ITEM 1. BUSINESS
THE COMPANY
Public Service Company of New Mexico (the "Company") was incorporated in the State of New Mexico in 1917 and has its principal offices at Alvarado Square, Albuquerque, New Mexico 87158 (telephone number 505-241-2700). The Company is a public utility engaged in the generation, transmission, distribution and sale of electricity and in the gathering, processing, transmission, distribution and sale of natural gas within the State of New Mexico. The Company also owns facilities for the pumping, storage, transmission, distribution and sale of water in Santa Fe, New Mexico.
On January 11, 1993, the Company announced its intention to dispose of the Company's natural gas gathering and natural gas processing assets and SDCW. Both sales are pending NMPUC approval. (See PART II, ITEM 7. --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- SALE OF GAS GATHERING AND PROCESSING ASSETS" and -- "SALE OF SDCW.")
The total population of the area served by one or more of the Company's utility services is estimated to be approximately 1.2 million, of which 51% live in the greater Albuquerque area.
For the year ended December 31, 1994, the Company derived 68.7% of its utility operating revenues from electric operations, 29.8% from natural gas operations and 1.5% from water operations.
As of December 31, 1994, the Company employed 2,768 persons.
Financial information relating to amounts of revenue and operating income and identifiable assets attributable to the Company's industry segments is contained in note 12 of the notes to consolidated financial statements.
ELECTRIC OPERATIONS
SERVICE AREA AND CUSTOMERS
The Company's electric operations serve four principal markets. Sales to retail customers and sales to firm-requirements wholesale customers, sometimes referred to collectively as "system" sales, comprise two of these markets. The third market consists of other contracted sales to utilities for which the Company commits to deliver a specified amount of capacity (measured in MW) or energy (measured in MWh) over a given period of time. The fourth market consists of economy energy sales made on an hourly basis to utilities at fluctuating, spot-market rates. Sales to the third and fourth markets are sometimes referred to collectively as "off-system" sales.
The Company provides retail electric service to a large area of north central New Mexico, including the cities of Albuquerque, Santa Fe, Rio Rancho, Las Vegas, Belen and Bernalillo. The Company also provides retail electric service to Deming in southwestern New Mexico and to Clayton in northeastern New Mexico. As of December 31, 1994, approximately 323,000 retail electric customers were served by the Company, the largest of which accounted for approximately 3.4% of the Company's total electric revenues for the year ended December 31, 1994.
The Company's largest retail electric customer, Kirtland Air Force Base ("KAFB"), has been recommended by the Department of the Air Force for realignment. Such recommendation will be reviewed by the Base Realignment and Closure Commission ("Closure Commission"). The Company's President and Chief Executive Officer is a member of the Closure Commission. The Closure Commission's recommendation, once finalized, is subject to approval by both the President and Congress. If the proposal is approved, major military units at KAFB would be deployed elsewhere and a portion of the base would be closed. The Department of the Air Force recommendation stated that the realignment could result in a maximum potential reduction of approximately 12,000 jobs
(both direct and indirect) over the 1996-2001 time period in the Bernalillo County area of New Mexico. The Company does not anticipate that such action will have a material effect on its total electric revenues.
The Company holds 23 long-term, non-exclusive franchise agreements for its electric retail operations, expiring between August 1996 and November 2028. The City of Albuquerque (the "City") franchise expired in early 1992. Customers in the area covered by the City franchise represent approximately 45.6% of the Company's 1994 total electric operating revenues, and no other franchise area represents more than 7.1%. These franchises are agreements that provide the Company access to public rights-of-way for placement of the Company's electric facilities. The Company remains obligated under state law to provide service to customers in the franchise area even in the absence of a franchise agreement with the City. (See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY - -- ALBUQUERQUE FRANCHISE ISSUES".)
POWER SALES
For the years 1990 through 1994, retail KWh sales have grown at a compound annual rate of approximately 4.2%. The Company's system and off-system sales (revenues and energy consumption) and system peak demands in summer and winter are shown in the following tables:
ELECTRIC SALES BY MARKET (THOUSANDS OF DOLLARS)
ELECTRIC SALES BY MARKET (MEGAWATT HOURS)
SYSTEM PEAK DEMAND* (MEGAWATTS)
During 1994 and 1993, the Company's sales in the off-system markets accounted for approximately 30.8 percent and 34.4 percent, respectively, of its total KWh sales and approximately 15.8 percent and 17.2 percent (before reduction of revenues from the M-S-R contingent power purchase contract, which were accounted for in the determination of the provision for loss recorded in 1992), respectively, of its total revenues from energy sales. During 1994, the Company's major off-system sale contracts in effect were with SDG&E, APPA, AEPCO, IID and PSCo.
The SDG&E contract requires SDG&E to purchase 100 MW from the Company through April 2001. On October 27, 1993, SDG&E filed a complaint with the FERC against the Company, alleging that certain charges under this 1985 power purchase agreement are unjust, unreasonable and unduly discriminatory. SDG&E is requesting that the FERC investigate the rates charged under the agreement. The relief, if granted, would reduce annual demand charges paid by SDG&E by up to $11 million per year from the date of the ruling through April 2001, and could require a refund of up to approximately $14 million. The Company responded to the complaint on December 8, 1993, and SDG&E and the Company filed subsequent pleadings. The FERC has not issued a ruling in the case and has not indicated when or if the complaint will be considered. The Company believes that the complaint is without merit, and the Company intends to vigorously resist the complaint.
The APPA contract requires APPA to purchase varying amounts of power from the Company through May 2008 and allows APPA to make adjustments to the purchase amounts subject to certain notice provisions. APPA provided notice that it was invoking its option to reduce the power demand in 1995, resulting in a peak demand of 89 MW. The AEPCO contract which required AEPCO to purchase 15 MW of power terminated on May 31, 1994. The IID contract which required IID to purchase a peak amount of 81 MW from the Company expired on February 28, 1995. The Company sold 75 MW of capacity and associated energy to PSCo from October 1, 1993 through September 30, 1994.
The Company furnishes firm-requirements wholesale power in New Mexico to the cities of Farmington and Gallup, TNP and Plains. Plains may terminate its contract for 10 MW at any time with one year's advance notice. The Company expects to receive a termination notice from Plains but cannot predict the timing of such notice. The Company is committed to provide service to the City of Gallup through April 2003. Average monthly demands under the City of Gallup contract for 1994 were approximately 26 MW. TNP is currently purchasing 36 MW but has provided notice that it will reduce its purchase to 15 MW for 1996. TNP may adjust its annual demand between 15 MW and 40 MW with one year's notice and may terminate service with two years' notice. No firm-requirements wholesale customer accounted for more than 1.6% of the Company's total electric operating revenues for the year ended December 31, 1994.
SOURCES OF POWER
As of December 31, 1994, the total net generation capacity of facilities owned or leased by the Company was 1,506 MW.
In addition, the Company has power purchase contracts with M-S-R for 105 MW through April 1995 and with SPS for up to 100 MW of interruptible power through April 1995 and up to 200 MW from May 1995 through May 2011. The Company may reduce its purchases from SPS by 25 MW annually upon three years' notice. Also, the Company has 39 MW of contingent capacity obtained from El Paso under a transmission capacity for generation capacity trade arrangement that increases to 70 MW from 1998 through 2003. In addition, the Company is interconnected with various utilities for economy interchanges and mutual assistance in emergencies.
FUEL AND WATER SUPPLY
The percentages of the Company's generation of electricity (on the basis of KWh) fueled by coal, nuclear fuel and gas and oil, and the average costs to the Company of those fuels (in cents per million BTU), during the past five years were as follows:
The estimated generation mix for 1995 is 72.2% coal, 27.7% nuclear and 0.1% gas and oil. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits and the generally abundant supply of nuclear fuel, the Company believes that adequate sources of fuel are available for its generating stations.
COAL
The coal requirements for SJGS are being supplied by SJCC, a wholly-owned subsidiary of BHP, from certain Federal, state and private coal leases under a coal sales agreement, pursuant to which SJCC will supply processed coal for operation of SJGS until 2017. BHP guaranteed the obligations of SJCC under the agreement, which contemplates the delivery of approximately 126 million tons of coal during its remaining term. Such amount would supply substantially all the requirements of SJGS through approximately 2017. The primary sources of coal are a mine adjacent to SJGS and a mine located approximately 25 miles northeast of SJGS in the La Plata area of northwestern New Mexico. The Company is currently discussing with SJCC alternatives for securing both short and long term fuel resource requirements which at this time are uncommitted. As a part of this discussion, the Company is also negotiating other issues which may result in modifications to certain coal sales agreement terms and provisions which include but are not limited to cost recovery and pricing. The average cost of fuel, including ash disposal and land reclamation costs, for SJGS for the years 1992, 1993 and 1994 was 175.5 cents, 177.4 cents and 172.1 cents, respectively, per million BTU ($34.28, $34.59 and $33.62 per ton, respectively).
Four Corners is supplied with coal under a fuel agreement between the owners and BHP, under which BHP agreed to supply all the coal requirements for the life of the plant. BHP holds a long-term coal mining lease, with options for renewal, from the Navajo Nation and operates a strip mine adjacent to Four Corners with the coal supply expected to be sufficient to supply the units for their estimated useful lives. The average cost of fuel, including ash disposal and land reclamation costs, for the years 1992, 1993 and 1994 at Four Corners was 114.3 cents, 114.9 cents and 125.8 cents, respectively, per million BTU ($20.19, $20.11 and $22.03 per ton, respectively).
NATURAL GAS
The natural gas used as fuel for the Company's Albuquerque electric generating plant (Reeves Station) is delivered by GCNM. (See "NATURAL GAS OPERATIONS".) In addition to rate changes under filed tariffs, the Company's cost of gas increases or decreases according to the average cost of gas supplied by GCNM or other sources.
NUCLEAR FUEL
The fuel cycle for PVNGS is comprised of the following stages: (1) the mining and milling of uranium ore to produce uranium concentrates, (2) the conversion of uranium concentrates to uranium hexafluoride, (3) the enrichment of uranium hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of fuel assemblies in reactors, and (6) the storage of spent fuel and the disposal thereof. The PVNGS participants made arrangements to obtain quantities of uranium concentrates anticipated to be sufficient to meet operational requirements through 1996. Existing
contracts and options could be utilized to meet 95% of requirements from 1997 through 2000. Spot purchases in the uranium market will be made, as appropriate. The PVNGS participants contracted for all conversion services required through 1995 and for up to 65% of conversion services required through 1998, with options to continue through the year 2000. The PVNGS participants, including the Company, have an enrichment services contract with USEC which obligates USEC to furnish enrichment services required for the operation of the three PVNGS units over a term expiring in November 2014. The participants have obtained 100% of the enrichment requirements through the year 2002 under the latest contract and options. The PVNGS participants are currently re-negotiating fuel assembly fabrication arrangements and anticipate finalizing contract terms during 1995.
Existing spent fuel storage facilities at PVNGS have sufficient capacity with certain modifications to store all fuel expected to be discharged from normal operation of all of the PVNGS units through at least the year 2005. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), DOE is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. The NRC, pursuant to the Waste Act, also requires operators of nuclear power reactors to enter into spent fuel disposal contracts with DOE. APS, on its own behalf and on behalf of the other PVNGS participants, executed a spent fuel disposal contract with DOE. The Waste Act also obligates DOE to develop the facilities necessary for the permanent disposal of all spent fuel generated and to be generated by domestic power reactors and to have the first such facility in operation by 1998 under prescribed procedures. In November 1989, DOE reported that such a permanent disposal facility will not be in operation until 2010. As a result, under DOE's current criteria for shipping allocation rights, PVNGS's spent fuel shipments to the DOE permanent disposal facility would begin in approximately 2025. In addition, APS believes that on-site storage of spent fuel may be required beyond the life of the PVNGS Units. APS currently believes that alternative interim spent fuel storage methods are or will be available on-site or off-site for use by PVNGS to allow its continued operation beyond 2005 and to safely store spent fuel until DOE's scheduled shipments from PVNGS begin.
WATER SUPPLY
Water for Four Corners and SJGS is obtained from the San Juan River. (See ITEM 3. --"LEGAL PROCEEDINGS -- SAN JUAN RIVER ADJUDICATION".) BHP holds rights to San Juan River water and has committed a portion of such rights to Four Corners through the life of the project. The Company and Tucson have a contract with the United States Bureau of Reclamation for consumption of 16,200 acre feet of water per year for SJGS, which contract expires in 2005, and in addition, the Company was granted the authority to consume 8,000 acre feet of water per year under a state permit that is held by BHP. The Company is of the opinion that sufficient water is under contract for SJGS until 2005.
On January 29, 1993, the U.S. Fish and Wildlife Service proposed a portion of the San Juan River as critical habitat for two fish species. This designation may impact uses of the river and its flood plains and will require certain analysis under the Endangered Species Act of 1973 of all significant Federal actions. Renewal of the SJGS water contract is considered a significant Federal action.
Due to extensive lead times required to renew the water rights contract, the Company has formally initiated the renewal and extension process for requesting rights through the year 2025. The Company is actively conducting an environmental assessment with the Bureau of Reclamation and a biological assessment with the U.S. Fish and Wildlife Service. These studies are required by the Federal agencies before the existing water contract can be renewed. The Company is currently unable to predict the outcome of these matters.
Sewage effluent used for cooling purposes in the operation of the PVNGS units has been obtained under contracts with certain municipalities in the area. The contracted quantity of effluent exceeds the amount required for the three PVNGS units. The validity of these effluent contracts is the subject of litigation in state and Federal courts. (See ITEM 3. --"LEGAL PROCEEDINGS -- PVNGS WATER SUPPLY LITIGATION".)
NATURAL GAS OPERATIONS
ACQUISITION OF NATURAL GAS OPERATIONS
In 1985, the Company acquired substantially all of the New Mexico natural gas utility assets of Southern Union (principally a natural gas retail distribution system operated by Southern Union as the Gas Company of New Mexico division and now operated by the Company as GCNM) and Sunbelt acquired all of the stock of Southern Union Gathering Company (subsequently renamed Sunterra Gas Gathering Company), a wholly-owned subsidiary of Southern Union, in connection with the settlement of antitrust litigation against Southern Union in which the Company and others were plaintiffs. In a separate transaction, a wholly-owned subsidiary of Sunbelt acquired from Southern Union all of the stock of Southern Union Processing Company (subsequently renamed Sunterra Gas Processing Company) in 1986. In 1990, the Company acquired all of the common stock of Gathering Company and Processing Company from Sunbelt and the Sunbelt subsidiary, respectively. Together with GCNM, Gathering Company and Processing Company are referred to as the Company's natural gas operations.
PROPOSED SALE OF GATHERING AND PROCESSING ASSETS
On February 12, 1994, the Company, Gathering Company and Processing Company entered an agreement to sell substantially all of their gas gathering and processing facilities. The Company believes that the sale, which requires prior NMPUC approval, will allow GCNM to focus on providing retail gas services to New Mexico gas consumers while maintaining its flexibility in accessing competitively priced, reliable and secure gas supplies. (See PART II, ITEM 7. - --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- SALE OF GAS GATHERING AND PROCESSING ASSETS".)
GAS COMPANY OF NEW MEXICO DIVISION
The Company distributes natural gas through GCNM to most of the major communities in New Mexico, including Albuquerque and Santa Fe, serving approximately 382,000 customers as of December 31, 1994. The Albuquerque metropolitan area accounts for approximately 54.4% of the Company's total customers. The Company holds long-term, non-exclusive franchises with varying expiration dates in all incorporated communities requiring franchise agreements. The expiration dates for the Company's franchises in Albuquerque and Santa Fe are 1998 and 1995, respectively. The Company is in the process of negotiation with the City of Santa Fe and anticipates that a new agreement will be in place prior to the termination of the current agreement. GCNM's customer base includes both "sales-service" customers and "transportation-service" customers. Sales-service customers purchase natural gas and receive transportation and delivery services from GCNM for which GCNM receives both cost-of-gas and cost-of-service revenues. Cost-of-gas revenues collected from sales service customers are a recovery of the cost of purchased gas in accordance with NMPUC rules and regulations and, in that sense, do not affect the net earnings of the Company. Transportation-service customers, who procure gas independently of GCNM and contract with GCNM for transportation and related services, provide GCNM with cost-of-service revenues only. Transportation services are provided both to gas marketers generally for delivery to locations throughout GCNM's distribution systems and to natural gas producers generally for delivery to other interstate pipelines.
For the twelve months ended December 31, 1994, GCNM had throughput of approximately 85.0 million decatherms, including sales of 41.9 million decatherms to sales-service customers. No single customer accounted for more than 1.5% of GCNM's therm sales in 1994. During 1994, approximately 50.8% of GCNM's total gas throughput was related to transportation gas deliveries. GCNM's transportation rates are unbundled, and transportation customers only pay for the amount of transportation service they receive from GCNM. GCNM's total operating revenues for the year ended
December 31, 1994, were approximately $234.9 million. Cost-of-gas revenues, received from sales-service customers, accounted for approximately 43.4% of GCNM's total operating revenues. Since a major portion of GCNM's load is related to heating, levels of therm sales are affected by the weather. Approximately 44.6% of GCNM's total therm sales in 1994 occurred in the months of January, February, November and December.
GATHERING COMPANY
Gathering Company is engaged in the ownership and operation of gas gathering facilities primarily in the San Juan Basin in northwestern New Mexico, the purchase of gas from sources in the San Juan Basin, the sale of natural gas to GCNM and the gathering of natural gas for third parties. In 1994, Gathering Company sold approximately 9.9 million decatherms of natural gas to GCNM and gathered 47.1 million decatherms of natural gas for third parties.
