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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. 2-97230
TEXAS-NEW MEXICO POWER COMPANY
(Exact name of registrant as specified in its charter)
TEXAS 75-0204070
(State of incorporation) (I.R.S. Employer Identification Number)
4100 International Plaza
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: None
Securities registered pursuant to Section 12(g) of the Act: None
Registrant is reporting pursuant to Section 15(d) of the Act:
Title of Each Class of Securities
First Mortgage Bonds:
Series M, 8.7% due 2006, Series R, 10.0% due 2017, Series S, 9.625% due 2019,
Series T, 11.25% due 1997 and Series U, 9.25% due 2000.
Secured Debentures:
12.5% due 1999
Series A, 10.75% due 2003
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 amendment to this
Form 10-K. [X]
As of March 11, 1994, all 10,705 shares of the Registrant's outstanding Common
Stock ($10 par value) were held, beneficially and of record, by the Registrant's
parent, TNP Enterprises, Inc.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
PART 1
Item 1. BUSINESS.
General Development of Business
Texas - New Mexico Power Company
Texas-New Mexico Power Company (Utility) 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 the principal subsidiary of TNP Enterprises, Inc. (TNPE),
a Texas corporation which owns all of the Utility's common stock. TNPE
also files a Form 10-K. The Utility and TNPE 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.
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. All financial information presented herein or
incorporated by reference is on a consolidated basis and all intercompany
transactions and balances have been eliminated.
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.
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. See note 2 to the consolidated
financial statements 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 Item 7, "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Financial Information About Industry Segments
1993 1992 1991
Operating Revenues
(thousands of dollars):
Residential $193,484 175,885 176,651
Commercial 138,680 128,550 119,745
Industrial 124,474 121,027 128,356
Other 17,604 18,365 16,591
Total $474,242 443,827 441,343
Sales
(thousand kilowatt-hours):
Residential 2,047,360 1,947,593 2,017,349
Commercial 1,567,083 1,499,927 1,485,211
Industrial 2,567,552 2,508,837 2,798,369
Other 104,882 109,954 115,406
Total 6,286,877 6,066,311 6,416,335
Number of customers
(at year-end):
Residential 181,298 178,154 174,859
Commercial 30,235 30,359 30,300
Industrial 141 155 160
Other 237 229 230
Total 211,911 208,897 205,549
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 Item 7, "Management's Discussion and Analysis of Financial Condition
and Results of Operations," for a discussion of the changes in operating
revenues, including rate increases.
It is not possible to attribute operating profit or loss and identifiable
assets to each of the classes of customers listed in the above table.
Narrative Description of Business
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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%
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
The Utility obtained its electric energy requirements during the year
ended December 31, 1993, from sources shown in the following table.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Sources of Energy
Year of Percent
Contract of Energy Fuel
Sources* Area Served Expiration Required Source
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 Texas2010 & 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%
* 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
Terminations of service by those suppliers regulated by the FERC (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 Item 3, "Legal Proceedings," Item 7,
"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.
Recovery of Purchased Power and Fuel Costs
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. 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.
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
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.
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 electric 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 juris-
diction 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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
systems 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
systems 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 for additional
information.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 note 5 to the consolidated financial
statements and Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
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.
All of the Utility's issued and outstanding common stock, 10,705
shares, is privately held, beneficially and of record, by its parent,
TNPE, and is not publicly traded.
For the years ended December 31, 1993 and 1992, the Utility paid
$17,344,000, and $13,840,200, respectively, in common dividends to its
parent, TNPE. Dividends were paid on a quarterly basis. Restrictions
on the Utility's ability to pay dividends are discussed in notes 2 and
3 to the consolidated financial statements.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Item 6. SELECTED CONSOLIDATED FINANCIAL DATA.
1993 1992 1991 1990 1989
(Dollars in Thousands)
Operating revenues $474,242 443,827 441,343 397,289 378,289
Net operating income $78,240 77,003 62,565 37,069 28,534
Net earnings $11,523 10,845 19,840 15,376 15,315
Earnings available for
common stock $10,644 9,877 18,762 14,161 13,964
Total assets (1) $1,095,119 1,156,567 1,111,281 789,651 409,869
CAPITALIZATION:
Common stock equity $214,184 205,875 171,393 166,419 136,068
Redeemable cumulative
preferred stock 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 $902,738 958,402 707,773 529,320 284,841
CAPITALIZATION RATIOS:
Common stock equity 23.7% 21.5 24.2 31.4 47.8
Redeemable cumulative
preferred stock 1.1 1.1 1.6 2.4 4.9
Long-term debt, net of
amount due within one
year (2)(3) 75.2 77.4 74.2 66.2 47.3
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
Unsecured notes payable
to banks (3) - - 36,000 41,900 13,900
$1,070 10,288 237,276 120,470 14,416
Per common share information omitted; see Item 5.
(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 Items 1, 2, 3 and 7 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 Item 7, "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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
This discussion presents management's analysis of significant factors
in the Utility's financial condition and results of operations and
should be read in conjunction with the consolidated financial
statements and notes thereto.
