilities Electric Company** Central, Northern 2006 & 22.7 Natural Gas, Lignite
(Subsidiary of Texas & West Texas 2010 & Nuclear
Utilities Company) (Oil Standby)
Houston Lighting & Power Texas Gulf Coast 2001 4.0 Natural Gas, Coal,
Company (Subsidiary of Lignite, Nuclear
Houston Industries, Inc.) & Cogeneration
(Oil Standby)
West Texas Utilities West Texas 2005 2.5 Natural Gas &
Company (Subsidiary Coal
of Central and South (Oil Standby)
West Corp.)
Southwestern Public Texas Panhandle 2005 2.1 Coal & Natural Gas
Service Company (Oil Standby)
Total 100.0%
NEW MEXICO
Purchased Power
El Paso Electric Southwest 2002 47.9% Coal, Natural Gas,
Company New Mexico Oil & Nuclear
Southwestern Public South Central 2001 22.2 Coal & Natural Gas
Service Company New Mexico (Oil Standby)
Public Service South Central & 2006 16.6 Coal, Natural Gas
Company of Southwest & Nuclear
New Mexico New Mexico (Oil Standby)
Other South Central & Various 13.3 Coal, Natural Gas,
Southwest Oil &
New Mexico Cogeneration
Total 100.0%
<FN>
* The Utility also has a continual contract with Union
Carbide to provide energy from natural gas sources for the Texas
Gulf Coast. This source did not contribute to the percent of
energy required in 1993.
** Except as to one point of delivery, a major source of supply
under the contract with an expiration date of 2010, the contract
expires in 2006.
</TABLE>
<page 5>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
This discussion presents management's analysis of
significant factors in the Company's financial condition and
results of operations and should be read in conjunction with the
consolidated financial statements and notes thereto.
The only business of the Company is conducted by the Utility.
The principal effects of nonutility activities on the
consolidated financial statements are from short-term
investments, certain tax benefits and issuance of the Company's
common stock.
The Utility and the Company currently face challenges to
their financial stability as a result of uncertainties with
respect to detrimental regulatory treatment and the servicing of
debt incurred for refinancings of both the Unit 1 and the Unit 2
financing facilities. These matters have arisen by reason of the
acquisition and operation by the Utility of TNP One, a two-unit,
300-megawatt, lignite-fueled, circulating fluidized bed
generating facility located in Robertson County, Texas, and the
related rate proceedings in Texas which disallowed recovery in
rates of certain costs of TNP One. While the outcome of certain
of these matters, and of other matters discussed below, cannot be
predicted, the Utility is vigorously pursuing their favorable
conclusion. The adverse resolution of certain of the matters
discussed below would require a write-off of some portion of the
disallowances and could result in a significant negative impact
on earnings in the period of final resolution. The following
discussion of certain regulatory proceedings related to TNP One
is essential to an analysis of the Company's financial condition
and results of operations.
FINANCIAL CONDITION
TNP One Generating Units and Related Regulatory Matters
Unit 1 and Unit 2 of TNP One each supply 150 megawatts and
together are providing, on an annualized basis, approximately 30%
of the Utility's electric capacity requirements in Texas. The
Utility operates the two units and sells the output of TNP One to
its Texas customers. Unit 1 began commercial operation on
September 12, 1990, and Unit 2 on October 16, 1991. As of
December 31, 1993, the costs of Unit 1 and Unit 2 were $357
million and $282.9 million, respectively. The costs of the two
units were funded principally by separate financing facilities.
PUCT Docket No. 9491
On February 7, 1991, in Docket No. 9491, the Public Utility
Commission of Texas (PUCT) approved an increase in annualized
revenues of approximately $36.7 million, or 67% of the Utility's
original $54.9 million rate request, primarily related to Unit 1.
The PUCT's final order allowed $298.5 million of the costs of
Unit 1 in rate base; however, the PUCT disallowed from rate base
$39.5 million of the requested investment costs of $338 million
for that unit. On appeal, a State district court overturned the
disallowances and ordered the case remanded to the PUCT for
further proceedings consistent with the court's judgment.
The Utility, the PUCT and certain intervenor cities (Cities)
appealed the State district court's judgment to a Texas Court of
Appeals. On August 25, 1993, the Court of Appeals rendered a
judgment partially reversing the State district court and
affirming the PUCT's disallowances for $30.4 million of the total
$39.5 million. The Court of Appeals remanded the cause to the
district court with instructions that the cause be remanded to
the PUCT for proceedings not inconsistent with the appellate
opinion. On September 9, 1993, the Utility, the Cities and the
PUCT filed motions for rehearing with the Court of Appeals. The
PUCT is not expected to act upon the district court's ordered
remand until the appellate process, including appeals to the
Texas Supreme Court, has been completed.
Based upon the opinions of the Utility's Texas regulatory
counsel, Johnson & Gibbs, a Professional Corporation, management
believes that it will prevail in obtaining a remand of a
significant portion of the disallowances in Docket No. 9491;
however, the ultimate disposition and quantification of these
items cannot presently be determined. Accordingly, no provision
for any loss that may ultimately be required upon resolution of
these matters has been made in the consolidated financial
statements.
If the Utility is not successful in obtaining a final
favorable disposition in the appellate proceedings relating to
the disallowances in Docket No. 9491, a write-off of some portion
of the $39.5 million disallowances would be required, which could
result in a significant negative impact on earnings in the period
of final resolution.
For a further discussion of Docket No. 9491, see note 5 to
the consolidated financial statements.
PUCT Docket No. 10200
On March 18, 1993, in Docket No. 10200, the PUCT approved an
increase in annualized revenues of $19 million, or 53% of the
Utility's original $35.8 million requested rate increase,
primarily related to Unit 2. The PUCT's order determined that
the reasonable costs for Unit 2 were $261.8 million. The PUCT
allowed in rate base $250.7 million of the $275.2 million
requested for Unit 2 costs. The difference between the $261.8
million in costs found to be prudent by the PUCT and the $282.9
million total costs of Unit 2 consisted of disallowances of
approximately $21.1 million. The PUCT also determined that $11.1
million of Unit 2 costs would be addressed in a future Texas rate
application. The PUCT also disallowed $800,000 of $16.1 million
in additional costs requested for Unit 1.
The revenue increase approved by the PUCT reflects
application to the Utility of a new method for calculating the
amount of Federal income tax expense allowed in cost of service,
which had the effect of reducing the allowed revenue
<page 6>
increase from $26 million to $19 million. The PUCT subsequently
approved collection by the Utility of an additional $1.6 million
in annualized revenues, subject to refund, on the condition that
the Utility seek and receive from the Internal Revenue Service
(IRS) a private letter ruling supporting the Utility's position
on "normalization" rules with respect to the PUCT order regarding
Federal income tax treatment for ratemaking purposes. After
receiving PUCT approval on October 19, 1993, the Utility filed,
on October 20, 1993, a request with the IRS for a private letter
ruling on the issue of a normalization violation. The Utility
expects to receive the private letter ruling in 1994. If the
private letter ruling supports the Utility's position, the amount
of revenues subject to refund ($3.4 million at December 31, 1993)
will be recognized in operations upon receipt of the letter.
The Docket No. 10200 rate order has been appealed to a Texas
district court by the Utility and other parties. Because of the
Court of Appeals judgment relating to the prudence of starting
construction of Unit 2 (Finding of Fact No. 84 in Docket No.
9491), the presiding judge in the Texas district court for the
Docket No. 10200 appeal has ordered that the procedural schedule
in this appeal be abated until final resolution of the Finding of
Fact No. 84 issue in Docket No. 9491. The Utility will
vigorously pursue reversal of the PUCT's new position regarding
Federal income tax expenses, in addition to seeking judicial
relief from the disallowances and certain other rulings by the
PUCT in Docket No. 10200. The opposing parties are seeking a
variety of relief to obtain lower rates and greater
disallowances, including overturning the basis of the Utility's
case as presented to the PUCT and sustaining the PUCT's adverse
Federal income tax position without regard to any IRS ruling on
the normalization issue.
Based upon the opinions of the Utility's Texas regulatory
counsel, Johnson & Gibbs, a Professional Corporation, management
believes that it will prevail in obtaining a remand of a
significant portion of the disallowances in Docket No. 10200;
however, the ultimate disposition and quantification of these
items cannot presently be determined. Accordingly, no provision
for any loss that may ultimately be required upon resolution of
these matters has been made in the consolidated financial
statements.
If the Utility is not successful in obtaining a final
favorable disposition in the appellate proceedings relating to
the disallowances in Docket No. 10200, a write-off of some
portion of the $21.9 million disallowances would be required,
which could result in a significant negative impact on earnings
in the period of final resolution.
For a further discussion of Docket No. 10200, see note 5 to
the consolidated financial statements.
Other TNP One Matters
In November 1987, the Utility entered into a fuel supply
agreement with Phillips Coal Company (Phillips), owner of a 300-
million-ton lignite reserve in Robertson County in proximity to
the TNP One site, to provide a lignite fuel source for the
38-year life of TNP One. Phillips subsequently entered into an
agreement with a subsidiary of Peter Kiewit Sons', Inc. for
development of the lignite mine by a joint venture partnership,
Walnut Creek Mining Company. Unit 1 and Unit 2 are capable of
utilizing Western coal, petroleum coke and natural gas as
alternative fuel sources.
New Mexico Rate Application
In August 1993, the Utility filed an application with the New
Mexico Public Utility Commission (NMPUC) to increase its base
rate revenues in New Mexico by $1.95 million, or 2.87%, and to
decrease overall its annualized revenues by $5.13 million.
On January 28, 1994, a unanimous settlement was executed by
all parties involved in the Utility's New Mexico rate
application. The settlement, if approved by the NMPUC, would
increase the Utility's annual base rate revenues in New Mexico by
approximately $400,000, or 0.57%. However, when a scheduled
decrease of approximately $7.1 million in firm purchased power
costs is considered with the $400,000 increase in base rates, the
Utility's customers will receive a net decrease in their overall
rates. The overall rate decrease is influenced by the fact that
a large part of the total revenue requirements in the Utility's
New Mexico operations is related to the cost of purchased power.
The settlement provides rates that have two very positive
aspects. First, it allows the Utility to recover through the
increase in base rates the current operating cost of providing
service to its customers in New Mexico including a reasonable
return on the Utility's investments. Second, it lowers the
overall rates charged to the Utility's New Mexico customers.
Subject to the successful completion of the proceedings before
the NMPUC on the settlement, the proposed rates would become
effective in the spring of 1994.
Consolidated Financial Condition
Nonutility operations did not substantially impact the
consolidated financial condition in 1993. Nonutility operations
from earlier periods allowed tax benefits in 1991 and in 1992 to
be carried back to those periods. The Company's capital
requirements are primarily those of the Utility as discussed
below in "Utility Financial Condition."
As a result of the assumption by the Utility of the financing
facilities for Unit 1 and Unit 2 in 1990 and 1991, respectively,
and related refinancings, the Company's capital structure
consisted of 75.2% debt, 23.7% common equity and 1.1% preferred
stock at December 31, 1993. Prior to 1990, the Company's capital
structure contained less than 50% debt. The Company's long-term
goal is to strive for an appropriate capital structure in line
with future business activities. (For capital structure ratios
for the years 1989 through 1993, see "Selected Annual
Consolidated Financial Data" elsewhere in this annual report.)
<page 7>
The preferred stock and the debt in the consolidated capital
structure were issued by the Utility. Although the Company has
the ability to issue both preferred stock and bonds, the Company
does not currently expect to issue either. Therefore, the
consolidated capital structure will be affected by the ability of
the Utility to obtain financing as discussed in "Utility
Financial Condition" and by the ability of the Company to issue
common stock. Since most of the assets, liabilities and earnings
capability of the Company are those of the Utility, the ability
of the Company to issue common stock and pay dividends will be
largely dependent upon the Utility's operations and the Utility's
restrictions regarding payment of its dividends as discussed in
"Capital Requirements" under "Utility Financial Condition."
The Company has a Shareholder Rights Plan designed to protect
the Company's shareholders from coercive takeover tactics and
inadequate or unfair takeover bids. See note 1(m) to the
consolidated financial statements.
Utility Financial Condition
Liquidity and Capital Resources
Unit 1 and Unit 2 Financing Facilities
The Unit 1 and Unit 2 financing facilities were originally
entered into by separate subsidiaries of a construction
consortium for the construction of Unit 1 and Unit 2 of TNP One.
The Unit 1 financing facility was assumed by Texas Generating
Company (TGC) on July 20, 1990. The Unit 2 financing facility
was assumed by Texas Generating Company II (TGC II) on July 26,
1991. TGC and TGC II are wholly owned subsidiaries of the
Utility.
As discussed further below, the balance of the secured notes
payable of the Unit 1 financing facility and a substantial amount
of loans under the Unit 2 financing facility were purchased or
prepaid on September 29, 1993 with proceeds from the issuance of
new debt securities. Such purchases and prepayments reduced the
amounts remaining to be repaid under the Unit 2 financing
facility to $147.75 million. Thereafter, the Utility made
additional unscheduled prepayments of approximately $69 million
under the Unit 2 financing facility; the Utility used existing
cash and a $15 million equity contribution from the Company to
make these additional prepayments. At December 31, 1993, the
Unit 2 financing facility balance was $78.8 million which
represents secured notes payable, consisting of a series of
renewable loans from various lenders in a financing syndicate.
In contemplation of the prepayments of the Unit 1 and Unit 2
financing facilities, the related credit agreements between the
secured lenders and the Utility were amended as of September 21,
1993 to facilitate the issuance of the secured debentures, due
2003, and to extend the maturities of the remaining loans from
due dates in 1994 and 1995. The effectiveness of the amendments
was contingent upon the application of net proceeds from the sale
of the secured debentures, due 2003, and the Series U Bonds. The
extension of the maturities of the remaining loans to be
outstanding under the Unit 2 financing facility has been approved
by the Federal Energy Regulatory Commission and is subject to
approval by the NMPUC. The Utility expects to receive the
necessary approval prior to June 30, 1994, as required by the
amendments. Upon the effective date of the extension, the
lenders will receive an extension fee of 1/4 of 1% on their
pro-rata share of the $147.75 million commitment. Based upon the
December 31, 1993 balance and assuming the approval of the
extensions of the maturities under the Unit 2 financing facility,
$1.6 million will be due on December 31, 1995, $3.4 million will
be due on December 31, 1996, with the remaining amounts due in
two equal installments of approximately $36.9 million on December
31, 1997 and 1998.
Under the amendments to the Unit 2 credit agreement, the
Utility is permitted to prepay up to $141.5 million of the
$147.75 million commitment under the Unit 2 financing facility
and reborrow thereunder up to the amount of such prepayments,
subject to scheduled reductions of the commitment of
approximately $36.9 million each in 1996, 1997 and 1998. Such
reborrowings under the Unit 2 financing facility will be subject
to compliance with the EBIT test (as described in note 2 to the
consolidated financial statements) and maintenance of an equity
to total capital ratio of 20% or more as defined in the credit
agreement. As of December 31, 1993, the unused commitment
available to be borrowed under the Unit 2 financing facility was
approximately $69 million. A commitment fee of 1/4 of 1% per
annum is payable on the unused portion of the reducing
commitment.
The Utility expects to file, during the first half of 1994, a
Texas application requesting an increase in annualized revenues.
If the Utility receives satisfactory results from the
application, the Utility expects to be able to repay the
remaining amount due under the Unit 2 financing facility through
receipt of common equity from the Company, internal cash
generation and issuance of debt. See "Capital Resources" below
for a discussion of the Utility's external sources for acquiring
capital.
Issuance of New Debt Securities
On September 29, 1993, the Utility issued $100,000,000 of
9.25% First Mortgage Bonds, Series U (New Bonds), due 2000, and
$140,000,000 of 10.75% Secured Debentures, Series A, due 2003.