In January 1990, Gathering Company entered into a natural gas sale and gathering contract with GCNM. The contract allows Gathering Company to recover from GCNM, effective January 1988, substantially all of its operating costs, net of its third-party revenues (including revenues received from Processing Company), and to earn a return on its investment in its operating assets. In addition, Gathering Company is permitted under the contract to charge to GCNM all payments made arising from take-or-pay obligations and from contract reformation. (See "RATES AND REGULATION -- Natural Gas Supply Matters".) On February 12, 1994, Gathering Company entered into an agreement to sell substantially all of its assets. (See PART II, ITEM 7. --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- SALE OF GAS GATHERING AND PROCESSING ASSETS".) As a result of the sale, the gas sales and gathering contract with GCNM will either be terminated or assigned to the purchaser of the assets.
PROCESSING COMPANY
Processing Company processes natural gas for GCNM, Gathering Company and others. The natural gas is processed at Processing Company's plants under separate contracts. Both GCNM and Gathering Company executed contracts with Processing Company in January 1990. The GCNM contract provides that GCNM will reimburse Processing Company for all of its operating costs, net of its third-party revenues (including fees from Gathering Company), and provides a return on Processing Company's investment in its operating assets, in return for providing the service of processing GCNM's natural gas. Additionally, Processing Company reimburses GCNM for all revenues from liquid by-products derived from GCNM's throughput processed at the plants. Such revenues, including all third party processing fees, are ultimately credited to GCNM's sales-service customers through the PGAC. The Gathering Company's contract with Processing Company provides the same service for Gathering Company and in return for such service, Gathering Company pays Processing Company a fee per mcf of gas which is processed on behalf of Gathering Company. Processing Company reimburses Gathering Company for all revenues from liquid by-products derived from Gathering Company's throughput processed at the plants. On February 12, 1994, Processing Company entered into an agreement to sell substantially all of its assets. (See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY - -- SALE OF GAS GATHERING AND PROCESSING ASSETS".) As a result of the sale, the processing agreements with GCNM and Gathering Company will either be terminated or assigned to the purchaser of the assets.
NATURAL GAS SUPPLY
During the late 1980's, there were significant changes in the natural gas industry brought about by Federal and state regulations which dramatically altered the way gas is bought, transported and sold nationwide. These changes required GCNM and Gathering Company to reform or terminate certain natural gas purchase contracts which required GCNM and Gathering Company to take gas in
excess of demand. This process resulted in breach of contract claims from some producers. GCNM and Gathering Company have been able to resolve substantially all of the producer litigation and reform their supply portfolio so that it better matches the demands of GCNM's sales-service customers. These reformations have also allowed GCNM to seek new sources of gas supplies through pipeline interconnects which have created a more flexible and reliable supply portfolio. GCNM may purchase natural gas through contracts which contain reservation fees. The NMPUC is currently examining in GCNM's PGAC continuation filing whether reservation fees, which have been paid to suppliers for standing ready to serve GCNM's needs during the winter heating season, should be recovered from sales-service customers through the PGAC or should be recovered in some other fashion. (See "RATES AND REGULATION -- Other Natural Gas Matters".)
GCNM obtains its supply of natural gas primarily from New Mexico wells pursuant to contracts with producers and marketers. In connection with the sale of substantially all of the assets of Gathering Company, GCNM has petitioned the NMPUC to approve assignment of all of the gas purchase contracts held by Gathering Company to GCNM. These contracts are generally sufficient to meet GCNM's peak-day demand.
GCNM serves certain cities which depend on EPNG or Transwestern Pipeline Company for transportation of gas supplies. Because these cities are not directly connected to GCNM's transmission facilities, gas transported by these companies is the sole supply source for those cities. Such transportation is regulated by FERC. As a result of FERC Order 636, GCNM's options for transporting gas to such cities and other portions of its distribution system have increased.
As a result of routine periodic audits since 1990 by Meridian Oil Inc. and its related or affiliated companies, Southland Royalty Company, Meridian Oil Production Inc. and Unicon Producing Company (collectively "Meridian"), Meridian has asserted claims against GCNM, Gathering Company and Processing Company regarding the allocation of natural gas liquids from Processing Company's Kutz and Lybrook plants. Meridian has also asserted certain related gathering and transportation claims. Some issues have been resolved, and certain other issues, primarily those regarding allocation of liquids and the measurement of gas under gathering/transportation agreements, are still pending. Unresolved claims appear to be approximately $4 million; however, the Company has responded to the majority of the claims, continues to evaluate the claims, and expects that such claims will be ultimately resolved at no material cost to the Company.
NATURAL GAS SALES
The following table shows gas throughput by customer class for GCNM and Gathering Company:
GAS THROUGHPUT (MILLIONS OF DECATHERMS)
The following table shows gas revenues by customer class for GCNM, Gathering Company and Processing Company:
GAS REVENUES (THOUSANDS OF DOLLARS)
RATES AND REGULATION
The Company is subject to the jurisdiction of the NMPUC with respect to its retail electric, gas and water rates, service, accounting, issuance of securities, construction of new generation and transmission facilities and other matters. The FERC has jurisdiction over rates and other matters related to wholesale electric sales.
JANUARY 12, 1994 STIPULATION
On January 12, 1994, the Company and the NMPUC staff and primary intervenor groups entered into a stipulation. The Company filed the stipulation with the NMPUC, recommending that electric retail rates be reduced by $30 million. On November 28, 1994, the NMPUC issued a final order approving the stipulation as interpreted and provided by the order which was effective for bills rendered starting November 29, 1994. (See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OVERVIEW -- SPECIFIC ACTIONS BY THE COMPANY".)
FPPCAC
RETAIL CUSTOMERS
On December 22, 1993, the Company and primary intervenors entered into a stipulation, agreeing to eliminate the FPPCAC from the Company's retail billings, and set the base fuel cost (defined in the stipulation as fuel costs plus net purchased power costs less off-system sales revenues) as a component of the cost of service effective with the order in the Company's next general rate case.
As part of the final order approving the January 12, 1994 stipulation, the Company's FPPCAC for its retail customers was eliminated. A base fuel cost was incorporated into the overall rates approved by the stipulation. Although the cost of fuel and the conditions in the off-system sales market could change either positively or negatively from the levels established, the Company currently does not believe that the elimination of the FPPCAC will have a material adverse impact on the Company's results of operation or financial condition.
FIRM-REQUIREMENTS WHOLESALE CUSTOMERS
The Company's firm-requirements wholesale customers have a FPPCAC which has an approximate 30-day time lag in implementation of the FPPCAC for billing purposes. The Company's FPPCAC for its firm-requirement wholesale customers had been at variance with the filed FERC tariffs. As a result, the Company filed a petition with FERC on October 28, 1993 to request deviation from the filed FERC tariffs for the period of July 1985 through January 1993. The Company's filing indicated that the four firm-requirement wholesale customers benefitted during that time period relative to the energy costs they would have been billed under the application of the filed FERC tariffs. The four affected customers concur with the Company's position and have filed a certificate of concurrence with FERC. Discussions regarding the Company's filing with FERC staff have occurred, but at this time no formal response has been given to the Company. The Company has no indication of when a formal response will be received. However, the Company does not anticipate any material adverse impacts on the Company's financial condition or results of operations as a result of this issue.
FOSSIL-FUELED PLANT DECOMMISSIONING COSTS
The Company's six owned or partially owned, in service and retired, fossil-fueled generating stations are expected to incur dismantling and reclamation costs as they are decommissioned. The Company's share of decommissioning costs for all of its fossil-fueled generating stations is projected to be approximately $134 million stated in 1994 dollars, including approximately $24.4 million (of which $10.2 million has already been expended) for Person, Prager and Santa Fe Stations which have been retired.
In June 1993, the Company filed for recovery of all estimated decommissioning costs by factoring such costs into the Company's depreciation rate study filed with the NMPUC.
As part of the final order approving the January 12, 1994 stipulation, the NMPUC approved the depreciation rates, except for those decommissioning costs related to the three retired generating units, and incorporated them into the determination of retail rates.
POSTRETIREMENT BENEFITS
The Company adopted SFAS No. 106, EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS, effective January 1, 1993. SFAS No. 106 requires accrual of postretirement benefits during the years employees provide services. Prior to 1993, the costs of these benefits were expensed on a pay-as-you-go basis. In 1993, the NMPUC issued a final order in a case regarding an inquiry into SFAS No. 106. In its final order, the NMPUC adopted a policy which provides for accrual accounting for the postretirement benefit costs, funding requirements into an irrevocable trust and specific reporting for the benefit costs in future rate cases. The order also provides for specific waiver provisions with respect to the external trust funding requirements and a deferral of the benefit costs in excess of the pay-as-you-go basis. The Company received approval on November 28, 1994 for the recovery of the full accrual amount of SFAS No. 106 expense for its electric business unit. As of December 31, 1994, no benefit costs were deferred for the electric business unit. The Company filed supplemental information regarding the funding of postretirement benefits on February 24, 1995, which outlined the types of funding vehicles and the amounts funded for 1994 related to the electric business unit. The Company defers the benefit costs in excess of the pay-as-you-go basis for the gas business unit ($2.8 million deferred as of December 31, 1994) and will address the recovery of this amount as well as the full accrual amount of SFAS No. 106 expense related to the gas business unit in its next general rate case which will be filed in 1995.
CONSOLIDATION ISSUES
Pursuant to a prior NMPUC order, the Company filed an application on December 21, 1993 for NMPUC approval to combine certain customer service functions of its gas and electric utility divisions in order to achieve cost savings and to improve service to customers. At the same time, the Company
filed a separate request for a declaratory order from the NMPUC confirming that the Company's realignment of senior corporate officers' responsibilities during 1993 complies with a 1984 NMPUC order placing certain organizational restrictions on the operation of the gas and electric divisions. On February 7, 1994, the NMPUC consolidated the two proceedings.
On January 17, 1995, the Company and the staff of the NMPUC entered into a stipulation regarding the consolidated cases. The stipulation provides for the approval of the consolidation of certain customer service functions of the gas and electric divisions, as proposed by the Company. The stipulation also provides for the dismissal of the declaratory order proceeding without a determination that the Company's 1993 or 1994 organizational structure was either in compliance or not in compliance with the 1984 NMPUC order. The basis for the dismissal of the Company's declaratory order petition is that the Company's post-January 1, 1995 organizational structure has rendered the case moot. The two intervenors in the consolidated cases, the City of Albuquerque and the New Mexico Industrial Energy Consumers, did not join in the stipulation, but filed statements of position supporting customer service consolidation and not agreeing to final determination of the compliance issues relating to the Company's organizational structure. The stipulation is subject to the approval of the NMPUC.
A hearing on the approval of the stipulation was held before an NMPUC hearing examiner on January 24, 1995, and the matter is currently pending before the hearing examiner. A decision from the NMPUC is anticipated in the first half of 1995.
NATURAL GAS SUPPLY MATTERS
On December 18, 1989, the NMPUC issued an order approving a stipulation relating to GCNM's need to reform its gas supply portfolio. This stipulation provides for the partial recovery of certain gas costs arising from reformation of gas purchase contracts and from claims by certain producers relating to take-or-pay obligations, contract pricing and other matters. The mechanism established by the order does not apply to any suits not settled or for which no initial judgement on the merits had been rendered by December 31, 1993. Under the order, GCNM bears 25% of producer take-or-pay costs (including such costs paid by GCNM to Gathering Company under their gas sale and gas gathering contract) for claims settled. GCNM will be permitted to recover from its sales and transportation customers the remaining 75% of take-or-pay costs over a period of years. The order allows GCNM to recover from its customers all take-or-pay costs assessed by interstate pipelines. The order also provides that GCNM may recover all costs (including costs paid by GCNM to Gathering Company under their natural gas sale and gathering contract) determined by the NMPUC to be prudently incurred or just and reasonable (on a case-by-case basis) as the result of the settlement or litigation of claims arising from certain intrastate natural gas purchase contracts that were the subject of the antitrust litigation that resulted in the Company's acquisition of GCNM from Southern Union in January 1985.
On March 29, 1993, GCNM was ordered to submit testimony concerning the allocation of certain take-or-pay settlement amounts paid to Unicon Producing Company ("Unicon"), Pioneer Exploration Company, Oryx Energy Company and EPNG. On July 12, 1993, the NMPUC issued an order granting motions filed by GCNM, the NMPUC staff and the AG concerning gas contract settlements among GCNM, Gathering Company, Amoco, Conoco, Mobil Producing Texas and New Mexico, Texaco, Inc. and Texaco Production Inc. The order required GCNM to file testimony concerning the amounts paid in the settlements, the allocation of such amounts between take-or-pay and contract pricing issues, and the prudence of the settlements involving the contract pricing issues. On December 15, 1993, GCNM filed testimony. On September 13, 1994, GCNM entered into a negotiated settlement with the parties in the proceedings. With this settlement, all outstanding issues regarding recovery of payments GCNM made to settle gas take-or-pay contracts and pricing disputes have been resolved in accordance with the December 18, 1989 NMPUC order. On December 5, 1994, the NMPUC issued a final order approving the stipulation. Under the stipulation, GCNM is authorized to recover a total of $43.4 million of the approximately $48.6 million it sought to recover. As a result of the stipulation, GCNM wrote off approximately $2.9 million of additional amounts that will not be recovered.
OTHER NATURAL GAS MATTERS
GCNM's retail gas rate schedules contain a PGAC which provides for timely recovery of the cost of gas purchased by GCNM for resale to its sales-service customers. On January 19, 1993, the NMPUC issued a final order which provided for the continuation of GCNM's PGAC substantially in its present form. The final order required GCNM to file its PGAC continuation filing by April 20, 1993 and specifically ordered GCNM to explain how its composite gas procurement strategy will be affected by the announced intention to sell all or major portions of Gathering Company's and Processing Company's assets. The case has been fully litigated and briefed. The principal unresolved issues in the case were whether gas supply reservation fees paid to certain gas suppliers are recoverable through the PGAC. The parties are awaiting a recommended decision from the hearing examiner. In this proceeding, GCNM agreed that recovery of costs paid to Gathering Company and Processing Company in excess of 1990/1991 levels would be deferred. Those amounts were considered in connection with the sale of substantially all of the assets of Gathering Company and Processing Company (see PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- SALE OF GAS GATHERING AND PROCESSING ASSETS".)
ENVIRONMENTAL FACTORS
The Company, in common with other electric and gas utilities, is subject to stringent regulations for protection of the environment by both state and Federal authorities. PVNGS is subject to the jurisdiction of the NRC, which has authority to issue permits and licenses and to regulate nuclear facilities in order to protect the health and safety of the public from radioactive hazards and to conduct environmental reviews pursuant to the National Environmental Policy Act. The Company believes that it is in compliance, in all material respects, with the environmental laws. The Company does not currently expect that material expenditures for environmental control facilities will be required in 1995 and 1996.
THE CLEAN AIR ACT
The Clean Air Act amendments of 1990 (the "Act") impose stringent limits on emissions of sulfur dioxide and nitrogen oxides from fossil-fueled electric generating plants. The Act is intended to reduce air contamination from every sizeable source of air pollution in the nation. Electric utilities with fossil-fueled generating units will be affected particularly by the section of the Act which deals with acid rain. To be in compliance with the Act, many utilities will be faced with installing expensive sulfur dioxide removal equipment, securing low sulfur coal, buying sulfur dioxide emission allowances, or a combination of these. Due to the existing air pollution control equipment on the coal-fired SJGS and Four Corners, the Company believes that it will not be faced with any material capital expenditures in order to be in compliance with the acid rain provision of the Act. SJGS and Four Corners have installed flow monitoring equipment and have completed certification testing of their continuous emission monitoring equipment. Certification testing data was submitted to the EPA on January 30, 1995, as required. Certification of the monitoring systems by the EPA is expected. Under other provisions of the Act, the Company will be required to obtain operating permits for its coal- and gas- fired generating units and to pay annual fees associated with the operating permit program. The New Mexico operating permit program was approved by the EPA in November 1994. Operating permit applications are due to the state in 1995.
The Act also established the Grand Canyon Visibility Transport Commission ("Commission") and charged it with assessing adverse impacts on visibility at the Grand Canyon. The Commission broadened its scope to assess visibility impairment in mandatory Class I areas (parks and wilderness areas) located in the Colorado Plateau ("Golden Circle"). The Commission must report to the EPA by November 1995 on its findings and make recommendations regarding what actions, if any, should be pursued in order to remedy the visibility impairment in the Golden Circle. Depending on the recommendations of the Commission, the EPA may require stricter controls on sources that may be
contributing to the visibility impairment. Both SJGS and Four Corners are located near the Golden Circle. The exact nature and cost of additional controls, if any, that may be required as a result of the recommendations cannot be estimated at this time.
TOXIC SUBSTANCES CONTROL ACT ("TSCA")
In December 1993, the EPA issued two enforcement notices and proposed penalty assessments against GCNM and Processing Company for alleged failure to file the 1990 inventory update reports ("IUR") on GCNM's and Processing Company's natural gas processing operations. The EPA proposed assessing penalties against GCNM in the amount of $42,000 and against Processing Company in the amount of $72,000. GCNM and Processing Company responded to the EPA's notice of enforcement and, consistent with the industry's position, contested the EPA's interpretation of the regulations requiring IUR for the natural gas processing industry. The EPA entered into a settlement agreement with the Gas Processors Association regarding the application of the IUR regulations to the industry. Subsequently, on February 6, 1995, the EPA, GCNM and Processing Company entered into a settlement agreement whereby amended 1990 IURs will be filed by GCNM and Processing Company; GCNM will pay a fine of $4,000 and Processing Company will pay a fine of $12,000. This settlement constitutes final resolution of this matter.
DEPARTMENT OF ENERGY ("DOE") GAS LINE REPLACEMENT
GCNM is a contractor to the DOE for the replacement of a natural gas line for which GCNM subcontracted the construction work. Work on the line commenced prior to filing a Notice of Intent ("NOI") for coverage under the Storm Water General Permit for construction activities with the EPA. The EPA issued a "Show Cause" letter for this violation. Following GCNM's timely response to the "Show Cause" letter, the EPA and GCNM entered into a Consent Order in connection with the violation, with an agreed penalty of $3,000. In addition, the NMED, responding to complaints regarding dust and sediment generation, and upon discovery that the requisite NOI and Storm Water Pollution Prevention Plan ("SWPPP") had not been prepared, requested GCNM to prepare a corrective action plan to implement a SWPPP and mitigate existing stream channel discharges. GCNM responded on a timely basis to the NMED's request. GCNM has been advised that, at this time, the NMED does not intend to take any further enforcement actions. The Company is unable to predict the ultimate outcome of any enforcement actions, but believes that any enforcement actions would not have a material impact on the Company's results of operations or financial condition.