The Utility currently faces challenges to its 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 Utility'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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
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 Utility's
parent, TNP Enterprises, Inc. (TNPE), 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
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 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 Utility's
parent, 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 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:
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Capital Requirements (1)
1994 1995 1996 1997 1998 1999 Total
(Dollars in Millions)
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
(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.
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 TNPE. 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 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 TNPE. Receipt of future equity contributions by the Utility from
TNPE will be largely dependent upon TNPE's ability to issue common
stock. Since most of the assets, liabilities and earnings capability
of TNPE are those of the Utility, the ability of TNPE 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 TNPE's future financial condition and
adequate and timely regulatory relief, including favorable resolution
of pending judicial appeals of rate cases.
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 Utility 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 Utility 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 Utility'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 Utility. 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.
Results of Operations
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 0.5 0.2
Earnings before interest charges 16.7 17.8 14.4
Total interest charges 14.3 15.4 9.9
Net earnings 2.4% 2.4% 4.5%
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
For information relating to actual KWH sales, number of customers, and
revenues, see Item 1, "Financial Information about Industry Segments."
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 Item 1 under "Sources of
Energy." 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 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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
As discussed in "Accounting for Income Taxes" under "Financial
Condition," implementation of SFAS 109 did not result in any
significant charge to earnings. For more information regarding the
Utility's income taxes, see note 4 to the consolidated financial
statements.
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
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.
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.
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Net Earnings
Net earnings increased $678,000 in 1993 after a significant decline of
$8,995,000 in 1992.
The decline of 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 net earnings also
reflects the adverse tax ruling by the PUCT, discussed above in "PUCT
Docket No. 10200" under "Financial Condition."
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.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Item 8. Consolidated Financial Statements and Supplementary Data.
Independent Auditors' Report
The Board of Directors
Texas-New Mexico Power Company:
We have audited the consolidated financial statements of Texas-New Mexico
Power Company (a wholly owned subsidiary of TNP Enterprises, Inc.) and
subsidiaries as listed in the accompanying index at Part IV. In connection
with our audits of the consolidated financial statements, we also have
audited the financial statement schedules as listed in the accompanying
index. These consolidated financial statements and financial statement
schedules are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements and financial statement schedules 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 Texas-New
Mexico Power Company 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. Also in our opinion, the related 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.
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 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
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
(a wholly owned subsidiary of TNP Enterprises, Inc.)
CONSOLIDATED STATEMENTS OF EARNINGS
Three Years Ended December 31, 1993
1993 1992 1991
(In Thousands)
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) 1,224 2,125 835
Earnings before interest charges 79,464 79,128 63,400
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 . . . . . . . . . 11,523 10,845 19,840
Dividends on preferred stocks . . . . 879 968 1,078
Earnings available for common
stock . . . . . . . . . . . . . $ 10,644 9,877 18,762
See accompanying notes to consolidated financial statements.
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
(a wholly owned subsidiary of TNP Enterprises, Inc.)
CONSOLIDATED BALANCE SHEETS
December 31, 1993 and 1992
ASSETS 1993 1992
(In Thousands)
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. . . . . . . . . . . 541 183
Current assets:
Cash and cash equivalents . . . . . . . . . . . 2,078 63,843
Customer receivables. . . . . . . . . . . . . . 764 122
Refundable income taxes . . . . . . . . . . . . - 2,870
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. . . . . . . . . . . . . . 1,091 985
Total current assets . . . . . . . . . . . . 32,550 93,986
Regulatory tax assets (note 4). . . . . . . . . . 16,915 -
Deferred charges (note 4) . . . . . . . . . . . . 39,118 46,689
$ 1,095,119 1,156,567
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity:
Common stock, $10 par value per share.
Authorized 12,000,000 shares; issued
10,705 shares . . . . . . . . . . . . . . .$ 107 107
Capital in excess of par value. . . . . . . . 175,094 160,085
Retained earnings (note 3). . . . . . . . . . 38,983 45,683
Total common stock equity. . . . . . . . . 214,184 205,875
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 . . . . . . . . . . . 902,738 958,402
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). . . . . . . . . . . . . 18,006 20,136
Customers' deposits . . . . . . . . . . . . . . 4,464 4,236
Revenues subject to refund (note 5) . . . . . . 3,400 17,515
Other current and accrued liabilities . . . . . 13,404 7,932
Total current liabilities. . . . . . . . . 78,909 94,785
Customers' advances for construction. . . . . . . 169 311
Regulatory tax liabilities (note 4) . . . . . . . 20,412 -
Accumulated deferred taxes on income
(note 4). . . . . . . . . . . . . . . . . . . . 75,809 84,917
Accumulated deferred investment tax credits
(note 4). . . . . . . . . . . . . . . . . . . . 17,082 18,152
Commitments and contingencies (note 5)
$ 1,095,119 1,156,567
See accompanying notes to consolidated financial statements.