Net proceeds from the issuance of the new securities and
existing cash were applied as follows: (i) $21.78 million to call
the aggregate principal amount, including redemption premiums, of
Series H, I, J and K First Mortgage Bonds, (ii) $9.14 million to
reimburse the Utility's treasury for funds used to redeem Series
G First Mortgage Bonds at maturity on July 1, 1993, (iii) $146
million to prepay or purchase all of the outstanding secured
notes payable to lenders under the Unit 1 financing facility and
(iv) $75.75 million to prepay secured
<page 8>
notes payable under the Unit 2 financing facility. Redemption of
Series H, I, J and K First Mortgage Bonds was necessary to permit
the issuance of the $100,000,000 in New Bonds because of certain
restrictions under the Utility's first mortgage bond indenture
(Bond Indenture), as discussed below.
Supplemental indentures relating to Series H, I, J and K
First Mortgage Bonds contained a requirement that Net Earnings
Available for Interest of the Utility for 12 consecutive months
out of the preceding 15 months be at least two-and-one-half (2.5)
times the aggregate amount of annual Interest Charges on Bonded
Indebtedness which gives effect to the interest on the additional
Bonds to be issued (the Interest Coverage Ratio). Under the 2.5
times Interest Coverage Ratio required for issuance of additional
First Mortgage Bonds, only a minimal amount of additional First
Mortgage Bonds could have been issued. Under the supplemental
indentures for the series of Bonds outstanding after the deposit
of proceeds from the offering of the new securities for the
redemption of Series H, I, J and K Bonds, the Interest Coverage
Ratio was reduced to two (2) times.
Capital Requirements
The Utility's 1993 capital requirements consisted of (1)
additions to utility plant and (2) bond sinking fund payments and
maturities and preferred stock redemptions. The Utility's cash
flows from operations for 1993 were reduced by an $18 million
rate refund to the appropriate Texas customers. The refund,
discussed in note 5 to the consolidated financial statements, was
related to the period from October 1991 through April 1993,
during which customers were billed at bonded rates which exceeded
the finally authorized rates. During 1993, the Utility's capital
requirements were funded with cash flows from operations (after
payment of cash dividends on common and preferred stock),
excluding the rate refund funded from existing cash. Due to the
seasonal nature of the Utility's business, cash flows from
operations may fluctuate between quarters, but the Utility
expects positive cash flows from operations on an annual basis.
During the period from January 1, 1994 to December 31, 1999,
the Utility currently estimates that its total debt and preferred
stock repayments will be $349.4 million. This amount includes
the repayments in 1995, 1996, 1997 and 1998 in discharge of the
$78.8 million balance outstanding under the Unit 2 financing
facility at December 31, 1993. In addition, the Utility expects
its utility plant additions to be approximately $180.9 million
during the period from January 1, 1994 to December 31, 1999. The
Utility expects the requirements for utility plant additions will
be funded internally with cash flows from operations. The
amounts and types of the foregoing requirements through 1999,
after giving effect to the extensions under the Unit 2 financing
facility, assuming pending regulatory approval, are estimated as
follows:
<TABLE>
<CAPTION>
Capital Requirements (1)
1994 1995 1996 1997 1998 1999 Total
(Dollars in Millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Preferred stock redemptions $ 0.9 0.9 0.8 0.6 0.6 0.2 4.0
Unit 2 financing facility (2) - 1.6 3.4 36.9 36.9 - 78.8
First Mortgage Bond sinking
fund payments and retirements 1.1 1.1 1.1 131.1 1.1 1.1 136.6
Secured Debentures,
due 1999 maturity. . . . . - - - - - 130.0 130.0
Total debt and preferred
stock repayments. . . . . 2.0 3.6 5.3 168.6 38.6 131.3 349.4
Utility plant additions . . 25.9 28.3 32.7 30.4 31.5 32.1 180.9
Total capital requirements $27.9 31.9 38.0 199.0 70.1 163.4 530.3
<FN>
(1) See note 2 to the consolidated financial statements for details of
the maturities of all outstanding debt.
(2) Based upon the balance outstanding at December 31, 1993.
</TABLE>
<page 9>
Included in the First Mortgage Bond sinking fund payments and
retirements amount for 1997 is $130 million of First Mortgage
Bonds, Series T, which mature January 15, 1997. The Utility
anticipates that it will refinance these bonds and the Secured
Debentures due in 1999 through the issuance of additional First
Mortgage Bonds or other debt securities, and/or the receipt of
common equity from the Company. The Utility does not need
additional Available Additions (described below under "Capital
Resources") in order to issue First Mortgage Bonds for the
purpose of refunding outstanding First Mortgage Bonds.
As a result of the assumption by the Utility of the financing
facilities for Unit 1 and Unit 2 in 1990 and 1991, respectively,
and related refinancings, the Utility's capital structure
consisted of 75.2% debt, 23.7% common equity and 1.1% preferred
stock at December 31, 1993. Prior to 1990, the Utility's capital
structure contained less than 50% debt. The Utility's long-term
goal is to strive for a conservative capital structure with a
debt ratio of less than 50%.
Capital Resources
At any time, the Utility's ability to access the capital
markets on a reasonable basis or otherwise obtain needed
financing for operating and capital requirements is subject to
the receipt of adequate and timely regulatory relief and market
conditions. The Utility's ability to access the capital markets
at reasonable costs will specifically be impacted by the ultimate
resolution of (1) the amount of rate relief granted for Unit 1
and Unit 2, (2) the contested disallowances of up to $40.3
million and $21.1 million of the costs of Unit 1 and Unit 2,
respectively, and (3) the adverse PUCT ruling concerning the
treatment of the Federal income tax component of the Utility's
cost of service.
In addition to the aforementioned Unit 2 financing facility,
the Utility's external sources for acquiring capital are outlined
below:
First Mortgage Bonds. Assuming an interest rate of 9.25% and
satisfactory market conditions, based upon December 31, 1993
financial information, the Utility could have issued
approximately $59 million of additional First Mortgage Bonds
under the Interest Coverage Ratio requirement. With certain
exceptions, the amount of additional First Mortgage Bonds that
may be issued is also limited by the Bond Indenture to a certain
amount of physical properties which are to be collateralized by
the first lien mortgage of the Bond Indenture (Available
Additions). Because of the issuance of the New Bonds in
September 1993, the Utility has limited ability to issue
additional First Mortgage Bonds until more Available Additions
are provided upon further repayment of amounts under the
financing facilities.
Secured Debentures. The indenture, under which the Series A
Secured Debentures were issued, permits, generally, the issuance
of additional secured debentures to the extent that the proceeds
from such issuance are used to purchase an equal amount of loans
under the Unit 1 and Unit 2 financing facilities.
Preferred Stock. Due to interest and dividend coverage tests
required for issuance of its preferred stock, the Utility cannot
presently issue any preferred stock. The Utility does not expect
to have the ability to issue preferred stock through 1996.
Receipt of Common Equity. One source for repayment of the
Unit 2 financing facility is anticipated to be the receipt of
common equity from the Company. Receipt of future equity
contributions by the Utility from the Company will be largely
dependent upon the Company's ability to issue common stock.
Since most of the assets, liabilities and earnings capability of
the Company are those of the Utility, the ability of the Company
to issue common stock and pay dividends will be largely dependent
upon the Utility's operations and the Utility's restrictions
regarding payment of cash dividends on its common stock.
The Utility may not pay dividends on its common stock unless
all past and current dividends on outstanding preferred stock of
the Utility have been paid or declared and set apart for payment
and all requisite sinking or purchase fund obligations for the
preferred stock of the Utility have been fulfilled. Charter
provisions relating to the preferred stock and the Bond Indenture
under which First Mortgage Bonds are issued contain restrictions
regarding the retained earnings of the Utility. At December 31,
1993, pursuant to the terms of the Bond Indenture, approximately
$12.8 million of the Utility's $38.9 million of retained earnings
was restricted. In addition, the financing facilities place
certain restrictions on the Utility's ability to pay dividends on
its common stock, unless certain threshold tests are met. The
Utility has satisfied the threshold tests since they became
effective, and the Utility does not expect that any of the
aforementioned contractual restrictions on the payment of
dividends will become operative in 1994. However, the Utility
can give no assurance that the Utility will satisfy such tests in
the future.
The Utility's 1993 common stock dividends of $17.3 million
exceeded 1993 earnings available for common stock of $10.6
million; however, the Utility's retained earnings were sufficient
to allow the dividends to be paid. Contributing to the low-level
of earnings in 1993 were the lower rates from the December 1992
adverse ruling of the PUCT regarding the Utility's Federal income
tax component in its cost of service and significant interest
charges.
As discussed in "Net Earnings" under "Results of Operations",
management has implemented cost saving measures during 1993 and
is seeking equitable regulatory treatment in efforts to improve
future results of operations. Cash dividend payments are subject
to approval of the Board of Directors and are dependent,
especially in the longer term, on the Utility's and the Company's
future financial condition and adequate and timely regulatory
relief, including favorable resolution of pending judicial
appeals of rate cases.
<page 10>
Other Matters
Accounting for Postretirement Benefits
On January 1, 1993, the Utility implemented Statement of
Financial Accounting Standards No. 106 (SFAS 106), "Employers'
Accounting for Postretirement Benefits Other Than Pensions,"
which addresses the accounting for other postretirement employee
benefits (OPEBs). For the Utility, OPEBs are comprised primarily
of health care and death benefits for retired employees. Prior
to 1993, the costs of these OPEBs were expensed on a
"pay-as-you-go" basis. Beginning in 1993, SFAS 106 requires a
change from the "pay-as-you- go" basis to the accrual basis of
recognizing the costs of OPEBs during the periods that employees
render service to earn the benefits. The 1993 accrual for OPEBs
of $2,952,000, based on adoption of SFAS 106, was $2,276,000
greater than the amount that would have been recorded under the
"pay-as-you-go" basis.
In March 1993, the PUCT issued its rules for ratemaking
treatment of OPEBs. As part of a general rate case, a utility
may request OPEBs expense in cost of service for ratemaking
purposes on an accrual basis in accordance with generally
accepted accounting principles. The PUCT's rule requires that
the amounts included in rates shall be placed in an irrevocable
external trust fund dedicated to the payment of OPEBs expenses.
Based on the PUCT's rule, the Utility intends to seek recovery of
OPEBs expense attributable to its Texas jurisdiction in its next
Texas rate case.
In order to comply with the PUCT's condition for possible
recovery of OPEBs expenses, the Utility established in June 1993
a Voluntary Employees' Beneficiary Association (VEBA) trust fund,
dedicated to the payment of OPEBs expenses. Monthly cash
payments made to the VEBA, which began in June 1993, will fund
OPEBs costs for the Utility's Texas and New Mexico operations.
See note 1(j) to the consolidated financial statements for
information about the funded status of the plan.
On August 23, 1993, the Utility filed a rate application with
the NMPUC which included a request for recovery of the applicable
costs of OPEBs. A stipulated agreement among the parties to the
proceeding, dated January 28, 1994, subject to approval by the
NMPUC, would include such applicable costs in the proposed New
Mexico rates, beginning in 1994.
For future periods, the costs of OPEBs will be affected by
changes in the assumed interest rate and the trends in health
care costs; based on actuarial assumptions, national health care
costs are expected to increase in the future, resulting in
further increases in the Utility's costs.
Accounting for Income Taxes
On January 1, 1993, the Company implemented Statement of
Financial Accounting Standards No. 109 (SFAS 109), "Accounting
for Income Taxes." The implementation of SFAS 109 did not
result in any significant charge to operations. See note 4 to
the consolidated financial statements for details relating to the
implementation of SFAS 109.
Accounting for Postemployment Benefits
The FASB has issued Statement of Financial Accounting
Standards No. 112 (SFAS 112), "Employers' Accounting for
Postemployment Benefits" which addresses the accounting and
reporting for the estimated costs of benefits provided by an
employer to former or inactive employees after employment but
before retirement. SFAS 112 is effective for fiscal years
beginning after December 15, 1993. The Utility estimates such
costs to be immaterial.
Effects of Inflation
The Company does not believe that the effects of inflation,
as measured by the Consumer Price Index over the last three
years, have had a material impact on the Company's consolidated
results of operations and financial condition.
Tax Law Change
The Omnibus Budget Reconciliation Act of 1993 was signed into
law on August 10, 1993. Beginning in 1994, the act provides for
the disallowance of certain business deductions, the effect of
which is not expected to be material for the Company. The act
also provided, effective January 1, 1993, for a corporate income
tax rate increase from 34% to 35% to be phased in for taxable
income between $10 million and $18 million.
<page 11>
RESULTS OF OPERATIONS
Consolidated
The Company and its subsidiaries, the Utility, Bayport
Cogeneration, Inc. and TNP Operating Company, combined to produce
consolidated earnings available for common stock and earnings per
share of common stock for each of the years shown as follows:
1993 1992 1991
Earnings Available for
Common Stock (In Thousands)
Utility operations $10,644 9,877 18,762
Nonutility operations 82 85 (307)
Total $10,726 9,962 18,455
Earnings Per Share of
Common Stock
Utility operations $ 1.00 1.16 2.27
Nonutility operations .01 .01 (.04)
Total $ 1.01 1.17 2.23
The following table sets forth the percentage relationship of
items to operating revenues in the consolidated statements of
earnings:
1993 1992 1991
Operating revenues 100.0% 100.0 100.0
Operating expenses:
Power purchased for resale 42.2 39.3 49.1
Fuel 9.4 10.1 5.8
Other operating and
general expenses 14.6 15.8 14.8
Maintenance 2.4 2.6 2.5
Depreciation of utility plant 7.6 7.9 6.4
Taxes, other than on income 6.4 6.6 5.4
Income taxes 0.9 0.4 1.8
Total operating expenses 83.5 82.7 85.8
Net operating income 16.5 17.3 14.2
Other income, net of taxes 0.2 0.6 0.1
Earnings before interest
charges 16.7 17.9 14.3
Total interest charges 14.3 15.4 9.9
Net earnings 2.4% 2.5 4.4
Utility Operations
Operating Revenues
Operating revenues for 1993 and 1992 reflect increases of
$30,415,000 and $2,484,000 over the respective prior years. The
following table presents the components of the changes in
operating revenues:
Increase (Decrease) From Prior Year
1993 1992
(Dollars In Thousands)
Base operating revenues $(1,515) (0.3)% $35,785 8.1%
Recovery of purchased
power costs 25,926 5.8 (42,561) (9.6)
Recovery of fuel costs (1,230) (0.3) 19,204 4.4
Customer usage 8,291 1.9 (11,746) (2.7)
Other revenues (1,057) (0.2) 1,802 0.4
Total $ 30,415 6.9% $ 2,484 0.6%
Base operating revenues are affected primarily by changes in
base rates resulting from regulatory commission orders and the
effects of variations in sales between customer classifications.
The significant increase in base operating revenues for 1992
was primarily attributable to bonded rates for Docket No. 10200
being placed into effect in October 1991. The PUCT's final order
approving these rates was received on October 16, 1992 and
subsequently was amended by the PUCT in an Order on Rehearing on
December 22, 1992. The result of this Order on Rehearing was to
lower the previously approved increase in annualized revenues by
approximately $7 million, from $26 million to approximately $19
million. The PUCT later increased, subject to refund, the
annualized revenues by an additional $1.6 million. Because the
increase continued to be subject to a possible refund, no
additional revenues were recognized in 1992 or 1993 and such
amounts were included in revenues subject to refund in the
consolidated balance sheets. For more information regarding
Docket No. 10200, see note 5 to the consolidated financial
statements.
Purchased power costs are recovered through cost recovery
factor clauses in both Texas and New Mexico. Fuel costs are
recovered through a fixed fuel factor approved by the PUCT.
Recoveries of purchased power and fuel costs are discussed
further in "Operating Expenses."
Customer usage increased in 1993 due to a 3.6% increase in
kilowatt-hour (KWH) sales to residential, commercial and
industrial customers. The residential usage increase related to
an increase in the number of residential customers and warmer
temperatures in the Texas service areas; in 1992, milder than
normal weather was experienced in the Texas service areas.
Commercial usage increased in the Utility's Texas service areas
as the result of general retail development in the Northern
Division and Southeast Division and the addition of a greyhound
race track in the Southeast Division. During 1993, the number of
industrial customers decreased by 14, but that
<page 12>
decrease included the consolidation of 10 customers into 2
customers for billing purposes and the reclassification of 3
customers to the commercial class of customers. The industrial
usage increase in the Utility's New Mexico service area resulted
from increased consumption of an existing mining customer and the
addition of a new mining customer.
