Annual Report (Form 10-K), fiscal year 1993

ITEM 1. BUSINESS
Valero Energy Corporation was incorporated under the laws of the State of Delaware in 1955 and became a publicly held corporation in 1979. Its principal executive offices are located at 530 McCullough Avenue, San Antonio, Texas 78215 (telephone number 210/246-2000). Unless otherwise required by the context, the term "Energy" as used herein refers to Valero Energy Corporation, and the term "Company" refers to Energy and its consolidated subsidiaries individually and collectively.
The Company's principal business is petroleum refining and marketing. Valero Refining Company ("VRC"), a wholly owned subsidiary of Valero Refining and Marketing Company ("VRMC"), owns a specialized petroleum refinery in Corpus Christi, Texas (the "Refinery") and engages in petroleum refining and marketing operations. VRMC is a wholly owned subsidiary of Energy. VRMC and VRC are collectively referred to herein as "Refining."
The Company also owns an approximate 49% effective equity interest in Valero Natural Gas Partners, L.P. and its subsidiaries, which own and operate natural gas pipeline systems serving Texas intrastate and certain interstate markets. Valero Natural Gas Partners, L.P. and its subsidiaries also process natural gas for the extraction of natural gas liquids ("NGL"). See "Valero Natural Gas Partners, L.P." Unless otherwise required by the context, the term "VNGP, L.P." as used herein refers to Valero Natural Gas Partners, L.P. and the term "Partnership" refers to VNGP, L.P. and its consolidated subsidiaries individually and collectively. The Company's investment in and equity in earnings of the Partnership are shown separately in the accompanying consolidated financial statements. In addition to its interest in the Partnership, the Company owns a natural gas processing plant, a natural gas pipeline and certain natural gas liquids fractionation facilities that the Company leases to the Partnership. The Company also owns two additional natural gas processing plants, related gathering lines and a natural gas liquids line that the Partnership operates for a fee. See "Other Natural Gas Operations."
For additional financial and statistical information regarding the Company's operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 10 of Notes to Consolidated Financial Statements. For information regarding cash flows provided by and used in the Company's operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."
RECENT DEVELOPMENTS
Proposal to Acquire the Partnership
Effective December 20, 1993, Energy, VNGP, L.P. and Valero Natural Gas Company ("VNGC"), the general partner of VNGP, L.P., entered into an agreement of merger (the "Merger Agreement") providing for the merger of VNGP, L.P. with a wholly owned subsidiary of Energy (the "Merger"). In the Merger, the 9.7 million issued and outstanding common units of limited partner interests ("Common Units") in VNGP, L.P. held by persons other than the Company (the "Public Unitholders") will be converted into a right to receive cash in the amount of $12.10 per Common Unit, and VNGP, L.P. will become a wholly owned subsidiary of Energy. A special committee of outside directors (the "Special Committee") of VNGC, appointed to consider the fairness of the transaction to the Public Unitholders, has received an opinion from its independent financial advisor that the consideration to be received by the Public Unitholders in the transaction is fair from a financial point of view. The Special Committee has determined that such transaction is fair to, and in the best interest of, the Public Unitholders. The Board of Directors of VNGC has unanimously recommended that the Public Unitholders vote in favor of the Merger. The transaction is subject, among other things, to: (i) approval by the holders of a majority of the issued and outstanding Common Units; (ii) approval by the holders of a majority of the Common Units held by the Public Unitholders and voted at a special meeting to be called for the purpose of considering the Merger; (iii) receipt of satisfactory waivers, consents or amendments to certain of the Company's financial agreements; and (iv) completion of an underwritten public offering of preferred stock by Energy. See "Recent Developments - Convertible Preferred Stock Offering." A proposal to approve the Merger will be submitted to the holders of Common Units at the special meeting of Unitholders tentatively scheduled to be held during the second quarter of 1994. The Company owns approximately 47.5% of the outstanding Common Units and intends to vote its Common Units in favor of the Merger. There can be no assurance, however, that the Merger will be completed. The foregoing discussion of the Merger omits certain information contained in the Merger Agreement. Statements in this Report concerning the Merger Agreement are not necessarily complete, and are qualified by and are made subject to the Merger Agreement filed as an exhibit to this Report.
The Company believes that the natural gas and NGL industries are undergoing a period of restructuring and consolidation that may create opportunities for expansions, acquisitions or strategic alliances which, if the Partnership could take advantage of them, could enable the Partnership to compete more effectively in the competitive natural gas environment. Because of Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") which requires interstate pipeline companies to offer services on an unbundled, nondiscriminatory basis, the Company believes that intrastate pipelines such as the Partnership may enjoy increased opportunities to compete for interstate business. In addition, an emerging trend of west-to-east movement of gas may provide beneficial transportation opportunities for the Partnership if the Partnership were able to make the necessary capital expenditures for added west-to-east capacity on its pipeline system. However, the Partnership's competitive position could be eroded if the Partnership is unable to respond effectively to the changing dynamics of the industry. The Merger was proposed because the Company believes that the Partnership has insufficient financial flexibility to participate fully in opportunities that may arise in the natural gas and NGL industries. The Company believes that the ability of the Partnership to compete effectively in these businesses will be enhanced through the Merger. The Company also believes that potential conflicts of interest between the Partnership and the Company can be eliminated through the Merger.
Convertible Preferred Stock Offering
During the fourth quarter of 1993, Energy filed a registration statement on Form S-3 (as amended, the "Registration Statement"), registering for issuance and sale in an underwritten public offering (the "Public Offering") $150 million (up to $172.5 million with underwriters' over-allotments) of a series of Energy's authorized but unissued Preferred Stock. Energy intends to offer for sale up to 3,000,000 shares (3,450,000 shares with underwriters' over-allotments) of convertible preferred stock in the Public Offering (the "New Preferred Stock"). Energy intends to use a portion of the proceeds from the Public Offering to fund the cash payment to the Public Unitholders contemplated by the Merger. See "Recent Developments - Proposal to Acquire the Partnership." Any remaining proceeds will be used to pay expenses of the Merger and for general corporate purposes, including the reduction of existing indebtedness under the Company's bank credit agreements. If the Merger is not consummated, the proceeds from the Public Offering will be added to the Company's funds and used for general corporate purposes, including repayment of indebtedness, financing of capital projects and additions to working capital. Offers to sell or the solicitation of offers to buy shares of the New Preferred Stock will be made exclusively by means of a prospectus complying in all respects with the Securities Act of 1933, as amended. The description of the New Preferred Stock herein is not and shall not be construed as an offer to sell or the solicitation of an offer to buy any shares of the New Preferred Stock.
Decline of Crude Oil and Refined Product Prices
Beginning in November 1993, crude oil prices fell significantly and have not recovered to prior levels. During the November 1993 meeting of the Organization of Petroleum Exporting Countries ("OPEC"), the member countries declined to adopt any cuts in crude oil production. This decision, combined with increased production from non-OPEC regions, continued uncertainty regarding Iraq's possible re-entry into world oil markets and weakened global demand for energy, caused a precipitous drop in crude oil prices to their lowest levels in five years. Refined product and NGL prices fell in conjunction with the decline in crude oil prices. Moreover, refined product and NGL prices were further depressed due to continued high refinery-capacity utilization rates and unusually high gasoline and NGL inventories. These conditions caused a substantial decline in refining margins and required the Company to write down the carrying value of its refinery inventories as of December 31, 1993. See Note 1 of Notes to Consolidated Financial Statements. The conditions causing the recent decline in crude oil, refined product and NGL prices have continued in 1994. Although refined product prices and refining margins have increased modestly since late December 1993, the Company's operating income and net income in the first quarter of 1994 are expected to be in the same range as operating income and net income for the fourth quarter of 1993, excluding the effect of the write-down in the carrying value of the Company's refinery inventories.
Refinery Facilities Additions
During 1993, the Company added certain facilities at the Refinery to enable the Company to produce reformulated gasolines containing the levels of oxygenates required by the Clean Air Act Amendments of 1990 (the "Clean Air Act"). A facility to produce methyl tertiary butyl ether ("MTBE") from butane feedstock (the "Butane Upgrade Facility") was placed in service during the second quarter of 1993. MTBE is a high-octane blendstock used to manufacture oxygenated and reformulated gasolines. The Butane Upgrade Facility can produce 15,000 barrels per day of MTBE. The Company can blend the MTBE produced at the Refinery into the Company's own gasoline cargos or sell the MTBE separately as a gasoline blendstock. All the butane feedstocks required to operate the Butane Upgrade Facility are available to the Company through the Refinery's and the Partnership's operations.
In November 1993, the Company placed in service an MTBE/TAME complex (the "MTBE/TAME Complex"). The MTBE/TAME Complex converts streams currently produced at the Refinery's heavy oil cracker into about 2,500 barrels per day of MTBE and 3,000 barrels per day of tertiary amyl methyl ether ("TAME"). TAME, like MTBE, is a high-octane, oxygen-rich gasoline blendstock. The Butane Upgrade Facility and MTBE/TAME Complex enable the Company to produce approximately 20,000 barrels per day of oxygenates for gasoline blending.
During the fourth quarter of 1993, the Company also placed in service a 25,000 barrel per day reformate splitter (the "Reformate Splitter"). The Reformate Splitter extracts a benzene concentrate stream from reformate produced at the Refinery's naphtha reformer unit. The benzene concentrate stream may be shipped to other refineries that can recover and purchase the benzene at market prices and then return the balance of the concentrate stream to the Company for gasoline blending or for sale as a petrochemical feedstock. The 1993 facilities additions enable the Company to produce all of its gasoline as reformulated gasoline and represent investments totalling approximately $300 million.
MTBE Plant in Mexico
Productos Ecologicos, S.A. de C.V., a Mexican corporation ("Proesa"), has executed a Memorandum of Understanding with Petroleos Mexicanos, the Mexican state-owned oil company ("PEMEX"), to construct a MTBE plant in Mexico, and has proposed a butane supply contract and MTBE sales contract with PEMEX. Proesa is owned 35% by the Company; 10% by Dragados y Construcciones, the largest construction company in Spain; and 55% by a corporation formed by Banamex, Mexico's largest bank, and Groupo Infomin, a privately held Mexican company. Proesa has also executed an option agreement for a plant site near the Bay of Campeche. The proposed Mexican MTBE plant is expected to have a capacity of approximately 15,000 barrels per day and to be similar to the Refinery's Butane Upgrade Facility. The project is expected to cost approximately $440 million and is subject to, among other things, the arrangement of satisfactory financing. Proesa has been advised by lenders with whom it is negotiating for project financing that certain provisions will be required in the proposed PEMEX contracts in order to secure satisfactory financing for the project. Proesa has entered into negotiations with PEMEX regarding such provisions.
As a result of delays incurred in completing financing, Proesa has determined that the commencement of plant construction will be delayed. If satisfactory financing is obtained, construction of the MTBE plant could not begin before late 1994, with approximately two years required for completion. As of February 1994, no material amounts have been invested in the project. The amount of the Company's equity contribution will depend upon the level of debt financing obtained by Proesa and the ultimate equity interest of each partner. Under the proposed commercial contracts, PEMEX will purchase approximately 75% of the MTBE plant's production, one-half at a formula price and one-half at market-related prices, with the remainder of the plant's production being sold to the Company at a formula price. In addition, the butane feedstocks required by the plant will be purchased from PEMEX at market-related prices. A subsidiary of Energy has agreed to provide technical advice and assistance to Proesa in connection with the design, engineering, construction and operation of the MTBE plant. There can be no assurance that financing for the project can be obtained or that the plant will be constructed.
PETROLEUM REFINING AND MARKETING
Refining Operations
The Refinery is designed to process primarily high- sulfur atmospheric tower bottoms, a type of residual fuel oil ("resid"), into a product slate of higher value products, principally unleaded gasoline and middle distillates. The Refinery also processes crude oil, butanes and other feedstocks. The Refinery can produce approximately 140,000 barrels per day of refined products, with gasoline and gasoline-related products comprising approximately 85% of the Refinery's throughput. The remaining product slate from the Refinery is primarily middle distillates. The Refinery has substantial flexibility to vary its mix of gasoline products to meet changing market conditions. Refining owns feedstock and product storage facilities with a capacity of approximately 6.4 million barrels. Approximately 4.1 million barrels of storage capacity are heated tanks for heavy feedstocks. During 1994, the Company anticipates having approximately 850,000 barrels of fuel oil storage available under lease in Malta. The Malta storage site will allow the Company to accumulate small parcels of high-sulfur resid for shipment to the Refinery. Refining also owns dock facilities that can simultaneously unload two 150,000 dead weight ton capacity ships and can dock larger crude carriers after partial unloading.
One of the Refinery's principal operating units is a hydrodesulfurization unit ("HDS Unit"), which removes sulfur and metals from resid, thereby improving its subsequent cracking characteristics. The HDS Unit has a capacity of approximately 64,000 barrels per day. The Refinery's other principal unit is a heavy oil cracking complex ("HOC"), which processes feedstock primarily from the HDS Unit. The capacity of the HOC is approximately 66,000 barrels per day. The Refinery also has a hydrocracker with a capacity of approximately 34,000 barrels per day (the "Hydrocracker"), a continuous catalyst regeneration reformer with a capacity of approximately 31,000 barrels per day (the "Reformer"), and a reformer feed hydrotreater, hydrogen purification unit and related equipment (collectively, the "H/R Units"). The Hydrocracker processes gas oil and distillate streams from the Refinery to produce reformer feed naphtha. The Hydrocracker naphtha and other naphtha streams produced at the Refinery provide feed for the Reformer to produce reformate, a high-octane, low vapor pressure gasoline blendstock, and other products. The Refinery's other refining units include a 30,000 barrel per day crude unit and a 24,000 barrel per day vacuum unit. In 1993, the Company added the Butane Upgrade Facility, MTBE/TAME Complex and Reformate Splitter. See "Recent Developments - Refinery Facilities Additions" for a discussion of these facilities.
The HDS Unit was down 15 days for a scheduled maintenance and catalyst change completed in December 1993. The Refinery's principal refining units operated during 1991, 1992 and 1993 with no significant unscheduled downtime. The HOC is scheduled for a turnaround in late 1994. For additional information with respect to Refining's operating results for the three years ended December 31, 1993, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Feedstock Supply
The principal feedstock for the Refinery is resid produced at refineries outside the United States. Most of the large refineries in the United States are complex, sophisticated facilities able to convert internally produced resid into higher value products. Many overseas refineries are less sophisticated, process smaller portions of resid internally and, therefore, produce larger volumes of resid for sale. As a result, Refining acquires and expects to acquire most of its resid in international markets. A substantial portion of Refining's feedstock supplies are obtained from Middle Eastern sources. These supplies are loaded aboard chartered vessels at ports in the Arabian Gulf and are subject to the usual maritime hazards. Refining maintains insurance on its feedstock cargos.
Under a feedstock supply agreement with the Company, Saudi Aramco (successor to the Saudi Arabian Marketing and Refining Company "SAMAREC") has agreed to provide an average of 55,000 barrels per day of resid to the Company at market-related prices. Deliveries under the agreement will continue through 1994 and provide approximately 75% of Refining's resid requirements. During 1993, Refining also purchased approximately 11,000 barrels per day of South Korean resid at market-related prices under an agreement which expires in the first quarter of 1994. The Company is negotiating to renew the agreement for South Korean resid on pricing terms more favorable to the Company than the existing contract. The Company also renewed a contract for approximately 22,000 barrels of crude produced in the People's Republic of China. Although the volume for this contract has been committed to the Company, the price must be renegotiated each quarter. The remainder of the Refinery's feedstocks are purchased at market-based prices under short-term contracts. The Company believes that if any of Refining's existing feedstock arrangements were interrupted, adequate supplies of feedstock could be obtained from other sources or on the open market.
Resid generally sells at a discount to crude oil. In recent years, however, developments in the market have reduced this discount. The Company generally expects the long-term trend in the relationship between the supply of and demand for resid to be favorable, and expects resid to continue to sell at a discount to crude oil. In the short term, other factors, including price volatility and political developments, are likely to play an important role in refining industry economics. See "Recent Developments - Decline in Crude Oil and Refined Product Prices."
Sales
Set forth below is a summary of Refining's throughput volumes per day, average throughput margin per barrel and sales volumes per day for the three years ended December 31, 1993. Average throughput margin per barrel is computed by subtracting total direct product cost of sales from product sales revenues and dividing the result by throughput.
Refining sells refined products principally on a spot and truck rack basis. A truck rack sale is a sale to a customer that provides trucks to take delivery at loading facilities. In 1993, spot and truck rack sales volumes accounted for 79% and 21%, respectively, of combined gasoline and distillate sales. Spot sales of Refining's products are made principally to larger oil companies and gasoline distributors. The principal purchasers of Refining's products from truck racks have been wholesalers and jobbers in the southeastern and midwestern United States. Refining's products are transported through common-carrier pipelines, barges and tankers. Interconnects with common-carrier pipelines give Refining the flexibility to sell products to the midwestern or southeastern United States.
Factors Affecting Operating Results
Refining's results of operations are determined principally by the relationship between refined product prices and resid prices, which in turn are largely determined by market forces. In recent years, the crude oil and refined product markets have experienced periods of extreme price volatility. During such periods, disproportionate changes in the prices of refined products and resid usually occur. Such changes have sometimes reduced margins, and, in some cases, such as in August 1990 at the beginning of the Arabian Gulf crisis, margins have expanded significantly. During the fourth quarter of 1993, however, refined product prices fell sharply, significantly reducing margins and requiring a writedown of the carrying value of the Company's Refinery inventories. See "Recent Developments - Decline of Crude Oil and Refined Product Prices" and Note 1 of Notes to Consolidated Financial Statements. The potential impact of changing crude oil and refined product prices on Refining's results of operations is further affected by the fact that, on average, Refining buys its resid feedstock approximately 40 days prior to processing it in the Refinery.
The Company believes that resid will continue to sell at a discount to crude oil, and expects to continue to generate higher margins in its refining operations than conventional refiners that use crude oil as a principal feedstock. The future price of resid will depend on the relationship between the growth in crude oil demand (which generates more resid when processed) and worldwide additions to resid conversion capacity (which has the effect of reducing the available supply of resid). The Company believes that industry-wide additions to resid conversion capacity are not likely to exceed the expected increase in resid availability caused by increasing crude runs, decreasing environmentally permissible uses for resid and other factors.
Refined product prices are influenced principally by factors of supply and demand. The Company expects that global demand for light products, including gasoline, will continue to increase in relation to the level of general economic activity, while fuel oil demand will increase more slowly. Most of the demand growth is expected to occur outside of the United States, particularly in Asia. The supply of gasoline and other light products is influenced by a variety of factors. Factors that may reduce available supplies include refinery shutdowns, vapor pressure reduction programs (which effectively remove butanes from the gasoline supply pool), lead phase-out programs and requirements for reformulated gasoline (which effectively remove benzene and other aromatics from the gasoline supply pool). Factors tending to increase supplies include imports, additions of conversion capacity and requirements for oxygenated gasoline under the Clean Air Act (which effectively adds oxygenates such as MTBE and ethanol to the gasoline pool). Predictions of future supply and demand are necessarily uncertain. However, the Company believes that prior to 1995, conversion capacity additions and projects to produce MTBE and other oxygenates are likely to cause gasoline supplies to increase more rapidly than demand. Thereafter, possible refinery closings and the more prevalent use of reformulated gasolines may reduce gasoline supplies and improve refining margins.
The anticipated growth in demand for MTBE may be adversely affected by recent oxygenate proposals promulgated by the EPA under the Clean Air Act. On December 15, 1993, the EPA issued proposed reformulated gasoline regulations requiring that at least 30% of the oxygenates used in reformulated gasolines come from renewable sources such as corn, grain, wood, and organic waste products. Ethanol and ether producers capable of manufacturing ethanol-based ethyl tertiary butyl ether ("ETBE") stand to benefit the most if the proposed oxygenate rules are adopted due to the resulting, immediate increase in demand for ethanol and ETBE likely to occur. The proposed mandate for renewable oxygenates is generally disfavored by the fossil fuel- based oxygenate industry, including producers of methanol and manufacturers of MTBE. The EPA is expected to issue a final rule on renewable oxygenates by June 1994.
Domestic gasoline production is supplemented with foreign imports. However, the Company believes that the availability of foreign gasoline supplies may decline because of the implementation of lead phasedown programs in some countries and a gradual increase in other environmental restrictions. The Company also believes that beginning in 1995, United States gasoline production capacity may become limited because of the prohibitive costs of new refinery construction and the expense of compliance for many older refineries with environmental regulations, including the Clean Air Act. Under provisions of the Clean Air Act, U.S. refineries must apply for new federal operating permits in 1995. Because the Refinery was completed in 1984, the Company expects to be able to comply with present and future environmental legislation more easily than older, conventional refineries. See "Environmental Matters" for a further discussion of the Clean Air Act and its impact on the refining industry.