For other environmental issues facing the Company, see PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- ENVIRONMENTAL ISSUES -- Gas Operations" and -- "ENVIRONMENTAL ISSUES -- Electric Operations".
ITEM 2.
ITEM 2. PROPERTIES
Substantially all of the Company's utility plant is mortgaged to secure its first mortgage bonds.
ELECTRIC
The Company's electric generating stations in commercial service as of December 31, 1994, were as follows:
FOSSIL-FUELED PLANTS
SJGS is located in northwestern New Mexico, and consists of four units operated by the Company. Units 1, 2, 3 and 4 at SJGS have net rated capacities of 316 MW, 312 MW, 488 MW and 498 MW, respectively. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. Unit 3 is owned 50% by the Company, 41.8% by SCPPA and 8.2% by Century. Century has agreed to sell its remaining 8.2% interest to Tri-State Generation and Transmission Association, Inc. Unit 4 is owned 38.457% by the Company, 8.475% by Farmington, 28.8% by M-S-R, 7.2% by Los Alamos, 10.04% by Anaheim and 7.028% by UAMPS. The Company's net aggregate ownership in SJGS is 750 MW. In connection with the Company's sale to M-S-R in December 1983 of a 28.8% interest in SJGS Unit 4, the Company agreed to purchase under certain conditions 73.53% (105 MW) of M-S-R's capacity through April 30, 1995, an amount which may be reduced by M-S-R under certain conditions. The Company also agreed to market the energy associated with the remaining 26.47% portion of M-S-R's capacity through April 30, 1995. This marketing arrangement may be terminated by M-S-R at any time upon 30 days notice.
The Company also owns 192 MW of net rated capacity derived from its 13% interest in Units 4 and 5 of Four Corners located in northwestern New Mexico on land leased from the Navajo Nation and adjacent to available coal deposits. Units 4 and 5 at Four Corners are jointly owned with SCE, APS, Salt River Project, Tucson and El Paso and are operated by APS.
The Company owns 154 MW of generation capacity at Reeves Station in Albuquerque, New Mexico, and 20 MW of generation capacity at Las Vegas Station in Las Vegas, New Mexico. These stations are used primarily for peaking and transmission support.
NUCLEAR PLANT
THE COMPANY'S INTEREST IN PVNGS
The Company is participating in the three 1,270 MW units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), Salt River Project, El Paso, SCE, SCPPA and The Department of Water and Power of the City of Los Angeles. The Company has a 10.2% undivided interest in PVNGS, with its interests in Units 1 and 2 held under leases. In September 1992, the Company purchased approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases for approximately $17.5 million. The Company's ownership and leasehold interests in PVNGS amount to 130 MW per unit, or a total of 390 MW. PVNGS Units 1, 2 and 3 were declared in commercial service by the Company in January 1986, September 1986 and January 1988, respectively. Commercial operation of PVNGS requires full power operating licenses which were granted by the NRC. Maintenance of these licenses is subject to NRC regulation.
STEAM GENERATOR TUBES
For information concerning steam generator tubes, see PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- PVNGS -- STEAM GENERATOR TUBES".
SALE AND LEASEBACK TRANSACTIONS OF PVNGS UNITS 1 AND 2
In eleven transactions consummated in 1985 and 1986, the Company sold and leased back its entire 10.2% interest in PVNGS Units 1 and 2, together with portions of the Company's undivided interest in certain PVNGS common facilities. In each transaction, the Company sold interests to an owner trustee under an owner trust agreement with an institutional equity investor. The owner trustees, as lessors, leased the interests to the Company under lease agreements having initial terms expiring January 15, 2015 (with respect to the Unit 1 leases) or January 15, 2016 (with respect to the Unit 2 leases). Each lease provides an option to the Company to extend the term of the lease as well as a repurchase option. The lease expense for the Company's PVNGS leases is approximately $66.3 million per year. Throughout the terms of the leases, the Company continues to have full and exclusive authority and responsibility to exercise and perform all of the rights and duties of a participant in PVNGS under the Arizona Nuclear Power Project Participation Agreement and retains the exclusive right to sell and dispose of its 10.2% share of the power and energy generated by PVNGS Units 1 and 2. The Company also retains responsibility for payment of its share of all taxes, insurance premiums, operating and maintenance costs, costs related to capital improvements and decommissioning and all other similar costs and expenses associated with the leased facilities. On September 2, 1992, the Company purchased approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases for $17.5 million. For accounting purposes, this transaction was recorded as a purchase with the Company recording approximately $158.3 million as utility plant and $140.8 million as long-term debt on the Company's consolidated balance sheet. In connection with the January 12, 1994 stipulation, the Company wrote down the purchased beneficial interests in PVNGS Units 1 and 2 leases to $46.7 million. The purchase is expected to provide the Company with (1) the residual value of a certain portion of the PVNGS Units at no cost, (2) reduced exposure to indemnification provisions in the lease agreements and (3) added flexibility to cause the retirement of the underlying lease obligation bonds ("LOBs"). (See also notes 7 and 9 of the notes to consolidated financial statements.) On January 3, 1995, the NMPUC approved the Company's request for authority to retire up to approximately $134 million of PVNGS LOBs. (See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES - -- Financing Capability and Dividend Restrictions".)
Each lease describes certain events, "Events of Loss" or "Deemed Loss Events", the occurrence of which could require the Company to, among other things, (1) pay the lessor and the equity investor, in return for such investor's interest in PVNGS, cash in the amount provided in the lease, which amount, primarily because of certain tax consequences, would exceed such equity investor's
outstanding equity investment, and (2) assume debt obligations relating to the PVNGS lease. The "Events of Loss" generally relate to casualties, accidents and other events at PVNGS, which would severely adversely affect the ability of the operating agent, APS, to operate, and the ability of the Company to earn a return on its interests in, PVNGS. The "Deemed Loss Events" consist mostly of legal and regulatory changes (such as changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). The Company believes the probability of such "Events of Loss" or "Deemed Loss Events" occurring is remote. Such belief is based on the following reasons: (a) to a large extent, prevention of "Events of Loss" and some "Deemed Loss Events" is within the control of the PVNGS participants, including the Company, and the PVNGS operating agent, through the general PVNGS operational and safety oversight process and (b) with respect to other "Deemed Loss Events," which would involve a significant change in current law and policy, the Company is unaware of any pending proposals or proposals being considered for introduction in Congress or any state legislative or regulatory body that, if adopted, would cause any such events.
PVNGS DECOMMISSIONING FUNDING
For information concerning PVNGS decommissioning funding, see PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- PVNGS DECOMMISSIONING FUNDING".
PVNGS LIABILITY AND INSURANCE MATTERS
The PVNGS participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under Federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. The maximum assessment per reactor under the retrospective rating program for each nuclear incident occurring at any nuclear power plant in the United States is approximately $79.3 million, subject to an annual limit of $10 million per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident is approximately $24.3 million, with an annual payment limitation of $3 million. The insureds under this liability insurance include the PVNGS participants and "any other person or organization with respect to his legal responsibility for damage caused by the nuclear energy hazard". The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of approximately $2.8 billion as of January 1, 1995, a substantial portion of which must be applied to stabilization and decontamination. The Company has also secured insurance against a portion of the increased cost of generation or purchased power resulting from certain accidental outages of any of the three PVNGS units if the outage exceeds 21 weeks.
OTHER ELECTRIC PROPERTIES
Four Corners and a portion of the facilities adjacent to SJGS are located on land held under easements from the United States and also under leases from the Navajo Nation, the enforcement of which leases might require Congressional consent. The risk with respect to the enforcement of these easements and leases is not deemed by the Company to be material. However, the Company is dependent in some measure upon the willingness and ability of the Navajo Nation to protect these properties. (See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- TRANSMISSION ISSUES -- TRANSMISSION RIGHT-OF-WAY".)
As of December 31, 1994, the Company owned, jointly owned or leased 2,781 circuit miles of electric transmission lines, 5,254 miles of distribution overhead lines, 2,982 cable miles of underground distribution lines (excluding street lighting) and 223 substations.
On May 1, 1984, the Company's board of directors approved plans to proceed with OLE, which involves construction of a 345 Kv transmission line connecting the existing Ojo 345 Kv line to the existing Norton Station. For discussion of issues relating to OLE, see PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- TRANSMISSION ISSUES -- OLE TRANSMISSION PROJECT".
NATURAL GAS
The property owned by GCNM, as of December 31, 1994, consisted primarily of natural gas gathering, storage, transmission and distribution systems. The gathering systems consisted of approximately 1,178 miles (approximately 355 miles of which are leased to Gathering Company) of pipe with compression and treatment facilities. Provisions for storage made by GCNM include ownership and operation of an underground storage facility located near Albuquerque and an agreement with owners of a unitized oil field located near Artesia, New Mexico, in which GCNM has injection and redelivery rights. The transmission systems consisted of approximately 1,355 miles of pipe with appurtenant compression facilities. The distribution systems consisted of approximately 9,551 miles of pipe.
GCNM leases approximately 128 miles of transmission pipe from the DOE for transportation of natural gas to Los Alamos and to certain other communities in northern New Mexico. The lease can be terminated by either party on 30 days written notice, although the Company has the right to use the facility for two years after termination. The Company understands that the DOE is considering issuing a request for proposals to purchase such transmission facility.
The property of Gathering Company includes approximately 553 miles of gathering pipe with appurtenant compression facilities.
Processing Company owns facilities located in northwestern New Mexico having an aggregate design capacity for processing of natural gas of approximately 300,000 mcf per day.
The Company, Gathering Company and Processing Company have entered into an agreement to sell substantially all of their natural gas gathering and processing assets. Such sale is pending NMPUC approval. (See PART II, ITEM 7. - --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- SALE OF GAS GATHERING AND PROCESSING ASSETS".)
WATER
The Company's water property consists of wells, water rights, pumping and treatment plants, storage reservoirs and transmission and distribution mains. The Company has reached agreement with the City of Santa Fe for the sale of its water utility division. Such sale is pending NMPUC approval. (See PART II, ITEM 7. --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION -- OTHER ISSUES FACING THE COMPANY -- SALE OF SDCW".)
OTHER INFORMATION
The electric and gas transmission and distribution lines are generally located within easements and rights-of-way on public, private and Indian lands. The Company leases interests in PVNGS Units 1 and 2 and related property, EIP and associated equipment, data processing, communication, office and other equipment, office space, utility poles (joint use), vehicles and real estate. The Company also owns and leases service and office facilities in Albuquerque and in other operating divisions throughout its service territory.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
PVNGS WATER SUPPLY LITIGATION
The validity of the primary effluent contract under which water necessary for the operation of the PVNGS units is obtained was challenged in a suit filed in January 1982 by the Salt River Pima-Maricopa Indian Community (the "community") against the Department of the Interior, the Federal agency alleged to have jurisdiction over the use of the effluent. The PVNGS participants, including the Company, were named as additional defendants in the proceeding, which is before the United States District Court for the District of Arizona. The portion of the action challenging the effluent contract has been stayed until the community litigates certain claims in the same action against the Department of the Interior and other defendants. On October 21, 1988, Federal legislation was enacted conforming to the requirements of a proposed settlement that would terminate this case without affecting the validity of the primary effluent contract. However, certain contingencies are to be performed before the settlement is finalized and the suit is dismissed. One of these contingencies is the approval of the settlement by the court in the Lower Gila River Watershed litigation referred to below.
The Company understands that a summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons and the rights of the PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. APS, as the PVNGS project manager, filed claims that dispute the court's jurisdiction over the PVNGS participants' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of such rights. No trial date has been set in this matter.
Although the foregoing matters remain subject to further evaluation, APS expects that the described litigation will not have a material adverse impact on the operation of PVNGS.
SAN JUAN RIVER ADJUDICATION
In 1975, the State of New Mexico filed an action entitled State of New Mexico v. United States, et al., in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the "San Juan River Stream System". The Company was made a defendant in the litigation in 1976. The action was expected to adjudicate water rights used at the Four Corners plant, at SJGS and at Santa Fe. (See ITEM 1. "BUSINESS -- ELECTRIC OPERATIONS -- Fuel and Water Supply".) The Company cannot at this time anticipate the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners, nor can it determine what effect the action will have on water for Santa Fe. It is the Company's understanding that final resolution of the case cannot be expected for several years.
PVNGS PROPERTY TAXES
On June 29, 1990, an Arizona state tax law was enacted, effective as of December 31, 1989, which adversely impacted the Company's earnings in the 1990, 1991, 1992, 1993 and 1994 tax years by approximately $5 million per year, before income taxes and capitalized and deferred costs. On December 20, 1990, the PVNGS participants, including the Company, filed a lawsuit in the Arizona Tax Court, a division of the Maricopa County Superior Court, against the Arizona Department of Revenue, the Treasurer of the State of Arizona, and various Arizona counties, claiming, among other things, that portions of the new tax law are unconstitutional. In December 1992, the court granted summary judgment to the taxing authorities, holding that the law is constitutional. The PVNGS participants appealed this decision to the Arizona Court of Appeals. The Company cannot currently predict the ultimate outcome of this matter.
OTHER PROCEEDINGS
RESOLUTION TRUST CORPORATION ("RTC") LITIGATION
On March 31, 1993, certain individuals ("the New Mexico Plaintiffs"), formerly affiliated with BCD, whose general partners include Meadows, filed suit ("the New Mexico suit") in the United States District Court for the District of New Mexico against numerous parties, including the Company, current and former employees of the Company or Meadows, and MCB Financial Group, Inc., a Delaware corporation ("MCB"), 50% of which stock is owned by Meadows. The New Mexico Plaintiffs have not requested any monetary relief against the Company or certain current and former employees of the Company and Meadows but have joined those parties in connection with insurance coverage and bad faith insurance practices alleged against the insurance company which had issued a directors and officers liability policy to various entities, including MCB and BCD. The insurance allegations are made in connection with claims which were then threatened by the RTC, as receiver for Western Savings & Loan Association ("Western"), against the Company and others. The New Mexico Plaintiffs also sued the RTC for a declaration that they are not liable for any claims asserted by the RTC involving Western and BCD. The Company and the current and former employees of the Company or Meadows counterclaimed against the New Mexico Plaintiffs and cross-claimed against the insurance company and the RTC in connection with insurance coverage and bad faith insurance practices. In addition, the Company and the current and former employees of the Company or Meadows cross-claimed against the RTC, seeking a declaration of non-liability.
The RTC moved to transfer the case to the United States District Court for the District of Arizona. On February 7, 1994, an order was entered transferring the case in its entirety. Prior to the transfer, however, the New Mexico magistrate judge issued a proposed order which, if accepted by the district judge, would require the parties to enter into mediation of all the claims. The parties to the New Mexico suit have reached agreement on a dismissal without prejudice of the claims remaining in that suit, and the Company expects that suit will be dismissed in the near future. Under the terms of the proposed order of dismissal, a motion for sanctions filed against the RTC by the Company and other parties to the suit (which asserts that RTC engaged in bad faith settlement negotiations) will remain pending before the Arizona court.
On April 16, 1993, the Company and certain current and former employees of the Company or Meadows were named as defendants in an action filed in the United States District Court for the District of Arizona by the RTC, as receiver for Western. Three of the individuals sued by the RTC have indemnity agreements with the Company. The claims relate to alleged actions of the Company's or Meadows' employees in 1987 in connection with a loan procured by BCD, whose general partners include Meadows, from Western and the purchase by that partnership of property owned by Western. The RTC apparently claims that the Company's liability stems from the actions of a former employee who allegedly acted on behalf of the Company for the Company's benefit. The RTC is claiming in excess of $40 million in actual damages from the BCD/Western transactions and is also claiming damages substantially exceeding that amount on Arizona racketeering, civil conspiracy and aiding and abetting theories. These allegations involve claims against the Company for damages to Western caused by other defendants and from other transactions to which BCD was not a party. The Company is sued only on the Arizona racketeering claims. The RTC claims that damages under the Arizona racketeering statute would be trebled under applicable Arizona law. The prevailing parties on the Arizona racketeering claims could seek their fees and costs from the parties who do not prevail.
In May 1994, the RTC filed a motion seeking to amend the complaint to allege against the Company civil conspiracy, common law fraud, negligent misrepresentation, aiding and abetting breach of fiduciary duties, aiding and abetting common law fraud, aiding and abetting violation of Federal and Arizona racketeering laws (all of which claims are already asserted against the Company's current and former employees named in the suit) and claims seeking to hold the Company liable on undisclosed principal and unjust enrichment theories. The Company filed an opposition to the motion
and, in September 1994, the Court denied the RTC's motion to amend. Previously the Court dismissed the RTC's claims for aiding and abetting violations of the Federal and Arizona racketeering laws against the Company, the current and former employees of the Company or Meadows and others.
Subsequent to the Court's denial of the RTC's motion to amend the complaint, the RTC filed a motion seeking to amend the case management order previously entered by the Court. The purpose of the motion was to allow the RTC to file an amended complaint which would include the allegations against the Company sought by the motion to amend that was denied by the Court in September 1994. On November 7, 1994, the Court denied this new motion.
The Company and the current and former employees of the Company or Meadows sued by the RTC continue to have settlement negotiations with the RTC, but, to date, those efforts have not been fruitful.
The Company continues to investigate all of the claims made by the RTC in this litigation and is vigorously defending those claims. The Company cannot predict the ultimate outcome of the case but believes that the RTC's contentions are without merit and currently believes that the outcome will not result in a material adverse impact on the Company's results of operations or financial condition.