The 1992 decrease in customer usage primarily reflected a
5.46% KWH sales decline. Part of the decrease in customer usage
was attributable to the milder than normal temperatures
experienced in Texas during 1992. Also contributing to the sales
decline was the failure of new customers and revenues to
materialize as expected within the industrial class to ameliorate
the loss of KWH sales to certain industrial customers.
From time to time, industrial customers of the Utility
express interest in cogeneration as a method of reducing or
eliminating reliance upon the Utility as a source of electric
service, or to lower fuel costs and improve operating efficiency
of process steam generation. During 1993, a major industrial
customer in the Utility's Southeast Division requested proposals
for a cogeneration project for evaluation by the customer. The
Utility's operating revenues from this customer during 1993 were
approximately $28 million. In January 1994, a potential
developer for the proposed project was selected by the customer.
The Utility's goal is to retain this customer and to lower
overall system operating costs through coordination with the
potential developer. Although the Utility cannot predict the
ultimate outcome of the process, the current project as proposed
by the customer, and as outlined by the potential developer,
appears to present a means by which the Utility may retain
electric service to this customer, at current levels. The
Utility is actively pursuing the development of the necessary
agreements with the potential developer to further define the
degree to which electric service to this customer is retained and
overall system operating costs may be lowered.
For information relating to actual KWH sales, number of
customers, and revenues, see "Selected Electric Operating
Statistics" elsewhere in this report.
Operating Expenses
As a regulated entity, the Utility must demonstrate to the
regulatory commissions in its rate filings that its requests for
recovery of operating expenses to provide service to its
customers are reasonable and necessary. In order to provide
reliable service to its customers at reasonable rates, management
endeavors to control costs through budgeting and monitoring of
operating expenses.
Commencement of commercial operations of Unit 1 in September
1990 and Unit 2 in October 1991 led to increases in certain
expenses and interest charges over prior years; however, the
Utility experienced decreases in the potential cost of power
purchased for resale as a result of the operations of Unit 1 and
Unit 2. The 1993 and 1992 levels of expenses each reflect a full
year's operations of both units. Variances in expenses from 1991
to 1992 due to a partial year's operation of Unit 2 in 1991 are
noted in the following discussion.
Power Purchased for Resale
Factors affecting the expense of power purchased for resale
are (1) the number of KWH purchased from suppliers, (2) the cost
per KWH purchased, (3) the recovery or refund of prior under- or
over-collections, respectively, of purchased power costs
(deferred purchased power costs), and (4) occasional fuel cost
refunds from the Utility's suppliers. The Utility's policy
regarding the accounting for deferred purchased power costs is
discussed in note 1(g) to the consolidated financial statements.
Power purchased for resale increased $25,926,000 in 1993, and
a decrease of $42,561,000 was experienced in 1992. The increase
in purchased power expense for 1993 was mainly due to an increase
in the average cost of KWH purchased from suppliers. Information
concerning the Utility's suppliers is disclosed in "Sources of
Energy," elsewhere in this report. Also contributing to the
increase in 1993 was an increase in the number of KWH purchased
as a result of increased customer usage, discussed under
"Operating Revenues." The decrease in 1992 resulted from a
decline in the number of KWH purchased. This KWH decrease was
caused by the replacement of purchased power with a full year's
generation of Unit 2 of TNP One and the decrease in customer
usage, discussed under "Operating Revenues." Partially
offsetting the effect of this reduction in the number of KWH
purchased in 1992 was an increase in the recovery of deferred
purchased power costs.
As in 1992, the 1993 level of KWH purchases reflects a full
year's generation of TNP One; therefore, KWH purchases for 1993
and 1992 are comparable in this respect. No significant changes
in KWH purchased resulting from TNP One's operations are expected
in the future.
While costs per KWH from purchased power suppliers are not
directly controllable, wholesale rates charged by various
suppliers are subject to regulatory authority. The Utility has
intervened and will continue to intervene in suppliers rate
cases for the purpose of assuring fair and equitable costs to its
customers.
Fuel
Fuel expense decreased $629,000 in 1993, as compared to an
increase of $19,204,000 in 1992.
The decrease in recovery of fuel costs for 1993 resulted from
a slightly lower fuel cost recovery factor than that utilized in
1992. These differing fuel factors resulted from using a factor
related to bonded rates in 1992 which was adjusted downward in
1993 to comply with the final order in Docket No. 10200. The
large increase in 1992 was related to a full year's commercial
operation of both Unit 1 and Unit 2.
Fuel expense primarily represents the recovery of fuel costs
through a fixed fuel factor set by the PUCT. The fixed fuel
factor is intended to permit the Utility to recover the cost of
<page 13>
fuel utilized to generate electricity sold in Texas. The factor
may be changed only upon approval of the PUCT and is expected to
be adjusted for any cumulative under- or over-recovery of fuel
costs. At December 31, 1993, the Utility had under-recovered
fuel costs, including interest, of approximately $13.6 million
related to both units of TNP One. Any requests to the PUCT for
recovery of fuel costs require the Utility's demonstration that
the costs were reasonable.
Beginning in 1993, a filing with the PUCT for a
reconciliation of fuel costs is required if for any given period
of time there is an over-or under-recovery of fuel costs of at
least 4% of revenues. Under the PUCT's rules, the months in
which utilities may initiate fuel reconciliation proceedings are
specified; for the Utility, these months are June and December.
In the event of an over- or under-recovery of fuel costs less
than the 4% threshold, a filing to adjust the fuel factor may be
made at the discretion of management. The Utility expects to
file a fuel reconciliation with its next Texas rate application
during the first half of 1994. Management will continue to
monitor its fuel cost recovery to determine the need to request a
change in its fixed fuel factor. For a discussion of the fuel
supply agreement for TNP One, see "Other TNP One Matters" under
"Financial Condition."
Other Operating and General Expenses and Maintenance
Other operating and general expenses decreased $597,000 in
1993 after an increase of $4,716,000 in 1992. The 1993 decrease
represents primarily decreases in employee pension and thrift
benefits and payroll costs which were offset somewhat by an
increase in employee postretirement medical costs resulting from
implementation of SFAS 106. The decrease in the employee
benefits for 1993 was due to an amendment to the pension plan and
the curtailment of employer thrift plan contributions on January
1, 1993. Payroll costs declined due to a 3.2% reduction in the
number of employees.
The increase in other operating and general expenses for 1992
was due primarily to additional wheeling costs which were
incurred for a full year's transfer of power generated by Unit 2
and to amortization of previously deferred rate case expenses.
Wheeling costs are incurred for the transfer of TNP One power
over other utilities' transmission systems for delivery to the
Utility's Texas systems. The years 1993 and 1992 reflected
wheeling costs for both Unit 1 and Unit 2; therefore, any future
changes in this level of expense would be the result of changes
in monthly wheeling charges. Regarding deferred rate case
expenses, a full year's amortization was reflected in both 1993
and 1992, making them comparable in this respect; in 1994,
another year's amortization remains for the deferred rate case
expenses.
As previously discussed under "Financial Condition,"
implementation of SFAS 106 may lead to additional costs in the
future. Other operating and general expenses will be affected in
1994 because of a 3% cost-of-living payroll adjustment for
full-time employees effective January 10, and the restoration of
employer thrift plan contributions scheduled to resume beginning
July 1. Since the last cost-of-living payroll adjustment granted
to the Utility's employees was in 1991, these changes were made
to maintain the level of experienced personnel necessary for
providing quality service to the Utility's customers.
No significant variances have occurred in maintenance expense
over the last three years. Maintenance outages are scheduled in
the first and fourth quarters of 1994 for Unit 2 and Unit 1,
respectively. Since prior years reflect expenses for past
scheduled outages of the units, no significant increase in
maintenance expense is anticipated in 1994.
Depreciation of Utility Plant
Depreciation expense increased $917,000 and $7,071,000 in
1993 and 1992, respectively. The 1993 increase was related to
normal additions to utility plant while the large increase in
1992 reflects a full year's expense for Unit 2 and Unit 1.
Future increases in depreciation would be the result of normal
utility plant additions and regulatory approvals of changes in
depreciation rates as supported by required periodic independent
studies.
Taxes, Other Than On Income
Taxes, other than on income increased $1,046,000 and
$5,462,000 in 1993 and 1992, respectively. The 1993 increase
related primarily to an increase in revenue-related taxes which
resulted from increased revenues upon which the taxes are based.
The increase in 1992 was primarily related to an increase in
property-related taxes resulting from (1) a full year's expense
related to Unit 2 as compared to only a partial year in 1991 and
(2) increases in the property tax rates in Texas.
Income Taxes
Income taxes increased $2,397,000 in 1993 after a decrease of
$5,963,000 in 1992. The increase in 1993 resulted from an
increase in earnings over 1992, a decline in the
regulatory-ordered amortization of excess deferred taxes, and an
increase in Federal income tax rates. Income taxes decreased in
1992 due to the decline in net earnings compared to 1991. For
the years 1993, 1992 and 1991, the Utility incurred tax net
operating losses due to accelerated tax depreciation deductions
and increased interest charges on debt related to TNP One and
subsequent refinancings; however, payments of current income
taxes were required based on minimum tax (MT) requirements. To
the extent that the Utility is subject to MT requirements and
limitations on the utilization of available credits, payments of
current Federal income taxes are expected to be required in 1994.
As discussed in "Accounting for Income Taxes" under
"Financial Condition," implementation of SFAS 109 did not result
in any significant charge to earnings. For information regarding
the Company's income taxes, see note 4 to the consolidated
financial statements.
<page 14>
As with all areas of the Utility's cost of service, recovery
of income tax expenses is expected in rates charged to customers.
However, as discussed in "PUCT Docket No. 10200" under "Financial
Condition," uncertainties exist with respect to the Utility's
Federal income tax expense component of cost of service. The
Utility is pursuing reversal of the PUCT's adverse decisions.
Other Income, Net of Taxes
The Utility's contribution to other income, net of taxes
increased in 1992 by $1,290,000 primarily because of interest
earned on short-term investments, principally repurchase
agreements and government money trusts, during the year.
Considerable cash was used in 1993 to make optional payments
under the Unit 2 financing facility thereby reducing cash
available for the aforementioned investments. This contributed
to the decrease of $901,000 in 1993. (For a discussion of
nonutility operations contribution to other income, see
"Nonutility Operations.")
Interest Charges
Total interest charges decreased slightly by $342,000 in 1993
after an increase of $24,723,000 in 1992.
The slight decrease in interest on long-term debt in 1993 was
the net result of several transactions. Decreases in 1993
expense resulted from (1) redemption of Series G First Mortgage
Bonds at maturity on July 1, 1993, (2) redemption of Series H, I,
J and K First Mortgage Bonds to permit issuance of Series U First
Mortgage Bonds and (3) prepayments made under the Unit 1 and Unit
2 financing facilities. Partially offsetting these decreases in
interest on long-term debt were the issuances of Series U First
Mortgage Bonds and Series A Secured Debentures in September 1993.
Interest on long-term debt increased in 1992 due to the
issuance in January 1992 of $130 million of 11.25% Series T First
Mortgage Bonds and $130 million of 12.50% Secured Debentures, due
in 1999. The Utility used $194 million of the proceeds from the
issuance to retire a portion of the Unit 1 and Unit 2 financing
facilities, as was required for extended payment dates under the
amended terms of the financing facilities. The notes payable
under the financing facilities had lower interest rates than the
new securities. Interest charges also increased in 1992 due to
the debt for Unit 2 being outstanding for a full year as compared
to a partial year in 1991.
In 1994, the full effects of the 1993 redemptions and new
issuances are expected to result in a net increase in interest on
long-term debt. Any changes in the interest rates or balances
related to the Unit 2 financing facility in 1994 will also have
an effect on long-term debt interest.
Other interest and amortization of debt discount, premium and
expense for 1993 reflects a fourth quarter amortization of debt
expense associated with the issuances of Series U Bonds and
Series A Secured Debentures and further amendments to the Unit 1
and Unit 2 financing facilities; therefore, an increase in this
expense can be expected in 1994 due to a full year's
amortization. In 1993, other interest included interest on the
provision for a refund of bonded revenues billed in excess of the
amounts allowed under Docket No. 10200.
Other interest and amortization of debt discount, premium and
expense increased during 1992 primarily as the result of the
issuances of the Series T Bonds and Secured Debentures, due 1999
discussed above, as well as the amortization of expenses related
to the amendments of the Unit 1 and Unit 2 financing facilities.
Other interest expense increased due to the accrual of interest
on the provision for a refund of bonded revenues billed in excess
of the amounts allowed in Docket No. 10200. Partially offsetting
these increases was a decrease in interest on unsecured notes
payable to banks. The Utility utilized a portion of the proceeds
from the issuance of the Series T Bonds and Secured Debentures,
due 1999 to retire $26 million of unsecured notes payable to
banks. The remaining $10 million portion of such notes was
retired in August 1992.
Allowance for borrowed funds used during construction (AFUDC)
decreased in 1992 when compared to 1991 because Unit 2 was placed
in commercial operation on October 16, 1991. AFUDC for 1991
reflected primarily the qualified capitalization of interest on
the financing facility for Unit 2 from the date of assumption
(July 26, 1991) until the date Unit 2 began commercial operation.
The Utility's receipt of equity contributions and proceeds
from future issuances of debt securities are anticipated to help
satisfy the scheduled repayments of the Unit 2 financing
facility. Interest rates on debt securities are expected to be
greater than those interest rates under the financing facility.
Interest rates on additional debt may be further increased if the
Utility's outstanding regulatory matters are not satisfactorily
resolved.
Net Earnings
The Utility's contribution to consolidated net earnings
increased $678,000 in 1993 after a significant decline of
$8,995,000 in 1992.
The decline in the Utility's contribution to consolidated net
earnings in 1992 was due primarily to (1) the decrease in
customer usage as discussed in "Operating Revenues," (2) the
PUCT's abandonment of its long-standing methodology for
determination of the Federal income tax expense component of cost
of service in the PUCT's Order on Rehearing in Docket No. 10200
and (3) the increases in interest expense.
The slight increase in 1993 resulted from increased KWH
sales, the effect of which was reduced by increases in
depreciation expense, taxes, other than on income and income
taxes and a decrease in other income as previously discussed.
The level of 1993 contribution to net earnings also reflects the
adverse tax ruling by the PUCT, discussed above in "PUCT Docket
No. 10200" under "Financial Condition."
<page 15>
Early in 1993, the Utility implemented cost saving measures
such as (1) suspension of the Utility's matching contributions to
the employees thrift plan, (2) revision to the Utility's pension
plan and (3) implementation of a general employee salary and wage
freeze and limitations on hiring new employees and replacements.
These cost saving measures more than offset the increase in
expenses related to the health care and death benefits plans
resulting from implementation of SFAS 106. With the exception of
the Utility's wage-step progression increases reactivated in
April 1993, these measures continued in effect throughout 1993.
The Utility reduced its labor force by 3.2% during 1993, trimming
$1.1 million from operations and maintenance expenses. Even so,
the Utility's return on common equity for 1993 and 1992 was 4.97%
and 4.80%, respectively, although the Utility's rate of return
granted in Docket No. 10200 authorized a return on common equity
of 13.16%. Based on the Utility's earnings for 1993 and 1992 and
the expected increases in interest on long-term debt and certain
other expenses, equitable rate relief in Texas appears to be
necessary for any significant improvement in financial results to
occur during 1994.
Future regulatory treatment and court decisions regarding
Docket Nos. 9491 and 10200, as previously discussed, will have a
direct bearing on future earnings.
Nonutility Operations
Contributions to earnings from nonutility operations during
1993 and 1992 were principally from short-term investment
activities and, during 1993, a refund of a portion of state
franchise tax paid by the Company in prior periods. Due to the
Company's equity contribution to the Utility in November 1993,
the Company's short-term investments declined during 1993.
Nonutility operations are reflected in other income, net of taxes
in the consolidated statements of earnings. The contributions
from nonutility operations to consolidated earnings are not
expected to increase until such time as nonutility operations
include new business that generates earnings; however, presently
the Company has no specific plans for new business.