Other Projects
Through its wholly owned subsidiary, the Company is a 20% general partner in Javelina Company ("Javelina"), which completed construction in 1991 of a plant in Corpus Christi (the "Javelina Plant") to process waste gases from the Refinery and other refineries in the Corpus Christi area and to extract hydrogen, ethylene, propylene and NGLs from the gas stream. The Company has made capital contributions and advances to Javelina of approximately $19.3 million through December 31, 1993, for the Company's proportionate share of capital expenditures and operating expenses. Javelina maintains a term loan agreement and a working capital and letter of credit facility which mature on January 31, 1996. The Company's guarantees of these bank credit agreements were approximately $19.6 million at December 31, 1993.
VALERO NATURAL GAS PARTNERS, L.P.
The Company holds an approximate 49% effective equity interest in the Partnership, and various subsidiaries of Energy serve as general partners of VNGP, L.P. and its subsidiary partnerships. For information with respect to the Company's investment in the Common Units of Limited Partner Interest ("Common Units") in VNGP, L.P., see Note 2 of Notes to Consolidated Financial Statements.
Natural Gas Operations
The Partnership owns and operates natural gas pipeline systems principally serving Texas intrastate markets. The Partnership's principal natural gas pipeline system is the intrastate gas system ("Transmission System") operated by Valero Transmission, L.P. ("Transmission") in the State of Texas. The Partnership also owns a 3.5-mile, 24-inch pipeline that connects the Partnership's pipeline near Penitas in South Texas to PEMEX's 42-inch pipeline outside of Reynosa, Mexico. The Partnership's wholly owned, jointly owned and leased natural gas pipeline systems include approximately 7,200 miles of mainlines, lateral lines and gathering lines. The Partnership leases and operates several natural gas pipelines, including approximately 240 miles of 24-inch pipeline extending from near Dallas to near Houston which the Partnership leases from a third party, and approximately 105 miles of pipeline in East Texas extending to Carthage, near the Louisiana border, which the Partnership leases from the Company. These integrated systems include 39 mainline compressor stations with a total of approximately 162,000 horsepower, together with gas processing plants, dehydration and gas treating plants and numerous measuring and regulating stations.
The Partnership's gas sales, including gas sales by those subsidiaries operating the Partnership's special marketing programs ("SMPs"), transportation volumes in million cubic feet ("MMcf") per day, average gas sales prices and average gas transportation fees for the three years ended December 31, 1993, are as follows:
The Partnership's natural gas operating results have improved in 1993 as natural gas supply and demand have become more balanced. Although increased industry competition will continue to affect the Partnership's operating results from natural gas operations, in 1993 the Partnership's natural gas throughput benefitted from increased business opportunities arising under FERC Order 636, a west-to-east shift in natural gas supply patterns and the temporary shutdown of a nuclear power plan in the Partnership's service area. See "Governmental Regulations - Federal Regulation" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
Natural Gas Liquids Operations
The Partnership's NGL operations include the processing of natural gas to extract a mixed stream of NGLs comprised of ethane, propane, butanes and natural gasoline, the separation ("fractionation") of mixed NGLs into component products and the transportation and marketing of NGLs. Extracted NGLs are transported to downstream fractionation facilities and end-use markets through NGL pipelines owned or leased by the Partnership and certain common carrier NGL pipelines.
The Partnership owns or operates for its own account nine gas processing plants including a plant near Thompsonville in South Texas, which is leased by the Partnership from the Company. The Partnership's owned and leased gas processing plants are located in the western and southern regions of Texas and process approximately 1.3 billion cubic feet of gas per day. The Partnership's NGL production is sold primarily in the Corpus Christi and Mont Belvieu (Houston) markets. A substantial portion of the Partnership's butane production is sold to the Company as a feedstock for the Refinery's Butane Upgrade Facility.
Volumes of NGLs produced at the Partnership's owned and leased plants (in thousands of barrels per day) and the average market price per gallon for the three years ended December 31, 1993, are as follows:
The Partnership also owns or leases approximately 375 miles of NGL pipelines and fractionation facilities at three locations. In 1993, the Partnership fractionated an average of 70,000 barrels per day, compared to 68,000 barrels per day in 1992 and 51,000 barrels per day in 1991. In addition, the Partnership operates for a fee two NGL processing plants, approximately 59 miles of NGL pipeline and 450 miles of gathering lines owned by a subsidiary of Energy. See "Other Natural Gas Operations."
Additional information regarding the Partnership is set forth in the Partnership's Annual Report on Form 10-K (Commission File No. 1-9433), which is separately filed with the Securities and Exchange Commission (the "Commission"). Items 1 through 3 of the Partnership's Annual Report on Form 10-K for the year ended December 31, 1993, as filed with the Commission on March 1, 1994, are filed as an Exhibit to this Report.
OTHER NATURAL GAS OPERATIONS
In addition to the natural gas and NGL operations conducted through the Partnership, the Company, through its wholly owned subsidiary Valero NGL Investments Company, owns certain South Texas NGL assets including two natural gas processing plants in Starr and Dimmit Counties, 450 miles of associated natural gas gathering lines, a 59-mile NGL pipeline and a 17.5% interest in a third gas processing plant in Nueces County. The Partnership operates these facilities for a fee under operating agreements with the Company. During 1993, these plants produced a daily average of approximately 9,500 barrels per day of NGLs. Prices realized from the sale of plant products were comparable to those obtained by the Partnership for its own production. See "Valero Natural Gas Partners, L.P. - Natural Gas Liquids."
The Company leases certain assets to the Partnership under capital leases. The leased assets include (i) a gas processing plant near Thompsonville in South Texas and 48 miles of NGL product pipeline (the "Thompsonville Project"), (ii) an interest in approximately 105 miles of pipeline in East Texas (the "East Texas pipeline"), and (iii) certain fractionation facilities in Corpus Christi. The Thompsonville Project lease commenced December 1, 1992, and has a term of 15 years. The East Texas pipeline lease commenced February 1, 1991, and has a term of 25 years. The lease for the fractionation facilities commenced December 1, 1991, and has a term of 15 years. The rate of return available to the Company from the leases is limited to the lease payments specified in the respective leases plus any related tax benefits. The Partnership has the right to purchase all or any portion of the leased assets, subject to certain restrictions, under purchase option provisions of the respective lease agreements.
Effective September 30, 1993, the Company sold its stock of Rio Grande Valley Gas Company ("RGV"), a wholly owned subsidiary of Energy whose operations are included in "Other Operations" of the Company, for cash in the amount of approximately $31 million. The disposition of RGV resulted in an after-tax gain, net of other nonoperating charges, of approximately $5 million. RGV owns approximately 1,552 miles of retail distribution lines, sells gas to approximately 75,000 retail customers in a number of communities in the Lower Rio Grande Valley of Texas and transports gas for approximately 60 transportation customers. Pursuant to contracts with the Partnership, RGV will continue to acquire all of its gas supply from the Partnership through the year 2000. RGV had aggregate gas sales and transportation volumes averaging approximately 14 MMcf per day in each of 1992 and 1991, and 15 MMcf per day for the first nine months of 1993.
Val Gas Company ("Val Gas"), a wholly owned subsidiary of VNGC, owns and operates several small gathering systems in Texas that are subject to regulation by the FERC. See "Governmental Regulations - Federal Regulation." Until December 31, 1993, Valero Interstate Transmission Company ("Vitco"), an indirect wholly owned subsidiary of Energy, operated a small interstate pipeline system in South Texas comprised of approximately 240 miles of transmission and gathering lines. Effective January 1, 1994, the FERC authorized Vitco's abandonment of its pipeline system which is no longer subject to FERC rate regulation.
GOVERNMENTAL REGULATIONS
Certain of the Company's subsidiaries are subject to regulations issued by the Railroad Commission under the Cox Act, the Gas Utilities Regulatory Act ("GURA") and the Natural Resources Code, all of which are Texas statutes, and the federal Natural Gas Policy Act ("NGPA"). In addition, certain activities of Val Gas Company are subject to the regulations of the FERC under the NGPA, the Department of Energy Organization Act of 1977 (the "DOE Act"), and the federal Natural Gas Act. The Company's activities are also subject to various state and federal environmental statutes and regulations. See "Environmental Matters."
Texas Regulation
The Railroad Commission regulates the intrastate transportation, sale, delivery and pricing of natural gas in Texas by intrastate pipeline and distribution systems, including those of the Partnership. During 1992, the Railroad Commission revised its rules governing the production and purchase of natural gas. As part of such revision, the Railroad Commission adopted the gas proration rule (the "gas proration rule") to prevent the production of gas in excess of market demand. The gas proration rule requires producers to tender and deliver, and gas purchasers, including pipelines and purchasers offering SMPs, to take, only volumes of gas equal to their market demand. The gas proration rule further requires purchasers to take gas by priority categories, ratably among producers without undue discrimination, and with high-priority gas (defined as casinghead gas, or gas from wells primarily producing oil, and certain special allowable gas that are the last to be shut in during periods of reduced market demand) having higher priority than gas well gas (defined as gas from wells primarily producing gas), notwithstanding any contractual commitments. The revised rules are intended to simplify the previous system of nominations and to bring production allowables in line with estimated market demand.
Federal Regulation
In 1992, the FERC issued Order 636 related to restructuring of the interstate natural gas pipeline industry. Order 636 requires pipelines subject to FERC jurisdiction to provide unbundled marketing, transportation, storage and load balancing services on a nondiscriminatory basis to producers and end users instead of offering only combined packages of services, thus increasing competition in the natural gas industry. No Company subsidiary or Partnership subsidiary operating partnership is directly subject to Order 636. However, Order 636 is expected to create new supply, marketing and transportation opportunities for the Partnership. See "Recent Developments - Proposal to Acquire the Partnership."
The Natural Gas Act and DOE Act grant to the FERC the authority to regulate rates and charges for natural gas transported in interstate commerce or sold by natural gas companies in interstate commerce for resale. Interstate natural gas sales for resale are made at rates subject to FERC regulation. Val Gas Company is subject to regulation as a "natural gas company" under the Natural Gas Act.
ENVIRONMENTAL MATTERS
The Company's Refinery operations and natural gas and NGL operations are subject to environmental regulation by federal and state authorities, including the EPA, the Texas Natural Resources Conservation Commission ("TNRCC"), the Texas General Land Office and the Railroad Commission. Compliance with regulations promulgated by these authorities increases the cost of designing, installing and operating such facilities. The regulatory requirements relate to water and storm water discharges, waste management and air pollution control measures. In 1993, Refining's capital expenditures attributable to compliance with environmental regulations (exclusive of expenditures for the Butane Upgrade Facility, MTBE/TAME Complex and Reformate Splitter, for which the amount of expenditures attributable to environmental regulation is not determinable) were approximately $8 million and are currently estimated to be approximately $6 million for 1994.
Under the Clean Air Act, U.S. refineries must apply for new federal operating permits in 1995. Compliance with this and other environmental requirements may prove difficult and expensive for many older refineries. As a result, many refineries during the next few years likely will focus their capital expenditures on bringing their facilities into compliance with environmental requirements, rather than adding to capacity. Because of the Clean Air Act and other environmental regulations, various U.S. refiners have announced their intention to sell or close those refineries where capital expenditures needed to ensure compliance are not economically feasible. Because the Refinery was completed in 1984, it was built under more stringent environmental requirements than most existing U.S. refineries. Accordingly, the Company expects to be able to comply with the Clean Air Act and future environmental legislation more easily than older, conventional refineries.
The Company expects that the demand for oxygenates such as MTBE will increase. (But see "Factors Affecting Operating Results" for a discussion of recent regulations proposed by the EPA that require the use of renewable oxygenates such as ethanol and ETBE.) The increase in demand for oxygenates is expected not only because of the mandates of the Clean Air Act for the use of clean burning fuels, but also because of the expected election by many areas to use reformulated gasolines even though not formally required by the Clean Air Act. The Clean Air Act requires the 39 areas that have failed to attain carbon monoxide air quality standards to use oxygenated gasolines during winter months. Beginning in 1995, the Clean Air Act also requires the nine areas that have the worst ozone air quality to use reformulated gasoline throughout the year to decrease their emissions of hydrocarbons and toxic pollutants. Also beginning in 1995, another 87 areas that have failed to attain certain ozone air-quality standards may elect to use reformulated gasolines throughout the year to decrease their emissions of hydrocarbons and toxic pollutants. Already, 43 of the 87 areas have notified the EPA of their election to use reformulated gasolines. Recent additions to the Refinery's facilities enable the Company to produce all of its gasoline as reformulated gasoline. See "Recent Developments - Refinery Facilities Additions."
During 1991, environmental legislation was passed in Texas which conformed Texas law with the Clean Air Act to allow Texas to administer the federal programs. The Company and the Partnership have been and will continue to be affected by provisions of these laws concerning control requirements for air toxins and new operating permit requirements. The Company and the Partnership also have been affected by the increasing regulation of wastes by the Railroad Commission and the TNRCC and the promulgation of EPA permitting requirements for storm water discharges associated with industrial activities. Although these new laws and requirements may increase operating costs, they are not expected to have a material adverse effect on the Company's or the Partnership's operations or financial condition.
The Oil Pollution Act of 1990 requires newly constructed tank vessels carrying crude oil to U.S. ports to be equipped with double hulls or double containment systems, and provides for a phaseout of existing vessels without double hulls beginning in 1995. Although these requirements are expected to increase the cost of transporting feedstocks to the Refinery, the staggered phaseout of existing vessels is expected to give existing vessel operators sufficient time to replace their fleets to provide adequate shipping capability.
COMPETITION
The refining industry is highly competitive with respect to both supply and markets. Refining competes with numerous other companies for available supplies of resid and other feedstocks and for outlets for its refined products. Prices of feedstocks and refined products are established principally by market conditions. Many of the companies with which Refining competes obtain a significant portion of their feedstocks from company-owned production and are able to dispose of refined products at their own retail outlets. Competitors that have their own production or retail outlets may be able to offset losses from refining operations with profits from producing or retailing operations and may be better positioned than the Company to withstand periods of depressed refining margins. See "Environmental Matters" for a discussion of the effects of environmental regulations on refining competition.
The natural gas industry is and is expected to remain highly competitive with respect to both gas supply and markets, with no company or small group of companies being dominant. Order 636 provides a mechanism for producers and marketers to sell gas directly to end users, resulting in increased competition for gas sales. See "Governmental Regulations - Federal Regulation."
EMPLOYEES
As of December 31, 1993, the Company had approximately 1,740 employees.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of December 31, 1993 regarding the present executive officers of Energy. Each officer named in the following table has been elected to serve until his successor is duly appointed and elected or his earlier removal or resignation from office. No family relationship exists among any of the executive officers, directors or nominees for director of Energy. Similarly, there is no arrangement or understanding between any executive officer and any other person pursuant to which he was or is to be selected as an officer.
Mr. Greehey has served as Chief Executive Officer and as a director of Energy since 1979 and as Chairman of the Board since 1983. Mr. Greehey is also a director of Weatherford International Incorporated and Santa Fe Resources, Inc., neither of which are affiliated with the Company or the Partnership.
Mr. Benninger has served as a director of Energy since 1990. He was elected Executive Vice President in 1989 and served as Chief Financial Officer from 1986 to 1992. In 1992, he was elected Executive Vice President and Chief Operating Officer of Valero Natural Gas Company.
Mr. McLelland was elected Executive Vice President and General Counsel in 1989 and had served as Senior Vice President and General Counsel of Energy since 1981.
Mr. Heep was elected Senior Vice President and Chief Financial Officer of Energy in 1994, prior to which he served as Vice President Finance since 1990. He has been employed by the Company in various capacities since 1977.
Mr. Fry was elected Vice President Administration of Energy in 1989 and served as Secretary of Energy from 1980 to 1992.
Mr. Zanotti has served as Executive Vice President of VRMC since 1988 and as President and Chief Operating Officer of VRC since 1990, and has served in other positions with the Company since 1983.
Mr. Manning has served as Senior Vice President of VRMC since 1986 and of VRC since 1987.
ITEM 2.



ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery and related facilities, three natural gas processing plants, and various natural gas and NGL pipelines, gathering lines and related facilities, all located in Texas. The Company also operates natural gas pipeline systems and NGL facilities, processing plants, compressor stations, treating plants, measuring and regulating stations, fractionation facilities, underground natural gas storage caverns and other properties owned or used by the Partnership, all of which are located in Texas. Substantially all of Refining's fixed assets are pledged as security under deeds of trust securing industrial revenue bonds issued on behalf of Refining, while its inventories and receivables are pledged as security under a bank credit agreement providing working capital to Refining. See Note 4 of Notes to Consolidated Financial Statements. The Partnership has pledged substantially all of its gas systems and processing facilities, except for certain pipeline, processing and fractionation assets leased from the Company, as collateral for its First Mortgage Notes. Reference is made to "Item 1. Business," which includes detailed information regarding properties of the Company.
Management believes that the Company's facilities are generally adequate for their respective operations, and that the facilities of the Company are maintained in a good state of repair. The Company and the Partnership are lessees under a number of cancelable and noncancelable leases for certain real properties. See Note 14 of Notes to Consolidated Financial Statements.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company is party to the following proceedings:
Coastal Oil and Gas Corporation v. TransAmerican Natural Gas Corporation ("TANG"), 49th State District Court, Webb County, Texas (filed October 30, 1991) (reported in the Company's Form 10-K for the year ended December 31, 1992 as Transamerican Natural Gas Corporation v. The Coastal Corporation et al). In March 1993, Valero Transmission Company and Valero Industrial Gas Company were served as third party defendants in this lawsuit. In August 1993, Energy, VNGP, L.P. and certain of their respective subsidiaries were named as additional third-party defendants (collectively, including the original defendant subsidiaries, the "Valero Defendants"). In TANG's counterclaims against Coastal and third-party claims against the Valero Defendants, TANG alleges that it contracted to sell natural gas to Coastal at the posted field price of Valero Industrial Gas Company and that the Valero Defendants and Coastal conspired to set such price at an artificially low level. TANG also alleges that the Valero Defendants and Coastal conspired to cause TANG to deliver unprocessed or "wet" gas thus precluding TANG from extracting NGLs from its gas prior to delivery. TANG seeks actual damages of approximately $50 million, trebling of damages under antitrust claims, punitive damages of $300 million, and attorneys' fees. The Valero Defendants' motion for summary judgment on TANG's antitrust claim was argued on January 24, 1994. The court has not ruled on such motion. The current trial setting for this case is March 14, 1994.
Toni Denman v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 15, 1993); Howard J. Vogel v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 15, 1993); 7547 Partners v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 19, 1993); Robert Endler Trust v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 27, 1993); Dorothy Real v. Valero Energy Corporation, Valero Natural Gas Company and Valero Natural Gas Partners, L.P., (filed November 4, 1993); Malcolm Rosenwald v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed November 9, 1993); Norman Batwin v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed November 15, 1993) Court of Chancery, New Castle County, Delaware. Each of the foregoing suits was filed in response to the announcement of Energy's proposal to acquire the publicly traded Common Units of VNGP, L.P. pursuant to a proposed merger of VNGP, L.P. with a wholly owned subsidiary of Energy. The suits were consolidated by the Court of Chancery on November 23, 1993. The plaintiffs sought to enjoin or rescind the proposed merger, alleging that the corporate defendants and the individual defendants, as officers or directors of the corporate defendants, engaged in actions in breach of the defendants' fiduciary duties to the holders of the Common Units by proposing the merger. The plaintiffs alternatively sought an increase in the proposed merger consideration, compensatory damages and attorneys' fees. In December 1993, the parties reached a tentative settlement of the consolidated lawsuit. The terms of the settlement will not require a material payment by the Company or the Partnership.
Garcia, et al. v. Coastal Chemical Company, Inc., Valero Refining Company, Javelina Company, et al., 347th Judicial District Court, Nueces County, Texas (filed August 31, 1993). This action was brought by certain residents of the Oak Park Triangle area of Corpus Christi, Texas, against several defendants including Valero Refining Company. All named defendants are either refiners or gas processors having facilities located at or near Up River Road in Corpus Christi. Plaintiffs allege in general terms damages resulting from ground water contamination and air pollution allegedly caused by the operations of the defendants. Plaintiffs seek unspecified actual and punitive damages.
The Long Trusts v. Tejas Gas Corporation, 123rd Judicial District Court, Panola County, Texas (filed March 1, 1989). Valero Transmission Company (an indirect wholly owned subsidiary of Energy, "VTC"), as buyer, and Tejas Gas Corporation ("Tejas"), as seller, are parties to various gas purchase contracts assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. Tejas is also a party to a series of gas purchase contracts between Tejas, as buyer, and certain trusts ("The Long Trusts"), as seller, which are in litigation ("The Long Trusts Litigation"). Neither the Partnership nor VTC is a party to The Long Trusts Litigation or the Tejas/Long Trusts contracts. However, because of the relationship between the Transmission/Tejas contracts and the Tejas/Long Trusts contracts, and in order to resolve existing and potential disputes, Tejas, VTC and Valero Transmission, L.P. have agreed that Tejas, VTC and Valero Transmission, L.P. will cooperate in the conduct of The Long Trusts Litigation, and that VTC and Valero Transmission, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against Tejas. In The Long Trusts Litigation, The Long Trusts allege that Tejas has breached various minimum take, take-or-pay and other contractual provisions of the Tejas/Long Trusts contracts, and assert a statutory non-ratability claim. The Long Trusts seek alleged actual damages of approximately $30 million including interest and an unspecified amount of punitive damages. The District Court ruled on the plaintiff's motion for summary judgment, finding that as a matter of law the three gas purchase contracts at issue were fully binding and enforceable, that Tejas breached the minimum take obligations under one of the contracts, that Tejas is not entitled to claimed offsets for gas purchased by third parties and that the "availability" of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, have not been determined. Because of existing contractual obligations of Valero Transmission, L.P. to Tejas, the lawsuit may ultimately involve a contingent liability for Valero Transmission, L.P. The Court recently granted Tejas's Motion for Continuance in connection with the former January 10, 1994 trial date. The Long Trusts Litigation is not currently set for trial.
