ITEM 1. BUSINESS
Valero Energy Corporation was incorporated in 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. 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, including the Partnership. The term "Partnership" refers collectively to Valero Natural Gas Partners, L.P. ("VNGP, L.P.") and its consolidated subsidiaries. See "Recent Developments - Acquisition of VNGP, L.P."
The Company is a diversified energy company engaged in the production, transportation and marketing of environmentally clean fuels and products. The Company's three core businesses are specialized refining, natural gas and natural gas liquids ("NGL"). The Company owns a specialized petroleum refinery in Corpus Christi, Texas (the "Refinery"), and refines high-sulfur atmospheric residual oil into premium products, primarily reformulated gasoline, and markets those refined products. See "Petroleum Refining and Marketing." The Company also has a network of approximately 8,000 miles of natural gas transmission and gathering lines throughout Texas. The Company purchases natural gas for resale to distribution companies, electric utilities, other pipelines and industrial customers throughout the United States and Mexico, and provides gas transportation services to third parties. See "Natural Gas." The Company also owns 11 natural gas processing plants and is a major producer and marketer of NGLs. See "Natural Gas Liquids."
For 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 a discussion of 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
Acquisition of VNGP, L.P.
Effective May 31, 1994, VNGP, L.P. merged with a wholly owned subsidiary of Energy (the "Merger"). The holders of the common units of limited partner interests of VNGP, L.P. ("Common Units") approved the Merger at a special meeting held at the offices of the Company on May 31, 1994. Upon consummation of the Merger, the publicly traded Common Units were converted into the right to receive cash in the amount of $12.10 per Common Unit. As a result of the Merger, all of the Common Units are owned by the Company. Prior to the Merger, the Company held an approximate 49% effective equity interest in the Partnership. Because of the Merger, the Company changed its method of accounting for its investment in the Partnership from the equity method to the consolidation method as of May 31, 1994. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of Notes to Consolidated Financial Statements. In March 1994, Energy issued 3,450,000 shares of $3.125 convertible preferred stock and received net cash proceeds of approximately $168 million. The Company used approximately $117.5 million of the convertible preferred stock proceeds to acquire the publicly traded Common Units. The remaining proceeds were used to reduce outstanding indebtedness and to pay expenses of the acquisition.
Methanol Plant Joint Venture
On December 1, 1994, Hoechst Celanese Chemical Group, Inc. ("Celanese") and the Company formed a joint venture to renovate and operate a 13,000-barrel-per-day methanol plant owned by Celanese in Clear Lake, Texas. The Company will contribute $75 million to the venture ($15 million of which was paid in 1994), while Celanese will provide the methanol unit and plant infrastructure and serve as operator of the facility. Celanese will refurbish and operate the plant, and each owner will be entitled to one-half of the plant's methanol production. The refurbished plant is expected to be placed in service in the second quarter of 1995. The plant will complement the Company's refining operations by providing the methanol feedstock necessary for the production of oxygenates at the Refinery. Recent market prices for methanol have been substantially in excess of the cost of production. If these higher market prices for methanol continue to prevail, the addition of this facility is expected to improve the Company's overall results of operations. The Company will also supply to the joint venture at least one-half of the natural gas feedstock required for the plant's production of methanol.
Uncertainty in Gasoline Markets
Two programs implemented by the Environmental Protection Agency ("EPA") under the Clean Air Act Amendments of 1990 (the "Clean Air Act") significantly affect the operations of the Company and the markets in which the Company sells its refined products: the oxygenated fuel program and the reformulated gasoline ("RFG") program. The oxygenated fuel program began in 1992, and requires the 39 areas designated nonattainment for carbon monoxide to use gasoline during winter months that contains a prescribed amount of clean burning "oxygenates." Oxygenates are liquid hydrocarbon compounds containing oxygen, which, when added to conventional gasoline, reduce the carbon monoxide emissions of gasoline. In addition, the EPA's RFG program commenced January 1, 1995. The RFG program is required in the nine areas designated nonattainment for ozone. In addition, approximately 43 of the 87 areas that have failed to attain other ozone air-quality standards have also "opted-in" to the RFG program to decrease their emissions of hydrocarbons and toxic pollutants. Use of RFG reduces ozone-forming compounds and total air toxics such as carbon monoxide. The RFG program requires the use of RFG on a year-round basis. RFG is manufactured by removing aromatics and benzene from regular gasoline and adding an oxygenate, primarily MTBE or ethanol. MTBE (methyl tertiary butyl ether) is an oxygen-rich, high-octane gasoline blendstock produced by reacting methanol and isobutylene, and is used to manufacture oxygenated and reformulated gasolines.