ARCHAEOLOGICAL RESOURCES PROTECTION ACT
In June 1994, a Company line crew used a bulldozer to blade an access road to electric transmission towers on U.S. Forest Service land. The Company became aware after the blading commenced that it did not have permission from the U.S. Forest Service, as well as other necessary permits. The Company immediately informed the U.S. Forest Service of the incident. The blading disturbed three archaeological sites, as well as trees and the surface in the general area.
The U.S. Forest Service conducted an investigation into the incident. The Company cooperated fully with the U.S. Forest Service in that regard, including taking appropriate actions to ensure that natural forces do not cause additional damage to the archaeological resources and the general area.
The incident may subject the Company and its employees to civil liability under the Federal Archaeological Resources Protection Act of 1979 ("ARPA"), as well as other applicable statutes. The office of the U.S. Attorney has determined not to pursue a criminal complaint against the Company or its employees and has referred the matter to its civil division. The likelihood and type of any citations or civil penalties that may be pursued by the U.S. Attorney or the U.S. Forest Service are not known at this time.
Maximum civil penalties for first violations under ARPA are the full cost of restoration and repair of the archaeological site plus either the archaeological value or the commercial value of the archaeological resources destroyed. An archaeological consultant, agreed upon by the Company and the U.S. Forest Service, has prepared an archaeological site damage assessment at a cost to the Company of approximately $14,000. The consultant estimated that the damage, based on archaeological value, is approximately $32,500, and that the cost of restoration and repairs is approximately $24,000. The archaeological consultant felt that commercial valuation of the archaeological resources was not applicable to the incident. The Company estimates that the cost of restoring the general surrounding area will be approximately $150,000. Although the Company is unable to predict the ultimate outcome of any proceedings in this case, the Company does not expect that the ultimate resolution will have a material adverse effect on the Company's financial condition or results of operations.
See PART II, ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- OTHER ISSUES FACING THE COMPANY -- ENVIRONMENTAL ISSUES" for a discussion of certain other environmental matters.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY
Executive officers, their ages, offices held with the Company in the past five years and initial effective dates thereof, were as follows on December 31, 1994:
All officers are elected annually by the board of directors of the Company.
All of the above executive officers have been employed by the Company and/or its subsidiaries for more than five years in executive or management positions, with the exception of P. T. Ortiz, M. D. Christensen, B. F. Montoya and R. J. Flynn. Prior to employment with the Company, P. T. Ortiz was employed by U S WEST Communications during the period of January 1988 to October 1991 as Chief Counsel -- New Mexico. The principal business of U S WEST Communications is telecommunications. Prior to employment with the Company, M. D. Christensen was employed with Southern California Gas. During the period 1990 through 1991, M. D. Christensen was Vice President of Planning and for the period 1987 through 1990, M. D. Christensen was Vice President of Public Affairs. Prior to employment with the Company, B. F. Montoya was employed with Pacific Gas and Electric Company ("PG&E") since 1989. In 1991, he was promoted to Senior Vice President and General Manager of the Gas Supply Business Unit of PG&E. Prior to his employment with PG&E, B. F. Montoya spent 31 years in the Civil Engineer Corps of the U.S. Navy, performing a wide range of management and utility-related assignments. B. F. Montoya achieved the rank of Rear Admiral when he became Commander, Naval Facilities Engineering Command and Chief of Civil Engineers. R. J. Flynn has a 30-year history in the utility industry working with PG&E. Since 1989, R. J. Flynn held the position of Regional Vice President, responsible for all gas and electric utility operations in the San Joaquin Valley. Prior to 1989, R. J. Flynn held the positions of Division Manager of Customer Service, Marketing, Engineering, Construction and Public Relations; Regional Electric Manager; Division Electric Superintendent; Assistant Superintendent; Senior Substation Engineer and Substation Engineer.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is traded on the New York Stock Exchange. Ranges of sales prices of the Company's common stock, reported as composite transactions (Symbol: PNM) for 1994 and 1993, by quarters, are as follows:
On January 31, 1995, there were 21,966 holders of record of the Company's common stock.
CUMULATIVE PREFERRED STOCK
While isolated sales of the Company's cumulative preferred stock have occurred in the past, the Company is not aware of any active trading market for its cumulative preferred stock. Quarterly cash dividends were paid on each series of the Company's cumulative preferred stock at their stated rates during 1994 and 1993.
For a discussion of dividend restrictions on the Company's common and preferred stock, see note 3 of notes to consolidated financial statements and ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES -- Financing Capability and Dividend Restrictions".
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data should be read in conjunction with the consolidated financial statements, the notes to consolidated financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is management's assessment of the Company's financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Company's consolidated financial statements.
OVERVIEW
COMPETITIVE ELECTRIC MARKET
The electric utility industry, as did the gas industry a decade ago, is currently undergoing major changes to meet a changing marketplace. Changes are occurring in response to actions by both Federal and state governments without an overarching plan to make all of the pieces and policies fit together and without a single government agency having the authority to impose one. At the Federal level, the passage of the National Energy Policy Act of 1992 (the "Energy Act") is causing the evolution of a traditional rate regulated industry into a competitive market environment. The Energy Act is intended to promote competition among utility and non-utility generators in the wholesale electric generation market. The Energy Act, coupled with increasing customer demands for lower-priced electricity, has accelerated industry restructuring and has intensified interest in increased competition at the retail level. In response to the Energy Act, FERC has released notices of proposed rulemakings which include topics such as transmission access and pricing, stranded investment, and regional pooling. Such proposed rulemakings would affect the electric utility industry generally. The Company is unable to predict the outcome of these proposals. In addition, initiatives at the state level in New Mexico relating to retail wheeling continue to receive attention (see "RETAIL WHEELING -- NEW MEXICO").
SPECIFIC ACTIONS BY THE COMPANY
On January 11, 1993, the Company announced specific actions determined to be necessary in order to accelerate the Company's preparation for the new challenges in the competitive electric energy market. As part of this announcement, the Company stated its intention to attempt to sell PVNGS Unit 3. As a result, the Company recorded a $126.2 million after-tax charge to 1992 earnings related to the write-down of PVNGS Unit 3 and the provision for loss associated with the M-S-R power purchase contract based on the estimated net realizable value of these resources.
On January 12, 1994, the Company and the NMPUC staff and primary intervenor groups entered into a rate reduction stipulation. The Company filed the stipulation with the NMPUC, recommending that electric retail rates be reduced by $30 million. This reduction was accomplished primarily through the write-down of the 22% beneficial interests in the PVNGS Units 1 and 2 leases purchased by the Company, the write-off of certain regulatory assets and other deferred costs, the write-off of certain PVNGS Units 1 and 2 common costs and the Company's previously announced cost reduction efforts. In conjunction with the stipulation, the Company charged approximately $108.2 million, after-tax, to the 1993 results of operations.
On November 28, 1994, the NMPUC issued a final order approving the stipulation as interpreted and provided by the order which was effective for bills rendered starting November 29, 1994.
As recommended in the stipulation, the Company's interests in PVNGS Units 1 and 2 are now confirmed in this NMPUC order as "used and useful" for the rate making purposes of the stipulation and the finding remains in force until the stipulation is superseded or otherwise terminated. The order confirms that the status of PVNGS Units 1 and 2 is no different from that of other used and useful assets. Any costs incurred for these units as of January 12, 1994, will be fully recoverable in the Company's jurisdictional rates consistent with the terms and conditions of the NMPUC order and the stipulation, and subject to assurance that all such costs have been accounted for accurately.
In approving the stipulation, the NMPUC reconfirmed its authority over the Company and its authority to issue orders in the public interest, finding nothing in the stipulation to supersede that authority. Pursuant to the stipulation, the signatories do not intend to file or cause the filing of a general rate case before January 1, 1998, in the absence of a significant restructuring of rate base or unforeseen circumstances occasioning a significant change in the Company's costs. As a result of the order, the Company believes that the rates agreed upon in the stipulation will be adequate to recover the cost of its New Mexico jurisdictional services going forward and further believes that the Company will be in a better position to compete in a competitive electric market environment.
UNCERTAINTIES
The Company believes that the stipulation has improved its competitive position in the electric market, but recognizes that low cost producers may have an advantage if the regulatory framework changes significantly towards retail wheeling concepts. The Company's generating costs are currently above those of some neighboring utilities due primarily to the expensive nuclear generation.
The future structure of the industry, the form and timing of competition and the method of regulation in a competitive environment remain uncertain. In the transition to a more competitive market environment from a traditional rate regulated environment, the value of a utility's assets could be affected significantly. If the cost of operating a utility's existing assets is above market prices, the utility may be unable to recover all of its costs without adequate treatment for stranded assets. In the Company's situation, if included generation costs currently being recovered in retail rates were to be based on a competitive market price which is lower than its current costs, the value of the Company's PVNGS Units 1 and 2 investment could be economically impaired.
STRATEGIC PLAN
In order to mitigate the exposures associated with a competitive electric market and transition into this changing environment, the Company, in addition to the January 11, 1993 announcement and other actions discussed above, has set the following strategic plan: (1) secure financial flexibility by retiring debt, (2) restructure the Company's expensive generating assets and nuclear leases, (3) control operating and maintenance costs, and (4) develop new business opportunities in the energy related area. It should be noted, however, that the Company's ability to restructure its generating assets and nuclear leases is limited. In addition, the Company's ability to develop new business opportunities will be subject to state laws, rules and regulations.
As part of this plan, the Company has internally restructured its operations into four separate business units, each targeted at a specific segment of its customer base. The new structure is intended to make the Company more customer oriented and responsive to the changing competitive environment. The four units - -- Electric Services, Gas Services, Bulk Power Services and Energy Services -- will be evaluated continuously for their contribution to building shareholder value.
LIQUIDITY AND CAPITAL RESOURCES
The Company's ability to generate sufficient amounts of cash to meet its operating and capital cash requirements ("liquidity") is a function of the rates it is allowed to charge and its ability to access the credit markets. The recent NMPUC order relating to the retail electric rate reduction and potential longer-term effects of a more competitive energy market are expected to negatively affect the Company's liquidity. However, the Company believes that anticipated sales of assets and cost reduction efforts will minimize the Company's need for external capital resources. The Company currently expects that cash generated from internal sources will be sufficient to meet the capital requirements during the 1995 through 1999 period. However, to cover differences in the amounts and timing of cash generation and cash requirements, the Company intends to utilize short-term borrowings under its liquidity arrangements.
CAPITAL REQUIREMENTS
Total capital requirements include construction expenditures as well as other major capital requirements, including retirements of long-term debt, preferred stock and long-term debt sinking funds and preferred stock dividend requirements. The main focus of the construction program is upgrading generating systems, upgrading and expanding the electric and gas transmission and distribution systems, and purchasing nuclear fuel. Total capital requirements for 1994 and projections for 1995-1999 are shown below:
LIQUIDITY
The Company's construction expenditures for 1994 were entirely funded through cash flow from operations. In addition to cash flow from operations, the Company received approximately $40 million, on June 2, 1994, from the sale of a 35 MW undivided interest in SJGS Unit 4 to UAMPS. On April 20, 1994, the Company retired its $45 million 10 1/8% series first mortgage bonds and at the end of 1994, the Company had $74.5 million of temporary investments and no short-term borrowings. In addition, at year-end 1994, the Company had available liquidity arrangements of $151 million consisting of a $100 million secured revolving credit facility ("Facility") which expires in June 1995, $40 million credit facility collateralized by electric accounts receivables of the Company and $11 million of local lines of credit. The Company expects to renew the Facility prior to its expiration.
On March 8, 1995, after the required consent of the holders of PVNGS LOBs was obtained, approximately $121 million in principal amount of PVNGS LOBs was retired. The retired LOBs consisted of approximately $58 million of 10.30% LOBs due 2014 retired at a price of 100% of par and approximately $63 million of 10.15% LOBs due 2016 retired at a price of 97.8% of par. In connection with the LOB retirements, approximately $65 million was borrowed under the Company's liquidity arrangements and approximately $19 million was obtained under the securitization facility related to certain amounts being recovered from gas customers relating to certain gas contract settlements. The Company intends to repay the borrowings from proceeds of pending asset sales.
Additionally, approximately $4.4 million and $4.8 million in principal amount of LOBs due 1996 and 1997 at interest rates of 9.125% and 8.95%, respectively, are expected to be redeemed at par on March 22, 1995.
The Company currently estimates a total of $864 million for its capital requirements for the period of 1995 through 1999. The Company expects that such cash requirements are to be met primarily through internally-generated cash.
The Company also expects to receive cash proceeds from asset sales during 1995. The Company expects to consummate the sale of the Company's water division to the City of Santa Fe for approximately $56 million (as currently adjusted) in the second quarter of 1995. The Company, along with its subsidiaries, Gathering Company and Processing Company, also anticipates to receive approximately $155 million from the sale of certain natural gas gathering and processing assets. If these sales are consummated, the current plan for the use of the proceeds from these sales which the Company is allowed to retain after tax payments and sharing of the gains with customers would be to retire debt. The sale of these assets, as well as the amount of proceeds the Company would ultimately retain and the use of those proceeds, will be subject to a number of conditions and various regulatory approvals.
FINANCING/CREDIT MARKET
The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on capital, results of operations, credit ratings, regulatory approvals and financial market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term debt securities and preferred stock, and to obtain short-term credit. However, all of the Company's securities are rated below investment grade by Standard & Poor's Corp. ("S&P") and Moody's Investors Service ("Moody's"), which may result in limited credit markets being available and/or higher financing costs to the Company.
While S&P recently upgraded the Company's rating outlook from "stable" to "positive" as a result of "approved settlement agreement, plans to sell unneeded assets and pay down debt, relatively strong electric sales growth, recent PVNGS operating performance and increasing confidence in management's basic business strategy", S&P indicated that a rating upgrade could be several years off. Moody's, however, has advised investors that it is reviewing for possible downgrades all lease obligation bonds associated with nuclear power plants.
FINANCING CAPABILITY AND DIVIDEND RESTRICTIONS
One impact of the Company's current ratings, together with covenants in the Company's PVNGS Units 1 and 2 lease agreements (see PART I, ITEM 2. -- PROPERTIES -- Nuclear Plant"), is to limit the Company's ability, without consent of the owner participants and bondholders in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. The Facility and a reimbursement agreement associated with the letter of credit supporting $37.3 million of pollution control revenue bonds impose similar restrictions irrespective of credit ratings.
The issuance of first mortgage bonds by the Company is subject to earnings coverage and bondable property provisions of the Company's first mortgage indenture. The Company also has the capability under the mortgage indenture, without regard to the earnings test but subject to other conditions, to issue first mortgage bonds on the basis of certain previously retired bonds. At December 31, 1994, based on the earnings test, the Company could have issued approximately $248 million of additional first mortgage bonds, assuming an annual interest rate of 11.5 percent. The Company's restated articles of incorporation limit the amount of preferred stock which may be issued. Assuming a preferred stock dividend rate of 10 percent, the Company could have issued $291 million
of preferred stock as of year end. At year-end 1994, the Company had $74.5 million of temporary investments. The Company currently has no requirements for long-term financing during the period of 1995 through 1999 period. However, during this period, the Company could enter into long-term financings for the purpose of strengthening its balance sheet and reducing its cost of capital. In 1995, subject to other investment opportunities available to the Company, the Company may potentially retire other long-term debt.
The Company's board of directors, which reviews the Company's dividend policy on a continuing basis, has not declared dividends on its common stock since January 1989. As of December 31, 1994, the Company had a deficit in retained earnings of $46 million and is currently unable to resume payment of dividends on its common stock. The resumption of common dividends is dependent upon a number of factors including earnings and financial condition of the Company and market conditions. The Company evaluated its ability to continue paying dividends on its preferred stock under restrictions imposed by the Federal Power Act due to the Company's negative retained earnings. In 1993, the Company advised the FERC staff of the Company's position that payment of preferred stock dividends would not be in violation of the Federal Power Act. As a result, the Company has continued to declare and pay dividends on its preferred stock on scheduled dates.
CAPITAL STRUCTURE:
The Company's capitalization, including short-term debt, at December 31 is shown below:
RESULTS OF OPERATIONS
Net earnings per common share in 1994 were $1.77, compared to a loss of $1.64 per common share in 1993 and a loss of $2.67 per common share in 1992. The loss experienced in 1993 was due primarily to the Company recording an after-tax charge of $108.2 million to earnings resulting from the stipulation filed with the NMPUC recommending that electric retail rates be reduced by $30 million. The loss experienced in 1992 was due primarily to the write-down of PVNGS Unit 3 and the provision for loss associated with the M-S-R power purchase contract. This resulted in an after-tax charge of $126.2 million to 1992 earnings.
The financial performance of the excluded resources has been improved by the PVNGS Unit 3 write-down and the provision for loss associated with the M-S-R power purchase contract recorded in 1992. The gains from the sale of generating facilities to Anaheim recorded in August 1993 and to UAMPS recorded in June 1994 have also improved the financial performance of the excluded resources. Operating results for the excluded resources for all these periods reflect the allocation of interest charges based on the average investment in excluded net utility plant as a percent of total utility plant for the period.
Selected financial information for the excluded resources for 1994, 1993 and 1992 is shown below:
The following discussion highlights other significant items which affected the results of operations in 1994, 1993 and 1992, and certain items impacting future earnings.
Results of operations for 1994 may not be indicative of future results of operations; for example, the electric retail rate reduction effective for bills rendered starting November 29, 1994, is expected to reduce electric revenues annually by approximately $30 million.
Electric gross margin (electric operating revenue less fuel and purchased power expense) increased $32.3 million in 1994, $23.2 million of which was caused by an increase in jurisdictional energy sales of 408.5 million KWh or a 7% increase. This increase was partially due to warmer weather than a year ago. A difference between the estimated unbilled revenues reported in 1993 and actual unbilled revenues also increased gross margin by $6.7 million in 1994. Electric gross margin increased $30.1 million in 1993 compared to 1992; $20.9 million of this was a result of the 1992 provision for loss associated with the M-S-R power purchase contract and $9.3 million from a 2.7% increase in jurisdictional energy sales of 145.5 million KWh.