NationsBank of Texas, N.A., Trustee of The Charles Gilpin Hunter Trust, et al. v. Coastal Oil & Gas Corporation, Valero Transmission Company, et al., 160th State District Court, Dallas County, Texas (filed February 2, 1993) (formerly reported as "Williamson, et al. v. Coastal Oil & Gas Corporation, Valero Transmission Company, et al., 68th State District Court, Dallas County, Texas (filed June 30, 1988)" in Energy's Form 10-K for the fiscal year ended December 31, 1992). In a lawsuit filed in 1988, certain plaintiffs alleged that defendants Coastal Oil & Gas Corporation ("Coastal") and Energy, VTC, VNGP, L.P., the Management Partnership and Valero Transmission, L.P. (the "Valero Defendants") were liable for failure to take minimum quantities of gas, failure to make take-or-pay payments and other breach of contract and breach of fiduciary duty claims. The plaintiffs sought declaratory relief, actual damages in excess of $37 million and unquantified punitive damages. The lawsuit was settled on terms immaterial to the Valero Defendants, and the parties agreed to a dismissal of the lawsuit. On November 16, 1992, prior to entry of an order of dismissal, NationsBank of Texas, N.A., as trustee for certain trusts (the "Intervenors"), filed a plea in intervention to intervene in the lawsuit. The Intervenors asserted that they held a nonparticipating mineral interest in the lands subject to the litigation and that their rights were not protected by the plaintiffs in the settlement. On February 4, 1993, the Court struck the Intervenors' plea in intervention. However, on February 2, 1993, the Intervenors had filed a separate suit in the 160th State District Court, Dallas County, Texas, against all prior defendants and an additional defendant, substantially adopting the allegations and claims of the original litigation. In February 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Company or the Partnership.
Valero Energy Corporation, et al. v. M.W. Kellogg Company, et al., 117th Judicial District Court, Nueces County, Texas (filed July 11, 1986). The Company claims that the defendants are liable for breach of warranty, breach of contract, negligence, gross negligence, breach of implied warranty of good and workmanlike performance, breach of the Texas Deceptive Trade Practices - Consumer Protection Act, breach of implied warranty of fitness for ordinary purposes and strict liability in tort in connection with services performed at the Refinery. The Company claims actual damages in excess of $165 million plus exemplary damages, statutory penalties, attorney's fees and costs of court. In September 1991, the court considered motions for summary judgment filed by the Company, Kellogg and Ingersoll-Rand, another primary defendant. On October 25, 1991, the court entered judgment which granted the motions of Kellogg and Ingersoll-Rand for summary judgment in their entirety, denied the motion for summary judgment filed by the Company and entered a take nothing judgment dismissing all of the Company's claims with prejudice. The Company appealed the trial court's decision to the Thirteenth Court of Appeals, Corpus Christi, Texas. On June 30, 1993, the Court of Appeals affirmed the trial court's decision. The Company has appealed the decision to the Texas Supreme Court.
White, et al. v. Coastal Javelina, Inc., Valero Energy Corporation, et al., 94th State District Court, Nueces County, Texas (filed November 27, 1991). Plaintiffs, as owners of real property situated near the Javelina Plant, have alleged that the operation and maintenance of the Javelina Plant have (i) interfered with their use and enjoyment of their property, (ii) caused depreciation in the value of their property, (iii) caused physical and mental injuries, (iv) damaged persons and property, and (v) caused a nuisance. Plaintiffs seek unspecified actual damages, punitive damages, prejudgment and postjudgment interest, costs of the lawsuit and equitable relief.
Javelina Company Litigation. Valero Javelina Company, a wholly owned subsidiary of Energy, is a general partner of Javelina Company, a general partnership. See "Petroleum Refining and Marketing - Other Projects" and Note 5 of Notes to Consolidated Financial Statements. In addition to White and Garcia (reported above), Javelina Company has been named as a defendant in five other lawsuits filed since 1992 in state district courts in Nueces County, Texas. Garcia and three other suits include as defendants several other companies that own refineries or other industrial facilities in Nueces County. These suits were brought by a number of plaintiffs who reside in neighborhoods near the facilities. The plaintiffs claim injuries relating to alleged exposure to toxic chemicals, and generally claim that the defendants were negligent, grossly negligent and committed trespass. The plaintiffs claim personal injury and property damages resulting from soil and ground water contamination and air pollution allegedly caused by the operations of the defendants. One of the suits seeks certification of the litigation as a class action. The plaintiffs seek an unspecified amount of actual and punitive damages. White and two other suits were brought by plaintiffs who either live or have businesses near the Javelina Company plant. The suits allege claims similar to those described above. These plaintiffs also fail to specify an amount of damages claimed.
City of Houston Claim. In a letter dated September 1, 1993 from the City of Houston (the "City") to Valero Transmission Company ("VTC"), the City stated its intent to bring suit against VTC for certain claims asserted by the City under the franchise agreement between the City and VTC. VTC is the general partner of Valero Transmission, L.P. The franchise agreement was assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. In the letter, the City declared a conditional forfeiture of the franchise rights based on the City's claims. In a letter dated October 27, 1993, the City claimed that VTC owes to the City franchise fees and accrued interest thereon aggregating approximately $13.5 million. In a letter dated November 9, 1993, the City claimed an additional $18 million in damages related to the City's allegations that VTC engaged in unauthorized activities under the franchise agreement by transmitting gas for resale and by transporting gas for third parties on the franchised premises. Any liability of VTC with respect to the City's claims has been assumed by the Partnership. The City has not filed a lawsuit.
Take-or-Pay and Related Claims. As a result of past market conditions and contracting practices in the natural gas industry, numerous producers and other suppliers brought claims against Transmission and Vitco asserting breach of contractual provisions requiring that they take, or pay for if not taken, certain volumes of natural gas. The Company and the Partnership have settled substantially all of the significant take-or-pay claims, pricing differences and contractual disputes heretofore brought against them. In 1987, Transmission and a producer from whom Transmission has purchased natural gas entered into an agreement resolving certain take-or-pay issues between the parties in which Transmission agreed to pay one-half of certain excess royalty claims arising after the date of the agreement. The royalty owners of the producer recently completed an audit of the producer and have presented to the producer a claim for additional royalty payments in the amount of approximately $17.3 million, and accrued interest thereon of approximately $19.8 million. Approximately $8 million of the royalty owners' claim accrued after the effective date of the agreement between the producer and Transmission. The producer and Transmission are reviewing the royalty owners' claims. No lawsuit has been filed by the royalty owners. The Company believes that various defenses under the agreement may reduce any liability of Transmission to the producer in this matter.
Although additional claims may arise under older contracts until their expiration or renegotiation, the Company believes that the Partnership and the Company have resolved substantially all of the significant take-or-pay claims that are likely to be made. The Company believes any remaining take-or-pay claims can be resolved on terms satisfactory to the Partnership and the Company. Any liability of Energy, VNGC or VNGC's wholly owned subsidiaries with respect to take-or-pay claims involving Transmission's intrastate pipeline operations has been assumed by the Partnership. If the Partnership were unable or otherwise failed to discharge any liability which it assumed, the Company would remain ultimately liable for such liability.
Conclusion. The Company is also a party to additional claims and legal proceedings arising in the ordinary course of business. The Company believes it is unlikely that the final outcome of any of the claims or proceedings to which the Company is a party including the claims and proceedings described above would have a material adverse effect on the Company's financial position or results of operations; however, due to the inherent uncertainty of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Company's results of operations for the fiscal period in which such resolution occurred. As described above, the Partnership has assumed the obligations and liabilities of the Company with respect to certain claims. If the Partnership were unable or otherwise failed to discharge any such obligation or liability, the Company could remain ultimately liable for the same.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 1993.
PART II
ITEM 5.

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Energy's Common Stock is listed on the New York Stock Exchange, which is the principal trading market for this security. As of February 14, 1994, there were 8,095 holders of record and an estimated 20,000 beneficial owners of Energy's Common Stock.
The range of the high and low sales prices of the Common Stock as quoted in The Wall Street Journal, New York Stock Exchange-Composite Transactions listing, and the amount of per- share dividends for each quarter in the preceding two years, are set forth in the tables shown below:
The Energy Board of Directors declared a quarterly dividend of $.13 per share of Common Stock at its January 20, 1994 meeting. Dividends are considered quarterly by the Energy Board of Directors and are limited by, among other things, the Company's financing agreements. See Note 4 of Notes to Consolidated Financial Statements.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year ended December 31, 1993 is derived from the Company's Consolidated Financial Statements contained elsewhere herein. The selected financial data for the years ended prior to December 31, 1993 is derived from the selected financial data contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1992.
The following summaries are in thousands of dollars except for per share amounts:
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
The following are the Company's financial and operating highlights for each of the three years in the period ended December 31, 1993. The Partnership operating income amounts presented below represent 100% of the Partnership's operating income by segment. The amounts in the following table are in thousands of dollars, unless otherwise noted:
GENERAL
The Company reported net income of $36.4 million or $.82 per share for the year ended December 31, 1993, compared to $83.9 million or $1.94 per share, respectively, for 1992. Operating income was $75.5 million in 1993 compared to $134 million in 1992. For the fourth quarter of 1993, the Company reported a net loss of $15.2 million or $.36 per share compared to net income of $8.2 million or $.18 per share for the same period in 1992. Operating loss was $17.7 million for the fourth quarter of 1993 compared to operating income of $15.9 million for the same period in 1992. The 1993 results were reduced by a $27.6 million, or $17.9 million after-tax, write-down in the carrying value of the Company's refinery inventories during the fourth quarter of 1993 to reflect existing market prices. Also affecting 1993 results compared to 1992 were depressed refining margins and the operation of the butane upgrade facility and other new refinery units discussed below.
Crude oil, refined product prices and refining margins were weak throughout 1993. During the November meeting of the Organization of Petroleum Exporting Countries ("OPEC"), the member countries decided to forego any cuts in production. This decision, combined with increased production from the North Sea region, continued uncertainty regarding Iraq's possible re-entry into world oil markets and weak global demand for energy caused a precipitous drop in crude oil prices to their lowest levels in five years. Refined product prices decreased faster and further than crude oil prices due to continuing high refinery capacity utilization rates and high gasoline inventories. These conditions resulted in a substantial decline in refining margins and the write-down in the carrying value of the Company's refinery inventories. Refined product prices and refining margins have increased modestly since late December. The Company's operating income and net income for the first quarter of 1994, however, are expected to be in the same range as operating income and net income for the fourth quarter of 1993, excluding the effect of the write-down in the carrying value of the Company's refinery inventories.
The following is a discussion of the Company's results of operations first comparing 1993 to 1992 results and then comparing 1992 to 1991 results:
1993 COMPARED TO 1992
Refining Operations
During 1993, the Company's specialized petroleum refinery (the "Refinery") began operation of a butane upgrade facility which converts butane into MTBE, a MTBE/TAME complex and a reformate splitter. See Note 5 of Notes to Consolidated Financial Statements. These projects have increased the Refinery's production capacity to approximately 140,000 barrels per day of refined products.
Refining's operating revenues were $1,044.7 million for the year ended December 31, 1993 compared to $1,056.9 million for 1992. Operating revenues remained level as an 8% decrease in the average sales price per barrel offset an 8% increase in sales volumes. Increased production capacity resulting from operation of the butane upgrade facility contributed to the increase in sales and throughput volumes. Refining's cost of sales increased $42.9 million to $910.2 million in 1993 compared to 1992. Cost of sales increased due to the increase in throughput volumes and the inventory write-down discussed above. Partially offsetting the increase in cost of sales was a decrease in the average feedstock cost per barrel. The average throughput margin per barrel, before operating costs, for 1993 was $5.99 ($5.44, including the effect of the inventory write-down) compared to $7.00 for 1992. Both Refinery operating costs, which are included in cost of sales, and depreciation expense increased for 1993 compared to 1992 due primarily to costs associated with operation of the butane upgrade facility and other new Refinery units. As a result of the above factors, Refining's operating income decreased 45% to $75.4 million.
The Refinery's hydrodesulfurization unit (the "HDS Unit") and heavy oil cracking unit (the "HOC Unit"), collectively the HDS/HOC complex, process high-sulfur atmospheric tower bottoms, a type of residual fuel oil ("resid") which normally sells at a significant discount to crude oil, the conventional feedstock for refineries. The remainder of the Refinery units process crude oil, butanes, and other feedstocks. The Company does not have retailing or crude oil producing operations. Refining's operations and throughput margins continue to benefit from the discount at which resid sells to crude oil. This discount per barrel has averaged $4.43, $4.73 and $4.87 for the years ended December 31, 1993, 1992, and 1991, respectively. The discount at which resid sells to crude oil generally decreases with decreases in crude oil prices due to price competition for resid from natural gas and other markets. However, resid is expected to continue to sell at a discount to crude. The Company believes that the Refinery's ability to process resid, combined with a product slate consisting primarily of unleaded gasoline and related higher value products, positions the Company to effectively compete in the emerging clean fuels marketplace.
Under a feedstock supply agreement with the Company, Saudi Aramco (successor to the Saudi Arabian Marketing and Refining Company "SAMAREC"), has agreed to provide an average of 55,000 barrels per day of resid to the Company at market-related prices. Deliveries under the agreement will continue through 1994 and provide approximately 75% of Refining's resid requirements. During 1993, Refining also purchased approximately 11,000 barrels per day of South Korean resid at market-related prices under an agreement which expires in the first quarter of 1994. The Company is negotiating to renew this agreement for South Korean resid on pricing terms more favorable to the Company than the existing contract. The Company also renewed a contract for approximately 22,000 barrels of crude produced in the People's Republic of China. Although the volume for this contract has been committed to the Company, the price must be renegotiated quarterly. The remainder of the Refinery's feedstocks are purchased at market-related prices under short- term contracts. The Company believes that if any of Refining's existing feedstock arrangements were interrupted, adequate supplies of feedstock could be obtained from other sources or on the open market.
Scheduled maintenance and catalyst changes of the HDS Unit were completed in April 1991, October 1992 and December 1993, and a turnaround of the HOC was completed in November 1991. The HOC is scheduled for a turnaround in late 1994.
Other Operations
The Company's other operations consist of certain minor natural gas pipeline and natural gas distribution operations not transferred to Valero Natural Gas Partners, L.P. ("VNGP, L.P." or the "Partnership") and the natural gas liquids assets ("NGL Assets") acquired from Oryx Energy in May 1992. Also included in other operations are the Company's activities as the General Partner of the Partnership and other miscellaneous revenues. The Company receives a management fee, which is included in operating revenues, equal to the direct and indirect costs incurred by it on behalf of the Partnership.
Operating income from other operations for 1993 increased $3.3 million from the same period in 1992 primarily due to an increase in operating income associated with the NGL Assets attributable to the full period effect of those operations in 1993 and decreased corporate expenses borne by the Company. On September 30, 1993, the Company sold Rio Grande Valley Gas Company ("RGV"), its natural gas distribution subsidiary, for approximately $31 million. The disposition of RGV resulted in an after-tax gain, net of other nonoperating charges, of approximately $5 million.
Partnership Operations
Effective December 20, 1993, Energy, Valero Natural Gas Company and Valero Natural Gas Partners, L.P. entered into an agreement of merger. In the merger, VNGP, L.P. will become a wholly owned subsidiary of Energy, with the public holders of common units receiving cash consideration of $12.10 per common unit, or a total of approximately $117.5 million. Energy has filed a registration statement with the Securities and Exchange Commission (the "Commission") for the issuance of $150 million (up to $172.5 million with underwriters' over-allotments) of convertible preferred stock to finance the merger and to use for general corporate purposes, including the reduction of existing indebtedness under the Company's bank credit agreements. The transaction is subject to approval by the holders of a majority of the issued and outstanding common units, approval by the holders of a majority of the common units held by the public unitholders and voted at a special meeting to be called to consider the merger, receipt of satisfactory waivers, consents or amendments to certain of the Company's financial agreements and completion of the offering of convertible preferred stock discussed above. These financial agreements, which include a new bank credit agreement as well as amendments to other financial agreements, are in the process of being negotiated to provide for the proposed merger. In the event that the proposed merger of VNGP, L.P. with the Company is not ultimately consummated, the proceeds from the offering would be added to the Company's funds and used for general corporate purposes, including the repayment of existing indebtedness, financing of capital projects and additions to working capital. There can be no assurance, however, that the merger can be completed.
The Company believes that the natural gas and natural gas liquids industries are undergoing a period of restructuring and consolidation that may create opportunities for expansions, acquisitions or strategic alliances which, if the Partnership could take advantage of them, could enable the Partnership to compete more effectively in the competitive natural gas environment. Because of the Federal Energy Regulatory Commission's Order No. 636 which requires interstate pipeline companies to offer various services on an unbundled, nondiscriminatory basis, the Company believes that intrastate pipelines such as the Partnership may enjoy increased opportunities to compete for interstate business. In addition, an emerging trend of west-to-east movement of gas across the United States may provide beneficial transportation opportunities for the Partnership if the Partnership were able to make the necessary capital expenditures for added west-to-east capacity on its pipeline system. However, the Partnership's competitive position could be eroded if the Partnership is unable to respond effectively to the changing dynamics of the industry. The merger was proposed because the Company believes that the Partnership has insufficient financial flexibility to participate fully in opportunities that may arise in the natural gas and natural gas liquids ("NGL") industries. The Company believes that the ability of the Partnership to compete effectively in these businesses will be enhanced through the merger. The Company also believes that potential conflicts of interest between the Partnership and the Company can be eliminated through the merger. For additional information regarding the proposed acquisition and pro forma consolidated financial data, see Note 2 of Notes to Consolidated Financial Statements.
During 1993, 1992 and 1991, the Company's equity in earnings of the Partnership contributed $6.8 million, $10.5 million and $15 million, respectively, to the Company's net income. The Company's equity in earnings of the Partnership decreased in 1993 due primarily to a decrease in operating income from the Partnership's NGL operations, partially offset by an increase in operating income from the Partnership's natural gas operations.
The profitability of the Partnership's NGL operations depends principally on the margin between NGL sales prices and the cost of the natural gas from which such liquids are extracted ("shrinkage cost"). Operating income from the Partnership's NGL operations decreased $31.3 million, or 55%, in 1993 compared to 1992 due primarily to a decrease in NGL prices in the last six months of 1993 resulting from continuing high levels of NGL inventories and the significant decline in refined product prices discussed above, combined with an increase in fuel and shrinkage costs resulting from a 22% increase in the cost of natural gas. The decline in NGL prices resulted in a $1.4 million operating loss from NGL operations for the fourth quarter of 1993 compared to operating income of $12.9 million for the fourth quarter of 1992. Also reducing fourth quarter 1993 operating results was an increase in depreciation expense resulting from the recognition in the 1992 period of a change in the estimated useful lives of the majority of the Partnership's NGL facilities from 14 to 20 years retroactive to January 1, 1992.
Operating income from the Partnership's natural gas operations increased $21 million, or 65%, for 1993 compared to 1992 due to a 10% increase in daily natural gas sales volumes and a 12% increase in transportation revenues resulting from continued strong demand for natural gas, certain favorable measurement, fuel usage and customer billing adjustments and an increase in income generated by the Partnership's Market Center Services Program. The Market Center Services Program was established in 1992 to provide price risk management services to gas producers and end users through the use of forward contracts and other tools which have traditionally been used in financial risk management. The Partnership recognized gas cost reductions and other benefits from this program of $18.7 million in 1993, which represents an increase of $5.8 million from 1992. Partially offsetting these increases in natural gas operating income was a decrease in the recovery of Valero Transmission, L.P.'s ("VT, L.P.", a subsidiary operating partnership) fixed costs resulting from the settlement of a customer audit of VT, L.P.'s weighted average cost of gas. For the fourth quarter of 1993, natural gas operating income increased $9.8 million to $15.8 million compared to $6 million in the fourth quarter of 1992 due to the factors noted above.
During the first quarter of 1994, NGL prices have increased modestly since late December 1993, but remain below first quarter 1993 levels. Concurrently, natural gas prices and resulting shrinkage costs have increased during the first quarter of 1994 compared to the same period in 1993. As a result, Partnership operating income and the Company's equity in earnings of the Partnership are expected to be substantially lower in the first quarter of 1994 compared to the fourth quarter of 1993.
Other
Interest and debt expense, net of capitalized interest, increased due to the issuance of medium-term notes in 1992 (see Note 4 of Notes to Consolidated Financial Statements) and decreased capitalized interest primarily due to the placing in service of the butane upgrade facility during the second quarter of 1993.