The mandated January 1, 1995 transition from conventional gasoline to RFG in many areas of the country caused considerable disarray in gasoline markets beginning in the fourth quarter of 1994, negatively impacting the Company's refining margins. The market instability was generally attributable to uncertainties during the first winter of the RFG program. In December 1994, as the industry prepared for the start-up of the RFG program, certain counties in Pennsylvania, New York and Maine which had formerly "opted-in" to the RFG program announced that they were "opting-out." Based on fears that other areas would create an RFG surplus by following these counties' lead, the market responded with severe declines in RFG and oxygenate prices. The EPA stated that it would allow the "opt- outs" by not enforcing RFG regulations in the "opt-out" areas. The market fears were exacerbated by New Jersey's announcement in early February 1995 of its intent to shorten the duration of its winter oxygenated gasoline programs and to reduce the required oxygen content in its gasoline to 2.0% by weight from 2.7% by March 1, 1995. These uncertainties, together with high refinery run rates and the general assumption that enough RFG exists to satisfy current demand, have kept RFG and oxygenate prices depressed in the spot market and have caused substantial price fluctuations. Depressed RFG prices and the build-up of MTBE inventories during the second half of 1994 also depressed the price of MTBE. In the fourth quarter of 1994, prices for methanol and butane (feedstocks for the manufacture of MTBE) remained strong, resulting in feedstock and manufacturing costs that exceeded the spot value of MTBE. Accordingly, the Company temporarily reduced its MTBE production by 37% in December 1994 (using existing MTBE inventories to satisfy customer needs). In January 1995, the Company's production of MTBE at capacity levels resumed.
Market stability was further delayed because of a request by Wisconsin to halt the use of RFG until April 1, 1995 in its six southeastern counties (which include the greater Milwaukee area, one of the nine U.S. areas designated nonattainment for ozone). In late February 1995, the EPA denied Wisconsin's request. Gasoline markets were cautious pending the EPA's decision, however, because the greater Milwaukee area would have been the first "mandated" (as opposed to "opt-in") area to be excused from full compliance with the RFG program if the EPA had granted the request. The Company believes that as the industry adapts to the RFG program throughout the first quarter of 1995, demand levels and pricing relationships among RFG, methanol and MTBE are likely to become more firmly established. Until the desired market stability is achieved, however, the Company remains unable to predict the future profitability of its RFG operations.
Finally, future demand for MTBE may be adversely affected by the renewable oxygenate regulations promulgated by the EPA under the Clean Air Act in June 1994. These regulations require that at least 15% of the oxygenates used in RFG in 1995 originate from renewable sources, primarily ethanol. The 15% requirement increases to 30% in 1996 and beyond. The American Petroleum Institute and the National Petroleum Refiners Association challenged in federal court the EPA's authority to promulgate the renewable oxygenate regulation. In September 1994, the United States Court of Appeals for the District of Columbia Circuit granted a motion to stay implementation of the regulations until the date of the court's ultimate ruling in the lawsuit. The court is not expected to rule on the matter until sometime during the second or third quarter of 1995.
Proesa MTBE Plant
The Company currently owns a 35% interest in Productos Ecologicos, S.A. de C.V., a Mexican corporation ("Proesa"), which is involved in a project (the "Project") to design, construct and operate a plant (the "Plant") in Mexico to produce MTBE. Proesa is also owned 10% by Dragados y Construcciones, S.A., a Spanish construction company ("Dragados"), and 55% by a corporation formed by a subsidiary of Banamex, Mexico's largest bank ("Banamex"), and Infomin, S.A. de C.V., a privately owned Mexican corporation ("Infomin"). The Company, Infomin, Banamex and Dragados have entered into a letter of understanding under which the interest of Banamex in Proesa would be acquired by the Company and Infomin at Banamex's investment cost, plus accrued interest, with the Company and Infomin each then owning a 45% interest in Proesa. This arrangement has not been formally documented and is subject to successfully obtaining financing for Infomin's interest in the Project. However, since August 1994, the Company has funded 45% of the Project's costs. The Plant, to be constructed at a site near the Bay of Campeche, has been estimated to cost approximately $450 million, and to produce approximately 17,000 barrels of MTBE per stream day (based on an estimated 346 stream days per year).