<page 16>
INDEPENDENT AUDITORS' REPORT
The Shareholders and Board of Directors
TNP Enterprises, Inc.:
We have audited the accompanying consolidated balance sheets
of TNP Enterprises, Inc. and subsidiaries as of December 31, 1993
and 1992, and the related consolidated statements of earnings,
common stock equity and redeemable cumulative preferred stocks,
and cash flows for each of the years in the three-year period
ended December 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 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, the consolidated financial statements
referred to above present fairly, in all material respects, the
financial position of TNP Enterprises, Inc. and subsidiaries as
of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 1993, in conformity with
generally accepted accounting principles.
As discussed in note 5 to the consolidated financial
statements, uncertainties exist with respect to the outcome of
certain regulatory matters. The ultimate outcome of these
matters cannot presently be determined. Accordingly, no
provision for any loss that may ultimately be required upon
resolution of these matters has been made in the accompanying
consolidated financial statements.
As discussed in note 4 to the consolidated financial
statements, the Company changed its method of accounting for
income taxes in 1993 to adopt the provisions of the Financial
Accounting Standards Board's Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes. As
discussed in note 1(j), the Company also adopted the provisions
of the Financial Accounting Standards Board's SFAS No. 106,
Employers Accounting for Postretirement Benefits Other Than
Pensions in 1993.
KPMG PEAT MARWICK
Fort Worth, Texas
January 28, 1994
<page 17>
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statements of Earnings
Three Years Ended December 31, 1993
<TABLE>
<CAPTION>
1993 1992 1991
(In Thousands Except Per Share Amounts)
<S> <C> <C> <C>
Operating revenues (note 5) $474,242 443,827 441,343
Operating expenses:
Power purchased for resale 200,183 174,257 216,818
Fuel 44,348 44,977 25,773
Other operating and general
expenses (note 1(j)) 69,406 70,003 65,287
Maintenance 11,460 11,342 11,225
Depreciation of utility plant 36,015 35,098 28,027
Taxes, other than on income 30,296 29,250 23,788
Income taxes (note 4) 4,294 1,897 7,860
Total operating expenses 396,002 366,824 378,778
Net operating income 78,240 77,003 62,565
Other income, net of taxes
(note 4) 1,306 2,210 528
Earnings before interest
charges 79,546 79,213 63,093
Interest charges:
Interest on long-term debt 63,833 63,893 44,919
Other interest and amortization
of debt discount,premium and
expense 4,411 4,539 3,266
Allowance for borrowed funds
used during construction (303) (149) (4,625)
Total interest charges 67,941 68,283 43,560
Net earnings 11,605 10,930 19,533
Dividends on preferred stocks 879 968 1,078
Earnings available for
common stock $ 10,726 9,962 18,455
Weighted average number of
common shares outstanding 10,641 8,545 8,275
Earnings per share of
common stock $ 1.01 1.17 2.23
Dividends per share of
common stock $ 1.63 1.63 1.63
<FN>
See accompanying notes to consolidated financial statements.
</TABLE>
<page 18>
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEETS
December 31, 1993 and 1992
1993 1992
(In Thousands)
<S> <C> <C>
ASSETS
Utility plant, at original cost
(notes 2,5):
Electric plant $1,203,636 1,184,635
Construction work in progress 5,282 3,922
1,208,918 1,188,557
Less accumulated depreciation 202,923 172,848
Net utility plant 1,005,995 1,015,709
Nonutility property, at cost 1,673 1,322
Current assets:
Cash and cash equivalents 12,423 86,785
Customer receivables 764 122
Refundable income taxes - 2,636
Inventories, at the lower of
average cost or market:
Fuel 1,422 1,246
Materials and supplies 7,793 7,185
Deferred purchased power and fuel costs 15,151 17,735
Accumulated deferred taxes on income
(note 4) 4,251 -
Other current assets 1,071 545
Total current assets 42,875 116,254
Regulatory tax assets (note 4) 16,915 -
Deferred charges (note 4) 37,779 49,422
$1,105,237 1,182,707
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock, no par value per share.
Authorized 50,000,000 shares;
issued 10,695,860 shares in 1993
and 10,597,564 shares in 1992 $ 131,615 129,914
Retained earnings (note 3) 82,012 88,621
Total common stock equity 213,627 218,535
Redeemable cumulative preferred stocks
(note 3) 9,560 10,440
Long-term debt, net of amount due within
one year (note 2) 678,994 742,087
Total capitalization 902,181 971,062
Current liabilities:
Long-term debt due within one year 1,070 10,288
Accounts payable 22,450 25,809
Accrued interest 16,115 8,869
Accrued taxes (note 4) 17,221 22,243
Customers' deposits 4,464 4,236
Revenues subject to refund (note 5) 3,400 17,515
Other current and accrued liabilities 13,412 8,029
Total current liabilities 78,132 96,989
Customers' advances for construction 169 311
Regulatory tax liabilities (note 4) 20,412 -
Accumulated deferred taxes on income
(note 4) 85,995 93,879
Accumulated deferred investment tax
credits (note 4) 18,348 20,466
Commitments and contingencies (note 5) $1,105,237 1,182,707
<FN>
See accompanying notes to consolidated financial statements.
</TABLE>
<page 19>
Consolidated Statements of Common Stock Equity
and Redeemable Cumulative Preferred Stocks
Three Years Ended December 31, 1993
<TABLE>
<CAPTION>
Common Stock Equity Redeemable
Cumulative
Common Stock Retained Preferred
Shares Amount Earnings Total Stocks
(In Thousands)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1991:
Balance, January 1, 1991 8,238 $ 84,462 87,377 171,839 12,600
Net earnings for the year 19,533 19,533
Dividends on preferred stocks (1,078) (1,078)
Dividends on common stock -
$1.63 per share (13,485) (13,485)
Sale of common stock 80 1,527 1,527
Purchase and retirement of
preferred stocks - 1,200
shares 4.65% Series B, 600
shares 4.75% Series C, 1,200
shares 11% Series D, 600
shares 11% Series E, 1,200
shares 11% Series F and
8,000 shares 11.875%
Series G 52 52 (1,280)
Balance, December 31, 1991 8,318 85,989 92,399 178,388 11,320
Year ended December 31, 1992:
Net earnings for the year 10,930 10,930
Dividends on preferred stocks (968) (968)
Dividends on common stock -
$1.63 per share (13,780) (13,780)
Sale of common stock 2,280 43,925 43,925
Purchase and retirement of
preferred stocks - 1,200
shares 4.65% Series B,
600 shares 4.75% Series C,
1,200 shares 11% Series D,
600 shares 11% Series E,
1,200 shares 11% Series F and
4,000 shares 11.875% Series G 40 40 (880)
Balance, December 31, 1992 10,598 129,914 88,621 218,535 10,440
Year ended December 31, 1993:
Net earnings for the year 11,605 11,605
Dividends on preferred stocks (879) (879)
Dividends on common stock -
$1.63 per share (17,344) (17,344)
Sale of common stock 98 1,701 1,701
Purchase and retirement of
preferred stocks - 1,200 shares
4.65% Series B, 600 shares 4.75%
Series C, 1,200 shares 11%
Series D, 600 shares 11% Series
E, 1,200 shares 11% Series F and
4,000 shares 11.875% Series G 9 9 (880)
Balance, December 31, 1993 10,696 $131,615 82,012 213,627 9,560
<FN>
See accompanying notes to consolidated financial statements.
<page 20>
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Cash Flows
Three Years Ended December 31, 1993
1993 1992 1991
(In Thousands)
<S> <C> <C> <C>
Cash flows from operations:
Net earnings $ 11,605 10,930 19,533
Items not requiring cash:
Depreciation of utility
plant 36,015 35,098 28,027
Amortization of debt
expense, discount and
premium, and other
deferred charges 4,939 5,667 1,227
Allowance for borrowed funds
used during construction (303) (149) (4,625)
Deferred taxes on income 5,534 541 19,370
Investment tax credit adjustments (953) (2,479) (10,825)
Changes in certain current assets
and liabilities:
Customer receivables (642) 1,784 (1,097)
Refundable income taxes 2,636 14,732
Inventories (784) (451) 113
Deferred purchased power and
fuel costs 2,584 (5,493) (8,202)
Other current assets (203) 659 723
Accounts payable (3,359) (2,007) 3,271
Accrued interest 7,246 2,256 (1,865)
Accrued taxes (3,729) 5,542 7,377
Customers' deposits 228 284 55
Revenues subject to refund (14,115) 15,961 1,554
Other current and accrued
liabilities 5,383 (1,553) (2,332)
Other - net (1,384) (4,042) (9,511)
TOTAL 50,698 62,548 57,525
Cash flows from investing
activities:
Additions to utility plant, net
of capitalized depreciation
and interest (25,998) (22,098) (29,931)
Additions to deferred charges (362) (312) (12,605)
TOTAL (26,360) (22,410) (42,536)
Cash flows from financing
activities:
Dividends on preferred and
common stocks (18,223) (14,748) (14,563)
Issuances:
Common stock 1,701 43,925 1,527
Long-term debt 240,000 271,500 32,000
Deferred expenses associated
with financings (8,940) (9,124) -
Redemptions:
Preferred stocks (880) (880) (1,280)
Long-term debt (312,358) (245,498) (574)
Short-term debt - (36,000) (5,900)
TOTAL (98,700) 9,175 11,210
Net change in cash and cash
equivalents (74,362) 49,313 26,199
Cash and cash equivalents at
beginning of year 86,785 37,472 11,273
Cash and cash equivalents at
end of year $ 12,423 86,785 37,472
Supplemental disclosures of
cash flow information:
Cash paid during the years for:
Interest (net of amount
capitalized) $ 59,028 62,130 41,708
Income taxes 3,263 1,230 847
<FN>
See accompanying notes to consolidated financial statements.
</TABLE>
<page 21>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1993, 1992 and 1991
(1) Summary of Significant Accounting Policies
(a) Principles of Consolidation
The consolidated financial statements include the accounts of
the Company and its wholly owned subsidiaries, Texas- New Mexico
Power Company (Utility), Bayport Cogeneration, Inc. and TNP
Operating Company. The Utility has two wholly owned
subsidiaries, Texas Generating Company (TGC) and Texas Generating
Company II (TGC II). All intercompany transactions and balances
have been eliminated in consolidation.
The principal subsidiary is the Utility. The Utility is a
public utility engaged in the generation, purchase, transmission,
distribution and sale of electricity within the states of Texas
and New Mexico. The Utility is subject to regulation by the
Public Utility Commission of Texas (PUCT) and the New Mexico
Public Utility Commission (NMPUC). The Utility is subject in
some of its activities, including the issuance of securities, to
the jurisdiction of the Federal Energy Regulatory Commission
(FERC), and its accounting records are maintained in accordance
with the FERC's Uniform System of Accounts.
TGC and TGC II were incorporated in Texas in 1988 and 1991,
respectively, as financing entities for the assumption of
ownership and liabilities related to two 150-megawatt
lignite-fueled generating units, Unit 1 and Unit 2, respectively,
collectively referred to as TNP One. The units were constructed
by a nonaffiliated consortium in Robertson County, Texas, and are
operated by the Utility under the terms of operating agreements
between the Utility and its subsidiaries. Notes 2 and 5 provide
additional information about the financings and regulatory
treatments of Unit 1 and Unit 2.
(b) Utility Plant
The costs of additions to utility plant and replacement of
retired units of property are capitalized. Costs include labor,
materials and similar items and indirect charges for such items
as engineering, supervision and transportation. Property repairs
and replacement of minor items of property are included in
maintenance expense.
The cost of depreciable units of plant retired or disposed of
in the normal course of business is eliminated from utility plant
accounts, and such cost plus removal expenses less salvage 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.
(c) Depreciation
Depreciation is provided on a straight-line basis over the
estimated service lives of the properties. Depreciation of
utility plant, other than transportation equipment, is charged to
earnings. Depreciation of transportation equipment is charged to
earnings and property accounts in accordance with the equipment's
use.
Depreciation as a percentage of average depreciable cost was
3.00%, 3.10% and 3.17% in 1993, 1992 and 1991, respectively.
(d) Unamortized Debt Expense, Discount and
Premium on Debt
Expenses incurred in connection with the issuance of
outstanding long-term debt and discount and premium related to such debt are
amortized on a straight-line basis over the lives of the respective issues.
(e) Revenues and Purchased Power
Revenues are recognized on the basis of meter readings which
are made on a monthly cycle. The Utility does not accrue
revenues for power sold but not billed at the end of an
accounting period.
Power purchased is recorded on the basis of billings from
suppliers; no accrual is made for power delivered to the Utility
between the dates of such billings and the end of an accounting
period.
(f) Customer Receivables
The Utility sells customer receivables to a nonaffiliated
company on a nonrecourse basis.
(g) Deferred Purchased Power and Fuel Costs
The deferral method of accounting is used for the portions of
purchased power and fuel costs which are recoverable in
subsequent periods under purchased power costs recovery
adjustment clauses. These clauses provide the ability to refund
or collect, in the second succeeding month, those amounts of
purchased power costs over- or under-collected in the current
month. At December 31, 1993 and 1992, the Utility had
under-recovered purchased power costs of approximately $1,520,000
and $6,640,000, respectively.
At December 31, 1993 and 1992, the Utility also had
under-recovered fuel costs of approximately $13,631,000 and
$11,095,000, respectively, related to TNP One. A fixed fuel
factor approved by the PUCT is intended to permit the Utility to
recover the cost of fuel utilized to generate electricity sold in
Texas. The factor may be changed only upon approval of the PUCT
and is expected to be adjusted for any cumulative over- or
under-recovery of fuel costs.
(h) Allowance for Borrowed Funds Used
During Construction
The applicable regulatory uniform system of accounts defines
allowance for funds used during construction as including the net
cost during the period of construction of borrowed funds used for
construction purposes and a reasonable rate on other funds when
so used. In that connection, the Utility used an accrual rate of
7.53% in 1993, 5.8% in 1992 and 8.0% in 1991 for borrowed funds
used during construction, excluding capitalized interest related
to the financing facilities.
Capitalized interest related to the financing facility for
Unit 2 (note 2) was approximately $4,234,000 in 1991. Interest
was capitalized from the date of assumption of the Unit 2
indebtedness, July 26, 1991, until the date on which Unit 2 began
commercial operation, October 16, 1991.
<page 22>
(i) Income Taxes
The Company and its subsidiaries account for certain income
and expense items differently for financial reporting purposes
than for income tax purposes. Provisions for deferred income
taxes are made for such differences. As discussed in note 4, the
Company changed its method of accounting for income taxes in 1993
to adopt the provisions of the Financial Accounting Standards
Board's Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes."
Investment tax credits utilized are deferred and amortized to
earnings ratably over the estimated service lives of the related
assets.
(j) Employee Benefit Plans
The Utility has in effect a trusteed defined benefit
retirement plan available to employees who are 21 years of age
and over and have at least one year of service with the Utility.
The Utility's funding policy is to contribute annually at least
the minimum amount required by government funding standards, but
not more than that which can be deducted for Federal income tax
purposes.
The net pension costs for 1993, 1992 and 1991 included the
following components:
<TABLE>
<CAPTION>
1993 1992 1991
(In Thousands)
<S> <C> <C> <C>
Service cost $1,472 2,148 1,914
Interest cost on projected
benefit obligation 4,191 4,504 4,197
Reduction for actual return
on plan assets (6,126) (5,071) (12,276)
Other - net 300 258 7,706
$ (163) 1,839 1,541
</TABLE>
The following table is a summary of the plan's funded
status at December 31, 1993 and 1992:
<TABLE>
<CAPTION>
1993 1992
(In Thousands)
<S> <C> <C>
Plan assets (principally marketable
securities) at estimated fair value $69,763 66,643
Projected benefit obligation (including
accumulated benefit obligations for
1993 and 1992 of approximately
$55,509,000 and $43,894,000,
respectively) (60,618) (58,190)
9,145 8,453
Unrecognized net asset (171) (198)
Unrecognized prior service cost (2,990) 3,668
Unrecognized net gain (9,554) (15,657)
Net pension liability (included in other
current and accrued liabilities in the
consolidated balance sheets) $ (3,570) (3,734)
</TABLE>
The weighted average discount rate and the rate of increase
in future compensation levels used in determining the actuarial
present value of the projected benefit obligation were 7.15% and
4.15%, respectively, for 1993 and 8.5% and 5.75%, respectively,
for 1992. The weighted average expected long-term rate of
return on plan assets for 1993 and 1992 was 9.5%. The vested
benefit obligations at December 31, 1993 and 1992, were
approximately $50,457,000 and $39,757,000, respectively.