Income tax expense decreased primarily due to a decrease in pre-tax income. Partially offsetting this was the effect of a federal tax rate increase due to the enactment of the Omnibus Budget Reconciliation Act of 1993, which provides for an increase in the corporate tax rate from 34% to 35%, retroactive to January 1, 1993. As a result of this legislation, the Company recorded a onetime, noncash charge to 1993 third quarter earnings of $8.2 million related to deferred taxes as of the end of 1992.
1992 COMPARED TO 1991
Refining Operations
Refining's operating revenues were $1,056.9 million for the year ended December 31, 1992, which represented a 19% increase over the same period in 1991. The increase in operating revenues was due to a 27% increase in sales volumes as a result of the commencement of operations of the hydrocracker/reformer units (the "H/R Units") during the early part of 1992, partially offset by the effect of a 7% decrease in Refining's average sales price per barrel in 1992. For 1992, Refining's operating income was $137.2 million, which represented a 3% increase over 1991. The average throughput margin for 1992 was $7.00 per barrel compared to $7.31 per barrel for 1991, calculated using total throughput volumes, or $8.84 per barrel for 1991, using only HDS/HOC complex volumes. The decrease in average throughput margin per barrel in 1992 compared to 1991 is primarily due to a decrease in refined product sales prices. Operating income in 1991 also benefitted significantly from a forward sale in 1991 of a significant portion of refined products at the higher prices which prevailed prior to the Arabian Gulf crisis in January 1991.
Other Operations
Operating income from other operations for 1992 increased $11.2 million primarily due to the inclusion of $9.3 million of operating income associated with the NGL Assets.
Partnership Operations
The Company's equity in earnings of the Partnership decreased in 1992 due to a decrease in operating income in both the Partnership's natural gas and NGL operations and a decrease in interest and other income.
Operating income from the Partnership's NGL operations decreased $5.4 million, or 9%, during 1992 compared to 1991 due to a decrease in the average NGL market price, higher shrinkage costs and higher operating expenses. This was partially offset by an increase in production, transportation and fractionation volumes and a decrease in depreciation expense. Operating income from the Partnership's natural gas operations decreased $4.6 million, or 12%, to $32.5 million during 1992 compared to 1991 due to a decrease in natural gas sales volumes, lower average transportation fees and higher operating expenses, primarily due to higher pipeline transportation expense and the charge from the Company for the Partnership's allocable cost of the Company's early retirement program. The decrease in operating income as a result of these factors was partially offset by gas cost reductions and other benefits of $12.9 million from its Market Center Services Program.
Other
The Company's other income, net, decreased during 1992 due to decreased interest income caused by decreased average investments resulting from the gradual utilization of proceeds from the issuance of Energy's 10.58% Senior Notes in December 1990 and January 1991 and lower interest rates. Interest and debt expense, net of capitalized interest, increased due to an increase in interest incurred from substantially higher borrowings outstanding to finance a portion of the Company's capital expenditure program and decreased capitalized interest primarily due to the completion of a major part of the Company's capital expenditure program, the H/R Units, in early 1992, partially offset by interest capitalized on the butane upgrade facility and the Thompsonville gas processing plant (see Notes 2 and 5 of Notes to Consolidated Financial Statements). Income tax expense was relatively unchanged primarily due to Texas franchise taxes, which are based on income, offsetting the effect of reduced income taxes attributable to lower pre-tax income. The reporting of a portion of Texas franchise taxes as part of income tax expense commenced in 1992 as a result of new state legislation enacted during 1991. Preferred stock dividend requirements decreased in 1992 due to the redemption of one-half of the outstanding $68.80 Cumulative Preferred Stock, Series B ("Series B Preferred Stock") in September of 1991 and the remainder in January of 1992. See Note 8 of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
During 1993, net cash provided by the Company's operating activities totalled $141.3 million compared to $152.5 million during 1992. Net cash provided by operating activities includes a $39 million favorable effect in 1993 and a $15.1 million unfavorable effect in 1992 from cyclical changes in current assets and liabilities. These changes for 1993 include a decrease in inventories compared to 1992, attributable to the inventory write-down discussed above. The Company utilized the cash provided by its operating activities, as well as bank borrowings and proceeds from the disposition of RGV (described above), to fund capital expenditures, deferred turnaround and catalyst costs and investments in joint ventures, to pay dividends and to repay principal on outstanding debt.
As described in Note 4 of Notes to Consolidated Financial Statements, during February 1992, Energy filed with the Commission a shelf registration statement to offer up to $150 million principal amount of medium-term notes (the "Medium-Term Notes"), $116 million of which had been issued through January 1994 with a weighted average life of 8.5 years and a weighted average interest rate of 8.56%. During March 1992, the Company issued 2,610,000 shares of Energy common stock ("Common Stock") at a price to the public of $30 per share which generated net proceeds of approximately $75 million.
Refining currently maintains a $160 million revolving credit and letter of credit facility that is available for working capital purposes and matures September 30, 1996. Energy has an unsecured $30 million revolving credit and letter of credit facility which matures February 29, 1996. As of December 31, 1993, Refining and Energy had approximately $52 million and $29 million, respectively, available under their committed bank credit facilities for additional borrowings and letters of credit. Energy also currently has $60 million of unsecured short-term credit lines which are unrestricted as to use, of which no amounts were outstanding at December 31, 1993. Total borrowings under Energy's bank credit facility and short-term lines are limited to $50 million.
Certain of the Company's financing agreements contain various financial ratio requirements, including fixed charge coverage and debt-to-capitalization and require each of the Company and Refining to maintain a minimum consolidated net worth and positive working capital (see Note 4 of Notes to Consolidated Financial Statements). Certain of these financial ratio requirements were amended, effective as of the fourth quarter of 1993, to improve the financial flexibility of the Company. Under the most restrictive of the debt-to-capitalization tests, the Company's indebtedness for borrowed money may not exceed 40% of its capitalization. At December 31, 1993, this ratio, as calculated under the most restrictive of the Company's financing agreements, was 38% and would permit additional borrowings or guarantees of $47 million. Increases or decreases in the Company's stockholders' equity, such as those resulting from incremental earnings or losses, cash dividends, stock issuances, or stock redemptions or repurchases, will disproportionately increase or decrease the amount of additional permitted borrowings or guarantees. As described in Note 4 of Notes to Consolidated Financial Statements, at December 31, 1993, the Company had the ability to pay $47.6 million in Common Stock dividends and other restricted payments under its principal bank credit agreements, which were the most restrictive of its provisions concerning restricted payments.
In September 1991 Energy redeemed one-half, and in November 1991 called for redemption the other one-half, of its Series B Preferred Stock for a total of $42.4 million. In June 1992, the Energy Board of Directors approved a stock repurchase program of up to one million shares of Common Stock. Through December 31, 1993, Energy had repurchased 455,000 shares at an average price of $23.75 per share.
During 1993, the Company incurred $166 million for capital expenditures, deferred turnaround and catalyst costs, investments and related expenditures. Expenditures for 1993 included $149 million for Refinery expenditures, such as the butane upgrade facility, the MTBE/TAME complex, the reformate splitter and the scheduled maintenance and catalyst change for the Refinery's HDS Unit completed in December 1993. Such amounts include $37 million for capital expenditures incurred in 1993, but not payable until 1994. For 1994, the Company currently expects to incur approximately $80 million for capital expenditures, deferred turnaround and catalyst costs, investments and related expenditures. In addition, the Company expects to pay approximately $117.5 million for an effective equity interest of 51% in VNGP, L.P. as discussed above. The Partnership currently expects to incur approximately $40 million in capital expenditures in 1994, much of which would be incurred after the expected merger date. The Company believes it has sufficient funds from operations, the convertible preferred stock offering discussed above, and to the extent necessary, from the public markets and private capital markets, to fund its current and ongoing operating requirements.
The Energy Board of Directors increased the quarterly dividend on its Common Stock from $.11 per share to $.13 per share at its September 1993 meeting, effective in the fourth quarter of 1993. Dividends are considered quarterly by the Energy Board of Directors, and may be paid only when approved by the Board. The Company knows of no reason why Common Stock dividends at the current levels could not be continued.
The Company's refining operations have a concentration of customers in the spot and retail gasoline markets. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, the Company believes that its portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize any potential credit risk. Historically, the Company has not had any significant problems collecting its accounts receivable. The accounts receivable and inventories of Refining are pledged as collateral under Refining's bank credit agreement.
The Company is subject to environmental regulation at both the federal and state level. The Company's expenditures for environmental control and protection for its refining operations are expected to be approximately $6 million in 1994 and totalled approximately $8 million in 1993. These amounts are exclusive of any amounts related to recently constructed facilities for which the portion of expenditures relating to environmental requirements is not determinable. The Refinery was completed in 1984 under more stringent environmental requirements than most existing United States refineries, which are older and were built before such environmental regulations were enacted. As a result, the Company is able to more easily comply with present and future environmental legislation. Under provisions of the Clean Air Act Amendments of 1990 (the "Clean Air Act"), all U.S. refineries must obtain new operating permits by 1995. However, the Clean Air Act is not expected to have any significant adverse impact on the Refinery's operations and the Company does not anticipate that it will be necessary to expend any material amounts in addition to those mentioned herein to comply with such legislation. The Clean Air Act also has requirements for oxygenated gasolines, which add oxygenates such as MTBE and ethanol to the gasoline pool. Such requirements are expected to increase the demand for MTBE. However, recent renewable oxygenate rules proposed under the Clear Air Act may adversely affect the anticipated growth in demand for MTBE. The Company is not aware of any material environmental remediation costs related to its operations. Accordingly, no amount has been accrued for any contingent environmental liability.
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Valero Energy Corporation:
We have audited the accompanying consolidated balance sheets of Valero Energy Corporation (a Delaware corporation) and subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, common stock and other stockholders' equity and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Valero Energy Corporation and subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules V, VI and IX are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
San Antonio, Texas February 17, 1994
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the accounts of Valero Energy Corporation ("Energy") and subsidiaries (collectively referred to herein as the "Company"). All significant intercompany transactions have been eliminated in consolidation. Energy conducts its refining operations through its wholly owned subsidiary, Valero Refining and Marketing Company ("VRMC"), and VRMC's principal operating subsidiary, Valero Refining Company ("VRC") (collectively referred to herein as "Refining"). Certain prior period amounts have been reclassified for comparative purposes.
The Company accounts for its investment in Valero Natural Gas Partners, L.P. ("VNGP, L.P.") and VNGP, L.P.'s consolidated subsidiaries, including Valero Management Partnership, L.P. (the "Management Partnership") and various subsidiary operating partnerships ("Subsidiary Operating Partnerships" or "SOPs") (collectively referred to herein as the "Partnership") on the equity method of accounting. The Partnership acquired substantially all of the Company's natural gas and natural gas liquids operations in March 1987 in exchange for cash and an effective equity interest in the Partnership of approximately 49%. See Note 2 for a further discussion of the Partnership. Income taxes on the Company's equity in earnings of the Partnership are included in the provision for income taxes.
Statements of Cash Flows
In order to determine net cash provided by operating activities, net income has been adjusted by, among other things, changes in current assets and current liabilities, excluding changes in cash and temporary cash investments, current maturities of long-term debt and notes payable. Those changes are shown in the following table as an (increase) decrease in current assets and an increase (decrease) in current liabilities. The Company's temporary cash investments are highly liquid low- risk debt instruments which have a maturity of three months or less when acquired and whose carrying amounts approximate fair value. (Dollars in thousands.)
The following provides information related to cash interest and income taxes paid by the Company for the periods indicated (in thousands):
Noncash investing and financing activities for the years ended December 31, 1993, 1992 and 1991 include reductions of $1.3 million, $1.2 million and $1.1 million, respectively, of the recorded guarantee by Energy of a $15 million long-term borrowing by the Valero Employees' Stock Ownership Plan ("VESOP") to purchase Common Stock. Such reductions were a result of debt service by the VESOP. See Notes 4 and 12. Noncash investing and financing activities for 1993 also include the reclassification to property, plant and equipment of $5 million previously included in deferred charges and other assets on the Consolidated Balance Sheet. Noncash investing activities between Energy and the Partnership include the East Texas pipeline and fractionation facilities leases in 1991 and the Thompsonville Project lease in 1992 (see Note 2). Noncash financing activities for 1991 include a benefit of $.9 million credited to stockholders' equity for stock option exercises and represents the tax effect of the difference between market value at date of grant and market value at date of exercise for all options exercised during the period.
Inventories
Inventories are carried at the lower of cost or market with cost determined primarily under the last-in, first-out ("LIFO") method of inventory costing. Inventories as of December 31, 1993 and December 31, 1992 were as follows (in thousands):
During the fourth quarter of 1993, Refining incurred a charge to earnings of $27.6 million to write down the carrying value of its inventories to reflect existing market prices. As a result of the inventory write-down, the replacement cost of Refining's inventories was approximately equal to its LIFO value at December 31, 1993.
Property, Plant and Equipment
Property additions and betterments include capitalized interest, and acquisition and administrative costs allocable to construction and property purchases.
The costs of minor property units (or components thereof), net of salvage, retired or abandoned are charged or credited to accumulated depreciation. Gains or losses on sales or other dispositions of major units of property are credited or charged to income.
Provision for depreciation of property, plant and equipment is made primarily on a straight-line basis over the estimated useful lives of the depreciable facilities. The rates for depreciation are as follows:
Income Taxes
Effective January 1, 1992, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income Taxes." SFAS No. 109 superseded SFAS No. 96 which the Company had adopted in 1987. These statements established financial accounting and reporting standards for deferred income tax liabilities that arise as a result of differences between the reported amounts of assets and liabilities for financial reporting and income tax purposes.
Deferred Charges
Catalyst and Refinery Turnaround Costs
Catalyst cost is deferred when incurred and amortized over the estimated useful life of that catalyst, normally one to three years. Refinery turnaround costs are deferred when incurred and amortized over that period of time estimated to lapse until the next turnaround occurs.
Other Deferred Charges
Other deferred charges consist of technological royalties and licenses, debt issuance costs, and certain other costs. Technological royalties and licenses are amortized over the estimated useful life of each particular related asset. Debt issuance costs are amortized by the effective interest method over the estimated life of each instrument or facility.
Transactions with Affiliates
Transactions with affiliates primarily represent those conducted with the Partnership. See Note 2.
Price Risk Management Activities
The Company periodically enters into exchange-traded futures and options contracts and forward contracts to hedge against a portion of the price risk associated with price fluctuations from holding inventories of feedstocks and refined products. Changes in the market value of such contracts are accounted for as additions to or reductions in inventory. Gains and losses resulting from changes in the market value of such contracts are recognized when the related inventory is sold. The Company also enters into futures and options contracts that are not specific hedges and gains or losses resulting from changes in the market value of these contracts are recognized in income currently. As of December 31, 1993 and 1992, the Company had outstanding contracts for quantities totalling 2,700 thousand barrels ("Mbbls") and 2,260 Mbbls, respectively, for which the Company is the fixed price payor and 2,615 Mbbls and 1,613 Mbbls, respectively, for which the Company is the fixed price receiver. Such contracts run for a period of approximately two to five months. A portion of such contracts represented hedges of inventory volumes which totalled approximately 8,082 Mbbls and 8,693 Mbbls at December 31, 1993 and 1992, respectively. See "Inventories" above. The Company's activities in both hedging and nonhedging futures and options contracts were not material to the Company's results of operations for the years ended December 31, 1993, 1992 and 1991.
Earnings Per Share
Earnings per share of common stock were computed, after recognition of the preferred stock dividend requirements, based on the weighted average number of common shares outstanding during each year. Potentially dilutive common stock equivalents and other potentially dilutive securities were not material and therefore were not included in the computation. The weighted average number of common shares outstanding for the years ended December 31, 1993, 1992 and 1991 was 43,098,808, 42,577,368, and 40,570,798, respectively.
Accounting Change
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." See Note 12.
Accrued Expenses
Accrued expenses for the periods indicated are as follows (in thousands):
2. VALERO NATURAL GAS PARTNERS, L.P.
The Company holds an effective equity interest of approximately 49% in the Partnership at December 31, 1993, consisting of general partner interests and common units of limited partner interests (the "Common Units"). The remaining equity interest in the Partnership consisting of publicly traded common units of limited partner interests are referred to herein as "Public Units" and holders of such units are referred to as "Public Unitholders."
Components of the line items Investment in and Leases Receivable from Valero Natural Gas Partners, L.P. in the accompanying Consolidated Balance Sheets and Equity in Earnings of and Income from Valero Natural Gas Partners, L.P. in the accompanying Consolidated Statements of Income, are as follows (in thousands):
Summarized financial information for the Partnership for each of the three years in the period ended December 31, 1993 is as follows (in thousands, except per Unit amounts):
The Partnership is required to make quarterly cash distributions with respect to all units in an amount equal to "Distributable Cash Flow" as defined in the Second Amended and Restated Agreement of Limited Partnership of VNGP, L.P. Beginning with the second quarter of 1992, the quarterly cash distributions were reduced from a rate of $.625 per unit to a rate of $.125 per unit. On January 25, 1994, the Board of Directors of VNGC declared a cash distribution of $.125 per unit for the fourth quarter of 1993 that is payable March 1, 1994.
Net income is allocated to partners based on their effective ownership interest in the Partnership, except that additional depreciation expense pertaining to the excess of the Partnership's acquisition cost over the Company's historical cost basis in net property, plant and equipment and certain other assets in which the Public Unitholders currently have an ownership interest is allocated solely to the Public Unitholders as a noncash charge to net income. The allocation of additional depreciation expense to the Public Unitholders does not affect the cash distributions with respect to the Public Units or to the Company as holder of the Common Units.
The Company enters into transactions with the Partnership commensurate with its status as the General Partner. The Company charges the Partnership a management fee equal to the direct and indirect costs incurred by it on behalf of the Partnership that are associated with managing the Partnership's operations. In addition, Refining purchases natural gas and NGLs from the Partnership and sells NGLs to the Partnership. The Company pays the Partnership a fee for operating the Company's NGL Assets. In connection with the NGL Assets, the Company also pays the Partnership a fee to process natural gas, buys natural gas from and sells natural gas and NGLs to the Partnership. The Company's retail natural gas distribution system operated by Rio Grande Valley Gas Company, a wholly owned subsidiary of Energy until its sale on September 30, 1993, purchases natural gas from the Partnership. Also, the Company and the Partnership enter into other operating transactions, including certain leasing transactions which are described below. As of December 31, 1993 and 1992, the Company had recorded approximately $31.8 million and $13.5 million, respectively, of accounts receivables, net of accounts payables, due from the Partnership.
The following table summarizes transactions between the Company and the Partnership for each of the three years in the period ended December 31, 1993 (in thousands):
During 1992, the Partnership entered into a capital lease with Energy to lease a 200-million cubic foot per day turboexpander gas processing plant near Thompsonville in South Texas and 48 miles of NGL product pipeline (the "Thompsonville Project") which were constructed by Energy. The Thompsonville Project lease commenced December 1, 1992 and has a term of 15 years. During 1991, the Company leased its interests in a newly constructed 105-mile pipeline in East Texas (the "East Texas Pipeline") and certain fractionation facilities in Corpus Christi, Texas, to the Partnership under capital leases. The fractionation facility lease, which commenced December 1, 1991, has a term of 15 years. The East Texas Pipeline lease, which commenced February 1, 1991, has a term of 25 years. Future minimum lease payments to be received from the Partnership for the years 1994 through 1998 are $12.9 million, $12.9 million, $13.9 million, $15.1 million and $15.4 million, respectively.
Components of the Company's net investment in these capital leases at December 31, 1993, which is included in Investment in and Leases Receivable from Valero Natural Gas Partners, L.P. in the accompanying Consolidated Balance Sheet, are as follows (in thousands):
Effective December 20, 1993, Energy, Valero Natural Gas Company ("VNGC", a wholly owned subsidiary of Energy and general partner of VNGP, L.P.,) and VNGP, L.P. entered into an agreement of merger. In the merger, the 9.7 million issued and outstanding Public Units will be converted into a right to receive cash consideration of $12.10 per Common Unit, and VNGP, L.P. will become a wholly owned subsidiary of Energy. A special committee of outside directors (the "Special Committee") of VNGC, appointed to consider the fairness of the transaction to the Public Unitholders, has received an opinion from its independent financial advisor that the consideration to be received by the Public Unitholders in the transaction is fair from a financial point of view. The Special Committee has determined that such transaction is fair to, and in the best interest of, the Public Unitholders. The Board of Directors of VNGC has unanimously recommended that the Public Unitholders vote in favor of the merger. The transaction is subject, among other things, to: (i) approval by the holders of a majority of the issued and outstanding Common Units, (ii) approval by the holders of a majority of the Common Units held by the Public Unitholders and voted at a special meeting to be called for the purpose of considering such merger; (iii) receipt of satisfactory waivers, consents or amendments to certain of the Company's financial agreements; and (iv) completion of the offering of convertible preferred stock (see Note 7 of Notes to Consolidated Financial Statements). These financial agreements, which include a new bank credit agreement as well as amendments to other financial agreements, are in the process of being negotiated to provide for the proposed merger. While Energy believes that it will obtain satisfactory new agreements and amendments, there can be no assurance in this regard. The Company currently owns approximately 47.5% of the Common Units and intends to vote such Common Units in favor of the transaction. A proposal to approve the merger agreement will be submitted to the holders of Common Units at a special meeting of unitholders tentatively scheduled to be held during the second quarter of 1994. There can be no assurance, however, that the merger can be completed.