Gas gross margin (gas operating revenues less gas purchased for resale) decreased $5.1 million from a year ago. Principal factors were the write-off of certain deferred charges relating to costs of gas and a decrease in gas deliveries resulting from a warmer than normal winter in 1994. Although gas gross margin remained flat from 1992 to 1993, gas operating revenues increased $27.9 million and gas purchased for resale increased $27.4 million in 1993 when compared to 1992. Increases in purchased gas costs (which are recovered from customers through the PGAC) and transportation revenues were the principal reasons. Purchased gas costs affect revenues and gas purchased for resale equally.
Other operation and maintenance expenses decreased $5.1 million from a year ago. Major factors were a $10.6 million decrease as a result of the Company's 1993 severance program, a deferral of gas operation's retirees health care costs of $2.8 million for regulatory purposes and lower electric regulatory commission expense of $2.1 million. There were, however, increased pension and retirees health care cost of $3 million, increased electric distribution expense of $3.6 million due to weather-related outages and increased tree trimming activity, increased workers' compensation liability of $2.2 million and increased generating station maintenance expense of $2.4 million.
Other operation and maintenance expenses increased $3.4 million in 1993 over 1992. The major factors were the Company's 1993 severance program costs of $10.6 million, increased pension and benefit expense of $4.8 million resulting from the adoption of SFAS No. 106, EMPLOYER'S ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS, higher electric regulatory expenses of $2.5 million and higher PVNGS decommissioning expense of $2.4 million. Such increases were partially offset by a decrease in PVNGS lease expense of $12.2 million resulting from the Company's purchase of approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases in September 1992 and a decrease in PVNGS operating costs of $5.6 million.
The January 12, 1994 stipulation resulted in an after-tax charge of $108.2 million in 1993. In 1992, the Company recorded an after-tax charge of $126.2 million for the write-down of the Company's investment in PVNGS Unit 3 and the provision for loss associated with the M-S-R power purchase contract (see note 2 of notes to consolidated financial statements).
Other, under the caption Other Income and Deductions, increased $9.3 million from a year ago and increased $16.1 million from 1992 to 1993.
Significant 1994 items, net of taxes, include the write-off of $3.0 million relating to gas take-or-pay settlement payments which are not recoverable through rates and additional provisions for legal expense of $3.6 million and a gain and associated tax benefit of $6.1 million from the sale of generating facilities to UAMPS.
Significant 1993 items, net of taxes, included the following: (1) the gain of $7.5 million recognized from the sale of an investment, (2) the gain and associated tax benefit of $7.6 million from the sale of generating facilities to Anaheim, and (3) tax benefits of $3.2 million from the Federal income tax rate change which will allow the Company to utilize its net operating loss at a higher tax rate. Partially offsetting such increases were: (1) additional provisions for legal and litigation expenses of $5.7 million, (2) a write-off of $4.6 million of other deferred costs, (3) PVNGS decommissioning fund adjustment of $2.8 million and (4) a write-off of $2.1 million resulting from costs associated with refunding certain pollution control and EIP bonds which represents the amount related to FERC firm-requirement wholesale customers and resources excluded from New Mexico jurisdictional rates.
Significant 1992 items, net of taxes, included the following: (1) a $9.8 million charge recorded as a result of the Company's conclusion in the fourth quarter of 1992 that it did not meet the criteria of SFAS No. 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION, for recording electric regulatory assets, (2) additional loss provision of $6.3 million related to gas contract disputes, (3) recognition of an additional $2.3 million of PVNGS decommissioning and decontamination costs related to the excluded resources, (4) write-offs of $2.3 million resulting from the application of SFAS No. 101, ACCOUNTING FOR THE DISCONTINUANCE OF APPLICATION OF SFAS NO. 71, to the Company's firm-requirement wholesale customers, (5) write-downs of $2.2 million for various non-utility properties, (6) a write-off of $2.2 million relating to a canceled transmission project and (7) additional transaction privilege taxes of $2.1 million. Partially offsetting such charges were the cumulative effect of the change in the method of accounting for unbilled revenues of $12.7 million.
Net interest charges decreased $15.2 million in 1994. Major factors were: (1) lower short-term borrowings in 1994, (2) the refinancing of $182 million of pollution control revenue bonds in January ($46 million) and September ($136 million) of 1993 and (3) the retirement of $45 million of first mortgage bonds in April 1994. In 1993, net interest charges increased $12.4 million compared to 1992. Major factors were: (1) recording long-term debt of $141 million for the purchase of approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases in September 1992, (2) the recording of the interest component of the provision for loss on the M-S-R power purchase contract which was recorded in 1992 and (3) interest resulting from the IRS examination settlement.
OTHER ISSUES FACING THE COMPANY
RETAIL WHEELING -- NEW MEXICO
During 1992, the Energy Act stimulated interest in the retail wheeling concept throughout the United States. In New Mexico, legislation was introduced in the 1993 New Mexico state legislature. On March 6, 1993, the New Mexico State Senate passed Senate Memorial 54, which called for the concept of retail wheeling to be studied by the Integrated Resource Planning Committee, an interim legislative committee, with a report to be made to the 1995 legislature. In its report, the Integrated Resource Planning Committee recommended to the legislature that the committee be continued for an additional two-year term and that the committee's oversight be expanded to include, among other things, consideration of the restructure of the electric utility industry and its regulation in light of competitive influences. A bill has been introduced in the 1995 legislature providing for the creation of the "Electric Utility Regulation Oversight Committee" and requiring such interim committee to report its findings and recommendations to the legislature by December 15, 1996. This bill was unanimously passed by the Senate and is awaiting consideration by the House. The Company provided information for the initial study effort and will continue to provide information should the legislature agree to continue the study committee. A bill which would have authorized retail wheeling and limited electric rates to 110% of those of the lowest cost electric utility in the state after a five year phase-in period has been tabled in committee. Other bills regarding retail wheeling have also been introduced in the legislature and are awaiting hearings.
TRANSMISSION ISSUES
OLE TRANSMISSION PROJECT
In 1984, the Company's board of directors approved plans to construct OLE, a 345 Kv transmission line connecting the existing Ojo 345 Kv line to the Norton station in northern New Mexico. The Company has incurred approximately $15.8 million of costs associated with OLE as of December 31, 1994, and it currently estimates that project costs will total approximately $54.3 million. A significant amount of the costs to date relate to obtaining regulatory and environmental approvals. OLE is designed to provide a needed improvement to the northern New Mexico transmission system and to allow greater delivery of power into the Company's two largest service territories, the greater Albuquerque area and the Santa Fe/Las Vegas area. The Company had obtained necessary right-of-way permits from two of the three Federal agencies having authority over the lands involved in the project. In 1991, the Company filed for NMPUC approval for construction of OLE and final briefs were filed in December 1992. However, OLE has faced considerable opposition by persons concerned primarily about the environmental impacts of the project. The Company is awaiting a final decision from the NMPUC.
On January 11, 1993, the Company's board of directors directed a project team to take a fresh look to see if any alternatives had not been considered. In 1994, a working group consisting of the Company and other interested parties identified an alternative route to the originally proposed OLE route. The group has determined that this alternative route could be environmentally, technically and economically better or equal to the original route. This route involves the rebuild of an existing 26-mile 115 Kv line owned by Plains and will require further environmental studies.
The 1994 record summer heat resulted in record high loads on the Company's transmission systems which brought greater attention to the problems related to delays in adding OLE transmission capacity to the northern transmission system. Outages at the Company's Reeves Station (oil and gas-fired units) due to emergency turbine repairs and interruptions of power deliveries from SPS resulted in the transmission loading exceeding the operating limits of the system during the summer of 1994. The Company would have experienced interruptions of load if an outage of any major transmission facility had occurred during this time period. The 1995 summer peak could result in load levels greater than 1994 levels. To prevent transmission limits from being exceeded this summer, the Company has negotiated with entities in southern New Mexico to insure that agreed import levels will
not be exceeded. Also, every effort is being made to insure that all Reeves Station units will be available and additional equipment has been installed on the Company's existing transmission system to mitigate potential problems.
TRANSMISSION RIGHT-OF-WAY
The Company has easements for right-of-way with the Navajo Nation for portions of several transmission lines that deliver the Company's generation resources to load centers. One grant of easement for approximately 4.2 miles of right-of-way for two parallel 345 Kv transmission lines expired on January 17, 1993. Prior to the expiration, the Company had unsuccessfully attempted to renew the grant. Thereafter, the Company was successful in reaching an interim agreement which provided for the Navajo Nation not to challenge the Company's use of the easement until July 17, 1994.
On October 31, 1994, the Navajo Nation adopted a Civil Trespass Statute providing for civil penalties, damages and other remedies, including removal, to be imposed for unconsented or unauthorized use of Navajo Nation lands. The Company is currently evaluating the impact, if any, of the new statute.
On November 8, 1994, the Navajo Nation elected a new President. On November 11, 1994, the Navajo Nation informed the Company that the President had directed the negotiation to be halted until the new administration could become familiarized with the issues. The Company is unable to predict what effect a new administration will have on the ongoing negotiations. However, the Company has scheduled meetings with new administration officials to discuss this issue.
The Company continues to assess its options but is not pursuing other alternatives unless it receives indications that settlement cannot be reached in a satisfactory manner. The Company currently cannot predict the outcome of the negotiations or the costs resulting therefrom; however, the Company believes that resolution of this issue will not have a material impact on the Company's results of operations or financial condition.
ENVIRONMENTAL ISSUES
The Company is committed to complying with all applicable environmental regulations in a responsible manner. Compliance with all environmental issues has and will continue to present a challenge to the Company. The Company has evaluated the potential impacts of the following environmental issues and believes, after consideration of established reserves, that the ultimate outcome of these environmental issues will not have a material adverse effect on the Company's financial condition or results of operations.
GAS OPERATIONS
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT ("CERCLA")
Two CERCLA 104(e) requests for information were received from the EPA in late 1993, requesting information regarding shipment of wastes to the Lee Acres Landfill, located on BLM land near the city of Bloomfield in San Juan County, New Mexico. The landfill is currently listed on the National Priorities List as a superfund site. GCNM and Gathering Company assessed their records and other information to determine whether wastes were ever shipped from their facilities to the landfill during the period when they owned and operated the natural gas facilities. GCNM and Gathering Company's assessment indicated that no hazardous materials were shipped from their facilities to the landfill during this time period. Nonetheless, GCNM and Gathering Company could be determined to be potentially responsible parties if the EPA ultimately determines GCNM and Gathering Company shipped wastes to the site, and could be asked or compelled to provide funds for site cleanup. GCNM and Gathering Company submitted their response to the EPA on March 8, 1994. To date, GCNM and Gathering Company have not received any further notification from the EPA regarding the Lee Acres site.
AIR PERMITS
An environmental audit performed in association with the Company's proposed sale of certain gas assets brought to light certain discrepancies regarding required air permits associated with certain natural gas facilities. The audit identified a total of thirteen facilities containing discrepancies. The vast majority of the discrepancies were minor in nature and included discrepancies in record keeping, equipment identification and inaccurate information in air permit applications. The discrepancies at three of the facilities involve permit issuance and modification and are more serious in nature. The Company is subject to administrative fines/penalties by the NMED for these discrepancies.
In April 1994, the Company met with the NMED to discuss the nature of the permit discrepancies and to propose methods and schedules to resolve the discrepancies. As a result of this meeting, the NMED has informed the Company that it will not pursue enforcement of the thirteen minor discrepancies noted above. On August 30, 1994, the Company submitted its permit modification application for the Lybrook Gas Processing Plant ("Lybrook"). On November 14, 1994, the Company received a written Notice of Violation ("NOV") from the NMED for Lybrook. The NOV indicates that the NMED has concluded that the Company violated air quality control regulations requiring permits for modification of stationary sources. The NOV indicated the Company may be subject to a civil action in district court for the appropriate relief and/or the assessment of civil penalties. The Company has responded to the NOV and is pursuing efforts to address the NOV with the NMED.
The Company anticipates that it will submit Processing Company's air permit modification application on the Kutz Canyon Gas Processing Plant ("Kutz") in the first quarter of 1995. While the Company cannot be certain, the Kutz filing, which will be similar to the Lybrook filing, may also result in an NOV from the NMED due to apparent permit discrepancies in the Kutz air permit.
GAS WELLHEAD PIT REMEDIATION
The New Mexico Oil Conservation Commission ("NMOCC") issued an order effective on January 14, 1993, that affects GCNM and Gathering Company's natural gas gathering facilities located in the San Juan Basin in Northwestern New Mexico. The NMOCC ruling prohibits the further discharge of fluids associated with the production of natural gas into unlined earthen pits in certain specified areas of the San Juan Basin. The NMOCC ruling required the cessation of discharge of production fluids in three specified areas within specific time frames. In addition, the ruling required the submission of closure plans for the closure of pits in which production fluids were previously discharged. The BLM has issued a similar ruling. GCNM and Gathering Company have ceased discharge in the first area identified by the NMOCC and are proceeding to cease discharge in the second area identified in the NMOCC ruling. GCNM and Gathering Company have also submitted and received approval of their pit closure plans from the OCD, the Energy Minerals and Natural Resources Department, as well as the BLM. Because the assets associated with GCNM and Gathering Company's gathering operations are the subject of the sale of gas assets to Williams, GCNM and Gathering Company will not be subject to the cease discharge requirement for the third and final area identified in the NMOCC's ruling if the sale closes prior to March 1, 1996.
The three previously mentioned gas operations environmental issues, with the exception of the third and final area identified in NMOCC's ruling related to gas wellhead pit remediation, are part of the retained environmental liabilities under the sale agreement with Williams (see "SALE OF GAS GATHERING AND PROCESSING ASSETS").
DIETHANOLAMINE ("DEA") SPILL
In June 1994, the Processing Company experienced a release of DEA due to an equipment malfunction. DEA wastes are oilfield exempt wastes which are not subject to regulation as hazardous wastes under the Resource Conservation and Recovery Act ("RCRA"). The spill and subsequent removal of DEA-contaminated soils were reported to the OCD which has jurisdiction over such spills and wastes. However, the release of DEA to the air in amounts that exceed the reportable quantity of one pound is potentially reportable under CERCLA as amended by the Superfund Amendments and Reauthorization Act ("SARA"). When it was discovered in September 1994 that the spill had not been
reported under CERCLA/SARA, as a precaution, the spill notification/report was forwarded to the National Response Center on September 22, 1994. The Company is currently unable to predict what, if any, enforcement action may ensue.
ELECTRIC OPERATIONS
PERSON STATION
The Company's current estimate to decommission its retired fossil-fueled plants includes approximately $10.9 million to complete the groundwater remediation program at Person Station. The Company, in compliance with the New Mexico Environment Department Corrective Action Directive, determined that groundwater contamination exists in the deep and shallow water aquifers. The Company is required to delineate the extent of the contamination and remediate the contaminant in the ground water. The extent of the contaminant plume in the deep water aquifer is not currently known, and the estimate assumes that the deep ground water plume can be easily delineated with a minimum number of monitoring wells. As part of the financial assurance requirements of the Person Station Hazardous Waste Permit, the Company posted a $5.1 million performance bond with a trustee. The remediation program continues on schedule.
SANTA FE STATION
The estimate to decommission Santa Fe Station includes monies for environmental issues related to the site. The NMED has been conducting an investigation of the groundwater contamination detected beneath the site to determine the source of the contamination. The source of groundwater contamination has not yet been definitely identified, and the Company is continuing to cooperate with the NMED site investigations pursuant to a consent agreement between the Company and the NMED.
CERCLA
On January 18, 1995, the Company received a CERCLA Section 104(e) request for information from the EPA regarding the Hansen Container Site in Grand Junction, Colorado ("Hansen Site"). The EPA is investigating the site and seeking information relating to the number and contents of drums, barrels and other materials that were sent to the Hansen Site for reconditioning, disposal or storage. The Company undertook an internal investigation to determine if the Company or its subsidiaries may have sent or shipped any drums, barrels or other materials containing hazardous materials to the Hansen Site. The Company filed its response to the EPA's request for information on March 2, 1995, and stated that the Company's records indicate that it did not dispose of any hazardous materials at the Hansen Site and did not cause others to transport hazardous materials for disposal at the Hansen Site. The Company's records did indicate, however, that the Company sold empty scrap drums to a drum recycler in the 1980's who has been linked to the Hansen Site by the EPA. The Company's position is that it is not a potential responsible party; however, given these transactions, the Company could possibly be determined to be a potential responsible party and could be asked or compelled to provide funds for site cleanup. Based on the Company's discussions with the EPA to date, the Company does not expect to be required to provide any significant funding for site cleanup.
PVNGS -- STEAM GENERATOR TUBES
APS, as the operating agent of PVNGS, has encountered tube cracking in the steam generators and has taken, and will continue to take, remedial actions that it believes have slowed further tube degradation. At the present time, APS is undergoing a refueling outage in Unit 2. The steam generator tubes are being inspected in conjunction with this outage. APS currently believes that the PVNGS steam generators are capable of operating for their designed life of forty years, although, at some point, long-term economic considerations may warrant examination of possible steam generator replacement. All of the PVNGS units were operating at full power at December 31, 1994 and are expected to continue operating at full power, except for scheduled (mid-cycle or refueling) outages.