The defined benefit retirement plan was amended to change,
for all participants retiring after December 31, 1992, the
determination of average monthly compensation used in calculating
the amount of retirement benefits from the average of the three
highest consecutive calendar years to the average of the
completed calendar years of compensation after 1992.
The Utility has a voluntary thrift plan, administered by a
trustee, with a provision for the Utility to contribute to the
plan amounts equal to certain percentages of amounts contributed
by employees. Employees have the option of investing their
contributions and contributions of the Utility, if any, in
either, or a combination of, certain government securities, the
Company's common stock or, since January 1, 1992, two mutual
funds. Effective January 1, 1992, the plan calls for the
Utility's contributions to be used to purchase the Company's
common stock which the employees may later convert into
investments in one or more of the other investing options.
Effective January 1, 1993, the Utility suspended its matching
contributions to the thrift plan for an indefinite period;
however, the Utility's Board of Directors has approved
restoration of the Utility's matching contributions, to be
effective for employee contributions made after June 30, 1994.
The Utility's contributions to the thrift plan amounted to
approximately $1,592,000 and $1,487,000 in 1992 and 1991,
respectively. Thrift plan assets included 1,471,213 shares and
1,482,490 shares of the Company's common stock at December 31,
1993 and 1992, respectively.
On November 9, 1993, the Board of Directors of the Utility
renewed forms of employment contracts between the Utility and its
officers and its other key personnel. The principal purpose of
the contracts is to encourage retention of management and other
key personnel required for the orderly conduct of the business of
the Utility during any threatened or pending acquisition of the
Company or the Utility and during any transition of ownership.
The terms of the contracts, from date of execution, are three
years as to certain officers and managers of the Utility and two
years as to the other key personnel. Upon the expiration date of
each contract, the Utility, at its option, may extend the
contract for additional three or two year periods, as
appropriate. The contracts provide for lump sum compensation
payments and other rights to the officers and the other key
personnel in the event of termination of employment or other
adverse treatment of such persons following a "change in control"
of the Company or the Utility, which event is
<page 23>
defined to include, among other things, substantial changes in
the corporate structure or ownership of either entity or in the
Board of Directors of either entity.
Health care and death benefits and an excess benefit plan
have been provided at minimal or no cost to retired employees.
The excess benefit plan is provided under an insurance policy
arrangement and is backed by a letter of credit which will be
funded only if a change in control occurs.
On January 1, 1993, the Utility implemented Statement of
Financial Accounting Standards No. 106 (SFAS 106), "Employers'
Accounting for Postretirement Benefits Other Than Pensions,"
which addresses the accounting for other postretirement employee
benefits (OPEBs). For the Utility, OPEBs are comprised
primarily of health care and death benefits for retired
employees. Prior to 1993, the costs of these OPEBs were expensed
on a "pay-as-you-go" basis. For 1992, these costs were
approximately $760,000. Beginning in 1993, SFAS 106 requires a
change from the "pay-as-you-go" basis to the accrual basis of
recognizing the costs of OPEBs during the periods that employees
render service to earn the benefits. SFAS 106 also requires
employers to recognize the costs of benefits already earned by
active employees and retirees at the date of adoption of SFAS 106
(the transition obligation).
For the Utility, an annual accrual for OPEBs is comprised of
(1) the portion of the expected postretirement benefit obligation
attributed to employee service during that period (the service
cost), (2) amortization of the transition obligation and (3) the
interest costs associated with the total unfunded accumulated
obligation for future benefits. For 1993, these costs amounted
to approximately $508,000, $934,000 and $1,510,000, respectively.
This total cost of $2,952,000 based on adoption of SFAS 106 was
$2,276,000 greater than the amount of $676,000 that would have
been recorded under the "pay-as-you-go" basis. The assumed
health care cost trend rate used to measure the expected cost of
benefits was 11.5% for 1993 and is assumed to diminish to 8.4%
for 1994, then trend downward slightly each year to a level of 6%
for 2003 and thereafter. The Utility's remaining transition
obligation of $17,750,000 at December 31, 1993 is to be amortized
over a remaining nineteen-year period. A 1% increase in the
assumed health care cost trend rate would result in (1) an
increase of $3,235,000 in the Utility's accumulated benefit
obligation at December 31, 1993 and (2) an increase of $538,000
for 1993 in the aggregate service and interest costs.
In March 1993, the PUCT issued its rules for ratemaking
treatment of OPEBs. As part of a general rate case, a utility
may request OPEBs expense in cost of service for ratemaking
purposes on an accrual basis in accordance with generally
accepted accounting principles. The PUCT's rule includes
recovery of the transition obligation and requires that the
amounts included in rates shall be placed in an irrevocable
external trust fund dedicated to the payment of OPEBs expenses.
Based on the PUCT's rule, the Utility intends to seek recovery of
OPEBs expense attributable to its Texas jurisdiction in its next
Texas rate case.
In order to comply with the PUCT's condition for possible
recovery of OPEBs expenses, the Utility established in June 1993
a Voluntary Employees Beneficiary Association (VEBA) trust fund,
dedicated to the payment of OPEBs expenses. Monthly cash
payments made to the VEBA, which began in June 1993, will fund
the three OPEBs expense components of the Utility's total Texas
and New Mexico operations.
On August 23, 1993, the Utility filed a rate application with
the NMPUC which included a request for recovery of the applicable
costs of OPEBs. A stipulated agreement among the parties in the
application, dated January 28, 1994, subject to approval by the
NMPUC, would include such applicable costs in the proposed New
Mexico rates, beginning in 1994.
The following table presents the plan's funded status
reconciled with amounts recognized in the consolidated balance
sheets at December 31, 1993 and 1992:
<TABLE>
<CAPTION>
1993 1992
(In Thousands)
<S> <C> <C>
Accumulated postretirement
benefit obligation:
Retirees and dependents $(15,828) (13,604)
Active employees (7,671) (5,080)
(23,499) (18,684)
Plan assets at fair value 1,297 -
Accumulated postretirement
benefit obligation in excess
of plan assets (22,202) (18,684)
Unrecognized net loss 3,533 -
Unrecognized transition obligation 17,750 18,684
Accrued postretirement benefit cost
included in other current and
accrued liabilities $ (919) -
</TABLE>
The discount rate used in determining the acutuarial present
value of the accumulated post retirement benefit obligation was
7.15% and 8.50% for 1993 and 1992, respectively.
(k) Fair Values of Financial Instruments
The fair value amounts of certain financial instruments
included in the accompanying consolidated balance sheets at
December 31, 1993 and 1992 were as follows:
* The fair value of cash and cash equivalents approximates
the carrying amount because of the short maturity of
those instruments.
* The total estimated fair value of long-term debt was
approximately $723 million and $755 million in 1993 and
1992, respectively. The total estimated fair value of
preferred stocks was $7.6 million and $7.7 million in
1993 and 1992, respectively. The estimated fair values
of long-term debt and preferred stocks were based on
quoted market prices of the same or similar issues.
<page 24>
(l) Statements of Cash Flows
For purposes of the consolidated statements of cash flows,
the Company considers temporary cash investments with original
maturities of three months or less to be cash equivalents.
On July 26, 1991, TGC II assumed ownership of TNP One, Unit 2
and assumed the related liabilities totaling approximately $269
million. In addition, approximately $12 million of deferred
charges related to TNP One, Unit 2 was reclassified to utility
plant.
During 1992, the Utility reclassified approximately $12
million of deferred charges to utility plant.
On January 1, 1993, the Utility recognized certain assets and
liabilities and certain reclassifications as a result of
implementation of Statement of Financial Accounting Standards No.
109 (SFAS 109). See note 4 for further discussion of SFAS 109,
including amounts of these transactions.
(m) Shareholder Rights Plan
The Company has a Shareholder Rights Plan (Rights Plan) that
is designed to protect the Company's shareholders from coercive
takeover tactics and inadequate or unfair takeover bids. The
Rights Plan, adopted in 1988 and amended on November 13, 1990, by
the Company's Board of Directors, provides for the distribution
of one right for each share of the Company's common stock held of
record as of the close of business on November 4, 1988 and for
each share of common stock issued thereafter until November 4,
1998. Each right entitles the shareholder to elect to exercise
the right in whole or in part to purchase, upon the occurrence of
certain events, one share of common stock at an initial price of
$45 per share or, under certain circumstances, shares of common
stock at half the then-current market price or, with an election
to exercise such rights without payment of cash, to receive the
number of shares of the Company's common stock or other
securities having an aggregate value equal to the excess of (i)
the value of the common stock or other securities on the date of
the exercise of the rights over (ii) the cash payment that would
have been payable upon the exercise of the rights if an election
for cash payment had been made. Until certain triggering events
occur, the rights will trade together with the Company's common
stock and separate rights certificates will not be issued. Among
the triggering events are the acquisition by a person or group of
persons of 10% or more of the Company's outstanding common stock
or the commencement of a tender or exchange offer which, upon
consummation, would result in a person or group of persons owning
15% or more of the Company's outstanding common stock. The
rights expire November 4, 1998, unless earlier redeemed or
exchanged by the Company, and have had no effect on earnings per
share.
(n) Common Stock
At December 31, 1993, 425,189 shares of the Company's common
stock were reserved for issuance to the Utility's Employees
Thrift Plan. Additionally, 417,991 shares of the Company's
common stock were reserved for subsequent issuance to the
Company's shareholders under a Dividend Reinvestment and Stock
Purchase Plan.
(o) Earnings Per Share
Earnings per share of common stock are computed for each year
based upon the weighted average number of common shares
outstanding. Net earnings are reduced for preferred dividend
requirements.
(2) Long-term Debt
Long-term debt outstanding was as follows:
<TABLE>
<CAPTION>
1993 1992
(In Thousands)
<S> <C> <C>
First mortgage bonds:
Series G, 4.700% due 1993 $ - 9,138
Series H, 4.950 due 1995 - 3,700
Series I, 6.075 due 1996 - 3,750
Series J, 9.000 due 1999 - 7,800
Series K, 8.500 due 2001 - 6,400
Series L, 10.500 due 2000 9,840 9,960
Series M, 8.700 due 2006 8,400 8,500
Series R, 10.000 due 2017 63,700 64,350
Series S, 9.625 due 2019 20,000 20,000
Series T, 11.250 due 1997 130,000 130,000
Series U, 9.250 due 2000 100,000 -
Total 331,940 263,598
Unamortized discount,
net of premium (676) (723)
First mortgage bonds, net 331,264 262,875
Secured debentures:
12.50% due 1999 130,000 130,000
Series A, 10.75% due 2003 140,000 -
270,000 130,000
Secured notes payable 78,800 359,500
Total long-term debt 680,064 752,375
Less long-term debt due
within one year (1,070) (10,288)
Total long-term debt, net $678,994 742,087
</TABLE>
Issuance of Additional First Mortgage Bonds
and Secured Debentures
On September 29, 1993, the Utility issued $100 million of
9.25% First Mortgage Bonds, Series U, due September 15, 2000 (New
Bonds), and $140 million of 10.75% Secured Debentures, Series A,
due September 15, 2003 (Debentures, due 2003).
After fees and expenses, combined net proceeds available to
<page 25>
the Utility from the issuances of the New Bonds and the
Debentures, due 2003, and existing cash were utilized as follows:
(a) $146 million was used to prepay or purchase all of the
outstanding secured notes payable to lenders under the Unit 1
financing facility, as discussed below;
(b) $75.75 million was used to prepay secured notes payable
under the Unit 2 financing facility, as discussed below;
(c) $21.78 million was deposited for the call for redemption
of the aggregate principal amount, including redemption premiums,
of Series H, I, J and K First Mortgage Bonds; and
(d) $9.14 million was used to reimburse the Utility's
treasury for funds used to redeem Series G First Mortgage Bonds
at maturity on July 1, 1993.
Supplemental indentures relating to Series H, I, J and K
First Mortgage Bonds contained a requirement that Net Earnings
Available for Interest of the Utility for 12 consecutive months
out of the preceding 15 months be at least two-and-one-half (2.5)
times the aggregate amount of annual Interest Charges on Bonded
Indebtedness which gives effect to the interest on the additional
Bonds to be issued (the Interest Coverage Ratio). Under the 2.5
times Interest Coverage Ratio required for issuance of additional
First Mortgage Bonds, only a minimal amount of additional First
Mortgage Bonds could have been issued. Under the supplemental
indentures for the series of Bonds outstanding after the deposit
of proceeds from the offering for the redemption of Series H, I,
J and K Bonds, the Interest Coverage Ratio was reduced to two (2)
times. The maturity of Series G Bonds on July 1, 1993, and the
call for redemption of Series H, I, J and K Bonds permitted the
issuance of additional Bonds and consummation of the offering of
$100 million of New Bonds.
Amendments to the Financing Facilities
At December 31, 1992, secured notes payable represented loans
issued under two financing facilities, which were originally
entered into by separate subsidiaries of a construction
consortium, for the construction of Unit 1 and Unit 2 of the TNP
One generating plant. The Unit 1 financing facility was assumed
by TGC on July 20, 1990. The Unit 2 financing facility was
assumed by TGC II on July 26, 1991.
On September 29, 1993, the balance of the secured notes
payable under the Unit 1 financing facility was purchased or
prepaid, and $75.75 million of secured notes payable under the
Unit 2 financing facility was prepaid, reducing that outstanding
commitment to $147.75 million; funds used for these prepayments
and purchases were provided from issuance of the New Bonds and
the Debentures, due 2003, and from existing cash, as discussed
above. Thereafter, the Utility made additional unscheduled
prepayments of approximately $69 million under the Unit 2
financing facility. The $78.8 million balance at December 31,
1993 represents secured notes payable under the Unit 2 financing
facility, consisting of a series of renewable loans from various
lenders in a financing syndicate.
In contemplation of the prepayments of the Unit 1 and Unit 2
financing facilities, the related credit agreements between the
secured lenders and the Utility were amended as of September 21,
1993 to facilitate the issuance of the Debentures, due 2003, and
to extend the maturities of the remaining loans from due dates in
1994 and 1995. The effectiveness of the amendments was
contingent upon the application of proceeds from the sale of the
Debentures, due 2003, and the New Bonds. The extension of the
maturities of the remaining loans to be outstanding under the
Unit 2 financing facility is subject to further approvals from
the FERC and the NMPUC. The Utility expects to receive the
necessary approvals within the period required by the amendments.
Upon the effective date of the extension, the lenders will
receive an extension fee of 1/4 of 1% on their pro-rata share of
the $147.75 million commitment. Based upon the December 31, 1993
balance and assuming the regulatory approvals of the extensions
of the maturities under the Unit 2 financing facility, $1.6
million will be due on December 31, 1995, $3.4 million will be
due on December 31, 1996, with the remaining amounts due in two
equal installments of approximately $36.9 million on December 31,
1997 and 1998.
Under the amendments to the Unit 2 credit agreement, the
Utility is permitted to prepay up to $141.5 million of the
$147.75 million commitment under the Unit 2 financing facility
and reborrow thereunder up to the amount of such prepayments,
subject to scheduled reductions of the commitment of
approximately $36.9 million each in 1996, 1997 and 1998. Such
reborrowings under the Unit 2 financing facility will be subject
to compliance with the EBIT test (as described below) and
maintenance of an equity to total capital ratio of 20% or more as
defined in the credit agreement. As of December 31, 1993, the
unused commitment available to be borrowed under the Unit 2
financing facility was approximately $69 million. A commitment
fee of 1/4 of 1% per annum is payable on the unused portion of
the reducing commitment.