Proesa has entered into license agreements with a third party relating to processes to be utilized in the Plant. Proesa's obligation under the license agreements is approximately $45 million, and Proesa's minimum obligation, if such license agreements were canceled, would be approximately $7 million at January 31, 1995. Under an existing MTBE sales agreement between Proesa and a subsidiary of Petroleos Mexicanos, S.A., the Mexican state-owned oil company ("Pemex"), Proesa has furnished a surety bond equal to 10% of the estimated value of MTBE to be delivered to Pemex during the Plant's first year of operations. Pemex may call for payment under the surety bond in the event that deliveries of MTBE are not made to Pemex as specified in the agreement. Under current market conditions, however, the Company believes that Proesa would be able to supply Pemex with the requisite quantities of MTBE even if the Plant were not ultimately built. The surety bond has an insurable value of 41.3 million New Pesos which, based on the exchange rate at February 23, 1995, was approximately $7.4 million. The Company has agreed to guarantee 45% of Proesa's obligations to the surety company under this arrangement but this agreement has not been formally documented. Proesa has no independent source of funding. Therefore, in the event of any cash requirements to fund payments under the license agreements, surety bond, or other operating needs, Proesa necessarily would request additional funding from its owners.
Beginning in December 1994, the Mexican peso experienced substantial devaluation as the exchange rate deteriorated from approximately 3.4 New Pesos per $1 U.S. to approximately 5.6 New Pesos per $1 U.S. at February 23, 1995. This instability caused interest rates in Mexico to increase significantly and the Mexican stock market to experience a substantial decline in market value. As a result of the current Mexican economic conditions, as well as other factors, the Company cannot currently determine if Infomin can fund its pro rata share of Project costs. Infomin has indicated to the Company that it is interested in reducing its interest in Proesa. However, the Company is not willing to increase its interest in Proesa, and believes that the willingness of Dragados or third parties to take additional shares in Proesa is limited. In addition, current operating margins for MTBE are considerably lower than when the Project was conceived.
Based on the foregoing factors, in January 1995 the Board of Directors of Energy determined that the Company would suspend further investment in the Project pending resolution of key issues related to the Project. In particular, the Board has required the renegotiation of purchase and sales agreements between Proesa and Pemex, the implementation of certain additional agreements with Pemex, and a reevaluation of the economics of the Project. Additionally, the Board has required that the Project participants reach definitive agreement regarding their ownership interests in Proesa and their funding commitments to the Project, including procedures for funding any possible cost overruns.
The Company has begun negotiations with Pemex and the Project participants to address the issues identified by the Board of Directors of Energy. If the foregoing matters can be satisfactorily resolved, the Company intends to proceed with the Project. However, there can be no assurance that mutually satisfactory agreements can be reached between Proesa and Pemex or among the Project participants. At December 31, 1994, the Company had invested approximately $13.4 million in the Project. See Note 6 of Notes to Consolidated Financial Statements. The Company estimates that if the Project is delayed and further expenditures are reduced to the minimum practicable level until resolution of the issues mentioned above, the Company will have a total investment in the Project of approximately $18 million at the end of the first quarter of 1995, excluding any funding that may be required with respect to the surety bond discussed above.
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 RFG and middle distillates. The Refinery also processes crude oil, butanes and other feedstocks. The Refinery can produce over 150,000 barrels per day of refined products, with gasoline and gasoline blendstocks comprising approximately 85% of the Refinery's throughput, and middle distillates comprising the remainder. The Refinery can produce all of its gasoline as RFG and all of its diesel fuel as low-sulfur diesel. The Refinery has substantial flexibility to vary its mix of gasoline products to meet changing market conditions. For additional information regarding the refining and marketing operating results of the Company for the three years ended December 31, 1994, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
The Refinery's principal operating units include its hydrodesulfurization unit ("HDS Unit") and heavy oil cracking complex ("HOC"). The HDS Unit removes sulfur and metals from resid to improve resid's subsequent cracking characteristics. The HDS Unit has a capacity of approximately 66,000 barrels per day. The HOC processes feedstock primarily from the HDS Unit, and has a capacity of approximately 70,000 barrels per day. The "MTBE Plant" can produce 15,500 barrels per day of MTBE from butane and methanol feedstocks. The Company can blend the MTBE produced at the Refinery into the Company's own gasoline cargos or sell the MTBE separately. The "HOC MTBE/TAME Unit" converts streams produced at the HOC 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 an oxygen-rich, high-octane gasoline blendstock. The MTBE Plant and HOC MTBE/TAME Unit enable the Company to produce approximately 21,000 barrels per day of MTBE and other oxygenates. All the butane feedstocks required to operate the MTBE Plant are available through the Company's operations. All the methanol feedstocks required for the production of oxygenates at the Refinery are expected to be provided by the methanol plant joint venture beginning in the second quarter of 1995. See "Recent Developments - Methanol Plant Joint Venture."