PVNGS DECOMMISSIONING FUNDING
The Company has a program for funding its share of decommissioning costs for PVNGS. Under this program, the Company makes a series of annual deposits to an external trust fund over the estimated useful life of each unit with the trust funds being invested under a plan which allows the accumulation of funds largely on a tax-deferred basis through the use of life insurance policies on certain current and former employees. The results of the 1992 decommissioning study indicate that the Company's share of the PVNGS decommissioning costs will be approximately $150.4 million, an increase from $98.9 million based on the previous study (both amounts are stated in 1994 dollars). The Company determined that a supplemental investment program will be needed as a result of both the cost increase and the under performance of the existing investment program. In 1995, the Company will file a request for permission from the NMPUC to establish a supplemental investment program, allowing for investment in more traditional classes of investments. The Company will also request the authority to establish a qualified tax advantaged trust for Units 1 and 2. Due to IRS regulations, Unit 3 will remain in a non-qualified trust. With the uncertainty of the FERC regulation regarding restrictions on investment vehicles, the Company will address any issues as they are resolved. In the November 28, 1994 NMPUC order (see "SPECIFIC ACTIONS BY THE COMPANY"), the NMPUC approved the increased decommissioning costs for PVNGS Units 1 and 2 and included such amounts as a component in the determination of retail rates. The market value of the existing trust at the end of 1994 was approximately $12 million, including cash surrender value of the policies. A new PVNGS decommissioning cost study will be performed during the latter half of 1995.
EL PASO ELECTRIC COMPANY BANKRUPTCY
El Paso, a joint owner in the PVNGS and Four Corners facilities, is and has been operating under Chapter 11 of the Bankruptcy Code since 1992. A plan whereby El Paso would become a wholly-owned subsidiary of Central and South West Corporation ("CSW") would resolve certain issues to which PVNGS participants could be exposed by the bankruptcy, has been confirmed by the bankruptcy court, but cannot become fully effective until several additional or related approvals are obtained. El Paso would also assume the Four Corners Operating Agreement and the Arizona Nuclear Power Project Participation Agreement under the plan. CSW has stated that certain issues have arisen which may impede completion of the merger, but it has not terminated merger efforts. If the approvals are not obtained, the plan could be withdrawn or terminated, thereby reintroducing issues affecting the Company. At this time, the Company is unable to predict the result of this bankruptcy proceeding.
SALE OF SDCW
On February 28, 1994, the Company and the City of Santa Fe (the "City") executed a purchase and sale agreement for the Company's water division for approximately $48 million. As currently adjusted, the purchase price will be approximately $56 million. In March 1994, the Company filed its application with the NMPUC for approval of the sale and hearings were commenced on December 12, 1994 and concluded on January 9, 1995. The NMPUC staff and intervenors recommended that the Company retain the estimated after-tax gain of $6 million for the sale. The proposed agreement excluded from the sale certain Santa Fe area real estate which the Company would either sell or trade separately. Under the agreement, the Company would continue to operate the water utility for up to four years for a fee under a proposed contract with the City. The NMPUC staff recommended that the Company be allowed to form an unregulated subsidiary to manage the water utility. The parties are awaiting a recommended decision from the hearing examiner. The Company currently expects that the closing will be in the second quarter of 1995.
SALE OF GAS GATHERING AND PROCESSING ASSETS
On February 12, 1994, an agreement was executed with Williams for the sale of substantially all of the assets of Gathering Company and Processing Company, and for the sale of Northwest and Southeast gas gathering and processing facilities of the Company. The agreement provides for a cash selling price of $155 million, subject to certain adjustments.
The sale is subject to NMPUC approval. The Company filed its application for approval with the NMPUC on May 20, 1994. On January 13, 1995, the Company and certain intervenors (the NMPUC Staff, the AG, Williams and GPM Gas Corporation) reached a stipulated agreement, subject to NMPUC approval, settling certain issues, including the division of the gain from the sale of the gas gathering and processing assets. Under the stipulation, the Company would recognize an after-tax gain of approximately $14.1 million, subject to certain adjustments at the closing, and would record a liability of approximately $35.5 million which would be credited to the Company's gas customers' bills over approximately five years. At the sixth year after the closing, such liability amount would be recalculated to reflect the actual transaction costs and any resulting difference would be refunded or billed to customers over a one year period.
The stipulated agreement provides for the approval of three 10-year contracts, each with an option to renew for an additional 5-year term, with Williams for competitively priced gathering and processing services. The Company believes that the contracts will save customers amounts estimated to be between $100 million and $128 million over 10 years. The stipulation also provides that GCNM will recover, as an expense of the sale, $3.3 million of the $4.8 million of costs deferred in GCNM's PGAC continuation proceeding. The Company wrote off $1.5 million of such costs against 1994 earnings (see "RATES AND REGULATION -- Other Natural Gas Matters").
On January 23, 1995, certain natural gas producers (Meridian Oil Inc., Marathon Oil Company, Conoco, Inc., Amoco Production Company and Caulkins Oil Company) filed a statement in opposition to the stipulation. Initially the producers claimed that the resulting gain from the sale was improperly calculated and allocated and that the proposed gathering and processing contracts with Williams are unreasonable. Prior to the hearing, two of the producers withdrew their opposition and another two withdrew their opposition concerning the proposed gathering and processing contracts.
Hearings began on February 13, 1995 and were completed on February 17, 1995. The parties to the stipulation requested a final order from the NMPUC on an expedited basis. If NMPUC approval is issued on an expedited basis, the Company expects to finalize the sale by the end of second quarter of 1995. However, the Company cannot predict the ultimate timing or outcome of the NMPUC action.
EXCLUDED CAPACITY
As of December 31, 1994, the Company had a total of 280 MW of capacity excluded from NMPUC jurisdictional rates which consists of 130 MW of PVNGS Unit 3, 45 MW of SJGS Unit 4 and the 105 MW M-S-R power purchase contract which expires April 30, 1995. The Company continues to be dependent on the wholesale power market for the recovery of its costs associated with excluded capacity (see "RESULTS OF OPERATIONS").
In accordance with the Company's plan announced in January 1993, the Company has sold 85 MW of its excluded capacity and continues to attempt to sell some or all of its interest in PVNGS Unit 3. To date, the Company's attempts to sell excluded nuclear generation have been unsuccessful.
ALBUQUERQUE FRANCHISE ISSUES
The Company's non-exclusive electric service franchise with the City of Albuquerque (the "City") expired in early 1992. The franchise agreement provided for the Company's use of City property for electric service rights-of-way. The Company continues service to the area, which contributed 45.6% of the Company's total 1994 electric operating revenues. The absence of a franchise does not change the Company's right and obligation to serve those customers under state law.
In November 1991, the NMPUC issued an order concluding, among other things, that the City could bid for services to its own facilities (Albuquerque municipal loads generated approximately $17.0 million in annual revenue for 1994), but not for service to other customers. In reaching this conclusion, the NMPUC noted that New Mexico law reflects a legislative choice to vest the NMPUC with exclusive control over utility rates and services. The NMPUC also noted that the Company's obligation to serve its customers in Albuquerque will continue irrespective of whether the municipal franchise is renewed. The City appealed the NMPUC's order to the New Mexico Supreme Court (the "Court"). On April 21, 1993, the Court issued its decision on the City's appeal of the NMPUC order. The Court ruled that a city can negotiate rates for its citizens in addition to its own facility uses. The Court also ruled that any contracts with utilities for electric rates are a matter of statewide concern and subject to approval, disapproval or modification by the NMPUC. In addition, the Court reaffirmed the NMPUC's exclusive power to designate providers of utility service within a municipality and confirmed that municipal franchises are not licenses to serve but rather to provide access to public rights-of-way.
In 1992, representatives of the Company and the City met in attempts to resolve the franchise renewal issue. Currently, the franchise renewal meetings are in abeyance due to the City's interest in the outcome of the retail wheeling legislation (see "RETAIL WHEELING -- NEW MEXICO"). The Company continues to pay franchise fees to the City.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
The management of Public Service Company of New Mexico is responsible for the preparation and presentation of the accompanying consolidated financial statements. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles and include amounts that are based on informed estimates and judgments of management.
Management maintains a system of internal accounting controls which it believes is adequate to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management authorization and the financial records are reliable for preparing the consolidated financial statements. The system of internal accounting controls is supported by written policies and procedures, by a staff of internal auditors who conduct comprehensive internal audits and by the selection and training of qualified personnel.
The board of directors, through its audit committee comprised entirely of outside directors, meets periodically with management, internal auditors and the Company's independent auditors to discuss auditing, internal control and financial reporting matters. To ensure their independence, both the internal auditors and independent auditors have full and free access to the audit committee.
The independent auditors, Arthur Andersen LLP, are engaged to audit the Company's consolidated financial statements in accordance with generally accepted auditing standards.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Public Service Company of New Mexico:
We have audited the accompanying consolidated balance sheets and statements of capitalization of Public Service Company of New Mexico (a New Mexico corporation) and subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of earnings (loss), retained earnings (deficit), and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Public Service Company of New Mexico and subsidiaries as of December 31, 1994 and 1993, and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
As explained in notes 1 and 6 to the financial statements, effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS, and No. 109, ACCOUNTING FOR INCOME TAXES.
ARTHUR ANDERSEN LLP
Albuquerque, New Mexico February 23, 1995
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders Public Service Company of New Mexico:
We have audited the consolidated statements of earnings (loss), retained earnings (deficit) and cash flows of Public Service Company of New Mexico and subsidiaries for the year ended December 31, 1992. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Public Service Company of New Mexico and subsidiaries for the year ended December 31, 1992, in conformity with generally accepted accounting principles.
The Company has substantial excess electric generating capacity, the cost and amount of which continue to negatively impact financial condition and results of operations as well as the level of New Mexico retail rates. The Company has adopted certain plans and is evaluating other options to address the negative effects related to its excess capacity. Because the ultimate outcome of these matters, including NMPUC regulatory responses thereto, is not presently determinable, the recovery of (i) the Company's remaining direct investment in Palo Verde Nuclear Generating Station (PVNGS) Unit 3, and (ii) its lease costs related to PVNGS Units 1 and 2, is uncertain. Accordingly, neither a provision for any additional loss related to PVNGS Unit 3 nor any provision for loss related to PVNGS Units 1 and 2 has been recognized in the accompanying 1992 consolidated financial statements.
As discussed in note 1 of notes to consolidated financial statements in the 1992 Form 10-K, the Company changed its method of accounting for unbilled revenues in 1992.
KPMG PEAT MARWICK LLP
Albuquerque, New Mexico March 11, 1993
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF RETAINED EARNINGS (DEFICIT)
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION
The accompanying notes are an integral part of these financial statements.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1994, 1993 AND 1992
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SYSTEMS OF ACCOUNTS
The Company maintains its accounts for utility operations primarily in accordance with the uniform systems of accounts prescribed by the Federal Energy Regulatory Commission ("FERC") and the National Association of Regulatory Utility Commissioners ("NARUC"), and adopted by the New Mexico Public Utility Commission ("NMPUC").
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and subsidiaries in which it owns a majority voting interest. All significant intercompany transactions and balances have been eliminated.
UTILITY PLANT
Utility plant, with the exception of Palo Verde Nuclear Generating Station ("PVNGS") Unit 3 and the Company's purchased 22% beneficial interests in the PVNGS Units 1 and 2 leases is stated at original cost, which includes capitalized payroll-related costs such as taxes, pension and other fringe benefits, administrative costs and an allowance for funds used during construction ("AFUDC"). Utility plant includes certain electric assets not subject to NMPUC regulation. The results of operations of such electric assets are included in operating income.
PVNGS Unit 3 and the Company's purchased 22% beneficial interests in the PVNGS Units 1 and 2 leases have been written down to net realizable value to reflect a permanent impairment in their estimated value.
It is Company policy to charge repairs and minor replacements of property to maintenance expense and to charge major replacements to utility plant. Gains or losses resulting from retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation.
DEPRECIATION AND AMORTIZATION
Provision for depreciation and amortization of utility plant is made at annual straight-line rates approved by the NMPUC. The average rates used are as follows:
As part of the final order approving the January 12, 1994 stipulation (see note 2), the NMPUC approved revised depreciation rates and incorporated them into the determination of retail rates. The new rates include a provision for the recovery of fossil-fueled plant decommissioning costs (see note 10).
The provision for depreciation of certain equipment is charged to clearing accounts and subsequently allocated to operating expenses or construction projects based on the use of the equipment.
Depreciation of non-utility property is computed on the straight-line method. Amortization of nuclear fuel is computed based on the units of production method.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) NUCLEAR DECOMMISSIONING
The Company accounts for nuclear decommissioning costs on a straight-line basis over the estimated useful life of the facilities. Such amounts are based on the net present value of expenditures estimated to be required to decommission the plant.
FUEL AND PURCHASED POWER ADJUSTMENT CLAUSE ("FPPCAC")
As part of the final order approving the January 12, 1994 stipulation, the Company's FPPCAC for its retail customers was eliminated (see note 2). The Company continues to use the deferral method of accounting for fuel and purchased power costs for its firm-requirements wholesale customers. Such amounts are reflected in subsequent periods under a FPPCAC approved by the FERC.
PURCHASED GAS ADJUSTMENT CLAUSE ("PGAC")
The Company uses the deferral method of accounting for gas purchase costs which are reflected in subsequent periods under gas adjustment clauses. Future recovery of these costs is based on orders issued by the NMPUC.
AMORTIZATION OF DEBT DISCOUNT, PREMIUM AND EXPENSE
Discount, premium and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. In connection with the retirement of long-term debt, such amounts associated with resources subject to NMPUC regulation are amortized over the lives of the respective issues. Amounts associated with the Company's firm-requirements wholesale customers and its excluded resources are recognized immediately as expense or income as they are incurred.
INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 109, ACCOUNTING FOR INCOME TAXES. SFAS No. 109 requires deferred income taxes for temporary differences between book and tax to be recorded using the liability method. Deferred income taxes are computed using the enacted tax rates scheduled to be in effect when the temporary differences reverse. Current NMPUC jurisdictional rates include the tax effects of the majority of these temporary differences (normalization). Recovery of reversing temporary differences previously accounted for under the flow-through method is also included in rates charged to customers. For regulated operations, any changes in tax rates applied to accumulated deferred income taxes may not be immediately recognized because of ratemaking and tax accounting provisions contained in the Tax Reform Act of 1986. For items accorded flow-through treatment under NMPUC orders, deferred income taxes and the future ratemaking effects of such taxes, as well as corresponding regulatory assets and liabilities, are recorded.
(2) ELECTRIC OPERATIONS
COMPETITIVE ELECTRIC MARKET
The electric utility industry, as did the gas industry a decade ago, is currently undergoing major changes to meet a changing marketplace. Changes are occurring in response to actions by both Federal and state governments without an overarching plan to make all of the pieces and policies fit together and without a single government agency having the authority to impose one. At the Federal level, the passage of the National Energy Policy Act of 1992 (the "Energy Act") is causing the evolution of a traditional rate regulated industry into a competitive market environment. The Energy Act is intended to promote competition among utility and non-utility generators in the wholesale electric generation market. The Energy Act, coupled with increasing customer demands for lower-priced electricity, has accelerated industry restructuring and has intensified interest in increased
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(2) ELECTRIC OPERATIONS (CONTINUED) competition at the retail level. In response to the Energy Act, FERC has released notices of proposed rulemakings which include topics such as transmission access and pricing, stranded investment, and regional pooling. Such proposed rulemakings would affect the electric utility industry generally. The Company is unable to predict the outcome of these proposals. In addition, initiatives at the state level in New Mexico relating to retail wheeling continue to receive attention
SPECIFIC ACTIONS BY THE COMPANY
On January 11, 1993, the Company announced specific actions determined to be necessary in order to accelerate the Company's preparation for the new challenges in the competitive electric energy market. As part of this announcement, the Company stated its intention to attempt to sell PVNGS Unit 3. As a result, the Company recorded a $126.2 million after-tax charge to 1992 earnings related to the write-down of PVNGS Unit 3 and the provision for loss associated with the M-S-R power purchase contract based on the estimated net realizable value of these resources.
On January 12, 1994, the Company and the NMPUC staff and primary intervenor groups entered into a rate reduction stipulation. The Company filed the stipulation with the NMPUC, recommending that electric retail rates be reduced by $30 million. This reduction was accomplished primarily through the write-down of the 22% beneficial interests in the PVNGS Units 1 and 2 leases purchased by the Company, the write-off of certain regulatory assets and other deferred costs, the write-off of certain PVNGS Units 1 and 2 common costs and the Company's previously announced cost reduction efforts. In conjunction with the stipulation, the Company charged approximately $108.2 million, after-tax, to the 1993 results of operations.
On November 28, 1994, the NMPUC issued a final order approving the stipulation as interpreted and provided by the order which was effective for bills rendered starting November 29, 1994.
As recommended in the stipulation, the Company's interests in PVNGS Units 1 and 2 are now confirmed in this NMPUC order as "used and useful" for the rate making purposes of the stipulation and the finding remains in force until the stipulation is superseded or otherwise terminated. The order confirms that the status of PVNGS Units 1 and 2 is no different from that of other used and useful assets. Any costs incurred for these units as of January 12, 1994, will be fully recoverable in the Company's jurisdictional rates consistent with the terms and conditions of the NMPUC order and the stipulation, and subject to assurance that all such costs have been accounted for accurately.
In approving the stipulation, the NMPUC reconfirmed its authority over the Company and its authority to issue orders in the public interest, finding nothing in the stipulation to supersede that authority. Pursuant to the stipulation, the signatories do not intend to file or cause the filing of a general rate case before January 1, 1998, in the absence of a significant restructuring of rate base or unforeseen circumstances occasioning a significant change in the Company's costs. As a result of the order, the Company believes that the rates agreed upon in the stipulation will be adequate to recover the cost of its New Mexico jurisdictional services going forward and further believes that the Company will be in a better position to compete in a competitive electric market environment.