The financing facilities contain certain covenants which,
under specified conditions, restrict the payment of cash
dividends on common stock of the Utility. The most restrictive
of such covenants are an interest coverage test and an equity
ratio test. Under the interest coverage test, the Utility may
not pay cash dividends on its common stock unless its prior
twelve months earnings (exclusive of any writedowns resulting
from actions of the PUCT, to the extent included in operating
expenses) before interest and income taxes equals or exceeds the
sum of all of the interest expense on indebtedness for the same
period (said calculation, the EBIT Test). This restriction
becomes effective only after the third consecutive calendar
quarter during which the Utility does not meet the EBIT Test and
continues in effect until after the quarter in which the Utility
has
<page 26>
met the twelve-month EBIT Test. The Utility has met the EBIT
Test at each quarterly date since this test became effective.
Under the recently required equity ratio test, the Utility may
not pay cash dividends on its common stock if, at the preceding
quarterly date, the Utility's ratio of equity capitalization to
total capitalization is less than 20%. As of December 31, 1993,
this test was met.
Under the two financing facilities, interest rates were
determined under several alternative methods. During 1993, all
rates at the time of each borrowing were no higher than the prime
lending rate plus a margin of 1 3/8%. The effective costs of
borrowing under the secured notes payable were 7.23% and 5.61% at
December 31, 1993 and 1992, respectively. Under the amended Unit
2 financing facility, the margins will increase by 1/2 of 1% each
year in 1994 and 1995 and by 1/4 of 1% each year in 1996, 1997
and 1998.
Additional Information
Substantially all utility plant owned directly by the Utility
is subject to the first lien of the Utility's first mortgage bond
indenture, as supplemented (the Bond Indenture). Until repaid,
the holders of the secured notes payable and of the secured
debentures have a lien junior to the first lien of the Bond
Indenture on substantially all utility plant in Texas owned
directly by the Utility.
The Debentures, due 2003, are secured by a pledge by the
Utility to the new debenture trustee of a replacement note (1993
Unit 1 Replacement Note) in an amount equal to the principal
amount of the Debentures, due 2003, purchased by the Utility from
secured lenders under the Unit 1 financing facility. The 1993
Unit 1 Replacement Note is secured ratably by the original Unit 1
First Lien Mortgage of the Unit 1 financing facility on the
assets of TGC, the existing second mortgage lien on the
Utility's Bond Indenture trust estate assets in Texas and certain
other collateral. The Debentures, due 2003, rank pari passu with
the outstanding secured debentures, due 1999, in their Unit 1
mortgage lien on the assets of TGC and other security interests.
The secured debentures, due 1999, are secured ratably by a
1992 Unit 1 replacement note and a 1992 Unit 2 replacement note
($65 million each), which are in turn secured by first liens on
the assets of TGC and TGC II, respectively, and by the existing
second mortgage lien on the Utility s Bond Indenture trust estate
assets in Texas and certain other collateral.
Under the terms of each financing facility, the secured notes
payable and the replacement notes are secured by related first
liens on Unit 1 and Unit 2 until undivided interests in Unit 1
and Unit 2 have been purchased from TGC and TGC II, respectively,
by the Utility, whereupon such undivided interests become subject
to the lien of the Bond Indenture. In connection with the
prepayments of the secured notes payable under the Unit 1 and
Unit 2 financing facilities in September 1993, the Utility
purchased from TGC and TGC II certain undivided direct interests
in Unit 1 and Unit 2, respectively; accordingly, these interests
were released from the first liens of the financing facilities.
These purchases were in addition to interests in Unit 1 acquired
by the Utility in 1992 and 1990.
As of December 31, 1993, TGC owns a 205/345 undivided
interest in Unit 1 with the remaining fractional interest being
owned directly by the Utility. (The denominator of 345
represents the historical maximum balance of $345 million that
was originally borrowed under the Unit 1 financing facility; the
numerator of 205 represents $205 million of replacement notes
secured by the Unit 1 First Lien Mortgage.) TGC's interest in
Unit 1 is subject to the lien of the Unit 1 First Lien Mortgage,
which secures equally and ratably the 1993 Unit 1 replacement
note of $140 million and the 1992 Unit 1 replacement note of $65
million.
As of December 31, 1993, TGC II owns a 212.75/288.50
undivided interest in Unit 2 with the remaining fractional
interest being owned directly by the Utility. (The denominator
of 288.50 represents the historical maximum balance of $288.50
million that was originally borrowed under the Unit 2 financing
facility; the numerator of 212.75 represents $212.75 million of
debt and available loan commitment that remains secured by the
Unit 2 First Lien Mortgage.) TGC II's interest in Unit 2 is
subject to the lien of the Unit 2 First Lien Mortgage, which
secures all remaining secured notes payable outstanding under the
Unit 2 financing facility and the 1992 Unit 2 replacement note of
$65 million.
During the repayment periods, the Utility will operate and
finance Unit 1 and Unit 2. Under the terms of each financing
facility, upon or after each repayment of construction debt or
replacement notes by TGC or TGC II through financings by the
Utility, the Utility may purchase a proportionate undivided
direct interest in the respective unit from TGC or TGC II to the
extent such purchase is necessary to enable the Utility to issue,
from time to time, first mortgage bonds. Upon such purchase, the
undivided interest will be released from the lien of such unit's
financing facility. In any event, the Utility may not purchase
and the respective subsidiary may not transfer any undivided
interest which would cause the fraction of the undivided interest
remaining subject to the lien of the respective financing
facility to be less than a certain fraction. The numerator of
such fraction is the sum of (a) the unused commitment provided by
lenders and the outstanding principal amounts owed to the lenders
under such financing facility and (b) the principal amount of the
respective replacement notes held as security for secured
debentures. The denominator of such fraction is (i) $345 million
under the Unit 1 financing facility and (ii) $288.5 million under
the Unit 2 financing facility. The Utility guarantees the
obligations of TGC and TGC II under each respective financing
facility.
The Utility expects, assuming adequate regulatory treatment,
to be able to repay the remaining amount due under the Unit 2
financing facility primarily through the receipt of common equity
from the Company, internal cash generation and issuance of debt.
<page 27>
Based upon the December 31, 1993 balance and assuming the
approvals of the extensions of the maturities of secured notes
payable under the Unit 2 financing facility, maturities and
sinking fund requirements for the Utility's long-term debt for
the five years following 1993 are as follows:
<TABLE>
<CAPTION>
First Mortgage Secured Notes
Bonds Payable
(In Thousands)
<S> <C> <C>
1994 $ 1,070 -
1995 1,070 1,600
1996 1,070 3,400
1997 131,070 36,900
1998 1,070 36,900
</TABLE>
(3) Redeemable Cumulative Preferred Stocks
Redeemable cumulative preferred stocks (authorized 1,000,000
shares at $100 par value per share) issued by the Utility and
outstanding at December 31, 1993 and 1992, with related
redemption prices (at the Utility's option), were as follows:
<TABLE>
<CAPTION>
Shares Outstanding Total Par Value
Redemption Price (In Thousands) (In Thousands)
Series 1993 1992 1993 1992 1993 1992
<S> <C> <C> <C> <C> <C> <C> <C>
B 4.650% $100.000 100.000 25.2 26.4 $2,520 2,640
C 4.750 100.000 100.000 14.4 15.0 1,440 1,500
D 11.000 101.570 102.090 3.2 4.4 320 440
E 11.000 101.570 102.090 1.6 2.2 160 220
F 11.000 101.570 102.090 3.2 4.4 320 440
G 11.875 106.927 107.422 48.0 52.0 4,800 5,200
95.6 104.4 $9,560 10,440
</TABLE>
On October 1 of each year, the Utility is required to offer
to purchase from the holders of shares in Series B and Series C,
at a price not exceeding $100 per share plus accrued dividends, a
number of shares equal to 2% of the maximum number of shares of
each series outstanding at any one time prior to August 15 of
such year. In addition, the Utility is required to redeem, at a
price of $100 per share plus accrued dividends, 1,200 shares each
of Series D and F and 600 shares of Series E on each March 15
through March 1, 1996. The requirement to redeem such shares is
cumulative and totals $300,000 on an annual basis. On each June
15 through June 15, 2008, the Utility is required to redeem 4,000
shares of Series G at a price of $100 per share plus accrued
dividends; the requirement to redeem such shares is cumulative.
The holders of Series G and/or the Utility separately have the
noncumulative option for redemption of an additional 4,000 shares
on each June 15 at a price of $100 per share plus accrued
dividends.
Charter provisions relating to the preferred stocks and the
Bond Indenture under which the bonds are issued contain
restrictions as to the payment of cash dividends on common stock
of the Utility. At December 31, 1993, the amount of restricted
retained earnings was approximately $12,800,000. As discussed in
note 2, terms for additional restrictions as to the payment of
common dividends became effective during 1992 and 1993 as a
result of the amended terms of the Unit 1 and Unit 2 financing
facilities.
In the event of voluntary liquidation of the Utility, holders
of the preferred stocks have a preference to the extent of
amounts payable on redemption, and in the event of involuntary
liquidation, to the extent of par plus accrued dividends.
The Company has authorized, but unissued, 5,000,000 shares of
no par value per share cumulative preferred stock.
<page 28>
(4) Income Taxes
Income taxes as set forth in the consolidated statements of
earnings consisted of the following components:
<TABLE>
1993 1992 1991
(In Thousands)
<S> <C> <C> <C>
Charged (credited) to operating
expenses:
Current:
Federal $ (356) 655 (2,652)
State 94 339 435
(262) 994 (2,217)
Deferred Federal income taxes 5,515 1,347 12,946
Investment tax credit adjustments:
Investment tax credits made
available through net
operating loss carrybacks - - (1,911)
Investment tax credits utilized 89 607 66
Amortization of accumulated
deferred investment tax
credits (1,048) (1,051) (1,024)
(959) (444) (2,869)
Total 4,294 1,897 7,860
Charged (credited) to other income:
Current - Federal 641 1,114 150
Deferred Federal income taxes 19 2,060 8,080
Investment tax credit adjustments:
Investment tax credits made
available through net
operating loss carrybacks - (2,035) (7,956)
Investment tax credits utilized 6 - -
6 (2,035) (7,956)
Total 666 1,139 274
Total income taxes $4,960 3,036 8,134
</TABLE>
The provisions for deferred income taxes for 1992 and 1991
resulted from the following timing differences:
<TABLE>
1992 1991
(In Thousands)
<S> <C> <C>
Charged (credited) to operating expenses:
Tax depreciation in excess of book
depreciation $13,615 19,540
Deferred charges and other costs expensed
for tax purposes, net 674 1,943
Deferred purchased power and fuel costs
expensed for tax purposes 1,765 2,049
Unbilled revenues for tax purposes 519 (1,778)
Accrual for revenues subject to refund (5,069) -
Minimum tax credit (2,608) (8,085)
Amortization of excess deferred taxes (1,153) (810)
Change in deferred taxes due to tax net
operating loss (6,256) -
Other (140) 87
1,347 12,946
Charged (credited) to other income:
Recognition of deferred income taxes 6,256 -
Minimum tax credit (4,196) 8,080
2,060 8,080
Total $ 3,407 21,026
</TABLE>
<page 29>
Total income tax expense for 1993, 1992 and 1991 was less
than the amount computed by applying the appropriate statutory
Federal income tax rate to income before income taxes. The
reasons for the differences were as follows:
<TABLE>
1993 1992 1991
(In Thousands)
<S> <C> <C> <C>
Income tax expense at statutory rate $ 5,601 4,633 9,259
Amortization of accumulated deferred
investment tax credits (1,048) (1,051) (1,024)
Amortization of excess deferred taxes (142) (1,153) (810)
Effect of tax rate change 235 - -
State income tax 94 339 435
Other - net 220 268 274
$ 4,960 3,036 8,134
</TABLE>
The Omnibus Budget Reconciliation Act of 1993 (Act) was
signed into law on August 10, 1993. Among other provisions, the
Act provided, effective January 1, 1993, for a corporate income
tax rate increase from 34% to 35% to be phased in for taxable
income between $10 million and $18 million. Adjustments have
been made to deferred tax amounts to reflect the future reversal
of temporary differences at the higher tax rate.
Under transitional rules of the Tax Reform Act of 1986,
certain capital expenditures incurred after December 31, 1985
continued to qualify for investment tax credits (ITC).
Accordingly, ITC adjustments reflect credits for the utilized
portion of ITC generated in 1990 associated with ITC applicable
to transitional property. The Company has ITC carryforwards for
Federal income tax purposes of approximately $17,400,000 which
are available to reduce future Federal income taxes through 2005.
The Company generated a Federal minimum tax (MT) for the year
ended December 31, 1993. The MT resulted in a net current
Federal income tax expense of approximately $285,000, after
utilization of ITC.
At December 31, 1993, the Company has a net operating loss
(NOL) carryforward for Federal income tax purposes of
approximately $28,600,000 which is available to offset future
Federal taxable income through 2008. In addition, the Company
has minimum tax credit carryforwards of approximately $10,100,000
which are available to reduce future Federal regular income taxes
over an indefinite period.
In order to fully realize the Federal regular tax NOL
carryforwards, the Company will need to generate future taxable
income of approximately $28,600,000 prior to expiration of the
Federal regular tax NOL carryforwards which will expire in 2008.
Based on the Company's historical and projected pretax earnings,
management believes it is more likely than not that the Company
will realize the benefit of the Federal regular tax NOL
carryforward existing at December 31, 1993 before such
carryforward expires in 2008. In addition, the remaining
deferred tax assets, exclusive of the MT credit carryforwards,
are considered current and expected to reverse in the next twelve
months.
The Company's consolidated Federal income tax returns for the
years 1987 through 1989 have been examined by the Internal
Revenue Service resulting in a revenue agent report (RAR). The
Company's carryforwards referred to above and the accompanying
consolidated financial statements reflect adjustments resulting
from the RAR. The RAR had no effect on the Company's results of
operations.
On January 1, 1993, the Company implemented Statement of
Financial Accounting Standards No. 109 (SFAS 109), "Accounting
for Income Taxes." Prior to implementation of SFAS 109, the
Company accounted for income taxes under Accounting Principles
Board Opinion No. 11 (APB 11). Implementation of SFAS 109
changed the method of accounting for income taxes from the
deferred method required under APB 11 to the asset and liability
method. Under the deferred method, annual income tax expense was
matched with pretax accounting income by providing deferred taxes
at the then current tax rates for timing differences between
pretax accounting income and taxable income. The objective of
the asset and liability method is to establish deferred tax
assets and liabilities for the temporary differences between the
financial reporting basis and the tax basis of assets and
liabilities at enacted tax rates expected to be in effect when
such temporary differences are realized or settled. The Company
elected to implement SFAS 109 on a prospective basis.
SFAS 109 provides that regulated enterprises are allowed to
recognize adjustments resulting from the adoption of SFAS 109 as
regulatory tax assets or liabilities if such amounts are probable
of being recovered from or returned to customers through future
rates.
Deferred taxes recorded under APB 11 were attributable
primarily to differences associated with book and tax
depreciation. Temporary differences under SFAS 109 include all
items considered timing differences under APB 11, as well as
certain new items including (1) a reduction in the depreciable
tax basis due to ITC, (2) ITC accounted for under the deferred
method and (3) prior flow-through treatment of tax benefits.
Adoption of SFAS 109 has affected the consolidated balance
sheet due to deferred Federal income tax effects for temporary
differences associated with prior flow-through ratemak
<page 30>
ing accounting practices, treatment of tax rate changes and
unamortized ITC. Unamortized ITC represent amounts being shared
with customers as future revenue requirements are reduced by the
amortization of accumulated deferred ITC. This gives rise to a
corresponding regulatory liability to reflect the ratemaking
treatment.
SFAS 109 requires the recognition of regulatory and deferred
tax assets and liabilities for the cumulative unrecognized
temporary differences. The result as of January 1, 1993 of
implementing SFAS 109 was as follows:
<TABLE>
<CAPTION>
December 31, Reclassi- January 1,
1992 fications 1993
(In Thousands)
<S> <C> <C> <C>
Assets:
Deferred charges $ 49,422 (20,262) 29,160
Regulatory tax assets - 17,974 17,974
Accumulated deferred taxes
on income - current - 6,006 6,006
$ 49,422 3,718 53,140
Liabilities:
Accrued taxes $ 22,243 (3,756) 18,487
Accumulated deferred taxes
on income - noncurrent 93,879 (15,719) 78,160
Regulatory tax liabilities - 23,193 23,193
$116,122 3,718 119,840
</TABLE>
The above reclassifications resulted from the recognition of
regulatory and deferred tax assets and liabilities for the
cumulative unrecognized temporary differences and
reclassification of certain other balances to comply with the
provisions of SFAS 109. The implementation of SFAS 109 did not
result in any significant charge to operations.