The accompanying unaudited pro forma condensed consolidated financial statements of Valero Energy Corporation and subsidiaries give effect to the sale of $150 million of convertible preferred stock and the utilization of approximately $117.5 million of the net proceeds therefrom to fund the acquisition by the Company of the Public Units. The remaining net proceeds, estimated to be approximately $28.4 million, are used to pay expenses of the proposed acquisition and reduce outstanding indebtedness under bank credit lines. The acquisition is accounted for as a purchase. The pro forma condensed consolidated financial statements are based on the historical consolidated financial statements of Valero Energy Corporation and Valero Natural Gas Partners, L.P. after certain adjustments as described below. The pro forma condensed consolidated balance sheet assumes that the above described transactions occurred on December 31, 1993. The pro forma consolidated statement of income assumes that the above described transactions occurred on January 1, 1993. Following these pro forma financial statements are accompanying explanatory notes. Such pro forma condensed consolidated financial statements are not necessarily indicative of the results of future operations.
[FN] (a) Reflects the elimination of transactions between the Company and VNGP, L.P., including product sales and purchases, management fees billed by the Company to the Partnership for direct and indirect costs, and accrued interest receivable and payable on leases.
(b) Adjustment to fair value of the portion of VNGP, L.P.'s assets acquired and liabilities assumed not currently held by the Company and the related income statement effects. Also included is the elimination of the noncurrent receivable and payable between the Company and VNGP, L.P. for postretirement benefits other than pensions.
(c) Reflects the elimination of the Company's investment in and leases receivable from VNGP, L.P. and related equity in earnings and interest income. The corresponding VNGP, L.P. partners' capital and current and long-term portions of VNGP, L.P.'s capital lease obligations to the Company and related interest expense are also eliminated.
(d) Represents the repayment of $21.7 million of indebtedness under bank credit lines with the excess of the net proceeds of the offering over the acquisition cost of the limited partner interests in VNGP, L.P. not currently held by the Company and the expenses of the acquisition, which causes a decrease in interest expense.
(e) Represents the net proceeds from the sale of $150 million of assumed 6.5% convertible preferred stock and the related increase in preferred stock dividends. The preferred stock is assumed to be convertible into Common Stock at a premium of 25% above a Common Stock market price of $22 per share at the date of issuance of the preferred stock. Conversion of the convertible preferred stock into Common Stock is antidilutive to earnings per share of common stock for the year ended December 31, 1993.
(f) Reflects the tax effects of the consolidation of VNGP, L.P. into the Company, primarily the taxability of VNGP, L.P.'s net income after its merger into the Company.
3. SHORT-TERM BANK LINES
At December 31, 1993, Energy maintained five separate short-term bank lines of credit totalling $60 million, of which no amounts were outstanding. One of these lines is payable on demand, and the others mature at various times in 1994. These short-term lines bear interest at each respective bank's quoted money market rate, have no commitment or other fees or compensating balance requirements and are unsecured and unrestricted as to use. Total borrowings under these short-term lines and Energy's bank credit facility described in Note 4 are limited to $50 million.
4. LONG-TERM DEBT AND BANK CREDIT FACILITIES
Long-term debt balances were as follows (in thousands):
The Company's bank credit agreements include a $160 million revolving credit and letter of credit facility for Refining and a separate unsecured $30 million revolving credit and letter of credit facility for Energy. Borrowings under Refining's agreement bear interest, at Refining's option, at either (i) the agent bank's prime rate, (ii) certain reference banks' adjusted Eurodollar rate plus 3/4 of 1% or (iii) certain reference banks' average CD rate plus 7/8 of 1%. Borrowings under Energy's agreement bear interest, at its option, at either (i) the agent bank's prime rate plus 1/4 of 1%, (ii) certain reference banks' adjusted Eurodollar rate plus 1 3/8% or (iii) certain reference banks' average CD rate plus 1 1/2%. The Company is charged various fees in connection with the bank credit agreements, including commitment fees based on the unused portion of the commitments and various letter of credit and facility fees. As of December 31, 1993, Energy and Refining had approximately $29 million and $52 million, respectively, available under their bank credit facilities for additional borrowings and letters of credit.
Energy filed with the Commission a shelf registration statement that became effective on February 28, 1992, and is being used to offer up to $150 million principal amount of Medium-Term Notes. Through January 1994, the Company has issued, in ten separate series, $116 million principal amount of Medium- Term Notes with a weighted average life of approximately 8.5 years and a weighted average interest rate of approximately 8.56%.
Certain of the Company's financing agreements contain various financial ratio requirements including fixed charge coverage and debt-to-capitalization and require each of the Company and Refining to maintain a minimum consolidated net worth and positive working capital. Certain of these financial ratio requirements were amended, effective as of the fourth quarter of 1993, to improve the financial flexibility of the Company. Under the fixed charge coverage ratio tests in the Company's principal bank credit agreements, the ratio of the Company's earnings to its fixed charges must be at least 2:1 during the most recent four consecutive quarters; however, any fiscal quarter in which one of the Refinery's major units is shut down for scheduled or periodic maintenance for more than 14 days (a "turnaround quarter") is excluded from such fixed charge coverage ratio tests, provided that only one such quarter in each five quarter period may be excluded. In addition, the Company's unsecured $30 million revolving credit and letter of credit facility requires that the Company's ratio of earnings to fixed charges be at least 1.5:1 for each quarter (excluding a turnaround quarter). Under the most restrictive of the debt-to-capitalization tests, the Company's indebtedness for borrowed money may not exceed 40% of its capitalization. At December 31, 1993, this ratio, as calculated under the most restrictive of the Company's financing agreements, was 38%, and would permit additional borrowings or guarantees of $47 million. Increases or decreases in the Company's stockholders' equity, such as those resulting from incremental earnings or losses, cash dividends, stock issuances, or stock redemptions or repurchases, will disproportionately increase or decrease the amount of additional permitted borrowings or guarantees.
The Company's principal bank credit agreements and certain other financing agreements contain covenants limiting Energy's ability to make certain "restricted payments," including dividend payments on and redemptions or repurchases of its capital stock and certain investments. Under its principal bank credit agreements, which currently contain the most restrictive of these covenants, Energy had the ability to pay $47.6 million in Common Stock dividends and other restricted payments at December 31, 1993. Under the Company's bank credit agreements, the amount available for such payments is increased by an amount equal to the Company's earnings, the net cash proceeds from any issuance of capital stock and funded indebtedness, and by an amount equal to the Company's depreciation and amortization expense (including amortization of deferred turnaround and catalyst costs), and is decreased by the amount of capital expenditures, turnaround and catalyst costs, previous dividends, investments (including advances to or assets leased to the Partnership), and repayments of funded indebtedness (other than under the Company's bank credit agreements). Certain of the Company's financing agreements also contain various other covenants, including capital expenditure limitations, limitations on creating liens or guaranteeing the obligations of others, limitations on additional debt and on certain transfers of assets, limitations on entering into new leases, restrictions on mergers or the acquisition of new subsidiaries or the capital stock or assets of other companies, customary default provisions and certain limitations on the businesses of the Company. Under the bank credit agreements, Energy and VRMC have guaranteed the obligations of Refining. The obligations of Refining are secured by a pledge of all inventories and receivables of Refining. The Company and Refining were in compliance with all required covenants as of December 31, 1993.
Based on long-term debt outstanding at December 31, 1993, maturities of long-term debt, including sinking fund requirements and excluding borrowings under bank credit facilities, for the years ending December 31, 1995 through 1998 are approximately $31.9 million, $36.8 million, $37 million and $37.2 million, respectively. Maturities of long-term debt under bank credit facilities for the year ended December 31, 1996 are $75 million, however it is expected that at such time these bank credit facilities will be replaced with new bank credit facilities on similar terms and conditions.
Based on the borrowing rates currently available to the Company for long-term debt with similar terms and average maturities, the fair value of the Company's long-term debt, including current maturities, was $584 million at December 31, 1993. The fair value of the Company's long-term debt was essentially equal to its carrying value at December 31, 1992.
5. INVESTMENTS AND CAPITAL EXPENDITURES
Refinery Projects
During the second quarter of 1993, the Refinery began operation of a butane upgrade facility which converts butane into MTBE, a high-octane blendstock used to manufacture oxygenated and reformulated gasolines. Also, during the fourth quarter of 1993, the Refinery placed in service a MTBE/TAME complex and a reformate splitter. The MTBE/TAME complex converts streams currently produced at the Refinery's heavy oil cracker into MTBE and TAME. TAME, like MTBE, is a high-octane, oxygen-rich gasoline blendstock. The reformate splitter extracts a benzene concentrate stream from the reformate produced at the Refinery's naphtha reformer unit. These projects, which represent investments totalling approximately $300 million, have increased the Refinery's production capacity to approximately 140,000 barrels per day of refined products.
Proesa
The Company holds a 35% interest in a Mexican corporation, Productos Ecologicos, S.A. de C.V. ("Proesa"). Proesa has executed a Memorandum of Understanding with Petroleos Mexicanos ("PEMEX") to construct a MTBE plant in Mexico, and has proposed a butane supply contract and MTBE sales contract with PEMEX. Proesa has also executed an option agreement for a plant site near the Bay of Campeche. The proposed Mexican MTBE plant is expected to have a capacity of approximately 15,000 barrels per day and to be similar to the Refinery's butane upgrade facility. The project is expected to cost approximately $440 million and is subject to, among other things, the arrangement of satisfactory financing. Proesa has been advised by lenders with whom it is negotiating for project financing that certain provisions will be required in the proposed PEMEX contracts in order to secure satisfactory financing for the project. Proesa has entered into negotiations with PEMEX regarding such provisions. However, as a result of delays incurred in completing financing, Proesa has determined that the commencement of plant construction will be delayed. If satisfactory financing is obtained, construction of the MTBE plant could not begin before late 1994, with approximately two years required for completion. As of February 1994, no material amounts have been invested in the project. The amount of the Company's equity contribution will depend upon the level of debt financing obtained by Proesa and the ultimate equity interest of each partner. Under the proposed commercial contracts, PEMEX will purchase approximately 75% of the MTBE plant's production, one- half at a formula price and one-half at market-related prices, with the remainder of the plant's production being sold to the Company at a formula price. In addition, the butane feedstocks required by the plant will be purchased from PEMEX at market- related prices. A subsidiary of Energy has agreed to provide technical advice and assistance to Proesa in connection with the design, engineering, construction and operation of the MTBE plant. There can be no assurance that financing for the project can be obtained or that the plant will be constructed.
Javelina Partnership
Valero Javelina Company, a wholly owned subsidiary of Energy, owns a 20% interest in Javelina Company ("Javelina"), a general partnership. Javelina maintains a term loan agreement and a working capital and letter of credit facility which mature on January 31, 1996. Because the Company accounts for its interest in Javelina on the equity method of accounting, its share of the borrowings outstanding under such bank credit agreements is not recorded on its Consolidated Balance Sheets. The Company's guarantees of these bank credit agreements were approximately $19.6 million at December 31, 1993.
At December 31, 1993, the Company's investment in Javelina included its equity contributions and advances to Javelina of approximately $19.3 million to cover its proportionate share of expenditures in excess of the proceeds available under Javelina's bank credit agreements, and capitalized interest and overhead.
6. REDEEMABLE PREFERRED STOCK
Energy is required to redeem and, commencing in 1986, has redeemed in December of each year its Cumulative Preferred Stock, $8.50 Series A ("Series A Preferred Stock"), at $100 per share at the rate of 11,500 shares annually ($1,150,000 per year). The redemption requirement for the Series A Preferred Stock for each of the five years following December 31, 1993 is also $1,150,000 per year. Energy also has the option to redeem shares of the Series A Preferred Stock at any time at $105.50 per share until November 30, 1994, with such amount being reduced by $.50 per share each year thereafter to $100 per share.
In the event of an involuntary liquidation, the holders of the outstanding Series A Preferred Stock would be entitled, after the payment of all debts, to $100 per share, plus any accrued and unpaid dividends. In the event of a voluntary liquidation, the holders of the outstanding Series A Preferred Stock would be entitled to $100 per share, any applicable premium Energy would have had to pay if it had elected to redeem the Series A Preferred Stock at that time and any accrued and unpaid dividends. In the event dividends on the Series A Preferred Stock are six or more quarters in arrears, holders may vote to elect two directors. No arrearages currently exist.
7. CONVERTIBLE PREFERRED STOCK
On October 18, 1993, Energy filed a registration statement with the Commission covering the offering of 2,500,000 shares of convertible preference stock. Energy intends to file an amended registration statement covering the offering of 3,000,000 shares (up to 3,450,000 shares with underwriters' over- allotments) of convertible preferred stock in March 1994. The proceeds from the offering would be utilized to fund the proposed acquisition of the Partnership (see Note 2).
8. REDEMPTION OF SERIES B PREFERRED STOCK
On September 1, 1991, Energy redeemed one-half of its 1.6 million Depositary Preferred Shares ("Depositary Shares"), each of which represented one-twentieth share of Energy's $68.80 Cumulative Preferred Stock, Series B, at a price of $26.475 per Depositary Share representing a total expenditure of approximately $21.2 million. On November 21, 1991, Energy called the remaining half of the Depositary Shares for redemption on January 15, 1992, also at a price of $26.475 per Depositary Share.
9. PREFERENCE SHARE PURCHASE RIGHTS
On November 15, 1985, Energy's Board of Directors declared a dividend distribution of one Preference Share Purchase Right ("Right") for each outstanding share of Energy's Common Stock. Until exercisable, the Rights are not transferable apart from Energy's Common Stock. Each Right will entitle shareholders to buy one-hundredth (1/100) of a share of a newly issued series of Junior Participating Serial Preference Stock, Series II, at an exercise price of $35 per Right.
10. INDUSTRY SEGMENT INFORMATION
The Company is primarily engaged in the refining and marketing of petroleum products. The Company's primary refining activities involve the operation of its Refinery. Refining sells refined products principally on a spot and truck rack basis. Spot sales of Refining's products are made principally to larger oil companies and gasoline distributors. The principal purchasers of Refining's products from truck racks have been wholesalers and jobbers in the southeastern and midwestern United States. The Company has no foreign operations other than storage facilities and no single customer accounts for more than 10% of its operating revenues.
11. INCOME TAXES
Components of income tax expense attributable to continuing operations are as follows (in thousands):
The Company has credited the tax benefit associated with expenses for certain employee benefits recognized differently for financial reporting and income tax purposes directly to stockholders' equity. Such amounts (in thousands) were $903, $1,758 and $915 for 1993, 1992 and 1991, respectively.
Total income tax expense differs from the amount computed by applying the statutory federal income tax rate to income before income taxes. The reasons for these differences are as follows (in thousands):
The tax effects of significant temporary differences representing deferred income tax assets and liabilities are as follows (in thousands):
At December 31, 1993, the Company had federal net operating loss carryforwards of approximately $7 million, which are available to reduce future federal taxable income and will expire in 1997 if not utilized. In addition, the Company had investment tax credit ("ITC"), Employee Stock Ownership Plan ("ESOP") tax credit and alternative minimum tax credit ("AMT") carryforwards of approximately $71 million which are available to reduce future federal income tax liabilities. The ITC and ESOP tax credits of approximately $55 million expire between 1995 and 2001 if not utilized and the AMT credit of approximately $16 million has no expiration date. The Company did not record any valuation allowances against deferred income tax assets at December 31, 1993.
The Company's federal income tax returns have been examined by the IRS for all taxable years through 1989. All issues were resolved with the exception of one in which the Company has petitioned the Tax Court. A decision from the Tax Court is expected during 1994 . The Company believes that adequate provisions for income taxes have been reflected in its consolidated financial statements.
12. EMPLOYEE BENEFIT PLANS
Pension and Other Employee Benefit Plans
The following table sets forth for the pension plans of the Company, the funded status and amounts recognized in the Company's consolidated financial statements at December 31, 1993 and 1992 (in thousands):
Net periodic pension cost for the years ended December 31, 1993, 1992 and 1991 included the following components (in thousands):
A participant in the Company's pension plan vests in plan benefits after 5 years of vesting service or upon reaching normal retirement date. The pension plan provides a monthly pension payable upon normal retirement of an amount equal to a set formula which is based on the participant's 60 consecutive highest months of compensation during credited service under the plan. The weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.2% and 8.3%, respectively, as of December 31, 1993 and 1992. The rate of increase in future compensation levels used in determining the projected benefit obligation as of December 31, 1993 was 4% for nonexempt personnel and 2% for exempt personnel, while the 1992 projected benefit obligation was based on an assumed overall 6.3% rate of compensation increase. The expected long-term rate of return on plan assets was 9% and 10% as of December 31, 1993 and 1992, respectively. Contributions, when permitted, are actuarially determined in an amount sufficient to fund the currently accruing benefits and amortize any prior service cost over the expected life of the then current work force. The Company also maintains a nonqualified Supplemental Executive Retirement Plan ("SERP") which provides additional pension benefits to the executive officers and certain other employees of the Company. The Company's contributions to the pension plan and SERP in 1993, 1992 and 1991 were approximately $7.5 million, $7.5 million and $8 million, respectively, and are currently estimated to be $5.9 million in 1994. The tables at the beginning of this note include amounts related to the SERP.
The Company is the sponsor of the Valero Energy Corporation Thrift Plan ("Thrift Plan") which is an employee profit sharing plan. Participation in the Thrift Plan is voluntary and is open to employees of the Company who become eligible to participate following the completion of three months of continuous employment. Participating employees may make a base contribution from 2% up to 8% of their annual base salary, depending upon months of contributions by a participant. Prior to the establishment of the VESOP, 100% of these contributions were matched by the Company. Subsequent to the establishment of the VESOP, the Company has made contributions to the Thrift Plan only to the extent employees' base contributions have exceeded the amount of the Company's contribution to the VESOP for debt service. In 1994, the Thrift Plan was amended to provide for a total Company match in both the Thrift Plan and the VESOP aggregating either 75% or 100% of employee base contributions, subject to certain conditions. Participants may also make a supplemental contribution to the Thrift Plan of up to an additional 10% of their annual base salary which is not matched by the Company. Company contributions to the Thrift Plan during 1993, 1992 and 1991 were approximately $660,000, $348,000 and $1,027,000, respectively.
In February 1989, the Company established the VESOP which is a leveraged employee stock ownership plan. Pursuant to a private placement in March 1989, the VESOP issued notes in the principal amount of $15 million, maturing February 15, 1999 (the "VESOP Notes"). The net proceeds from this private placement were used by the VESOP trustee to fund the purchase of Common Stock. The Company makes semi-annual contributions of approximately $1.16 million to the VESOP until maturity to fund the debt service on the VESOP Notes, and, as explained above, the Company's annual contribution to the Thrift Plan during such period is reduced accordingly. During the third quarter of 1991, the Company made an additional loan of $8 million to the VESOP which was also used by the Trustee to purchase Common Stock. This new VESOP loan matures on August 15, 2001. During 1993, the Company contributed $3,596,000 to the VESOP, incurred $947,000 of interest on the VESOP Notes and recognized $2,173,000 of compensation expense. During 1992, the Company contributed $3,596,000 to the VESOP, incurred $1,065,000 of interest on the VESOP Notes and recognized $2,055,000 of compensation expense. Such amounts for 1991 were $2,320,000, $1,172,000 and $1,448,000, respectively. Dividends paid on Common Stock during 1993, 1992 and 1991 have not been used to reduce the VESOP obligation.
In addition to the above plans, the Company also sponsors other employee benefit plans, including the Valero Energy Corporation Employee's Stock Ownership Plan. During the third quarter of 1991, the Company contributed $2.3 million to the ESOP for investment tax credits claimed on Refining's separate 1982 federal income tax return which had not been utilized. The Company also sponsors the Executive Deferred Compensation Plan, the Key Employee Deferred Compensation Plan and the Excess Thrift Plan. At December 31, 1993 and 1992, the amount recorded as deferred compensation on the consolidated balance sheets under these plans was $4.9 million and $4.8 million, respectively.
The Company also provides certain health care and life insurance benefits for retired employees, referred to herein as "postretirement benefits other than pensions." Substantially all of the Company's employees may become eligible for those benefits if, while still working for the Company, they either reach normal retirement age or take early retirement. Health care benefits are provided by the Company through a self-insured plan while life insurance benefits are provided through an insurance company.
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions", which requires a change in the Company's accounting for postretirement benefits other than pensions from a pay-as-you-go basis to an accrual basis of accounting. The Company is amortizing the transition obligation over 20 years, which is greater than the average remaining service period until eligibility of active plan participants. The Company continues to fund its postretirement benefits other than pensions on a pay- as-you-go basis. The adoption of this standard resulted in a decrease to net income in 1993 of $1.7 million, or $.04 per share, after allocation to the Partnership of its pro rata portion of such costs.