The Refinery's other significant units include a 34,000 barrel per day "Hydrocracker" (which produces reformer feed naphtha from the Refinery's gas oil and distillate streams), a 34,000 barrel per day continuous catalyst regeneration "Reformer" (which produces reformate, a low vapor pressure high- octane gasoline blendstock, from the Refinery's naphtha streams), a 25,000 barrel per day reformate splitter (which extracts a benzene concentrate stream from reformate produced at the Reformer), a 30,000 barrel per day crude unit, and a 23,000 barrel per day vacuum unit. An application to repermit the entire Refinery was submitted in 1994 to enable the Refinery to operate at even higher throughput rates.
In 1994, the Company added a marine vapor recovery unit at the Refinery. The unit enhances air quality by capturing and recycling vapors that are displaced when gasoline is loaded onto ships and barges. The retrieved vapors are condensed and blended back into gasoline. Approximately two gallons of gasoline are recovered for every 1,000 gallons loaded onto ship or barge. The Company also constructed an environmentally friendly bio-slurry reactor process at the Refinery which uses microorganisms to biodegrade and treat solid waste.
The HOC was down in the fall of 1994 for a scheduled turnaround completed in October. Improvements made during the downtime increased the HOC's capacity by approximately 4,000 barrels per day and improved its product yields. The MTBE Plant was down in November 1994 to correct certain mechanical problems. The Refinery's other principal refining units operated during 1994 without significant unscheduled downtime. The HDS Unit is scheduled to be down beginning in the first quarter of 1995 for maintenance and a catalyst change. This maintenance and catalyst change is required about every 15 months. Also, the Hydrocracker and the Reformer are scheduled for turnarounds beginning in the first quarter of 1995. Other than the HDS Unit, most of the principal refining units are required to undergo maintenance turnarounds every three years.
The Company 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. The Company has approximately 850,000 barrels of fuel oil storage available under lease in Malta, and leases refined product storage facilities in various locations. See Note 13 of Notes to Consolidated Financial Statements. The Company also owns dock facilities that can unload simultaneously two 150,000 dead weight ton capacity ships and can dock larger crude carriers after partial unloading.
Through a wholly owned subsidiary, the Company is a 20% general partner in Javelina Company ("Javelina"), which owns a plant in Corpus Christi (the "Javelina Plant") that processes waste gases from the Refinery and other refineries in the Corpus Christi area, and extracts hydrogen, ethylene, propylene and NGLs from the gas stream. The Company has made capital contributions and advances to Javelina of approximately $20.2 million (including capitalized interest and overhead) through December 31, 1994, 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 that mature on January 31, 1996. The Company's guarantees of these bank credit agreements were approximately $16.3 million at December 31, 1994.
Sales
Set forth below is a summary of refining and marketing throughput volumes per day, average throughput margin per barrel and sales volumes per day for the three years ended December 31, 1994. 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 volumes.
The Company has historically sold refined products on a spot and truck rack basis, but has recently begun selling refined products under term contracts as well. A truck rack sale is a sale to a customer that provides trucks to take delivery at loading facilities. In 1994, spot and truck rack sales volumes accounted for 87% and 13%, respectively, of combined gasoline and distillate sales. Spot sales of the Company's refined products are made to large oil companies and gasoline distributors. The principal purchasers of the Company's products from truck racks have been wholesalers and jobbers in the eastern and midwestern United States. The Company's products are transported through common-carrier pipelines, barges and tankers. Interconnects with common-carrier pipelines give the Company the flexibility to sell products to the midwestern or southeastern United States.