The tax effects of temporary differences that gave rise to
significant portions of net current accumulated deferred taxes on
income and net noncurrent accumulated deferred taxes on income at
December 31, 1993 are presented below (in thousands):
Current accumulated deferred taxes on income:
Deferred tax assets:
Unbilled revenues $ 6,914
Revenues subject to refund 1,053
Other 1,435
9,402
Deferred tax liability - Deferred purchased
power and fuel costs (5,151)
Current accumulated deferred taxes
on income, net $ 4,251
Noncurrent accumulated deferred taxes on income:
Deferred tax assets:
Minimum tax credit carryforwards $ 10,067
Federal regular tax NOL carryforwards 10,005
Other 1,036
21,108
Deferred tax liabilities:
Utility plant, principally due to depreciation
and capitalized basis differences (101,839)
Deferred rate case expenses (2,553)
Deferred loss on reacquired debt (1,823)
Deferred accounting treatment (1,617)
Other 729
(107,103)
Noncurrent accumulated deferred taxes
on income, net $ (85,995)
(5) Commitments and Contingencies
In October 1991, the second unit of TNP One, the Utility's
two-unit, 300-megawatt, circulating fluidized bed generating
facility, was completed and successfully placed in operation. At
December 31, 1993, the costs of Unit 1 totalled approximately
$357 million and the costs of Unit 2 totalled approximately
$282.9 million.
The Utility has received rate orders (in Docket Nos. 9491 and
10200) from the PUCT placing the majority of the costs of the two
units of TNP One in rate base, resulting in rate increases for
the Utility's Texas customers. In Docket No. 9491, the PUCT
disallowed from rate base approximately $39.5 million of the
costs of Unit 1. On appeal, a State district court overturned
the disallowances; however, a Texas Court of Appeals rendered a
judgment partially reversing the State district court. In its
October 16, 1992 rate order in Docket No. 10200, the PUCT
disallowed $21.1 million of the costs of Unit 2 . On rehearing
of Docket No. 10200, the PUCT unexpectedly reversed consistent
precedent to adopt a new methodology for calculating the amount
allowed in rates for Federal income taxes. The immediate result
was a reduction in the rate increase previously granted on
October 16, 1992. Each of the rate orders is the subject of
continuing appellate process in the courts. Further detailed
information of Docket Nos. 9491 and 10200 is provided below.
In litigating Docket Nos. 9491 and 10200, the Utility's
<page 31>
opponents are seeking, among other things, lower rates and
greater disallowances, and the Utility is seeking higher rates
and no disallowances. While the ultimate outcome of these cases
and of other matters discussed below cannot be predicted, the
Utility is vigorously pursuing their favorable conclusion.
Material adverse resolution of certain of the matters discussed
below would have a material adverse impact on earnings in the
period of resolution.
PUCT Docket No. 9491
On February 7, 1991, in Docket No. 9491, the PUCT approved an
increase in annualized revenues of approximately $36.7 million,
or 67% of the Utility's original $54.9 million rate request filed
in 1990. The approval allowed $298.5 million of the costs of TNP
One, Unit 1 in rate base; however, the PUCT disallowed $39.5
million of the requested investment costs of $338 million for
that unit. Additional Unit 1 costs, not requested in Docket No.
9491, were included in the Utility's subsequent Texas rate
request, Docket No. 10200, filed on April 11, 1991.
In Docket No. 9491 in Finding of Fact No. 84 (FF No. 84), the
PUCT also found that the Utility failed to prove that its
decision to start construction of Unit 2 was prudent. Since the
costs incurred for Unit 2 construction were not at issue in the
Docket No. 9491 proceeding, the quantification of a disallowance,
if any, that might result from this finding was to be determined
subsequently in Docket No. 10200.
On June 5, 1991, the Utility filed a petition in a Travis
County district court which sought to overturn the PUCT's ruling
regarding the disallowances and prudence decisions in Docket No.
9491. Certain intervenors also appealed other aspects of the
PUCT's decisions in Docket No. 9491. On July 6, 1992, the
presiding judge of the district court signed a judgment finding
that the PUCT's disallowance of rate base treatment for certain
costs of Unit 1 was in error and that the PUCT's "decision to
deny $39,508,409 in capital costs for TNP One Unit 1 is not
supported by substantial evidence and is arbitrary and
capricious."
The Utility, the PUCT and certain of the intervenor cities
(the Cities) appealed the district court's judgment regarding the
appeal of the PUCT's decision in Docket No. 9491 to the Third
District Court of Appeals in Austin, Texas. The Utility's appeal
related to the district court s decision which upheld the PUCT
finding that the Utility failed to prove that its decision to
start construction of Unit 2 was prudent and certain other
matters. The PUCT and the Cities sought to reinstate the
disallowances, and the Cities sought, among other things, to deny
rate base treatment and to significantly lower rates granted by
the PUCT.
On August 25, 1993, the Third District Court of Appeals
rendered a judgment partially reversing the district court and
affirming the PUCT s disallowances for $30.4 million of the total
$39.5 million. The Court of Appeals judgment states that the
district court erred in (1) reversing that part of the PUCT's
order disallowing "the Compressed Schedule Payment, the Force
Majeure Payment, and a portion of the increased costs for the
installation of a natural gas pipeline in Change Order No. 9,
Item 2;" (2) affirming that part of the PUCT's order dealing with
the prudence of the decision to construct Unit 2 (FF No. 84); and
(3) affirming that part of the PUCT's order that failed to pass
on to ratepayers the federal income tax savings for expenses
disallowed by the PUCT. The Court of Appeals remanded the cause
to the district court with instructions that the cause be
remanded to the PUCT for proceedings not inconsistent with the
appellate opinion.
On September 9, 1993, the Utility, the Cities and the PUCT
filed motions for rehearing with the Court of Appeals. The PUCT
is not expected to act upon the district court's ordered remand,
discussed above, until the appellate process, including appeals
to the Texas Supreme Court, has been completed.
Based upon the opinions of the Utility's Texas regulatory
counsel, Johnson & Gibbs, a Professional Corporation, management
believes that it will prevail in obtaining a remand of a
significant portion of the disallowances in Docket No. 9491;
however, the ultimate disposition and quantification of these
items cannot presently be determined. Accordingly, no provision
for any loss that may ultimately be required upon resolution of
these matters has been made in the accompanying consolidated
financial statements.
If the Utility is not successful in obtaining a final
favorable disposition in the appellate proceedings relating to
the disallowances in Docket No. 9491, a write-off of some portion
of the $39.5 million disallowances would be required, which could
result in a significant negative impact on earnings in the period
of final resolution.
PUCT Docket No. 10200
On April 11, 1991, the Utility filed a rate application,
Docket No. 10200, with the PUCT for inclusion of $275.2 million
of capital costs of Unit 2 and $16.1 million of additional
capital costs of Unit 1 in the Utility's rate base.
The Administrative Law Judge (ALJ) in Docket No. 10200
initially required briefs of all parties on the issue of whether
the inclusion of Unit 2 in the Utility's rate base would be
precluded by the PUCT finding in Docket No. 9491, FF No. 84,
that the Utility failed to prove that its decision to start
construction of Unit 2 was prudent. In its brief to the ALJ, the
Utility argued that FF No. 84 could not have the effect of
barring litigation in Docket No. 10200 of all aspects of Unit 2
costs, asserting that evidence as to Unit 2 costs presented in
Docket No. 9491 had been presented for the purpose of discussion
of facilities which were common to both Unit 1 and Unit 2. The
General Counsel of the PUCT argued that the issue of the
Utility's prudence as to Unit 2 was barred by FF No. 84 and
requested that the Utility's entire prudence testimony in Docket
No. 10200 be stricken, along with all associated schedules and
exhibits.
The ALJ ruled on June 7, 1991 that the PUCT's finding in
<page 32>
Docket No. 9491 could not be relitigated in Docket No. 10200.
However, the ALJ determined that the PUCT did not decide "what
specific action by TNP, instead of beginning construction when it
did, would have been prudent" and that the PUCT did not "quantify
the disallowance resulting from its finding that TNP had failed
to prove that beginning construction of Unit 2 was prudent."
Therefore, the ALJ concluded that the parties could raise those
particular issues in Docket No. 10200. The ALJ further stated
that, "The disallowance, if any, will be determined using
principles set forth in previous cases regarding prudence." The
ALJ determined that, in order for the Utility's request for
inclusion of the Unit 2 investment in rate base as plant in
service to be considered, the Utility must present a prima facie
case in its direct testimony as to how a disallowance resulting
from FF No. 84 should be quantified. The Utility appealed the
ALJ's ruling to the PUCT, which voted not to hear the appeal. On
August 16, 1991, the Utility filed supplemental prudence
testimony, under protest, responding to the ALJ's order and
supporting the Utility's entitlement to rate base treatment for
the costs of Unit 2. In its supplemental testimony, the Utility
contended that it prudently could have released Unit 2 for
construction in February 1989, rather than September 1988, when
the unit was actually released. The Utility argued that this
alternative would cost no less than the actual cost of Unit 2,
and thus no disallowance should result from any imprudence in
releasing Unit 2 for construction in September 1988. Two
intervenors in this proceeding objected to the Utility's
presentation of a prudent alternative, but the PUCT included such
evidence in the record.
In a "final" order dated October 16, 1992, the PUCT
commissioners approved an increase in annualized revenues of $26
million, or 72% of the Utility's original $35.8 million requested
increase. The PUCT's order determined that the reasonable costs
for Unit 2 were $261.8 million. The PUCT allowed in rate base
$250.7 million of the $275.2 million requested for Unit 2 costs.
The difference between the $261.8 million in costs found to be
prudent by the PUCT and the $282.9 million total costs of Unit 2
consisted of disallowances of approximately $21.1 million. The
PUCT also determined that $11.1 million of Unit 2 costs will be
addressed in a future Texas rate application.
The order in Docket No. 10200 also allowed approximately
$15.3 million of the requested approximately $16.1 million of
Unit 1 costs not sought by the Utility in Docket No. 9491. The
approximately $800,000 disallowance was primarily related to debt
service on disallowed costs determined in Docket No. 9491.
Subsequent to the issuance of the "final" order on October
16, 1992, motions for rehearing of certain issues were filed by
parties to the case. On December 22, 1992, the PUCT issued an
Order on Rehearing which reduced the $26 million increase in
annualized revenues that was originally granted by the PUCT in
its order on October 16, 1992.
The primary issue in the Order on Rehearing was the PUCT's
reversal of its original Docket No. 10200 order as to the use of
the "return method" for calculating the amount allowed in cost of
service for the Utility's Federal income tax expense. The
"return method" of computing Federal income tax expense requested
by the Utility followed consistent precedent of the PUCT. The
concept of the return method is to match a utility s taxes with
the same revenues and expenses included in rates. The new method
adopted by the PUCT in the Order on Rehearing flowed through to
ratepayers the tax benefits of expenses disallowed and not
included in rates. The net effect of this Order on Rehearing
was a decrease of approximately $7 million from the October 16,
1992 order, resulting in a $19 million increase in annualized
revenues.
On January 26, 1993, the PUCT considered motions for
rehearing on the December 22, 1992 Order on Rehearing but did not
alter the $19 million increase in annualized revenues or the
disallowances. In its Order on Rehearing, dated February 4,
1993, the PUCT ordered the Utility to seek a private letter
ruling from the Internal Revenue Service (IRS) to determine if
the Order on Rehearing resulted in violations of the
"normalization" rules concerning investment tax credits and
accelerated tax depreciation on public utility property.
The PUCT's February 4, 1993 Order on Rehearing stated that
the tax method utilized does not violate the "normalization"
rules of the Internal Revenue Code; however, a December 1992
private letter ruling of the IRS to an unrelated utility
indicates that regulatory treatment which flows through tax
benefits of investment tax credits on disallowed public utility
property violates the "normalization" rules. A "normalization"
violation ultimately results in a utility's loss of benefits from
investment tax credit and/or accelerated depreciation on public
utility property. Without the curative action of the PUCT on
March 10, 1993, discussed in the following paragraph, an IRS
determination that a "normalization" violation had occurred would
subject the Utility to paying additional income taxes for the
amount of the accumulated deferred investment tax credits as of
the time of the violation and taxes on the amount of tax
depreciation in excess of book depreciation for all tax years
open for IRS review.
On March 10, 1993, the PUCT considered motions for rehearing
on the February 4, 1993 Order on Rehearing and expressed its
position that its earlier actions not create a "normalization"
violation for the Utility. As a result, in its Order on
Rehearing, dated March 18, 1993, the PUCT ordered that the
Utility be granted, subject to refund, an additional $1.6 million
in annualized revenues which matches recovery in rates with only
the investment tax credits and accelerated tax depreciation
related to utility property included in rate base. Accordingly,
the benefits of investment tax credits and accelerated tax
depreciation related to disallowed public utility property would
not be passed through to ratepayers; therefore, the Utility
believes that the "normalization" rules with respect to
<page 33>
investment tax credits and accelerated tax depreciation would not
be violated. Further, the PUCT affirmed its February 4, 1993
Order on Rehearing directing the Utility to seek a private letter
ruling from the IRS to determine if the earlier methodology
adopted in the December 22, 1992 Order on Rehearing would violate
the "normalization" rules concerning investment tax credits and
accelerated tax depreciation on public utility property. If the
IRS determines that the PUCT's December 22, 1992 order would not
constitute a "normalization" violation, then the additional $1.6
million in annualized revenues would be revoked by the PUCT, and
the Utility would be required to refund excess amounts collected.
The PUCT did not reverse its December 22, 1992 position to pass
through to ratepayers the tax benefits of interest charges
related to disallowed public utility property. The net resultant
effect of Docket No. 10200 (by the PUCT action of March 10, 1993)
is an increase in annualized revenues of $20.6 million, of which
$1.6 million is subject to refund.
The March 18, 1993 Order on Rehearing was appealed by the
Utility and certain intervening parties to a State district
court. Because of the Court of Appeals judgment relating to FF
No. 84 in the Docket No. 9491 appeals, the presiding judge in the
State district court for the Docket No. 10200 appeal has ordered
that the procedural schedule in this appeal be abated until final
resolution of the FF No. 84 issue in Docket No. 9491. The
Utility will vigorously pursue reversal of the PUCT's new
position regarding Federal income tax expense in addition to
seeking judicial relief from the disallowances and certain other
rulings by the PUCT in Docket No. 10200.
During the third quarter of 1993, the Utility refunded, to
the appropriate Texas customers, amounts collected under bonded
rates in excess of the $20.6 million in annualized revenues
granted on rehearing in Docket No. 10200. The refund
(approximately $18 million, including interest) was related to
the period beginning on the effective date for bonded rates
(October 16, 1991) through April 1993.
After receiving PUCT approval on October 19, 1993, the
Utility filed, on October 20, 1993, a request with the IRS for a
private letter ruling on the issue of a "normalization" violation
resulting from the PUCT's proposed treatment of investment tax
credits and accelerated tax depreciation. Revenues related to the
conditionally granted $1.6 million annualized increase will not
be refunded unless the IRS determines that a "normalization"
violation would not result from flowing through benefits of
investment tax credits and accelerated tax depreciation related
to disallowed public utility property. If the IRS so determines,
a refund will be made after that determination. Accordingly,
revenues associated with the $1.6 million annualized increase
have not been recognized in results of operations as of December
31, 1993, and a provision for revenues subject to refund,
including interest, has been made for $3.4 million in the
consolidated balance sheet as of December 31, 1993. The Utility
expects to receive the private letter ruling in 1994.
Based upon the opinions of the Utility's Texas regulatory
counsel, Johnson & Gibbs, a Professional Corporation, management
believes that it will prevail in obtaining a remand of a
significant portion of the disallowances in Docket No. 10200;
however, the ultimate disposition and quantification of these
items cannot presently be determined. Accordingly, no provision
for any loss that may ultimately be required upon resolution of
these matters has been made in the accompanying consolidated
financial statements.