UNCERTAINTIES
The Company believes that the stipulation has improved its competitive position in the electric market, but recognizes that low cost producers may have an advantage if the regulatory framework changes significantly towards retail wheeling concepts. The Company's generating costs are currently above those of some neighboring utilities due primarily to the expensive nuclear generation.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(2) ELECTRIC OPERATIONS (CONTINUED) The future structure of the industry, the form and timing of competition and the method of regulation in a competitive environment remains uncertain. In the transition to a more competitive market environment from a traditional rate regulated environment, the value of a utility's assets could be affected significantly. If the cost of operating a utility's existing assets is above market prices, the utility may be unable to recover all of its costs without adequate treatment for stranded assets. In the Company's situation, if included generation costs currently being recovered in retail rates were to be based on a competitive market price which is lower than its current costs, the value of the Company's PVNGS Units 1 and 2 investment could be economically impaired.
STRATEGIC PLAN
In order to mitigate the exposures associated with a competitive electric market and transition into this changing environment, the Company, in addition to the January 11, 1993 announcement and other actions discussed above, has set the following strategic plan: (1) secure financial flexibility by retiring debt, (2) restructure the Company's expensive generating assets and nuclear leases, (3) control operating and maintenance costs, and (4) develop new business opportunities in the energy related area. It should be noted, however, that the Company's ability to restructure its generating assets and nuclear leases is limited. In addition, the Company's ability to develop new business opportunities will be subject to state laws, rules and regulations.
As part of this plan, the Company has internally restructured its operations into four separate business units, each targeted at a specific segment of its customer base. The new structure is intended to make the Company more customer oriented and responsive to the changing competitive environment. The four units - -- Electric Services, Gas Services, Bulk Power Services and Energy Services -- will be evaluated continuously for their contribution to building shareholder value.
(3) CAPITALIZATION Changes in common stock, additional paid-in capital and cumulative preferred stock are as follows:
COMMON STOCK
The number of authorized shares of common stock with par value of $5 per share is 80 million shares.
The payment of cash dividends on the common stock of the Company is subject to certain restrictions, including those contained in the Company's mortgage indenture, which effectively prevent the payment of dividends on common stock unless the Company has positive retained
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(3) CAPITALIZATION (CONTINUED) earnings. The Company's board of directors, which reviews the Company's dividend policy on a continuing basis, has not declared dividends on its common stock since January 1989. As of December 31, 1994, the Company had a deficit in retained earnings of $46 million and is, therefore, currently unable to resume payment of dividends on its common stock. The resumption of common dividends is dependent upon a number of factors including earnings and financial condition of the Company and market conditions.
CUMULATIVE PREFERRED STOCK
The number of authorized shares of cumulative preferred stock is 10 million shares. The Company's restated articles of incorporation limit the amount of preferred stock which may be issued. The earnings test in the Company's restated articles of incorporation currently allows for the issuance of preferred stock.
The Company, upon 30 days notice, may redeem the cumulative preferred stock at stated redemption prices plus accrued and unpaid dividends. Redemption prices are at reduced premiums in future years.
The Company evaluated its ability to continue paying dividends on its preferred stock under restrictions imposed by the Federal Power Act due to the Company's negative retained earnings. In 1993, the Company advised the FERC staff of the Company's position that payment of preferred stock dividends would not be in violation of the Federal Power Act. As a result, the Company continued to declare and pay dividends on its preferred stock on scheduled dates.
There are no mandatory redemption requirements for 1995 through 1998 and only $75,000 in 1999. During any period that the Company is unable to pay preferred dividends, if that should occur, the Company would be prohibited by its restated articles of incorporation from making future mandatory redemption payments.
LONG-TERM DEBT
Substantially all utility plant is pledged to secure the Company's first mortgage bonds. A portion of certain series of long-term debt will be redeemed serially prior to their due dates. The issuance of first mortgage bonds by the Company is subject to earnings coverage and bondable property provisions of the Company's first mortgage indenture. The Company also has the capability under the mortgage indenture without regard to the earnings test but subject to other conditions to issue first mortgage bonds on the basis of certain previously retired bonds and earnings.
The aggregate amounts (in thousands) of maturities for 1995 through 1999 on long-term debt outstanding at December 31, 1994 are as follows:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(3) CAPITALIZATION (CONTINUED) FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the Company's long-term debt and preferred stock (including current maturities) is estimated to be approximately:
(4) REVOLVING CREDIT FACILITY AND OTHER CREDIT FACILITIES At December 31, 1994, the Company had a $100 million secured revolving credit facility (the "Facility") with the expiration date of June 13, 1995. The Company must pay commitment fees of .5% per year on the total amount of the Facility. The Company expects to renew the Facility prior to its expiration. The Company also has a $40 million credit facility, collateralized by the Company's electric customer accounts receivable (the "Accounts Receivable Securitization") with an expiration date of December 20, 1998. Together with $11 million in local lines of credit, the Company has $151 million in liquidity arrangements. As of December 31, 1994, there were no borrowings outstanding under the Facility, the Accounts Receivable Securitization or any of the local lines of credit.
(5) INCOME TAXES Income taxes consist of the following components:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(5) INCOME TAXES (CONTINUED) The Company's provision for income taxes differed from the Federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
Deferred income taxes result from certain differences between the recognition of income and expense for tax and financial reporting purposes, as described in note 1. The major sources of these differences for which deferred taxes have been provided and the tax effects of each are as follows:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(5) INCOME TAXES (CONTINUED) The components of the net accumulated deferred income tax liability were:
At December 31, 1994, the Company had net operating loss carryforwards for Federal income tax purposes of $69.1 million, $15.1 million, and $55.1 million which expire in 2004, 2005 and 2007, respectively. For purposes of New Mexico state income tax, these carryforwards, if unused, would expire in 2004, 2005 and 1997, respectively. New Mexico law provides a five-year carryforward for all net operating losses incurred after 1990. The Company anticipates that all of these carryforwards will be fully utilized before expiration, and the financial statements reflect that expectation.
The Company defers investment tax credits related to utility assets and amortizes them over the estimated useful lives of those assets. Investment tax credits related to non-utility assets have been flowed through in earlier years.
(6) EMPLOYEE AND POST-EMPLOYMENT BENEFITS
PENSION PLAN
The Company and its subsidiaries have a pension plan covering substantially all of their employees, including officers. The plan is non-contributory and provides for benefits to be paid to eligible employees at retirement based primarily upon years of service with the Company and their average of highest annual base salary for three consecutive years. The Company's policy is to fund actuarially-determined contributions. Contributions to the plan reflect benefits attributed to employees' years of service to date and also for services expected to be provided in the future. Plan assets primarily consist of common stock, fixed income securities, cash equivalents and real estate.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(6) EMPLOYEE AND POST-EMPLOYMENT BENEFITS (CONTINUED) The components of pension cost (in thousands) are as follows:
The following sets forth the plan's funded status and amounts (in thousands) at December 31, 1994 and 1993:
The weighted average discount rate used to measure the projected benefit obligation was 8.25% for 1994 and 7.0% for 1993 and the expected long-term rate of return on plan assets was 8.75% for 1994 and 9.0% for 1993. The rate of increase in future compensation levels based on age-related scales was 4.1% for 1994 and 1993.
OTHER POSTRETIREMENT BENEFITS
The Company adopted SFAS No. 106, EMPLOYERS' ACCOUNTING FOR POSTRETIREMENT BENEFITS OTHER THAN PENSIONS, effective January 1, 1993. The Company provides medical and dental benefits to
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(6) EMPLOYEE AND POST-EMPLOYMENT BENEFITS (CONTINUED) eligible retirees. Currently, retirees are offered the same benefits as active employees after reflecting Medicare coordination. The components of postretirement benefit cost (in thousands) for 1994 and 1993 are as follows:
The following sets forth the plan's funded status and amounts (in thousands) at December 31, 1994 and 1993:
Prior to 1993, the costs of these benefits were expensed on a pay-as-you-go basis. The cost of providing these benefits was approximately $1.5 million for 1992. The discount rate used to measure the postretirement benefit obligation was 8.25% for 1994 and 7% for 1993. The health care cost trend rate was 7.5% and 6% for 1994 and 1993, respectively. The effect of a 1% increase in the health care trend rate assumption would increase the accumulated postretirement benefit obligation as of December 31, 1994 by approximately $9.1 million and the aggregate service and interest cost components of net periodic postretirement benefit cost for 1994 by approximately $1.2 million.
SFAS No. 106 requires accrual of postretirement benefits during the years employees provide services. In 1993, the NMPUC issued a final order in a case regarding an inquiry into SFAS No. 106. In its final order, the NMPUC adopted a policy which provides for accrual accounting for the postretirement benefit costs, funding requirements into an irrevocable trust and specific reporting for the benefit costs in future rate cases. The order also provides for specific waiver provisions with respect to the external trust funding requirements and a deferral of the benefit costs in excess of the pay-as-you-go basis. The Company received approval on November 28, 1994 for the recovery of the full accrual amount of SFAS No. 106 expense for its electric business unit. As of December 31, 1994, no benefit costs were deferred for the electric business unit. The Company filed supplemental
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(6) EMPLOYEE AND POST-EMPLOYMENT BENEFITS (CONTINUED) information regarding the funding of postretirement benefits on February 24, 1995, which outlined the types of funding vehicles and the amounts funded for 1994 related to the electric business unit. The Company defers the benefit costs in excess of the pay-as-you-go basis for the gas business unit ($2.8 million deferred as of December 31, 1994) and will address the recovery of this amount as well as the full accrual amount of SFAS No. 106 expense related to the gas business unit in its next general rate case which will be filed in 1995.
PERFORMANCE STOCK PLAN
As approved by the Company's shareholders on May 25, 1993, the Company adopted a nonqualified stock option plan (Performance Stock Plan) covering a group of management employees. Under the terms of the plan which became effective on July 1, 1993, options to purchase shares of the Company's common stock are granted with an exercise price equal to the fair market value of the stock at the date of grant. On July 1, 1993, the Company granted 370,000 options to the covered employees under the plan at an exercise price of $13.75 per share. In 1994, the Company made an additional initial grant under the plan of 8,306 options with an exercise price of $11.50 per share. In addition, based on the Company's 1994 performance, 803,127 options were granted at an exercise price of $13.00. The remaining 842,385 options, including 23,818 returned options, are available for future grants. Options may be exercised following vesting as described in the plan. Currently no options are eligible for exercise.
EXECUTIVE RETIREMENT PROGRAM
The Company had an executive retirement program for a group of management employees. The program was intended to attract, motivate and retain key management employees. The Company's projected benefit obligation for this program, as of December 31, 1994, was $17.7 million, of which the accumulated and vested benefit obligation was $16.3 million. As of December 31, 1994, the Company has recognized an additional liability of $1.1 million for the amount of unfunded accumulated benefits in excess of accrued pension costs. The net periodic pension cost for 1994, 1993 and 1992 was $2.2 million, $2.1 million and $2.0 million, respectively. In 1989, the Company established an irrevocable grantor trust in connection with the executive retirement program. Under the terms of the trust, the Company may, but is not obligated to, provide funds to the trust, which was established with an independent trustee, to aid it in meeting its obligations under such program. Funds in the amount of approximately $11.1 million (fair market value of $11.4 million) are presently in trust. No additional funds have been provided to the trust since 1989.
(7) CONSTRUCTION PROGRAM AND JOINTLY-OWNED PLANTS It is estimated that the Company's construction expenditures for 1995 will be approximately $117 million, including expenditures on jointly-owned projects. The Company's proportionate share of expenses for the jointly-owned plants is included in operating expenses in the consolidated statement of earnings.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(7) CONSTRUCTION PROGRAM AND JOINTLY-OWNED PLANTS (CONTINUED) At December 31, 1994, the Company's interests and investments in jointly-owned generating facilities are:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
December 31, 1994, 1993 and 1992
(7) CONSTRUCTION PROGRAM AND JOINTLY-OWNED PLANTS
SAN JUAN GENERATING STATION ("SJGS")
The Company operates and jointly owns SJGS. At December 31, 1994, SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson Electric Power Company, Unit 3 is owned 50% by the Company, 41.8% by Southern California Public Power Authority and 8.2% by Century Power Corporation ("Century"). Century has agreed to sell its remaining 8.2% interest to Tri-State Generation and Transmission Association, Inc. Unit 4 is owned 38.457% by the Company, 8.475% by the City of Farmington, 28.8% by M-S-R, 7.2% by the County of Los Alamos, 10.04% by the City of Anaheim, California and 7.028% by Utah Associated Municipal Power Systems.
PALO VERDE NUCLEAR GENERATING STATION
The Company has a 10.2% interest in PVNGS. Commercial operation commenced in 1986 for Unit 1 and Unit 2 and 1988 for Unit 3. In 1985 and 1986, the Company completed sale and leaseback transactions for its undivided interests in Units 1 and 2 and certain related common facilities.
On September 2, 1992, the Company purchased approximately 22% of the beneficial interests in PVNGS Units 1 and 2 leases for approximately $17.5 million. For accounting purposes, this transaction was recorded as a purchase with the Company recording approximately $158.3 million as utility plant (written down to $46.7 million as a result of the January 12, 1994 stipulation, see note 2) and $140.8 million as long-term debt on the Company's consolidated balance sheet.
The PVNGS participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under Federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry wide retrospective assessment program. The maximum assessment per reactor under the retrospective rating program for each nuclear incident occurring at any nuclear power plant in the United States is approximately $79.3 million, subject to an annual limit of $10 million per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident is approximately $24.3 million, with an annual payment limitation of $3 million. The insureds under this liability insurance include the PVNGS participants and "any other person or organization with respect to his legal responsibility for damage caused by the nuclear energy hazard".
The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of approximately $2.8 billion as of January 1, 1995, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against a portion of the increased cost of generation or purchased power resulting from certain accidental outages of any of the three PVNGS units if such outage exceeds 21 weeks.
The Company has a program for funding its share of decommissioning costs for PVNGS. Under this program, the Company makes a series of annual deposits to an external trust fund over the estimated useful life of each unit with the trust funds being invested under a plan which allows the accumulation of funds largely on a tax-deferred basis through the use of life insurance policies on certain current and former employees. The results of the 1992 decommissioning study indicate that the Company's share of the PVNGS decommissioning costs will be approximately $150.4 million, an increase from $98.9 million based on the previous study (both amounts are stated in 1994 dollars). The Company determined that a supplemental investment program will be needed as a result of both the cost increase and the under performance of the existing investment program. In 1995, the Company will file a request for permission from the NMPUC to establish a supplemental investment program,
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(7) CONSTRUCTION PROGRAM AND JOINTLY-OWNED PLANTS (CONTINUED) allowing for investment in more traditional classes of investments. The Company will also request the authority to establish a qualified tax advantaged trust for Units 1 and 2. Due to IRS regulations, Unit 3 will remain in a non-qualified trust. With the uncertainty of the FERC regulation regarding restrictions on investment vehicles, the Company will address any issues as they are resolved. In the November 28, 1994 NMPUC order (see note 2), the NMPUC approved the increased decommissioning costs for PVNGS Units 1 and 2 and included such amounts as a component in the determination of retail rates. The market value of the existing trust at the end of 1994 was approximately $12 million, including cash surrender value of the policies. A new PVNGS decommissioning cost study will be performed during the latter half of 1995.
(8) LONG-TERM POWER CONTRACTS AND FRANCHISES The Company has two long-term contracts for the purchase of electric power. Under a contract with M-S-R, which expires in early 1995, the Company is obligated to pay certain minimum amounts and a variable component representing the expenses associated with the energy purchased and debt service costs associated with capital improvements. Total payments under this contract amounted to approximately $42 million for 1994 and 1993, and $40 million for 1992. The minimum payment under this contract is $9.0 million for the first four months of 1995, at which time this contract expires. The Company recorded a provision for loss associated with the M-S-R power purchase contract in its 1992 results of operation.
The Company has a long-term contract with Southwestern Public Service Company ("SPS") to purchase interruptible power which began in June 1991. Total payments under this contract amounted to approximately $9.0 million in 1994. Minimum payments under the contract amount to approximately $11.7 million and $14.0 million for 1995 and 1996, respectively. In addition, the Company will be required to pay for any energy purchased under the contract. The amount of minimum payments for future years will depend on whether the Company exercises its option to reduce its purchase obligations under the contract. Such options require three years advance notification.
(9) LEASE COMMITMENTS The Company classifies its leases in accordance with generally accepted accounting principles. The Company leases Units 1 and 2 of PVNGS, transmission facilities, office buildings and other equipment under operating leases. The lease expense for PVNGS is $66.3 million per year over base lease terms expiring in 2015 and 2016. Prior to 1992, the aggregate lease expense for the PVNGS leases was $84.6 million per year over the base lease terms; however, this amount was reduced by the purchase of approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases (see note 7). Each PVNGS lease contains renewal and fair market value purchase options at the end of the base lease term.
Future minimum operating lease payments (in thousands) at December 31, 1994 are:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(9) LEASE COMMITMENTS (CONTINUED) Operating lease expense, inclusive of PVNGS, was approximately $79.1 million in 1994, $80.6 million in 1993 and $91.1 million in 1992. The aggregate minimum payments to be received in future periods under noncancelable subleases are approximately $7.1 million.
(10) ENVIRONMENTAL ISSUES AND FOSSIL-FUELED PLANT DECOMMISSIONING COSTS The Company is committed to complying with all applicable environmental regulations in a responsible manner. Compliance with all environmental issues has and will continue to present a challenge to the Company. The Company has evaluated the potential impacts of the following environmental issues and believes, after consideration of established reserves, that the ultimate outcome of these environmental issues will not have a material adverse effect on the Company's financial condition or results of operations.
ENVIRONMENTAL ISSUES -- GAS
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION AND LIABILITY ACT ("CERCLA")
Two CERCLA 104(e) requests for information were received from the United States Environmental Protection Agency ("EPA") in late 1993, requesting information regarding shipment of wastes to the Lee Acres Landfill, located on Bureau of Land Management ("BLM") land near the city of Bloomfield in San Juan County, New Mexico. The landfill is currently listed on the National Priorities List as a superfund site. Gas Company of New Mexico, a division of the Company ("GCNM") and Sunterra Gas Gathering Company, a wholly-owned subsidiary of the Company ("Gathering Company") assessed their records and other information to determine whether wastes were ever shipped from their facilities to the landfill during the period when they owned and operated the natural gas facilities. GCNM and Gathering Company's assessment indicated that no hazardous materials were shipped from their facilities to the landfill during this time period. Nonetheless, GCNM and Gathering Company could be determined to be potentially responsible parties if the EPA ultimately determines GCNM and Gathering Company shipped wastes to the site, and could be asked or compelled to provide funds for site cleanup. GCNM and Gathering Company submitted their response to the EPA on March 8, 1994. To date, GCNM and Gathering Company have not received any further notification from the EPA regarding the Lee Acres site.