Sales of refined products under term contracts are made principally to large oil companies. The Company recently implemented a new marketing strategy to capitalize on the emerging RFG and oxygenates markets. Approximately 50% of the Company's 1995 RFG production is already under contract to supply major gasoline marketers in the Houston and Dallas/Fort Worth areas at market-related prices. In 1994, the Company also appointed an exclusive agent for a three-year term for the wholesale truck rack marketing of the Company's refined products in the northeast United States. In addition, the Company has contracted for two tankers to transport RFG to the Northeast. The Northeast is currently the largest RFG market in the United States.
Resid 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 end-products. Many overseas refineries, however, are less sophisticated, process smaller portions of resid internally, and therefore produce larger volumes of resid for sale. As a result, the Company acquires and expects to acquire most of its resid in international markets. A substantial portion of the Company's resid supplies are obtained from the Middle East. These supplies are loaded aboard chartered vessels at ports in the Arabian Gulf and are subject to the usual maritime hazards. The Company maintains insurance on its feedstock cargos.
Under a feedstock supply agreement with the Company renewed in late 1994, Arabian American Oil Company ("Aramco") has agreed to provide an average of 36,000 barrels per day of resid to the Company at market-based prices. Resid delivery levels were approximately 55,000 barrels per day under the prior arrangement. Deliveries under the new agreement will continue through 1996 and provide approximately 45% of the Company's resid requirements. This contract is subject to possible price renegotiation at the end of the first year, with offtake volumes being subject to possible reduction if agreement is not reached. During 1994, the Company also purchased approximately 11,000 barrels per day of South Korean resid at market-based prices under an agreement that expired in the first quarter of 1995. The South Korean contract was renewed for an additional year for 11,000 barrels per day of resid to be purchased by the Company at market-based prices. The Company believes that if either of the existing feedstock arrangements were interrupted or terminated, supplies of resid could be obtained from other sources or on the open market. However, over the past year, demand for the type of resid feedstock now processed at the Refinery has increased in relation to the availability of supply. See "Petroleum Refining and Marketing - Factors Affecting Operating Results." Accordingly, if either arrangement were to terminate, the Company could be required to incur higher feedstock costs or substitute other types of resid, thereby producing less favorable operating results. The remainder of the Refinery's resid feedstocks are purchased at market-based prices under short-term contracts.
Factors Affecting Operating Results
The Company's refining and marketing operating results are determined principally by the relationship between refined product prices and resid prices, which in turn are largely determined by market forces. The crude oil and refined product markets typically experience periods of extreme price volatility. During such periods, disproportionate changes in the prices of refined products and resid usually occur. The potential impact of changing crude oil and refined product prices on the Company's results of operations is further affected by the fact that the Company generally buys its resid feedstock approximately 45 to 50 days prior to processing it in the Refinery. The Company uses its price risk management activities to hedge various portions of its refining operations. See Note 5 of Notes to Consolidated Financial Statements. Because the Refinery is technically more sophisticated and complex than many conventional refineries, and is designed principally to process resid rather than crude oil, its operating costs per barrel are necessarily higher than those of most conventional refineries. However, resid usually sells at a discount to crude oil ("resid discount") sufficient to enable the Company to recover its higher operating costs and generate higher margins in its refining operations than conventional refiners that use crude oil as the principal feedstock. The price of resid is affected by 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).
In 1994, the resid discount was reduced by over $2.50 per barrel in the spot market. This change in the resid discount impacted the Company's market-related term feedstock arrangements, although by an amount less than the spot market decline. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - 1994 Compared to 1993 - Segment Results - Refining and Marketing." Several factors contributed to the recent narrowing of the resid discount including a shift in Saudi Arabia's production to lighter grades of crude instead of heavy sour types that yield more resid, and decreased exports of resid from the former Soviet Union. Refinery upgrades in recent years also have curtailed the output of resid in favor of the production of lighter end-products such as gasoline and diesel fuel. Moreover, unusually hot weather in Japan in 1994 boosted that country's demand for resid for power generation. The Company expects resid to continue to sell at a discount to crude oil, but is unable to predict future relationships between the supply of and demand for resid. Installation of additional refinery upgrading facilities, price volatility, international political developments and other factors beyond the control of the Company are likely to continue to play an important role in refining industry economics.