The following table sets forth for the Company's postretirement benefits other than pensions, the funded status and amounts recognized in the Company's consolidated financial statements at December 31, 1993 (in thousands):
Net periodic postretirement benefit cost for the year ended December 31, 1993 included the following components (in thousands):
For measurement purposes, the health care cost trend rate was 10% in 1993, decreasing gradually to 5.5% in 1998 and remaining level thereafter. The health care cost trend rate assumption has a significant effect on the amount of the obligation and periodic cost reported. An increase in the assumed health care cost trend rate by 1% in each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $4.7 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $.6 million. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation as of December 31, 1993 was 7.2%.
Prior to 1993, the cost of providing health care and life insurance benefits to retired employees was recognized as expense as health care claims and life insurance premiums were paid. These costs totaled approximately $675,000 and $700,000 for 1992 and 1991, respectively.
Stock Option and Bonus Plans
Energy has three non-qualified stock option plans, Stock Option Plan No. 5, Stock Option Plan No. 4, and Stock Option Plan No. 3, collectively referred to herein as the "Stock Option Plans." The Stock Option Plans provide for the granting of options to purchase shares of Energy's Common Stock. Such options are granted to key officers, employees and prospective employees of the Company. Under the terms of the Stock Option Plans, the exercise price of the options granted will generally not be less than 75% of the fair market value of Common Stock at the date of grant. All stock options granted since 1990 contain exercise prices equal to the market value at the date of grant. Stock options become exercisable pursuant to the individual written agreements between Energy and the participants in the Stock Option Plans, which provide for options becoming exercisable in three equal annual installments beginning one year after the date of grant, with unexercised options expiring ten years from the date of grant. The aggregate difference between the market value of Common Stock at date of grant and the option price is recorded as compensation expense during the exercise period. At December 31, 1993, 1,261,624 options were outstanding, at a weighted-average exercise price of $23.69 per share, of which 357,258 options were exercisable at a weighted- average exercise price of $20.88 per share. During 1993, 597,050 options were granted at a weighted-average exercise price of $23.19, 140,588 options were exercised at a weighted-average exercise price of $10.46 and 53,433 options were terminated and/or forfeited. At December 31, 1993, there were 194,375 shares available for grant under these Stock Option Plans, including shares transferred from previously terminated stock option plans of the Company.
For each share of stock that can be purchased thereunder pursuant to a stock option, Stock Option Plans No. 3 and 4 provide that a stock appreciation right ("SAR") may also be granted. A SAR is a right to receive a cash payment equal to the difference between the fair market value of Energy's Common Stock on the exercise date and the option price of the stock to which the SAR is related. SARs are exercisable only upon the exercise of the related stock options. At the end of each reporting period within the exercise period, Energy records an adjustment to deferred compensation expense based on the difference between the fair market value of Energy's Common Stock at the end of each reporting period and the option price of the stock to which the SAR is related. At December 31, 1993, 139,315 SARs were outstanding, at a weighted-average exercise price of $14.52 per share, of which 138,940 SARs were exercisable at a weighted- average exercise price of $14.52 per share. During 1993, 113,999 SARs were exercised at a weighted-average exercise price of $10.32 per share, and 1,466 SARs were terminated and/or forfeited. Compensation expense recognized during 1993 in connection with the grant of options and SARs under the Company's Stock Option Plans was $110,000.
The Company maintains a Restricted Stock Bonus and Incentive Stock Plan ("Bonus Plan") for certain key executives of the Company. Under the Bonus Plan, 750,000 shares of Common Stock were reserved for issuance. At December 31, 1993, there were 18,927 shares available for award and 77,750 shares awarded under this plan during 1993. The amount of Bonus Stock and terms governing the removal of applicable restrictions, and the amount of Incentive Stock and terms establishing predefined performance objectives and periods, are established pursuant to individual written agreements between Energy and each participant in the Bonus Plan. Compensation expense recognized in connection with the Bonus Plan for 1993 was $570,000. The Company also maintains an executive incentive bonus plan (the "Incentive Plan") for the purpose of providing bonus compensation to key executive and managerial employees. During 1993, bonuses were paid in cash and Common Stock. Compensation expense recognized during 1993 in connection with the Incentive Plan was approximately $2.4 million.
13. DEFERRED CREDITS AND OTHER LIABILITIES
Deferred credits and other liabilities are as follows (in thousands):
Deferred management fees were recorded upon the formation of the Partnership in March 1987 and are being amortized over the ten-year period during which VNGC agreed not to withdraw as General Partner of the Partnership.
14. LEASE AND OTHER COMMITMENTS
The Company has two major operating lease commitments in connection with a gas storage facility leased to the Partnership and its corporate headquarters office complex. The remaining primary lease term for the gas storage facility is six years, while the corporate headquarters lease has a primary term remaining of three years with eight optional renewal periods of five years each. The Company has the right to purchase the office complex at any time after the end of the third renewal period at the then determined fair market value. The Company also has other noncancelable operating leases with remaining terms ranging from one year to 7 years. The related future minimum lease payments as of December 31, 1993 are as follows (in thousands):
The future minimum lease payments listed above under the caption "Other" exclude certain operating lease commitments which are cancelable by the Company upon notice of one year or less. Consolidated rent expense amounted to $12,948,000, $12,643,000, and $11,740,000 for 1993, 1992 and 1991, respectively, and includes various month-to-month and other short-term rentals in addition to rents paid and accrued under long-term lease commitments. A portion of these amounts was charged to and reimbursed by the Partnership for its proportionate use of the Company's corporate headquarters office complex and for the use of certain other properties managed by the Company.
The obligations of Valero Gas Storage Company ("Gas Storage"), a wholly owned subsidiary of VNGC, under the gas storage facility lease include its obligation to make scheduled lease payments and, in the event of a declaration of default and acceleration of the lease obligation, to make certain lump sum payments based on a stipulated loss value for the gas storage facility less the fair market sales price or fair market rental value of the gas storage facility. Under certain circumstances, a default by Energy or a subsidiary of Energy under its bank credit facilities could result in a cross default under the gas storage facility lease. The Company believes that it is unlikely that a default by Energy or a subsidiary of Energy would result in actual acceleration of the gas storage facility lease, and further believes that such event, if it occurred, would not have a material adverse effect on the Company or the Partnership. The obligation of the Company to make certain payments to Gas Storage equal to the amount of Gas Storage's required payments under the gas storage facility lease has been assumed by the Partnership.
15. LITIGATION AND CONTINGENCIES
Partnership Related Claims
In 1987, VT, L.P. and a producer from whom VT, L.P. has purchased natural gas entered into an agreement resolving certain take-or-pay issues between the parties in which VT, L.P. agreed to pay one-half of certain excess royalty claims arising after the date of the agreement. The royalty owners of the producer recently completed an audit of the producer and have presented to the producer a claim for additional royalty payments in the amount of approximately $17.3 million, and accrued interest thereon of approximately $19.8 million. Approximately $8 million of the royalty owners' claim accrued after the effective date of the agreement between the producer and VT, L.P.. The producer and VT, L.P. are reviewing the royalty owners' claims. No lawsuit has been filed by the royalty owners. The Company believes that various defenses under the agreement may reduce any liability of VT, L.P. to the producer in this matter.
Seven lawsuits were filed in Chancery Court in Delaware against VNGP, L.P., VNGC and Energy and certain officers and directors of VNGC and/or Energy in response to the announcement by Energy on October 14, 1993 of its proposal to acquire the publicly traded Common Units of VNGP, L.P. pursuant to a proposed merger of VNGP, L.P. with a wholly owned subsidiary of Energy. See Note 2. The suits were consolidated into a single proceeding by the Chancery Court on November 23, 1993. The plaintiffs sought to enjoin or rescind the proposed merger, alleging that the corporate defendants and the individual defendants, as officers or directors of the corporate defendants, engaged in actions in breach of the defendants' fiduciary duties to the Public Unitholders by proposing the merger. The plaintiffs alternatively sought an increase in the proposed merger consideration, unspecified compensatory damages and attorneys' fees. In December 1993, the parties reached a tentative settlement of the consolidated lawsuit. The terms of the settlement will not require a material payment by the Company or the Partnership. However, there can be no assurance that the settlement will be completed, or that it will be approved by the Chancery Court.
In a letter dated September 1, 1993 from the City of Houston (the "City") to Valero Transmission Company ("VTC"), an indirect wholly owned subsidiary of Energy, the City stated its intent to bring suit against VTC for certain claims asserted by the City under the franchise agreement between the City and VTC. VTC is the general partner of VT, L.P., an indirect subsidiary partnership of VNGP, L.P. The franchise agreement was assigned to and assumed by VT, L.P. upon formation of the Partnership in 1987. In the letter, the City also declared a conditional forfeiture of the franchise rights based on the City's claims. In a letter dated October 27, 1993, the City claimed that VTC owes to the City franchise fees and accrued interest thereon aggregating approximately $13.5 million. In a letter dated November 9, 1993, the City claimed an additional $18 million in damages relating to the City's allegations that VTC engaged in unauthorized activities under the franchise agreement by transmitting gas for resale and by transporting gas for third parties on the franchised premises. The City has not filed a lawsuit. While any liability of VTC with respect to the City's claims has been assumed by the Partnership, if the proposed merger with VNGP, L.P. is consummated, the Company's financial position would necessarily reflect the full amount of any Partnership liability. Additionally, in the event that the Partnership failed to pay any such liability, the Company could remain ultimately responsible. The Company believes that the City's claims are significantly overstated, and that VTC has a number of meritorious defenses to the claims.
VTC and one of its gas suppliers are parties to various gas purchase contracts assigned to and assumed by VT, L.P. upon formation of the Partnership in 1987. The supplier is also a party to a series of gas purchase contracts between the supplier, as buyer, and certain trusts, as seller, which are in litigation. Neither the Partnership nor VTC is a party to this litigation or the contracts between the supplier and the trusts. However, because of the relationship between VTC's contracts with the supplier and the supplier's contracts with the trusts, and in order to resolve existing and potential disputes, the supplier, VTC and VT, L.P. have agreed that they will cooperate in the conduct of this litigation, and that VTC and VT, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against the supplier. In the litigation, the trusts allege that the supplier has breached various minimum take, take-or-pay and other contractual provisions and assert a statutory nonratability claim. The trusts seek alleged actual damages, including interest, of approximately $30 million and an unspecified amount of punitive damages. The District Court ruled on the plaintiff's motion for summary judgment, finding, among other things, that as a matter of law the three gas purchase contracts at issue were fully binding and enforceable, the supplier breached the minimum take obligations under one of the contracts, the supplier is not entitled to claimed offsets for gas purchased by third parties and the "availability" of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, have not been determined. Because of existing contractual obligations of the Partnership to its supplier, the lawsuit may ultimately involve a contingent liability for the Partnership. The Company believes that the claims brought against the supplier have been significantly overstated, and that the supplier has a number of meritorious defenses to the claims, including various regulatory, statutory, contractual and common law defenses. The Court recently granted the supplier's Motion for Continuance of the former January 10, 1994 trial date. This litigation is not currently set for trial.
In March 1993, two indirect wholly owned subsidiaries of Energy serving as general partners of two of the Partnership's principal subsidiary operating partnerships were served as third- party defendants in a lawsuit originally filed in 1991 by a subsidiary of the Coastal Corporation ("Coastal") against TransAmerican Natural Gas Corporation ("TANG"). In August 1993, Energy, VNGP, L.P. and certain of their respective subsidiaries were named as additional third-party defendants (collectively, including the original defendant subsidiaries, the "Valero Defendants") in this lawsuit. In its counterclaims against Coastal and third-party claims against the Valero Defendants, TANG alleges that it contracted to sell natural gas to Coastal at the posted field price of one of the Valero Defendants and that the Valero Defendants and Coastal conspired to set such price at an artificially low level. TANG also alleges that the Valero Defendants and Coastal conspired to cause TANG to deliver unprocessed or "wet" gas thus precluding TANG from extracting NGLs from its gas prior to delivery. TANG seeks actual damages of approximately $50 million, trebling of damages under antitrust claims, punitive damages of $300 million, and attorneys' fees. The Company believes that the plaintiff's claims have been exaggerated, and that it has meritorious defenses to such claims. In the event of an adverse determination involving the Company, the Company likely would seek indemnification from the Partnership under terms of the partnership agreements and other applicable agreements between VNGP, L.P., its subsidiary partnerships and their respective general partners. The Valero Defendants' motion for summary judgment on TANG's antitrust claims was argued on January 24, 1994. The court has not ruled on such motion. The current trial setting for this case is March 14, 1994.
The Company was a party to a lawsuit originally filed in 1988 in which Energy, VTC, VNGP, L.P. and subsidiaries of VNGP, L.P. (the "Valero Defendants") and a subsidiary of Coastal were alleged to be liable for failure to take minimum quantities of gas, failure to make take-or-pay payments and other breach of contract and breach of fiduciary duty claims. The plaintiffs sought declaratory relief, actual damages in excess of $37 million and unspecified punitive damages. During the third quarter of 1992, the plaintiffs, Coastal and the Valero Defendants settled this lawsuit on terms which were not material to the Valero Defendants and on July 19, 1993, this lawsuit was dismissed. On November 16, 1992, prior to entry of the order of dismissal, NationsBank of Texas, N.A., as trustee for certain trusts (the "Intervenors"), filed a plea in intervention to intervene in the lawsuit. The Intervenors asserted that they held a non-participating mineral interest in the lands subject to the litigation and that their rights were not protected by the plaintiffs in the settlement. On February 4, 1993, the Court struck the Intervenors' plea in intervention. However, on February 2, 1993, the Intervenors had filed a separate suit in the 160th State District Court, Dallas County, Texas, against all prior defendants and an additional defendant, substantially adopting in form and substance the allegations and claims in the original litigation. In February 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Company or the Partnership.
The Partnership has settled substantially all of the significant take-or-pay claims, pricing differences and contractual disputes heretofore brought against it. Although additional take-or-pay claims may continue to be brought against the Partnership, the Company believes that the Partnership has resolved substantially all of the significant take-or-pay claims that are likely to be made. Any liability of the Company with respect to these claims has been assumed by the Partnership. No provision has been made with respect to these claims because the Company believes that the Partnership has valid defenses with respect to such claims and because the Company believes that the Partnership will fulfill its obligation to pay any such liability as may ultimately be determined to exist.
The Company and the Partnership believe it is unlikely that the final outcome of any of the claims or proceedings described above would have a material adverse effect on either the Company's or the Partnership's financial position or results of operations; however, due to the inherent uncertainty of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any of these claims or proceedings would not have an adverse effect on either the Company's or the Partnership's results of operations for the fiscal period in which the resolution occurred.
Other Litigation
On August 31, 1993, suit was brought by certain residents of the Oak Park Triangle area of Corpus Christi, Texas, against several defendants including Valero Refining Company. All named defendants are either refiners or gas processors having facilities located at or near Up River Road in Corpus Christi. Plaintiffs allege in general terms damages resulting from ground water contamination and air pollution allegedly caused by the operations of the defendants. Plaintiffs seek unspecified actual and punitive damages. No provision has been made with respect to the claims of the plaintiffs because the Company believes that Valero Refining Company has meritorious defenses to the claims.
Valero Javelina Company, a wholly owned subsidiary of Energy, owns a 20% general partner interest in Javelina Company, a general partnership. See Note 5 of Notes to Consolidated Financial Statements. Javelina Company has been named as a defendant in seven lawsuits filed since 1992 in state district courts in Nueces County, Texas. Four of the suits include as defendants other companies that own refineries or other industrial facilities in Nueces County. These suits were brought by a number of plaintiffs who reside in neighborhoods near the facilities. The plaintiffs claim injuries relating to an alleged exposure to toxic chemicals, and generally claim that the defendants were negligent, grossly negligent and committed trespass. The plaintiffs claim personal injury and property damages resulting from soil and ground water contamination and air pollution allegedly caused by the operations of the defendants. One of the suits seeks certification of the litigation as a class action. The plaintiffs seek unspecified actual and punitive damages. The other three suits were brought by plaintiffs who either live or have businesses near the Javelina Plant. The suits allege claims similar to those described above. These plaintiffs also fail to specify an amount of damages claimed.
The Company is also a party to additional claims and legal proceedings arising in the ordinary course of business. The Company believes it is unlikely that the final outcome of any of the claims or proceedings to which the Company is a party, including those described above, would have a material adverse effect on the Company's financial position or results of operations; however, due to the inherent uncertainty of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Company's results of operations for the fiscal period in which such resolution occurred.
As is described above, the Partnership has assumed the obligations and liabilities of the Company with respect to claims relating to the business or properties transferred by the Company to the Partnership in 1987. If the Partnership were unable or otherwise failed to discharge any such liability of the Company which it assumed, the Company could remain ultimately liable for such liability.
16. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended December 31, 1993 and 1992 were as follows (in thousands of dollars, except per share amounts):
For the fourth quarter of 1993, results of operations were affected by a $27.6 million or $17.9 million after-tax ($.42 per share) write-down in the carrying value of the Company's refinery inventories to reflect existing market prices. This was due to a significant decline in feedstock and refined product prices, which were weak throughout 1993. Also affecting the decrease in the Company's fourth quarter operating and net income compared to the first three quarters of 1993 is the effect of seasonal market conditions on the Company's refining operations. The Company's refinery processes a type of residual fuel oil as a feedstock to produce a product slate consisting primarily of unleaded gasoline. The national demand for and price of gasoline is typically lower in the fourth quarter compared to other quarters due to the lower level of driving during the winter season. Gasoline prices are typically higher during the second and third quarters due to the increased demand related to the summer driving season. In addition, demand for and the price of fuel oils are typically higher in the fourth quarter because of the approaching heating season; these factors tend to adversely affect feedstock costs in the fourth quarter. A typical combination of lower gasoline sales prices and higher feedstock costs decreases refining throughput margins in the fourth quarter. Quarterly results for 1992 were also affected by seasonal market conditions.
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 REGISTRANT), ITEM 11.

ITEM 11. (EXECUTIVE COMPENSATION), ITEM 12.



ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements-
The following Consolidated Financial Statements of Valero Energy Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K:
Page
Report of independent public accountants . . . . . . . . . Consolidated balance sheets as of December 31, 1993 and 1992 . . . . . . . . . . . . . . . . . . . . . . . . Consolidated statements of income for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . Consolidated statements of common stock and other stockholders' equity for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . Consolidated statements of cash flows for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . Notes to consolidated financial statements . . . . . . . .
2. Financial Statement Schedules and Other Financial Information-
(A) Schedules required to be furnished for the years ended December 31, 1993, 1992 and Schedule V-Property, plant and equipment. . . . . . . . . . . . . . . Schedule VI-Accumulated depreciation, depletion and amortization of property, plant and equipment. . . . . Schedule IX-Short-term borrowings. . . .
All other schedules are not submitted because they are not applicable or because the required information is included in the financial statements or notes thereto.
3. Exhibits
Filed as part of this Form 10-K are the following exhibits:
2.1 - Agreement of Merger, dated December 20, 1993, among Valero Energy Corporation, Valero Natural Gas Partners, L.P., Valero Natural Gas Company and Valero Merger Partnership, L.P.-- incorporated by reference from Exhibit 2.1 to Amendment No. 2 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-70454, filed December 29, 1993). 3.1 -- Restated Certificate of Incorporation of Valero Energy Corporation--incorporated by reference from Exhibit 4.1 to the Valero Energy Corporation Registration Statement on Form S-8 (Commission File No. 33-53796, filed October 27, 1992). 3.2 -- By-Laws of Valero Energy Corporation, as amended and restated October 17, 1991--incorporated by reference from Exhibit 4.2 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-45456, filed February 4, 1992). 3.3 -- Amendment to By-Laws of Valero Energy Corporation, as adopted February 25, 1993-- incorporated by reference from Exhibit 3.3 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). 4.1 -- Amended and Restated Rights Agreement, dated as of October 17, 1991, between Valero Energy Corporation and Ameritrust Texas, N.A., successor to Mbank Alamo, N.A., as Rights Agent --incorporated by reference from Exhibit 1 to the Valero Energy Corporation Current Report on Form 8-K (Commission File No. 1- 4718, filed October 18, 1991). 4.2 -- $200,000,000 Senior Notes Purchase Agreement dated as of December 19, 1990--incorporated by reference from Exhibit 4.2 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 21, 1992). 4.3 -- $160,000,000 Amended and Restated Credit Agreement, dated as of December 4, 1992, among Valero Refining Company, Bankers Trust Company, as Agent and certain other banks party thereto--incorporated by reference from Exhibit 4.3 to the Valero Energy Corporation Form 10-K (Commission File No. 1-4718, filed February 26, 1993). 4.4 -- First Amendment to Amended and Restated Credit Agreement, dated as of August 25, 1993-- incorporated by reference from Exhibit 4.5 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-70454, filed October 18, 1993). *4.5 -- Second Amendment to Amended and Restated Credit Agreement, dated as of December 31, 1993. +10.1 -- Valero Energy Corporation Executive Deferred Compensation Plan, amended and restated as of October 21, 1986--incorporated by reference from Exhibit 10.16 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.2 -- Valero Energy Corporation Key Employee Deferred Compensation Plan, amended and restated as of October 21, 1986--incorporated by reference from Exhibit 10.17 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.3 -- Valero Energy Corporation Amended and Restated Restricted Stock Bonus and Incentive Stock Plan dated as of January 24, 1984 (as amended through January 1, 1988)--incorporated by reference from Exhibit 10.19 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.4 -- Valero Energy Corporation Stock Option Plan No. 3, as amended and restated November 28, 1993--incorporated by reference from Exhibit 10.5 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed March 1, 1994). +10.5 -- Valero Energy Corporation Stock Option Plan No. 4, as amended and restated effective November 28, 1993--incorporated by reference from Exhibit 10.6 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed March 1, 1994). +10.6 -- Valero Energy Corporation 1990 Restricted Stock Plan for Non-Employee Directors, dated effective as of November 14, 1990--incorporated by reference from Exhibit 10.23 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1- 4718, filed February 26, 1991). +10.7 -- Valero Energy Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 1990--incorporated by reference from Exhibit 10.24 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1- 4718, filed February 26, 1991). +10.8 -- Valero Energy Corporation Executive Incentive Bonus Plan--incorporated by reference from Exhibit 10.9 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-4718, filed February 20, 1992). +10.9 -- Executive Severance Agreement between Valero Energy Corporation and William E. Greehey, dated December 15, 1982--incorporated by reference from Exhibit 10.11 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). +10.10 -- Schedule of Executive Severance Agreements-- incorporated by reference from Exhibit 10.12 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). +10.11 -- Employment Agreement between Valero Energy Corporation and William E. Greehey, dated May 16, 1990--incorporated by reference from Exhibit 10.1 to the Valero Energy Corporation Quarterly Report on Form 10-Q (Commission File No. 1-4718, filed November 14, 1990). +10.12 -- Indemnity Agreement, dated as of February 24, 1987, between Valero Energy Corporation and William E. Greehey--incorporated by reference from Exhibit 10.16 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). +10.13 -- Schedule of Indemnity Agreements--incorporated by reference from Exhibit 10.17 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). *11 -- Computation of Earnings Per Share. *21.1 -- Valero Energy Corporation subsidiaries, including state or other jurisdiction of incorporation or organization. *23.1 -- Consent of Arthur Andersen & Co., dated March 1, 1994. *24.1 -- Power of Attorney, dated March 1, 1994--set forth at the signatures page of this Form 10-K. *99.1 -- Items 1 through 3 of the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 1993 (Commission File No. 1-9433, filed March 1, 1994). ______________ * Filed herewith + Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.