If the Utility is not successful in obtaining a final
favorable disposition in the appellate proceedings relating to
the disallowances in Docket No. 10200, a write-off of some
portion of the $21.9 million disallowances would be required,
which could result in a significant negative impact on earnings
in the period of final resolution.
Other TNP One Matters
In Docket No. 9491, the Utility requested deferred accounting
treatment (DAT) for Unit 1 which would (1) defer $1.4 million and
$2.8 million of operating costs and interest costs, respectively,
(2) recover such amounts in rates through amortizations over the
life of the unit and (3) include such unamortized amounts in the
Utility's rate base, thereby recovering a carrying cost on the
unamortized amount.
The PUCT granted the Utility's DAT request except the
inclusion of interest costs ($2.8 million) in rate base. In the
final order meeting for Docket No. 9491, the PUCT commissioners
indicated that their decision to exclude interest costs from the
Utility's rate base was influenced by a recent appeals court
ruling. In that ruling, which involved an appeal of a decision
by the PUCT granting DAT to an unrelated electric utility, the
appeals court found that the DAT component for interest costs
could not be included in rate base. The electric utility has
filed an application for writ of error with the Texas Supreme
Court regarding the appeals court ruling. The ultimate effect of
the appeals court ruling on the order granting DAT for Unit 1 is
uncertain at this time.
The Utility entered into a fuel supply agreement dated
November 18, 1987 with Phillips Coal Company (Phillips), owner of
a 300-million-ton lignite reserve in Robertson County in
proximity to TNP One. The agreement provides for a lignite fuel
source for the 38-year life of TNP One. Phillips subsequently
entered into an agreement with a subsidiary of Peter Kiewit
Sons', Inc. for development of the lignite mine by a joint
venture partnership, Walnut Creek Mining Company. Unit 1 and
Unit 2 are capable of utilizing Western coal, petroleum coke and
natural gas as alternative fuel sources.
Legal Actions
The Utility is involved in various claims and other legal
actions arising in the ordinary course of business. In the
opinion of management, the ultimate disposition of these matters
will not have a material adverse effect on the Utility's and the
Company's consolidated financial position.
<page 34>
SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
The following selected quarterly consolidated financial data
is unaudited, and, in the opinion of the Company's management, is
a fair summary of the results of operations for such periods:
<TABLE>
<CAPTION>
March 31 June 30 Sept. 30 Dec. 31
(In thousands - except per share amounts)
<S> <C> <C> <C> <C>
1993
Operating revenues $103,150 107,530 150,067 113,495
Net operating income $ 14,454 15,722 29,576 18,488
Net earnings (loss) $ (1,866) (410) 13,579 302
Earnings (loss) available
for common stock $ (2,099) (634) 13,368 91
Weighted average number of
common shares outstanding 10,604 10,626 10,653 10,680
Earnings (loss) per share of
common stock $ (0.20) (0.06) 1.25 0.01
Dividends per share of
common stock $ 0.4075 0.4075 0.4075 0.4075
1992
Operating revenues $ 98,719 105,847 137,287 101,974
Net operating income $ 15,625 19,669 29,110 12,599
Net earnings (loss) $ (772) 2,881 12,653 (3,832)
Earnings (loss) available
for common stock $ (1,027) 2,635 12,420 (4,066)
Weighted average number of
common shares outstanding 8,333 8,406 8,492 8,945
Earnings (loss) per share
of common stock $ (0.12) 0.31 1.46 (0.45)
Dividends per share of
common stock $0.4075 0.4075 0.4075 0.4075
</TABLE>
Generally, variations between quarters reflect seasonal
variations in sales, increases in the weighted average number of
common shares outstanding and other factors. In addition,
quarterly results of operations have been affected by
implementation in 1993 of Statement of Financial Accounting
Standards No. 106, Employers Accounting for Postretirement
Benefits Other Than Pensions, variations in interest charges,
rate orders received by the Utility, customer growth and changes
in customer usage. See notes 1(j), 2 and 5 to the consolidated
financial statements and Management's Discussion and Analysis of
Financial Condition and Results of Operations for a discussion of
these matters.
<page 35>
SELECTED ANNUAL CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
(In thousands except per share amounts and
percents)
<S> <C> <C> <C> <C> <C>
Operating revenues $ 474,242 443,827 441,343 397,289 378,289
Power purchased for resale $ 200,183 174,257 216,818 253,416 257,259
Total operating expenses $ 396,002 366,824 378,778 360,220 349,755
Net operating income $ 78,240 77,003 62,565 37,069 28,534
Net earnings $ 11,605 10,930 19,533 16,352 16,759
Earnings available for common stock $ 10,726 9,962 18,455 15,137 15,408
Common shares outstanding:
Weighted average 10,641 8,545 8,275 8,207 8,130
End of year 10,696 10,598 8,318 8,238 8,179
Per share of common stock:
Earnings $ 1.01 1.17 2.23 1.84 1.90
Cash dividends declared $ 1.63 1.63 1.63 1.63 1.55
Book value $ 19.97 20.62 21.45 20.86 20.66
Total assets (1) $1,105,237 1,182,707 1,122,591 807,854 442,840
Capitalization:
Common stock equity $ 213,627 218,535 178,388 171,839 168,946
Redeemable cumulative preferred stocks 9,560 10,440 11,320 12,600 13,880
Long-term debt, net of amount
due within one year (2, 3, 4) 678,994 742,087 525,060 350,301 134,893
Total capitalization $ 902,181 971,062 714,768 534,740 317,719
Capitalization ratios:
Common stock equity 23.7% 22.5 25.0 32.1 53.2
Redeemable cumulative preferred stocks 1.1 1.1 1.6 2.4 4.4
Long-term debt, net of amount due
within one year (2, 3) 75.2 76.4 73.4 65.5 42.4
Total capitalization 100.0% 100.0 100.0 100.0 100.0
Short-term debt:
Long-term debt due within one
year (2, 3, 4) $ 1,070 10,288 201,276 78,570 516
Notes payable to banks, unsecured (3) 36,000 41,900 13,900
$ 1,070 10,288 237,276 120,470 14,416
<FN>
(1) The significant increases in total assets for 1990 and 1991
reflect the assumption of the costs of Unit 1 and Unit 2,
respectively. Unit 1 and Unit 2 are two 150-megawatt
lignite-fueled generating units using circulating fluidized bed
technology. See Management's Discussion and Analysis of
Financial Condition and Results of Operations and notes 2 and 5
to the consolidated financial statements for more information
about the units.
(2) The significant increases in long-term debt in 1990 and 1991
reflect the assumption of the debt obligations of the financing
facilities related to Unit 1 and Unit 2, respectively. See note
2 to the consolidated financial statements for more information
about the financing facilities.
(3) With proceeds from the issuances of long-term debt securities
in January 1992, the Utility repaid and prepaid certain amounts
under the Unit 1 and Unit 2 financing facilities and repaid a
portion of outstanding unsecured notes payable to banks.
(4) With proceeds from the issuances of long-term debt securities
in September 1993, the Utility prepaid additional amounts under
the Unit 1 and Unit 2 financing facilities. See note 2 to the
consolidated financial statements for more information.
See Management's Discussion and Analysis of Financial Condition
and Results of Operations and note 5 to the consolidated
financial statements for discussion of material uncertainties
which might cause the information above not to be indicative of
future financial condition or results of operations.
</TABLE>
<page 36>
SELECTED ELECTRIC OPERATING STATISTICS
<TABLE>
<CAPTION>
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
Operating revenues - thousands
of dollars:
Residential $ 193,484 175,885 176,651 153,844 143,070
Commercial 138,680 128,550 119,745 102,320 95,302
Industrial 124,474 121,027 128,356 125,640 125,098
Other 17,604 18,365 16,591 15,485 14,819
Total $ 474,242 443,827 441,343 397,289 378,289
Sales thousand kilowatt-hours:
Residential 2,047,360 1,947,593 2,017,349 1,998,727 1,915,772
Commercial 1,567,083 1,499,927 1,485,211 1,441,275 1,363,518
Industrial 2,567,552 2,508,837 2,798,369 2,848,020 2,796,162
Other 104,882 109,954 115,406 133,549 136,701
Total (a) 6,286,877 6,066,311 6,416,335 6,421,571 6,212,153
Number of customers end of period:
Residential 181,289 178,154 174,859 172,560 170,860
Commercial (b) 30,235 30,359 30,300 30,161 29,828
Industrial (b, c) 141 155 160 173 188
Other 246 229 230 227 229
Total 211,911 208,897 205,549 203,121 201,105
Average annual use per residential
customer KWH 11,362 11,003 11,584 11,613 11,236
Average annual revenue per residential
customer dollars 1,067 987 1,010 892 839
Average revenue per KWH sold
residential - cents 9.45 9.03 8.76 7.70 7.47
Average revenue per KWH sold
total sales - cents 7.54 7.32 6.88 6.19 5.98
Source net generated and purchased
thousand kilowatt-hours:
Generated 2,363,493 2,247,664 1,337,366 395,852 198
Purchased 4,385,697 4,261,129 5,452,132 6,375,418 6,596,650
Total (a) 6,749,190 6,508,793 6,789,498 6,771,270 6,596,848
Average cost per KWH generated and
purchased - cents 4.13 3.86 3.94 3.92 3.94
Net utility plant - in thousands of
dollars $1,005,995 1,015,709 1,016,602 728,989 363,242
Electric line total pole miles 10,532 10,472 10,397 10,335 10,280
Estimated population served at retail 616,000 605,000 595,000 587,000 581,000
Total employees 1,051 1,086 1,104 1,121 1,105
<FN>
(a) Difference between total sources and total sales represents
Utility use and line losses.
(b) Three and seven industrial customers became commercial
customers during 1993 and 1991, respectively.
(c) Ten industrial customers were combined into two industrial
customers for billing purposes during 1993.
</TABLE>
<page 37>
COMMON STOCK INFORMATION
In February 1994, the Company's Board of Directors declared
quarterly common stock dividends of $0.4075 per share. This
produces an indicated annual dividend of $1.63 per share. None
of the dividends paid during 1993 constituted a return of
capital.
As of December 31, 1993, the Company had 7,031 common
shareholders of record.
During 1993, the Company obtained $1.7 million of new capital
during the year by issuing 98,296 shares of common stock to the
Dividend Reinvestment and Stock Purchase Plan and the Utility's
Thrift Plan for Employees.
The Company has a Shareholder Rights Plan which is described
in note 1(m) to the consolidated financial statements.
Charter provisions, bond indentures, and financing facilities
contain certain restrictions as to the payment of cash dividends
on common stock of the Utility. Explanations of these
restrictions are included in notes 2 and 3 to the consolidated
financial statements.
<TABLE>
Quarterly Dividends Paid Per Share *
1993 1992
<S> <C> <C>
1st Quarter $0.4075 0.4075
2nd Quarter 0.4075 0.4075
3rd Quarter 0.4075 0.4075
4th Quarter 0.4075 0.4075
Yearly $1.6300 1.6300
<FN>
*Through 1993, TNP Enterprises, Inc., or its predecessor
companies, paid 232 consecutive quarterly dividends.
</TABLE>
Market Price Range Price of Common Stock
(as reported by the New York Stock Exchange)
<TABLE>
1993 1992
High Low High Low
<S> <C> <C> <C> <C>
1st Quarter $19 3/8 18 1/8 21 1/4 19
2nd Quarter 19 1/2 17 1/2 20 3/4 18 1/2
3rd Quarter 17 7/8 14 5/8 21 5/8 17 1/4
4th Quarter 17 3/4 16 3/8 21 1/2 17 1/4
Yearly $19 1/2 14 5/8 21 5/8 17 1/4
</TABLE>
<page 38>
DIRECTORS AND OFFICERS
Board of Directors
TNP Enterprises, Inc. and
Texas-New Mexico Power Company
R. D. Woofter (19), A, B, C, D
Chairman
TNP Enterprises, Inc.
Texas-New Mexico Power Company
Fort Worth, Texas
R. Denny Alexander (5), A, B
Owner
R. Denny Alexander & Co.
(investment management)
Fort Worth, Texas
Cass O. Edwards II (19), A, C
Managing Partner
Edwards-Geren Limited
(ranching and farming)
Fort Worth, Texas
John A. Fanning (10), A, B
Executive Vice President
Snyder Oil Corporation
Fort Worth, Texas
Harris L. Kempner, Jr. (14), B, D
President
Kempner Capital Management
Galveston, Texas
Dr. T. S. Mackey, P.E.* (17), C, D
President
Key Metals & Minerals Engineering Corp.
Texas City, Texas
Dwight R. Spurlock (1), B, D
Interim President & Chief Executive Officer
TNP Enterprises, Inc.
Texas-New Mexico Power Company
Fort Worth, Texas
Gail Potts Williamson** (1)
Chairman of the Board
Williamson-Dickie Manufacturing Company
Fort Worth, Texas
*A member of the Board and Committees until the
time of his death on February 25, 1994
**Advisory Director-TNP Enterprises, Inc. and
Texas-New Mexico Power Company
(A) Audit Committee
(B) Financial Committee
(C) Personnel, Organization and Nominating Committee
(D) Administrative Committee of Employee Benefits
(Numerals indicate years on board)
Officers
TNP Enterprises, Inc.
D. R. Spurlock
Interim President &
Chief Executive Officer
D. R. Barnard
Vice President &
Chief Financial Officer
M. D. Blanchard
Secretary
M. W. Smith
Treasurer
B. Jan Adkins
Assistant Secretary
Officers
Texas-New Mexico Power Company
D. R. Spurlock
Interim President &
Chief Executive Officer
Retired in 1992 with 33 years of service
D. R. Barnard (32)
Sector Vice President -
Chief Financial Officer
J. V. Chambers, Jr. (15)
Sector Vice President -
Revenue Production
M. C. Davie (29)
Vice President - Corporate Affairs
A. B. Davis (28)
Vice President - Chief Engineer
L. W. Dillon (18)
Vice President - Operations
R. J. Wright (14)
Vice President -
Corporate Services/Generation
T. R. Ownby (20)
Assistant Vice President
M. D. Blanchard (10)
Secretary & General Counsel
M. W. Smith (7)
Treasurer
B. Jan Adkins (24)
Assistant Secretary
P. L. Bridges (3)
Assistant Treasurer
G. L. Spooner (24)
Assistant Treasurer
(Numerals indicate years of service)
Division Managers
Texas-New Mexico Power Company
J. L. Sears (19)
Central Division
C. N. Bundick (20)
New Mexico Division
D. L. Hudson (41)
Northern Division
D. H. Bryson (32)
Southeast Division
J. W. Garrison (38)
Western Division
Numerals indicate years of service)
<PAGE 39>
SHAREHOLDER INFORMATION
Annual Meeting
The annual meeting of TNP Enterprises, Inc. will be held
Thursday, April 28, 1994 at 11:00 a.m., Central Time, at 4100
International Plaza, Fort Worth, Texas. In connection with this
meeting, proxies will be solicited by the Board of Directors of
the Company. A notice of the meeting, together with a proxy
statement, a form of proxy and the Annual Report to Shareholders
for 1993, were mailed on or about March 28, 1994 to shareholders
of record as of March 9, 1994.
Form 10-K Available
TNP Enterprises, Inc. will file its annual report on Form
10-K with the Securities and Exchange Commission by March 30,
1994. Many of the SEC's 10-K information requirements are
satisfied by this 1993 annual report. However, a copy of the
Form 10-K, including the consolidated financial statements and
schedules, will be available without charge after March 31, 1994
by writing to the Treasurer of TNP Enterprises, Inc., P.O. Box
2943, Fort Worth, Texas, 76113.
The information contained in this report is given in response
to general requests for information about the Company, and not in
connection with any sale, offer of sale or solicitation of an
offer to buy any securities.
Registrar, Transfer Agent and
Dividend Disbursing Agent for
Preferred Stocks and Common Stock
Society National Bank
3200 Renaissance Tower
1201 Elm Street
Dallas, Texas 75270
1-800-527-7844
<page 40>