The Company expects the global demand for gasoline to continue to increase along with the general growth in economic activity worldwide. Most of this demand growth is expected to occur outside the United States. With the increase in upgrading capacity in 1994, combined with new upgrading capacity planned in 1995, it is expected that the supply of gasoline will be adequate to meet all of the demand increase. This upgrading capacity is expected to reduce resid output further. Therefore, the Company believes that the resid discount will remain tight through 1995.
Although domestic gasoline production will continue to be supplemented significantly with foreign imports, the Company believes that the availability of foreign gasoline supplies for import into the United States may be reduced because of the implementation of the RFG program in this country. For a further discussion of the Clean Air Act and its impact on the refining industry, see "Recent Developments - Uncertainty in Gasoline Markets" and "Environmental Matters."
NATURAL GAS
The Company owns and operates natural gas pipeline systems principally serving Texas intrastate markets. The Company also markets natural gas throughout the United States through interconnections with interstate pipelines. The Company's natural gas pipeline and marketing operations consist principally of purchasing, gathering, transporting and selling natural gas to gas distribution companies, electric utilities, other pipeline companies and industrial customers, and transporting natural gas for producers, other pipelines and end users. The Company's natural gas operations consist primarily of the natural gas operations conducted through the Partnership which were acquired in connection with the Merger described above (see "Recent Developments - Acquisition of VNGP, L.P."). In addition, the Company's natural gas operations also include certain minor natural gas pipeline operations, and prior to September 30, 1993, certain minor natural gas distribution operations, not conducted through the Partnership. For comparability purposes, the information and statistics below reflect the combination of all such natural gas operations for all of 1994, 1993 and 1992. For a discussion of the Company's method of accounting for its investment in the Partnership, see Note 1 of Notes to Consolidated Financial Statements.
Transmission System
The Company's principal natural gas pipeline system is its Texas intrastate gas system ("Transmission System"). The Transmission System generally consists of large diameter transmission lines that receive gas at central gathering points and move the gas to delivery points. The Transmission System also includes numerous small diameter lines connecting individual wells and common receiving points to the Transmission System's larger diameter lines. The Company's wholly owned, jointly owned and leased natural gas pipeline systems include approximately 8,000 miles of mainlines, lateral lines and gathering lines. These pipeline systems are located along the Texas Gulf Coast and throughout South Texas and extend westerly to near Pecos, Texas; northerly to near the Dallas-Fort Worth area; easterly to Carthage, Texas, near the Louisiana border; and southerly into Mexico near Reynosa. These integrated systems include 42 mainline compressor stations with a total of approximately 174,000 horsepower, together with gas processing plants, dehydration and gas treating plants and numerous measuring and regulating stations. The Company's pipeline systems have considerable flexibility in providing connections between many producing and consuming areas, and are able to handle widely varying loads caused by changing supply and demand patterns. Annual average throughput was approximately 2.8 TBtu per day in 1994, and has been in excess of 2.3 TBtu per day in recent years. The Company's owned and leased pipeline systems have 69 interconnects with 19 intrastate pipelines, 39 interconnects with 13 interstate pipelines, and two international interconnects with Pemex in South Texas.
[FN]
The term "Btu" means British Thermal Unit, a standard measure of heating value. The terms MMBtu, BBtu and TBtu mean million Btu's, billion Btu's, and trillion Btu's, respectively. The number of MMBtu's of total natural gas deliveries is approximately equal to the number of Mcf's (thousand cubic feet) of such deliveries. An Mcf is a standard unit for measuring natural gas volumes at a pressure base of 14.65 pounds per square inch absolute and at 60 degrees Fahrenheit. The term "MMcf" means million cubic feet, and the term "Bcf" means billion cubic feet.
Gas Sales
The following table sets forth the Company's gas sales volumes and average gas sales prices for the three years ended December 31, 1994.