Copies of exhibits filed as a part of this Form 10-K may be obtained by stockholders of record at a charge of $.15 per page, minimum $5.00 each request. Direct inquiries to Rand C. Schmidt, Corporate Secretary, Valero Energy Corporation, P.O. Box 500, San Antonio, Texas 78292.
Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S- K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the Commission upon its request, copies of certain instruments, each relating to long- term debt not exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.
(b) No reports on Form 8-K were filed during the three- month period ended December 31, 1993.
For the purposes of complying with the rules governing Form S-8 under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into registrant's Registration Statements on Form S-8 No. 2-66297 (filed December 21, 1979), No. 2-82001 (filed February 23, 1983), No. 2-97043 (filed April 15, 1985), No. 33-23103 (filed July 15, 1988), No. 33-14455 (filed May 21, 1987), No. 33-38405 (filed December 3, 1990) and No. 33-53796 (filed October 27, 1992).
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Valero Natural Gas Company as General Partner of Valero Natural Gas Partners, L.P. and to the Common Unitholders:
We have audited the accompanying consolidated balance sheets of Valero Natural Gas Partners, L.P. (a Delaware limited partnership) as of December 31, 1993 and 1992, and the related consolidated statements of income, partners' capital and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Valero Natural Gas Partners, L.P. as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules V, VI and IX are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
San Antonio, Texas February 17, 1994
VALERO NATURAL GAS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Control
Valero Natural Gas Partners, L.P. ("VNGP, L.P."), Valero Management Partnership, L.P. (the "Management Partnership") and various subsidiary operating partnerships (the "Subsidiary Operating Partnerships"), all Delaware limited partnerships, are the successors to substantially all of the natural gas and natural gas liquids businesses, assets and liabilities of substantially all of the subsidiaries of Valero Natural Gas Company ("VNGC") and the transmission division of Rio Grande Valley Gas Company ("Rio"). VNGC is, and Rio at the time of such succession was, a wholly owned subsidiary of Valero Energy Corporation (unless otherwise required by the context, the term "Energy" as used herein refers to Valero Energy Corporation and its consolidated subsidiaries, both individually and collectively). VNGC is the general partner of VNGP, L.P. and the Management Partnership (in such capacity, the "General Partner"), while subsidiaries of VNGC are general partners (the "Subsidiary General Partners") of the respective Subsidiary Operating Partnerships.
In March 1987, VNGP, L.P. sold in an underwritten public offering 9.5 million preference units of limited partner interests (the "Preference Units"), representing a 52% limited partner interest in VNGP, L.P. VNGP, L.P. concurrently issued approximately 8.6 million common units of limited partner interests (the "Common Units"), representing a 47% limited partner interest, to subsidiaries of Energy, and issued a 1% general partner interest in VNGP, L.P. to VNGC. Subsequent to March 1987, VNGP, L.P. issued .4 million additional Common Units to a subsidiary of Energy. In addition, approximately .2 million Common Units held by a subsidiary of Energy were transferred to employees of Energy and converted into Preference Units in connection with an employee benefit plan adopted by Energy. During 1992, all outstanding Preference Units were automatically converted into Common Units (see "Allocation of Net Income and Cash Distributions"). The original Common Units and former Preference Units converted into Common Units are collectively referred to herein as the "Units." Holders of the Units are referred to herein as the "Unitholders."
Under the partnership structure, VNGP, L.P. holds a 99% limited partner interest and VNGC holds a 1% general partner interest in the Management Partnership. The Management Partnership in turn holds a 99% limited partner interest and various wholly owned subsidiaries of VNGC each hold a 1% general partner interest in the various Subsidiary Operating Partnerships to which the acquired businesses, assets and liabilities were transferred. Valero Transmission, L.P. ("Transmission"), one of the Subsidiary Operating Partnerships, owns and operates the principal pipeline system of the Partnership. (References to Transmission prior to March 25, 1987 refer to Valero Transmission Company, a wholly owned subsidiary of VNGC, and after that date to its successor in interest, Valero Transmission, L.P.) Transmission is principally a transporter of natural gas as it transports gas for affiliates and third parties. Transmission also sells natural gas to intrastate customers under long-term contracts; however, most of the Partnership's gas sales are made through other Subsidiary Operating Partnerships which operate special marketing programs ("SMPs"). Subsequent to March 1987, VNGP, L.P. acquired a wholly owned subsidiary that makes certain intrastate gas sales, and formed certain subsidiary partnerships, one of which leases certain assets from Energy under capital leases as described in Note 5. Also, during 1992, an additional Subsidiary Operating Partnership was formed to make certain intrastate gas sales. VNGP, L.P., the Management Partnership, the original Subsidiary Operating Partnerships and the additional entities acquired or formed subsequent to March 1987 are collectively referred to herein as the "Partnership." As of December 31, 1993, Energy's total effective equity interest in the Partnership was approximately 49%.
In October 1993, Energy publicly announced its proposal to acquire the 9.7 million issued and outstanding Common Units in VNGP, L.P. held by persons other than Energy (the "Public Unitholders") pursuant to a merger of VNGP, L.P. with a wholly owned subsidiary of Energy. The Board of Directors of VNGC appointed a special committee of outside directors (the "Special Committee") to consider the merger and to determine the fairness of the transaction to the Public Unitholders. The Special Committee thereafter retained independent financial and legal advisors to assist the Special Committee. Upon the recommendation of the Special Committee, the Board of Directors of VNGC unanimously approved the merger. Effective December 20, 1993, Energy, VNGP, L.P. and VNGC entered into an agreement of merger (the "Merger Agreement") providing for the merger. In the merger, the Common Units held by the Public Unitholders will be converted into the right to receive cash in the amount of $12.10 per Common Unit. As a result of the merger, VNGP, L.P. would become a wholly owned subsidiary of Energy.
Consummation of the merger is subject to, among other things, (i) approval of the Merger Agreement by the holders of a majority of the issued and outstanding Common Units; (ii) approval by the holders of a majority of the Common Units held by the Public Unitholders and voted at a special meeting of holders of Common Units to be called to consider the Merger Agreement; (iii) receipt of satisfactory waivers, consents or amendments to certain of Energy's financial agreements; and (iv) completion of an underwritten public offering of convertible preferred stock by Energy. Energy currently owns approximately 47.5% of the outstanding Common Units and intends to vote its Common Units in favor of the merger.
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles and are not the basis for reporting taxable income to Unitholders. The consolidated financial statements include the accounts of VNGP, L.P. and its consolidated subsidiaries. All significant interpartnership transactions have been eliminated in consolidation.
Statements of Cash Flows
In order to determine net cash provided by operating activities, net income has been adjusted by, among other things, changes in current assets and current liabilities, excluding changes in cash and temporary cash investments, cash held in debt service escrow for principal (see Note 3), and current maturities of long-term debt and capital lease obligations. Those changes, shown as an (increase)/decrease in current assets and an increase/ (decrease) in current liabilities, are provided in the following table. Temporary cash investments are highly liquid low-risk debt instruments which have a maturity of three months or less when acquired and whose carrying amount approximates fair value. (Dollars in thousands.)
Cash interest paid by the Partnership (net of amounts capitalized) for the years ended December 31, 1993, 1992 and 1991 was $62.7 million, $66.4 million and $62.5 million, respectively. No cash payments for federal income taxes were made during these periods as the Partnership is not subject to federal income taxes (see "Income Taxes" below). Cash payments for state income taxes made during these periods were insignificant.
Noncash investing and financing activities for the years ended December 31, 1992 and 1991 included $26 million and $75 million, respectively, of various natural gas and natural gas liquids facilities acquired by the Partnership through capital lease transactions entered into with Energy. See Note 5.
Transactions with Energy
The Partnership enters into various types of transactions with Energy in the normal course of business on market-related terms and conditions. The Partnership is charged a management fee for the direct and indirect costs incurred by Energy on behalf of the Partnership that are associated with managing its operations. The Partnership sells natural gas and natural gas liquids ("NGLs") to, and purchases NGLs from, Energy's refining subsidiary. The Partnership sold natural gas to Energy's retail natural gas distribution business operated by Rio until September 30, 1993, when Rio was sold by Energy. The Partnership operates for a fee two natural gas processing plants and related facilities for Energy and sells natural gas to, purchases natural gas and NGLs from, and processes natural gas owned by Energy in connection with these NGL operations. The Partnership also enters into other operating transactions with Energy, including certain leasing transactions discussed in Note 5. As of December 31, 1993 and 1992, the Partnership had recorded approximately $31.8 million and $13.5 million, respectively, of accounts payable and accrued expenses, net of accounts receivable, due to Energy.
During the fourth quarter of 1992, the Partnership recognized a charge to earnings through the management fee billed by Energy of approximately $4.4 million, or $.23 per limited partner unit, representing the Partnership's allocable portion of the cost of a voluntary early retirement program implemented by Energy.
The following table summarizes transactions between the Partnership and Energy for the years ended December 31, 1993, 1992 and 1991 (in thousands):
The direct and indirect costs incurred by the General Partner on behalf of the Partnership that are charged to the Partnership through the management fee include, among other things, salaries and wages and other employee-related costs. Effective January 1, 1993, Energy adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." This statement requires a change in Energy's accounting for postretirement benefits other than pensions from a pay-as-you-go basis to an accrual basis of accounting. Energy is amortizing the transition obligation over 20 years, which is greater than the average remaining service period until eligibility of active plan participants. As a result of Energy's adoption of this statement, the Partnership's proportionate share of other postretirement employee benefits included in the management fee in 1993 increased by approximately $1.5 million and the Partnership's proportionate share of the total accumulated postretirement benefit obligation at December 31, 1993 was approximately $15 million. The adoption of this statement by Energy did not affect the Partnership's cash flows in 1993, nor is it expected to affect the Partnership's future cash flows, as Energy expects to continue to fund its postretirement benefits other than pensions, and require reimbursement from the Partnership for the Partnership's proportionate share of such funding, on a pay-as-you-go basis.
Gas Sales and Transportation
In the course of making gas sales and providing transportation services to customers, Transmission experiences measurement and other volumetric differences related to the amounts of gas received and delivered. Transmission has in the past experienced overall net volume gains due to such differences and its Rate Order allows such volumes to be sold to its customers. Transmission historically has derived a substantial benefit from such sales. The amount included in operating income in 1993 was substantially the same as in 1992. However, the implementation of more precise gas measurement equipment and standards and the reduction in Transmission's total sales volumes, discussed in Note 6 - "Customer Audit of Transmission", is expected to reduce operating income from such sales in future periods.
Inventories
Inventories are carried principally at weighted average cost not in excess of market. Inventories as of December 31, 1993 and 1992 were as follows (in thousands):
In addition to the above noted natural gas storage inventories, which are located at the Wilson Storage Facility in Wharton County, Texas (see Note 5), the Partnership also had natural gas in third-party storage facilities, available under exchange agreements, totalling $10.8 million and $1.2 million at December 31, 1993 and 1992, respectively. Such amounts are included in receivables in the accompanying consolidated balance sheets.
Property, Plant and Equipment
Property, plant and equipment at date of inception of the Partnership was increased by the excess of the acquisition cost of the holders of the Preference Units over VNGC's historical net cost basis. Accordingly, approximately 51% of property, plant and equipment was recorded at fair value reflecting the value attributable to the holders of the Preference Units while the remaining 49% was recorded at historical net book cost to reflect the value attributable to the General Partner and the holders of the original Common Units.
Property additions and betterments include capitalized interest and acquisition and administrative costs allocable to construction and property purchases. Assets under capital leases are included in property, plant and equipment and are recorded at the lesser of the fair value of the leased property at the inception of the lease or the present value of the related future minimum lease payments.
The costs of minor property units (or components thereof), net of salvage, retired or abandoned are charged or credited to accumulated depreciation. Gains or losses on sales or other dispositions of major units of property are credited or charged to income.
Provision for depreciation of property, plant and equipment is made primarily on a straight-line basis over the estimated useful lives of the depreciable facilities. Assets under capital leases are depreciated on a straight-line basis over the lease term. The rates for depreciation are as follows:
During the fourth quarter of 1992, the Partnership extended the estimated useful lives of the majority of its natural gas liquids facilities from 14 to 20 years to better reflect the estimated periods during which such assets are expected to remain in service. The effect of this change in accounting estimate, which was made retroactive to January 1, 1992, was to decrease depreciation expense and increase net income for 1992 by approximately $5.6 million, or $.29 per limited partner unit.
Other Assets
Payments made or agreed to be made in connection with the settlement of certain disputed contractual issues with gas suppliers of Transmission are initially deferred. The balance of such payments is subsequently reduced as recoveries are made through Transmission's rates. The balance of deferred gas costs of $67 million and $72 million at December 31, 1993 and 1992, respectively, is included in noncurrent other assets and is expected to be recovered over future periods. See Note 6 - "Customer Audit of Transmission."
Debt issuance costs are included in deferred charges and other assets and are amortized by the effective interest method over the term of each respective issue of the Management Partnership's First Mortgage Notes ("First Mortgage Notes"). See Note 3.
Income Taxes
Income and deductions of the Partnership for federal income tax purposes are includable in the tax returns of the individual partners. Accordingly, no recognition has been given to federal income taxes in the accompanying consolidated financial statements of the Partnership. At December 31, 1993 and 1992, the net difference between the tax bases and the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets was $314 million and $322 million, respectively. Under the Revenue Act of 1987, certain publicly traded limited partnerships will be taxed as corporations after December 31, 1997 unless specifically exempted. This Act exempted natural resource partnerships including those dealing with natural gas transportation and processing of natural gas liquids, such as the Partnership, from its taxation provision.
Price Risk Management Activities
The Partnership, through its Market Center Services Program established in 1992, enters into exchange-traded futures and options contracts, forward contracts, swaps and other financial instruments with third parties to hedge natural gas inventories and certain anticipated natural gas purchase requirements in order to minimize the risk of market fluctuations. The Partnership also utilizes such price risk management techniques to provide services to gas producers and end users. Changes in the market value of these contracts are deferred until the gain or loss is recognized on the hedged transaction. As of December 31, 1993 and 1992, the Partnership had outstanding contracts for natural gas totalling approximately 15.0 billion cubic feet ("Bcf") and 4.8 Bcf, respectively, for which the Partnership is the fixed price payor and 27.1 Bcf and 10.0 Bcf, respectively, for which the Partnership is the fixed price receiver. Such contracts run for a period of one to twelve months. A portion of such contracts represented hedges of natural gas volumes in underground storage and in third-party storage facilities which totalled approximately 10.3 Bcf and 7.4 Bcf at December 31, 1993 and 1992, respectively. See "Inventories" above.
In 1993 and 1992, the Partnership recognized $18.7 million and $12.9 million, respectively, in gas cost reductions and other benefits from this program. An additional $5.1 million and $3.6 million in other reductions of cost of gas was generated by transactions entered into in 1993 and 1992, respectively, which is recognized in income in the subsequent year as the related gas is sold.
Allocation of Net Income and Cash Distributions
Net income is allocated to partners based on their effective ownership interest in the operating results of the Partnership, except that additional depreciation expense pertaining to the excess of the Partnership's acquisition cost over the historical cost basis in net property, plant and equipment and certain other assets in which the former holders of Preference Units have an ownership interest is allocated solely to such holders as a noncash charge to net income. The allocation of additional depreciation expense to the former holders of Preference Units does not affect the cash distributions with respect to the Units. Under the Partnership structure, the income of the Subsidiary Operating Partnerships is allocated to the Subsidiary General Partners, which hold a 1% general partner interest, and to the Management Partnership, which holds a 99% limited partner interest. As a result, net income allocable to the Subsidiary General Partners is not reduced by interest expense associated with the Management Partnership's First Mortgage Notes.
The Partnership is required to make quarterly cash distributions with respect to all Units in an amount equal to "Distributable Cash Flow" as defined in the Second Amended and Restated Agreement of Limited Partnership of VNGP, L.P. (the "Partnership Agreement") and as determined by the General Partner. With the payment on May 30, 1992 of the cash distribution of $.625 per Unit for the first quarter of 1992, the Partnership completed the payment of cumulative cash distributions of $12.50 per Preference Unit resulting in the termination of the period (the "Preference Period") during which the holders of Preference Units were entitled to a preferential distribution amount. As a result of the termination of the Preference Period, all outstanding Preference Units were automatically converted into Common Units in accordance with the terms of the Partnership Agreement. The Partnership subsequently reduced cash distributions to $.125 per Unit for the remaining quarters of 1992 and the first three quarters of 1993. On January 25, 1994, the VNGC Board of Directors declared a cash distribution of $.125 per Unit for the fourth quarter of 1993 that is payable March 1, 1994 to holders of record as of February 7, 1994. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of factors that have reduced the amount of cash available for distribution to Unitholders.
If the proposed merger with Energy described above under "Organization and Control" occurs after March 9, 1994, the General Partner intends and expects to declare and pay a pro rata distribution to holders of record of the Common Units on the effective date of the merger based upon the number of days elapsed between February 7, 1994 and such effective date.
2. SHORT-TERM BANK LINES
The Partnership, through the Management Partnership, currently maintains five separate short-term bank lines of credit totalling $80 million. In accordance with the terms of the indenture of mortgage and deed of trust pursuant to which the Management Partnership's First Mortgage Notes were issued (the "Mortgage Note Indenture"), at least $20 million of revolving credit agreements must be maintained at all times; however, no more than $50 million of borrowings are permitted to be outstanding at any time. See Note 3. The Partnership had borrowings of as much as $39.9 million under its short-term bank lines during 1993. No borrowings were outstanding under these lines at December 31, 1993 or 1992. The lines of credit mature at various times during 1994, bear interest at each respective bank's prime, quoted money market or Eurodollar rate and require commitment fees based on the unused amount of the credit. If the proposed merger with Energy does not occur, the General Partner believes that these short-term bank lines could be renewed or replaced with other short-term lines during 1994 on terms and conditions similar to those currently existing. If the proposed merger with Energy is completed, the General Partner anticipates that new bank credit agreements will be negotiated and that the Partnership's existing short-term bank lines will be cancelled.
3. LONG-TERM DEBT
Long-term debt balances were as follows (in thousands):
The First Mortgage Notes, which are currently comprised of eight remaining series due serially from 1994 through 2009, are secured by mortgages on and security interests in substantially all of the currently existing and after-acquired property, plant and equipment of the Management Partnership and each Subsidiary Operating Partnership and by the Management Partnership's limited partner interest in each Subsidiary Operating Partnership (the "Mortgaged Property"). As of December 31, 1993, the First Mortgage Notes have a remaining weighted average life of approximately 7.3 years and a weighted average interest rate of 10.12% per annum. Interest on the First Mortgage Notes is payable semiannually, but one-half of each interest payment and one-fourth of each annual principal payment are escrowed quarterly in advance. At December 31, 1993 and 1992, $34.2 million and $32.9 million, respectively, had been deposited with the Mortgage Note Indenture trustee ("Trustee") in an escrow account. The amount on deposit is classified as a current asset (cash held in debt service escrow) and the liability to be paid off when the cash is released by the Trustee from escrow is classified as a current liability.