AIR PERMITS
An environmental audit performed in association with the Company's proposed sale of certain gas assets brought to light certain discrepancies regarding required air permits associated with certain natural gas facilities. The audit identified a total of thirteen facilities containing discrepancies. The vast majority of the discrepancies were minor in nature and included discrepancies in record keeping, equipment identification and inaccurate information in air permit applications. The discrepancies at three of the facilities involve permit issuance and modification and are more serious in nature. The Company is subject to administrative fines/penalties by the New Mexico Environment Department ("NMED") for these discrepancies.
In April 1994, the Company met with the NMED to discuss the nature of the permit discrepancies and to propose methods and schedules to resolve the discrepancies. As a result of this meeting, the NMED has informed the Company that it will not pursue enforcement of the thirteen minor discrepancies noted above. On August 30, 1994, the Company submitted its permit modification application for the Lybrook Gas Processing Plant ("Lybrook"). On November 14, 1994, the Company received a written Notice of Violation ("NOV") from the NMED for Lybrook. The NOV indicates the NMED has concluded that the Company violated air quality control regulations requiring permits for
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(10) ENVIRONMENTAL ISSUES AND FOSSIL-FUELED PLANT DECOMMISSIONING COSTS (CONTINUED) modification of stationary sources. The NOV indicated the Company may be subject to a civil action in district court for the appropriate relief and/or the assessment of civil penalties. The Company has responded to the NOV and is pursuing efforts to address the NOV with the NMED.
The Company anticipates that it will submit Processing Company's air permit modification application on the Kutz Canyon Gas Processing Plant ("Kutz") in the first quarter of 1995. While the Company cannot be certain, the Kutz filing, which will be similar to the Lybrook filing, may also result in an NOV from the NMED due to apparent permit discrepancies in the Kutz air permit. At this point in time, the Company cannot estimate the amount of any fine or penalty, if any, that may be attributable to the Kutz filing.
GAS WELLHEAD PIT REMEDIATION
The New Mexico Oil Conservation Commission ("NMOCC") issued an order effective on January 14, 1993, that affects GCNM and Gathering Company's natural gas gathering facilities located in the San Juan Basin in Northwestern New Mexico. The NMOCC ruling prohibits the further discharge of fluids associated with the production of natural gas into unlined earthen pits in certain specified areas of the San Juan Basin. The NMOCC ruling required the cessation of discharge of production fluids in three specified areas within specific time frames. In addition, the ruling required the submission of closure plans for the closure of pits in which production fluids were previously discharged. The BLM has issued a similar ruling. GCNM and Gathering Company have ceased discharge in the first area identified by the NMOCC and are proceeding to cease discharge in the second area identified in the NMOCC ruling. GCNM and Gathering Company have also submitted and received approval of their pit closure plans from the New Mexico Oil Conservation Division, ("OCD"), the Energy Minerals and Natural Resources Department, as well as the BLM. Because the assets associated with GCNM and Gathering Company's gathering operations are the subject of the sale of gas assets to Gas Processing Blanco, Inc., a subsidiary of the Williams Field Service Group, Inc. ("Williams"), GCNM and Gathering Company will not be subject to the cease discharge requirement for the third and final area identified in the NMOCC's ruling if the sale closes prior to March 1, 1996.
The three previously mentioned gas operations environmental issues, with the exception of the third and final area identified in NMOCC's ruling related to gas wellhead pit remediation are part of the retained environmental liabilities under the sale agreement with Williams (see note 11).
DIETHANOLAMINE ("DEA") SPILL
In June 1994, Sunterra Gas Processing Company, a wholly-owned subsidiary of the Company ("Processing Company"), experienced a release of DEA due to an equipment malfunction. DEA wastes are oilfield exempt wastes which are not subject to regulation as hazardous wastes under the Resource Conservation and Recovery Act ("RCRA"). The spill and subsequent removal of DEA-contaminated soils were reported to the OCD which has jurisdiction over such spills and wastes. However, the release of DEA to the air in amounts that exceed the reportable quantity of one pound is potentially reportable under CERCLA as amended by the Superfund Amendments and Reauthorization Act ("SARA"). When it was discovered in September 1994 that the spill had not been reported under CERCLA/SARA, as a precaution, the spill notification/report was forwarded to the National Response Center on September 22, 1994. The Company is currently unable to predict what, if any, enforcement action may ensue.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(10) ENVIRONMENTAL ISSUES AND FOSSIL-FUELED PLANT DECOMMISSIONING COSTS (CONTINUED) ENVIRONMENTAL ISSUE -- ELECTRIC
PERSON STATION
The Company's current estimate to decommission its retired fossil-fueled plants includes approximately $10.9 million to complete the groundwater remediation program at Person Station. The Company, in compliance with the New Mexico Environment Department Corrective Action Directive, determined that groundwater contamination exists in the deep and shallow water aquifers. The Company is required to delineate the extent of the contamination and remediate the contaminant in the ground water. The extent of the contaminant plume in the deep water aquifer is not currently known, and the estimate assumes that the deep ground water plume can be easily delineated with a minimum number of monitoring wells. As part of the financial assurance requirements of the Person Station Hazardous Waste Permit, the Company posted a $5.1 million performance bond with a trustee. The remediation program continues on schedule.
SANTA FE STATION
The estimate to decommission Santa Fe Station includes monies for environmental issues related to the site. The NMED has been conducting an investigation of the groundwater contamination detected beneath the site to determine the source of the contamination. The source of groundwater contamination has not yet been definitely identified, and the Company is continuing to cooperate with the NMED site investigations pursuant to a consent agreement between the Company and the NMED.
CERCLA
On January 18, 1995, the Company received a CERCLA Section 104(e) request for information from the EPA regarding the Hansen Container Site in Grand Junction, Colorado ("Hansen Site"). The EPA is investigating the site and seeking information relating to the number and contents of drums, barrels, and other materials that were sent to the Hansen Site for reconditioning, disposal, or storage. The Company undertook an internal investigation to determine if the Company or its subsidiaries may have sent or shipped any drums, barrels or other materials containing hazardous materials to the Hansen Site. The Company filed its response to the EPA's request for information on March 2, 1995, and stated that the Company's records indicate that it did not dispose of any hazardous materials at the Hansen Site and did not cause others to transport hazardous materials for disposal at the Hansen Site. The Company's records did indicate, however, that the Company sold empty scrap drums to a drum recycler in the 1980's who has been linked to the Hansen Site by the EPA. The Company's position is that it is not a potential responsible party; however, given these transactions, the Company could possibly be determined to be a potential responsible party and could be asked or compelled to provide funds for site cleanup. Based on the Company's discussions with the EPA to date, the Company does not expect to be required to provide any significant funding for site cleanup.
FOSSIL-FUELED PLANT DECOMMISSIONING COSTS
The Company's six owned or partially owned, in service and retired, fossil-fueled generating stations are expected to incur dismantling and reclamation costs as they are decommissioned. The Company's share of decommissioning costs for all of its fossil-fueled generating stations is projected to be approximately $134 million stated in 1994 dollars, including approximately $24.4 million (of which $10.2 million has already been expended) for Person, Prager and Santa Fe Stations which have been retired.
In June 1993, the Company filed for recovery of all estimated decommissioning costs by factoring such costs into the Company's depreciation rate study filed with the NMPUC.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(10) ENVIRONMENTAL ISSUES AND FOSSIL-FUELED PLANT DECOMMISSIONING COSTS (CONTINUED) As part of the final order approving the January 12, 1994 stipulation, the NMPUC approved the depreciation rates, except for those decommissioning costs related to the three retired generating units, and incorporated them into the determination of retail rates.
(11) ASSET SALES
SALE OF SDCW
On February 28, 1994, the Company and the City of Santa Fe (the "City") executed a purchase and sale agreement for the Company's water division for approximately $48 million. As currently adjusted, the purchase price will be approximately $56 million. The NMPUC staff and intervenors recommended that the Company retain the estimated after-tax gain of $6 million for the sale. In March 1994, the Company filed its application with the NMPUC for approval of the sale and hearings were commenced on December 12, 1994 and concluded on January 9, 1995. The proposed agreement excluded from the sale certain Santa Fe area real estate which the Company would either sell or trade separately. Under the agreement, the Company would continue to operate the water utility for up to four years for a fee under a proposed contract with the City. The NMPUC staff recommended that the Company be allowed to form an unregulated subsidiary to manage the water utility. The parties are awaiting a recommended decision from the hearing examiner. The Company currently expects that the closing will be in the second quarter of 1995.
SALE OF GAS GATHERING AND PROCESSING ASSETS
On February 12, 1994, an agreement was executed with Williams for the sale of substantially all of the assets of Gathering Company and Processing Company, and for the sale of Northwest and Southwest gas gathering and processing facilities of the Company. The agreement provides for a cash selling price of $155 million, subject to certain adjustments.
The sale is subject to NMPUC approval. The Company filed its application for approval with the NMPUC on May 20, 1994. On January 13, 1995, the Company and certain intervenors (the NMPUC Staff, the New Mexico Attorney General, Williams and GPM Gas Corporation) reached a stipulated agreement, subject to NMPUC approval, settling certain issues, including the division of the gain from the sale of the gas gathering and processing assets. Under the stipulation, the Company would recognize an after-tax gain of approximately $14.1 million, subject to certain adjustments at the closing, and would record a liability of approximately $35.5 million which would be credited to the Company's gas customers' bills over approximately five years. At the sixth year after the closing, such liability amount would be recalculated to reflect the actual transaction costs and any resulting difference would be refunded or billed to customers over a one year period.
The stipulated agreement provides for the approval of three 10-year contracts, each with an option to renew for an additional 5-year term, with Williams for competitively priced gathering and processing services. The Company believes that the contracts will save customers amounts estimated to be between $100 million and $128 million over 10 years. The stipulation also provides that GCNM will recover, as an expense of the sale, $3.3 million of the $4.8 million of costs deferred in GCNM's Purchase Gas Adjustment Clause ("PGAC") continuation proceeding. The Company wrote off $1.5 million of such costs against 1994 earnings.
On January 23, 1995, certain natural gas producers (Meridian Oil Inc., Marathon Oil Company, Conoco, Inc., Amoco Production Company and Caulkins Oil Company) filed a statement in opposition to the stipulation. Initially the producers claimed that the resulting gain from the sale was improperly
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(11) ASSET SALES (CONTINUED) calculated and allocated and that the proposed gathering and processing contracts with Williams are unreasonable. Prior to the hearing, two of the producers withdrew their opposition and another two withdrew their opposition concerning the proposed gathering and processing contracts.
Hearings began on February 13, 1995 and were completed on February 17, 1995. The parties to the stipulation requested a final order from the NMPUC on an expedited basis. If NMPUC approval is issued on an expedited basis, the Company expects to finalize the sale by the end of second quarter of 1995. However, the Company cannot predict the ultimate timing or outcome of the NMPUC action.
(12) SEGMENT INFORMATION The financial information pertaining to the Company's electric, gas and other operations for the years ended December 31, 1994, 1993 and 1992 are as follows:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1994, 1993 AND 1992
(12) SEGMENT INFORMATION (CONTINUED)
On January 11, 1993, the Company announced its intention to dispose of SDCW and all or major portions of the natural gas gathering and natural gas processing assets (see note 11). Such sales are pending NMPUC approval.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES QUARTERLY OPERATING RESULTS
The unaudited operating results by quarters for 1994 and 1993 are as follows:
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES COMPARATIVE OPERATING STATISTICS
- -------------------------- * Due to the provision for the loss associated with the M-S-R contingent power purchase contract recognized in 1992, operating revenues were reduced by $25 million and $20.5 million for 1994 and 1993, respectively. (See Note 2 of the notes to consolidated financial statements.)
Note: In 1991, the Company implemented a FERC order requiring classification of economy sales as operating revenues. Prior period amounts have been reclassified for comparability purposes.
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES COMPARATIVE OPERATING STATISTICS
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of stockholders to be held on April 25, 1995 (the "1995 Proxy Statement") and to PART I, SUPPLEMENTAL ITEM -- "EXECUTIVE OFFICERS OF THE COMPANY".
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Reference is hereby made to "Executive Compensation" in the 1995 Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Reference is hereby made to "Voting Information", "Election of Directors" and "Stock Ownership of Certain Executive Officers" in the 1995 Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Reference is hereby made to the 1995 Proxy Statement for such disclosure, if any, as may be required by this item.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) -- 1. See Index to Financial Statements under Item 8.
(a) -- 2. Financial Statement Schedules for the years 1994, 1993, and 1992 are omitted for the reason that they are not required or the information is otherwise supplied.
(a) -- 3-A. Exhibits Filed:
E-1
(a) -- 3-B. Exhibits Incorporated By Reference: - ------------------------
** Designates each management contract or compensatory plan arrangement required to be identified pursuant to paragraph 3 of Item 14(a) of Form 10-K.
E-2
In addition to those Exhibits shown above, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation 201.24 by reference to the filings set forth below:
E-3
E-4
E-5
E-6
E-7
E-8
E-9
E-10
E-11
E-12
E-13
E-14
E-15
E-16
E-17
E-18
E-19
E-20
(b) Reports on Form 8-K:
During the quarter ended December 31, 1994, and during the period beginning January 1, 1995 and ending March 9, 1995, the Company filed, on the dates indicated, the following reports on Form 8-K.
E-21
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PUBLIC SERVICE COMPANY OF NEW MEXICO (Registrant)
Date: March 9, 1995 By /s/ B. F. MONTOYA
----------------------------------- B. F. Montoya PRESIDENT AND CHIEF EXECUTIVE OFFICER
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
SIGNATURE CAPACITY DATE - ----------------------------------- ------------------------- ----------------
/s/ B. F. MONTOYA Principal Executive March 9, 1995 - ----------------------------------- Officer and Director B. F. MONTOYA PRESIDENT AND CHIEF EXECUTIVE OFFICER
/s/ M. H. MAERKI Principal Financial March 9, 1995 - ----------------------------------- Officer M. H. Maerki SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
/s/ D. M. BURNETT Principal Accounting March 9, 1995 - ----------------------------------- Officer D. M. Burnett CORPORATE CONTROLLER AND CHIEF ACCOUNTING OFFICER
/s/ J. T. ACKERMAN Chairman of the Board March 9, 1995 - ----------------------------------- J. T. Ackerman
/s/ R. G. ARMSTRONG Director March 9, 1995 - ----------------------------------- R. G. Armstrong
/s/ J. A. GODWIN Director March 9, 1995 - ----------------------------------- J. A. Godwin
/s/ L. H. LATTMAN Director March 9, 1995 - ----------------------------------- L. H. Lattman
/s/ M. LUJAN JR. Director March 9, 1995 - ----------------------------------- M. Lujan Jr.
/s/ R. U. ORTIZ Director March 9, 1995 - ----------------------------------- R. U. Ortiz
/s/ R. M. PRICE Director March 9, 1995 - ----------------------------------- R. M. Price
/s/ P. F. ROTH Director March 9, 1995 - ----------------------------------- P. F. Roth
E-22
INDEX TO EXHIBITS
SEQUENTIALLY EXHIBIT NUMBERED NO. DESCRIPTION OF EXHIBIT PAGE - ------- ---------------------- ------------ 2.1.1 First Amendment to Purchase and Sale Agreement By and Among Public Service Company of New Mexico, Sunterra Gas Gathering Company, Sunterra Gas Processing Company (Sellers) and Williams Gas Processing--Blanco, Inc. (Buyer). . . . . . . .
2.1.2 Second Amendment to Purchase and Sale Agreement By and Among Public Service Company of New Mexico, Sunterra Gas Gathering Company, Sunterra Gas Processing Company (Sellers) and Williams Gas Processing--Blanco, Inc. (Buyer). . . . . . . .
2.2.1 First Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.2 Second Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.3 Third Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.4 Fourth Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.5 Fifth Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.6 Sixth Amendment to Agreement to Purchase and Sell Between City of Santa Fe, New Mexico and Public Service Company of New Mexico . . . . . . . . . . . . . . . . . . . . . . . . .
3.2 Bylaws of Public Service Company of New Mexico With All Amendments to and Including December 5, 1994 . . . . . . . .
10.49 Employment Contract By and Between the Public Service Company of New Mexico and Roger J. Flynn . . . . . . . . . .
10.5.2 Modifications No. 3 to San Juan Project Agreements dated July 17, 1994 (refiled). . . . . . . . . . . . . . . . . . .
10.8.4 Amendment No. 9 to Arizona Nuclear Power Project Participation Agreement dated as of June 12, 1984 (refiled).
10.12 Amendment and Restated San Juan Unit 4 Purchase and Participation Agreement dated as of December 28, 1984 between the Company and the Incorporated County of Los Alamos (refiled) . . . . . . . . . . . . . . . . . . . . . .
10.49 NMPUC Order, Case 2501 and 2503 regarding negotiated agreement with intervenors to settle all outstanding issues regarding recovery of payments GCNM made to settle gas take- or-pay contracts and pricing disputes . . . . . . . . . . .
10.50 NMPUC Order, Case 2526 regarding GCNM's proposed Balancing Rules . . . . . . . . . . . . . . . . . . . . . . . . . . .
23.1 Consent of Arthur Andersen & Co. . . . . . . . . . . . . . .
23.2 Consent of KPMG Peat Marwick . . . . . . . . . . . . . . . .
27 Financial Data Schedule. . . . . . . . . . . . . . . . . . .