Sales of natural gas accounted for approximately 40%, 41% and 41% of the Company's total daily gas volumes for 1994, 1993 and 1992, respectively. The Company supplies both intrastate and interstate markets with gas supplies acquired from producers, marketers and pipelines. Gas sales are made on both a long-term basis and a short-term interruptible basis. The Company also engages in off-system sales. During 1994, the Company sold natural gas under hundreds of separate short- and long-term gas sales contracts. Through the use of financial instruments such as swaps, futures and options, the Company hedges the risk associated with fluctuating natural gas prices. See Note 5 of Notes to Consolidated Financial Statements. The Company's gas sales are made primarily to gas distribution companies, electric utilities, other pipeline companies and industrial users. The gas sold to distribution companies is resold to consumers in a number of cities including San Antonio, Dallas, Austin, Corpus Christi and Chicago. The demand for natural gas has increased at a rate of approximately 3.5% per year since 1986. The Company expects that long-term demand will continue to grow about 2% per year, especially in the industrial and power generation sectors, although natural gas demand in 1994 was negatively affected by unseasonably mild weather during the fourth quarter and the operations of alternative fuel facilities in the Company's core service area. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - 1994 Compared to 1993 - Segment Results - Natural Gas."
The Company's largest gas sales customer is San Antonio City Public Service ("CPS"). The Company supplies 100% of CPS's natural gas requirements. The CPS contract is effective until 2002, subject to possible renegotiation of certain contract terms beginning in 1997. Natural gas sales to CPS in 1994 represented approximately 12% of the Company's total consolidated daily gas sales volumes (but less than 10% of the Company's consolidated operating revenues). Except for the CPS contract, the Company's gas sales contracts with its intrastate customers generally require the Company to provide a fixed and determinable quantity of gas rather than total customer requirements, however, certain gas sales contracts with intrastate customers provide for either maximum volumes or total requirements, subject to priorities and allocations established by the Railroad Commission of Texas. See "Governmental Regulations - Texas Regulation."
Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") has effectively transformed the interstate gas industry into a service-oriented business with natural gas and transportation trading as separate commodities. Because of Order 636, local distribution companies ("LDCs") and power generation companies must acquire their own gas supplies, including managing their needs for swing, transportation and storage services. See "Governmental Regulations - Federal Regulation." The Company is continuing to emphasize diversification of its customer base through interstate sales. By the end of 1994, the Company had secured contracts to provide gas supply and swing services to certain LDCs, electric utilities and industrial customers primarily in the Midwest, Northeast and Western United States providing for deliveries of up to approximately 300 BBtu per day with terms ranging from one to ten years.
Order 636 has created a new market for the Company, requiring that the Company efficiently provide an array of value- added services to the customer base. In response, the Company offers a broad range of marketing services. The Company has marketing offices located throughout Texas as well as in Los Angeles, Chicago, Louisville and Mexico City. The Company also operates the Waha-Permian Basin Hub in West Texas under a 1994 agreement with a third party to support that party's electronic trading system to forward buy and sell physical quantities of gas. In 1995, the Company also agreed to operate the Waha hub as the designated delivery point for a new futures contract proposed by the Kansas City Board of Trade. This futures contract would provide risk management opportunities for natural gas markets in the Western United States. Finally, in anticipation of new opportunities expected in connection with the FERC's deregulation of the electric power generation industry, the Company secured its power marketing certificate from the FERC in 1994 in order to participate in the wholesale bulk power business.
Gas Transportation and Exchange
The following table sets forth the Company's gas transportation volumes and average transportation fees for the three years ended December 31, 1994.
Gas transportation and exchange transactions (collectively referred to as "gas transportation" or "transportation") constitute the largest portion of the Company's natural gas volumes, representing 60%, 59% and 59% of total daily gas volumes for 1994, 1993 and 1992, respectively. The Company's natural gas operations have been affected by an emerging trend of west-to-east movement of gas across the United States caused by increased production in western supply basins, the pipeline expansions from Canada and the Rocky Mountains and increasing demand for power generation in the East and Southeast. In 1994, transportation rates were notably higher on eastbound transmission than on east-to-west transmission. To capitalize on the west-to-east trend, the Company in 1994 completed a capacity expansion project on its joint venture North Texas pipeline which added incremental capacity of approximately 90 MMcf of gas per day to the pipeline. Despite this increased capacity, the Company's 1994 transportation revenues were negatively impacted by reduced demand for natural gas in 1994 and increased competition for transportation services. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - 1994 Compared to 1993 - Segment Results - Natural Gas."
The Company transports gas for third parties under hundreds of separate short- and long-term transportation contracts. The Company's transportation contracts generally limit the Company's maximum transportation obligation (subject to available capacity) but generally do not provide for any minimum transportation requirement. The Company's transportation customers include major oil and natural gas producers and pipeline companies.