The Mortgage Note Indenture contains covenants prohibiting the Management Partnership and the Subsidiary Operating Partnerships (collectively referred to herein as the "Operating Partnerships") from incurring additional indebtedness, including any additional First Mortgage Notes, other than (i) up to $50 million of indebtedness to be incurred for working capital purposes (provided that for a period of 45 consecutive days during each 16 consecutive calendar month period no such indebtedness will be permitted to be outstanding) and (ii) up to the amount of any future capital improvements financed through the issuance of debt or equity by VNGP, L.P. and the contribution of such amounts as additional equity to the Management Partnership. The Mortgage Note Indenture also prohibits the Operating Partnerships from (a) creating new indebtedness unless certain cash flow to debt service requirements are met; (b) creating certain liens; or (c) making cash distributions in any quarter in excess of the cash generated in the prior quarter, less (i) capital expenditures during such prior quarter (other than capital expenditures financed with certain permitted indebtedness), (ii) an amount equal to one-half of the interest to be paid on the First Mortgage Notes on the interest payment date occurring in or next following such prior quarter and (iii) an amount equal to one-quarter of the principal required to be paid on the First Mortgage Notes on the principal payment date occurring in or next following such prior quarter, plus cash which could have been distributed in any prior quarter but which was not distributed. The Operating Partnerships are further prohibited from purchasing or owning any securities of any person or making loans or capital contributions to any person other than investments in the Subsidiary Operating Partnerships, advances and contributions of up to $20 million per year and $100 million in the aggregate to entities engaged in substantially similar business activities as the Operating Partnerships, temporary investments in certain marketable securities and certain other exceptions.
The Mortgage Note Indenture also prohibits the Operating Partnerships from consolidating with or conveying, selling, leasing or otherwise disposing of all or any material portion of their property, assets or business as an entirety to any other person unless the surviving entity meets certain net worth requirements and certain other conditions are met, or from selling or otherwise disposing of any part of the Mortgaged Property, subject to certain exceptions. The Mortgage Note Indenture also provides that it will be an event of default if VNGC withdraws as General Partner of the Management Partnership prior to 1997, if VNGC is removed as General Partner but the Subsidiary General Partners are not also removed, or if the General Partner or any Subsidiary General Partner withdraws or is removed and is not replaced within 30 days.
Maturities of long-term debt for the years ending December 31, 1995 through 1998 are $30.3 million, $32.9 million, $35.3 million and $37.9 million, respectively.
Based on the borrowing rates currently available to the Partnership for long-term debt with similar terms and average maturities, the fair value of the Partnership's First Mortgage Notes, including current maturities, at December 31, 1993 was approximately $562 million. At December 31, 1992, the fair value of the First Mortgage Notes was essentially equal to their carrying value.
4. INDUSTRY SEGMENT INFORMATION
The Partnership operates in the natural gas and natural gas liquids industry segments. The natural gas operations consist of purchasing, gathering, transporting and selling natural gas, principally to gas distribution companies, electric utilities, pipeline companies and industrial customers. The Partnership also transports gas for a fee for sales customers, other pipelines and end users and provides price risk management services to gas producers and end users through its Market Center Services Program. The natural gas liquids operations include the extraction of natural gas liquids, principally from natural gas throughput of the natural gas operations, and the fractionation and transportation of natural gas liquids. The primary markets for sales of natural gas liquids are petrochemical plants, refineries and domestic fuel distributors. Intersegment revenue eliminations relate primarily to transportation provided by the natural gas segment for the natural gas liquids segment. During 1993, natural gas sales and transportation revenues from San Antonio City Public Service accounted for approximately 11% of the Partnership's total consolidated operating revenues. No single unaffiliated customer accounted for more than 10% of the Partnership's total consolidated operating revenues during 1992 or 1991. Energy and its consolidated subsidiaries accounted for approximately 12%, 12% and 11% of the Partnership's total consolidated operating revenues during 1993, 1992 and 1991, respectively.
The Partnership's natural gas segment has a concentration of customers in the natural gas transmission and distribution industries while its natural gas liquids segment has a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, the General Partner believes that the Partnership's portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize any potential credit risk. Historically, the Partnership has not had any significant problems in collecting its accounts receivable. The Partnership's accounts receivable are generally not collateralized.
5. LEASE AND OTHER COMMITMENTS
Valero Gas Storage Company ("Gas Storage"), a wholly owned subsidiary of VNGC, is the lessee under an operating lease for a gas storage facility (the "Wilson Storage Facility"). Gas Storage and Valero Transmission Company had previously entered into a gas storage agreement ("Gas Storage Agreement") which required Valero Transmission Company to pay to Gas Storage amounts essentially equivalent to the lease payments and operating costs in connection with Valero Transmission Company's use of the Wilson Storage Facility. Upon formation of the Partnership, Valero Transmission Company assigned the Gas Storage Agreement to Valero Transmission, L.P., and Valero Transmission, L.P. assumed Valero Transmission Company's obligation to make such payments to Gas Storage. The remaining primary lease term for the Wilson Storage Facility is six years with options to renew at varying terms. The future minimum lease payments related to this lease are included in the table below. The Partnership has other noncancelable operating leases with remaining terms ranging generally from one year to 13 years.
During 1992, the Partnership entered into a capital lease with Energy to lease a gas processing plant near Thompsonville in South Texas and 48 miles of NGL product pipeline (the "Thompsonville Project"). The Thompsonville Project lease commenced December 1, 1992 and has a term of 15 years. During 1991, the Partnership entered into capital leases with Energy to lease an interest in an approximate 105-mile pipeline in East Texas (the "East Texas pipeline") and certain fractionation facilities in Corpus Christi, Texas. The East Texas pipeline lease commenced February 1, 1991 and has a term of 25 years while the lease for the fractionation facilities commenced December 1, 1991 and has a term of 15 years. As a result of the settlement and dismissal in 1992 of certain claims asserted in litigation filed against Energy and certain of its affiliates, officers and directors, Energy agreed to adjust the payments and certain other terms under these capital leases. Such adjusted payments are reflected in the table of future minimum lease payments shown below.
The assets and associated obligations related to the capital leases with Energy described above are not subject to the Mortgage Note Indenture. The Partnership has the right to purchase all or any portion of these assets, subject to certain restrictions, under purchase option provisions of the respective lease agreements. The total cost of these leased facilities, which is included in the accompanying consolidated balance sheets under property, plant and equipment, was approximately $101 million. Amortization of these capital leases, which is included in depreciation expense in the accompanying consolidated income statements, was $5.3 million, $3.5 million and $2.2 million for 1993, 1992 and 1991, respectively.
The related future minimum lease payments under the Partnership's capital leases and noncancelable operating leases as of December 31, 1993 are as follows (in thousands):
The future minimum lease payments listed above under the caption "Partnership Lease Commitments" exclude certain operating lease commitments which are cancelable by the Partnership upon notice of one year or less. Consolidated rent expense was approximately $698,000, $833,000 and $746,000 for the years ended December 31, 1993, 1992 and 1991, respectively, and excludes amounts billed by Energy to the Partnership for its proportionate use of Energy's corporate headquarters office complex and related charges which are included in the management fee charged to the Partnership. See Note 1 - "Transactions with Energy." Rentals paid of $10,438,000 per year for 1993, 1992 and 1991 in connection with the Wilson Storage Facility were included in the computation of Transmission's weighted average cost of gas.
The obligations of Gas Storage under the gas storage facility lease include its obligation to make scheduled lease payments and, in the event of a declaration of default and acceleration of the lease obligation, to make certain lump sum payments based on a stipulated loss value for the gas storage facility less the fair market sales price or fair market rental value of the gas storage facility. Under certain circumstances, a default by Energy or a subsidiary of Energy, including VNGC, with respect to its own indebtedness could result in a cross default under the gas storage facility lease. The General Partner believes that it is unlikely that a default by Energy or a subsidiary of Energy would result in acceleration of the gas storage facility lease, and further believes that such event, if it occurred, would not have a material adverse effect on the Partnership.
6. LITIGATION AND CONTINGENCIES
Take-or-Pay and Related Claims
As a result of past market conditions and contracting practices in the natural gas industry, numerous producers and other suppliers brought claims against Transmission asserting that it was in breach of contractual provisions requiring that it take, or pay for if not taken, certain specified volumes of natural gas. The Partnership has settled substantially all of the significant take-or-pay claims, pricing differences and contractual disputes heretofore brought against it. Although additional claims may arise under older contracts until their expiration or renegotiation, the General Partner believes that the Partnership has resolved substantially all of the significant take-or-pay claims that are likely to be made. As described below, Energy and/or the Partnership have agreed to bear a portion of certain potential liabilities that may be incurred by certain Partnership suppliers. Although the General Partner is currently unable to predict the total amount Transmission or the Partnership ultimately may pay or be required to pay in connection with the resolution of existing and potential take-or- pay claims, the General Partner believes that any remaining claims can be resolved on terms satisfactory to the Partnership and that the resolution of such claims and any potential claims has not had and will not have a material adverse effect on the Partnership's financial position or results of operations.
In 1987, Transmission and a producer from whom Transmission has purchased natural gas entered into an agreement resolving certain take-or-pay issues between the parties in which Transmission agreed to pay one-half of certain excess royalty claims arising after the date of the agreement. The royalty owners of the producer recently completed an audit of the producer and have presented to the producer a claim for additional royalty payments in the amount of approximately $17.3 million, and accrued interest thereon of approximately $19.8 million. Approximately $8 million of the royalty owners' claim accrued after the effective date of the agreement between the producer and Transmission. The producer and Transmission are reviewing the royalty owners' claims. No lawsuit has been filed by the royalty owners. The General Partner believes that various defenses under the agreement may reduce any liability of Transmission to the producer in this matter.
Valero Transmission Company and one of its gas suppliers are parties to various gas purchase contracts assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. The supplier is also a party to a series of gas purchase contracts between the supplier, as buyer, and certain trusts, as seller, which are in litigation. Neither the Partnership nor Valero Transmission Company is a party to this litigation or the contracts between Transmission's supplier and the trusts. However, because of the relationship between Transmission's contracts with the supplier and the supplier's contracts with the trusts, and in order to resolve existing and potential disputes, the supplier, Valero Transmission Company and Valero Transmission, L.P. have agreed that they will cooperate in the conduct of this litigation, and that Valero Transmission Company and Valero Transmission, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against the supplier. In the litigation, the trusts allege that Transmission's supplier has breached various minimum take, take-or-pay and other contractual provisions, and assert a statutory nonratability claim. The trusts seek alleged actual damages, including interest, of approximately $30 million and an unspecified amount of punitive damages. The District Court ruled on the plaintiff's motion for summary judgment, finding, among other things, that as a matter of law the three gas purchase contracts at issue were fully binding and enforceable, the supplier breached the minimum take obligations under one of the contracts, the supplier is not entitled to claimed offsets for gas purchased by third parties and the "availability" of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, have not been determined. Because of existing contractual obligations of Valero Transmission, L.P. to its supplier, the lawsuit may ultimately involve a contingent liability for Valero Transmission, L.P. The General Partner believes that the claims brought against the supplier have been significantly overstated, and that the supplier has a number of meritorious defenses to the claims including various regulatory, statutory, contractual and common law defenses. The Court recently granted the supplier's Motion for Continuance of the former January 10, 1994 trial date. This litigation is not currently set for trial.
Payments that Transmission has made or agreed to make in connection with settlements to date are included in its deferred gas costs. The General Partner believes that the rate order under which Transmission currently operates (the "Rate Order"), issued in 1979 by the Railroad Commission of Texas (the "Railroad Commission," which regulates the sale and transportation of natural gas by intrastate pipeline systems in Texas), allows for the recovery of such costs. See Note 1 - "Other Assets" and "Customer Audit of Transmission" below. Certain take-or-pay and other claims have been resolved through the Partnership agreeing to provide discounted transportation services. These agreements do not involve a cash outlay by the Partnership but in certain cases have the effect of reducing transportation margins over an extended period of time.
Any liability of Energy with respect to take-or-pay claims involving Transmission's intrastate pipeline operations has been assumed by the Partnership. Based upon the General Partner's beliefs and rate considerations discussed above, no liabilities have been recorded for any unresolved take-or-pay claims.
Other Litigation
Seven lawsuits were filed in Chancery Court in Delaware against VNGP, L.P., VNGC and Energy and certain officers and directors of VNGC and/or Energy in response to the announcement by Energy on October 14, 1993 of its proposal to acquire the publicly traded Common Units of VNGP, L.P. pursuant to a proposed merger of VNGP, L.P. with a wholly owned subsidiary of Energy. See Note 1 - "Organization and Control." The suits were consolidated into a single proceeding by the Chancery Court on November 23, 1993. The plaintiffs sought to enjoin or rescind the proposed merger, alleging that the corporate defendants and the individual defendants, as officers or directors of the corporate defendants, engaged in actions in breach of the defendants' fiduciary duties to the Public Unitholders by proposing the merger. The plaintiffs alternatively sought an increase in the proposed merger consideration, unspecified compensatory damages and attorneys' fees. In December 1993, the parties reached a tentative settlement of the consolidated lawsuit. The terms of the settlement will not require a material payment by Energy or the Partnership. However, there can be no assurance that the settlement will be completed, or that it will be approved by the Chancery Court.
In March 1993, two indirect wholly owned subsidiaries of Energy serving as general partners of two of VNGP, L.P.'s principal Subsidiary Operating Partnerships were served as third- party defendants in a lawsuit originally filed in 1991 by a subsidiary of The Coastal Corporation ("Coastal") against TransAmerican Natural Gas Corporation ("TANG"). In August 1993, Energy, VNGP, L.P. and certain of their respective subsidiaries were named as additional third-party defendants (collectively, including the original defendant subsidiaries, the "Valero Defendants") in this lawsuit. In its counterclaims against Coastal and third-party claims against the Valero Defendants, TANG alleges that it contracted to sell natural gas to Coastal at the posted field price of one of the Valero Defendants and that the Valero Defendants and Coastal conspired to set the posted field price at an artificially low level. TANG also alleges that the Valero Defendants and Coastal conspired to cause TANG to deliver unprocessed or "wet" gas, thus precluding TANG from extracting NGLs from its gas prior to delivery. TANG seeks actual damages of approximately $50 million, trebling of damages under antitrust claims, punitive damages of $300 million, and attorneys' fees. The General Partner believes that the plaintiff's claims have been exaggerated, and that Energy and the Partnership have meritorious defenses to such claims. In the event of an adverse determination involving Energy, Energy likely would seek indemnification from the Partnership under terms of the partnership agreements and other applicable agreements between VNGP, L.P., its subsidiary partnerships and their respective general partners. The Valero Defendants' motion for summary judgment on TANG's antitrust claims was argued on January 24, 1994. The court has not ruled on such motion. The current trial setting for this case is March 14, 1994.
In September 1991, a lawsuit was filed by Valero Transmission, L.P. alleging breach of contract against a producer. On January 11, 1993, the defendant filed a cross- action against Valero Transmission, L.P., Valero Industrial Gas, L.P. and Reata Industrial Gas, L.P. The defendant asserted claims for actual damages for failure to pay for goods and services delivered. Additionally, the defendant asserted various other cross-claims, including conversion, breach of contract, breach of an alleged duty to market gas in good faith, tortious breach of a duty imposed by law and tortious negligence. The defendant sought actual damages aggregating not less than $1 million, injunctive relief, attorneys fees and costs, and exemplary damages in the amount of not less than $20 million. In January 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
The Partnership was a party to a lawsuit originally filed in 1988 in which Energy, Valero Transmission Company, VNGP, L.P., the Management Partnership and Valero Transmission, L.P. (the "Valero Defendants") and a subsidiary of Coastal were alleged to be liable for failure to take minimum quantities of gas, failure to make take-or-pay payments and other breach of contract and breach of fiduciary duty claims. The plaintiffs sought declaratory relief, actual damages in excess of $37 million and unspecified punitive damages. During the third quarter of 1992, the plaintiffs, Coastal and the Valero Defendants settled this lawsuit on terms which were not material to the Valero Defendants and on July 19, 1993, this lawsuit was dismissed. On November 16, 1992, prior to entry of the order of dismissal, NationsBank of Texas, N.A., as trustee for certain trusts (the "Intervenors"), filed a plea in intervention to intervene in the lawsuit. The Intervenors asserted that they held a non-participating mineral interest in the lands subject to the litigation and that their rights were not protected by the plaintiffs in the settlement. On February 4, 1993, the Court struck the Intervenors' plea in intervention. However, on February 2, 1993, the Intervenors had filed a separate suit in the 160th State District Court, Dallas County, Texas, against all prior defendants and an additional defendant, substantially adopting in form and substance the allegations and claims in the original litigation. In February 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
City of Houston Franchise Fee Audit
In a letter dated September 1, 1993 from the City of Houston (the "City") to Valero Transmission Company ("VTC"), the City stated its intent to bring suit against VTC for certain claims asserted by the City under the franchise agreement between the City and VTC. VTC is the general partner of Valero Transmission, L.P. The franchise agreement was assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. In the letter, the City declared a conditional forfeiture of the franchise rights based on the City's claims. In a letter dated October 27, 1993, the City claimed that VTC owes to the City franchise fees and accrued interest thereon aggregating approximately $13.5 million. In a letter dated November 9, 1993, the City claimed an additional $18 million in damages related to the City's allegations that VTC engaged in unauthorized activities under the franchise agreement by transmitting gas for resale and by transporting gas for third parties on the franchised premises. The City has not filed a lawsuit. The General Partner believes that the City's claims are significantly overstated and that VTC has a number of meritorious defenses to the claims. Any liability of VTC with respect to the City's claims has been assumed by the Partnership.
Customer Audit of Transmission
Transmission's Rate Order provides for Transmission to sell gas at its weighted average cost of gas, as defined ("WACOG"), plus a margin of $.15 per Mcf. In addition to the cost of gas purchases, Transmission's WACOG has included storage, gathering and other fixed costs totalling approximately $19 million per year, and amortization of deferred gas costs related to the settlement of take-or-pay and related claims (see Note 1 - "Other Assets" and "Take-or-Pay and Related Claims" above). Transmission's gas purchases include high-cost casinghead gas and certain special allowable gas that Transmission is required to purchase contractually and under the Railroad Commission's priority rules. Transmission's sales volumes have been decreasing with the expiration of its sales contracts including the July 1992 expiration of a contract representing approximately 37% of Transmission's sales volumes for the first six months of 1992. As a result of each of these factors, Transmission's WACOG and gas sales price are substantially in excess of market clearing levels.
Transmission's WACOG has been periodically audited by certain of its customers, as allowed under the Rate Order. One such customer (the "Customer") questioned the application of certain of Transmission's current rate policies to future periods in light of the decreases that have occurred in Transmission's throughput, and the Customer has recently completed its audit of Transmission's WACOG with respect thereto. For 1993, the Customer represented approximately 70% of Transmission's sales volumes and such percentage is expected to increase as other sales contracts expire and are not renewed. As a result of the Customer's audit, Transmission and the Customer entered into a settlement agreement which excludes certain of the fixed costs described above from Transmission's WACOG, effective with July 1993 sales, resulting in a reduction of the Partnership's annual net income by approximately $6 million. Upon the termination of Transmission's gas sales contract with the Customer in 1998, Transmission's fixed costs, including storage (see Note 5), would be charged to income instead of recovered through its gas sales rates. Transmission expects to recover its deferred gas costs over a period of approximately eight years. The recovery of any additional payments made in connection with any future settlements would be limited.
The Partnership is also a party to additional claims and legal proceedings arising in the ordinary course of business. The General Partner believes it is unlikely that the final outcome of any of the claims or proceedings to which the Partnership is a party, including those described above, would have a material adverse effect on the Partnership's financial position or results of operations; however, due to the inherent uncertainties of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Partnership's results of operations for the fiscal period in which such resolution occurred.
7. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended December 31, 1993 and 1992 were as follows (in thousands of dollars, except per Unit amounts):
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.
VALERO ENERGY CORPORATION (Registrant)
By /s/ William E. Greehey (William E. Greehey) Chairman of the Board and Chief Executive Officer
Date: March 1, 1994
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints William E. Greehey, Stan L. McLelland and Rand C. Schmidt, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.
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 Title Date
Director, Chairman of the Board and Chief Executive Officer (Principal /s/ William E. Greehey Executive Officer) March 1, 1994 (William E. Greehey)
Senior Vice President and Chief Financial Officer (Principal Financial /s/ Don M. Heep and Accounting Officer) March 1, 1994 (Don M. Heep)
/s/ Edward C. Benninger Director March 1, 1994 (Edward C. Benninger)
/s/ Robert G. Dettmer Director March 1, 1994 (Robert G. Dettmer)
/s/ A. Ray Dudley Director March 1, 1994 (A. Ray Dudley)
/s/ James L. Johnson Director March 1, 1994 (James L. Johnson)
/s/ Lowell H. Lebermann Director March 1, 1994 (Lowell H. Lebermann)
/s/ Sally A. Shelton Director March 1, 1994 (Sally A. Shelton)
Director (Philip K. Verleger, Jr.)