Gas Supply and Storage
Gas supplies available to the Company for purchase and resale or transportation include supplies of gas committed under both short- and long-term contracts with independent producers as well as additional gas supplies contracted for purchase from pipeline companies, gas processors and other suppliers that own or control reserves. There are no reserves of natural gas dedicated to the Company and the Company does not own any gas reserves other than gas in underground storage which comprises an insignificant portion of the Company's gas supplies. Because of recent changes in the natural gas industry, gas supplies have become increasingly subject to shorter term contracts, rather than long-term dedications.
During 1994, the Company purchased natural gas under hundreds of separate contracts. Surplus gas supplies, if available, may be purchased to supplement the Company's delivery capability during peak use periods. A majority of the Company's gas supplies are obtained from sources with multiple connections. In such instances, the Company frequently competes on a monthly basis for available gas supplies. Because of the extensive coverage within the State of Texas by the Company's pipeline systems, the Company believes that the Company can access a number of supply areas. While there can be no assurance that the Company will be able to acquire new gas supplies in the future as it has in the past, the Company believes that Texas will remain a major producing state, and that for the foreseeable future the Company will be able to compete effectively for sufficient new gas supplies to meet customer demand.
The Company operates an underground gas storage facility in Wharton County, Texas. The current storage capacity of this facility is approximately 7.2 Bcf of gas available for withdrawal. Natural gas can be continuously withdrawn from the facility at initial rates of up to approximately 800 MMcf of gas per day and at declining delivery rates thereafter until the inventory is depleted. To meet Order 636 term business, the Company supplemented its own natural gas storage capacity by securing during 1994 an additional 5 Bcf of third-party storage capacity for the 1994-95 winter heating season.
NATURAL GAS LIQUIDS
The Company owns 11 gas processing plants and is a major producer and marketer of NGLs. The Company's NGL operations provide strong integration among the Company's three core businesses. The Company's ability to process natural gas is a value-added service offered to producers and attracts additional quantities of gas to the Company's pipeline system. Production from the Company's NGL plants also provides butane feedstocks for the production of oxygenates at the Refinery. The Company's NGL operations consist primarily of the NGL operations conducted through the Partnership which were acquired in connection with the Merger described above (see "Recent Developments - Acquisition of VNGP, L.P."). In addition, the Company's NGL operations include the operations of certain South Texas NGL assets acquired by the Company in May 1992 and not included within the operations of the Partnership. For comparability purposes, the information and statistics below reflect the combination of all such NGL operations for all of 1994, 1993 and 1992. For a discussion of the Company's method of accounting for its investment in the Partnership, see Note 1 of Notes to Consolidated Financial Statements.
Recent expansions and improvements at the Company's gas processing plants increased 1994 NGL production to 29 million barrels for the year and a record average for the Company of approximately 80,000 barrels per day. The table below sets forth NGL production volumes, average NGL market prices, and average gas costs for the three years ended December 31, 1994.
The Company's NGL operations include the extraction of NGLs, the separation ("fractionation") of mixed NGLs into component products (e.g., ethane, propane, butane, natural gasoline), and the transportation and marketing of NGLs. Extraction is the process of removing NGLs from the gas stream, thereby reducing the Btu content and volume of incoming gas (referred to as "shrinkage"). In addition, some gas from the gas stream is consumed as fuel during processing. The principal source of gas for processing is from the Transmission System. The Company receives revenues from the extraction of NGLs principally through the sale of NGLs extracted in its gas processing plants and the collection of processing fees charged for the extraction of NGLs owned by others. The Company compensates gas suppliers for shrinkage and fuel usage in various ways, including sharing NGL profits, returning extracted NGLs to the supplier or replacing an equivalent amount of gas. Extracted NGLs are transported to downstream fractionation facilities and end-use markets through the Company's NGL pipelines, certain common-carrier NGL pipelines and trucks. The primary markets for NGLs are petrochemical plants (all NGLs), refineries (butanes and natural gasoline), and domestic fuel distributors (propane). The Company's NGL production is sold primarily in the Corpus Christi and Mont Belvieu (Houston) markets. NGL prices are generally set by or in competition with prices for refined products in the petrochemical, fuel and motor gasoline markets. During 1994, approximately 77% of the Company's butane production was used as a feedstock for the Refinery's MTBE Plant.
The Company's 11 gas processing plants are located in South and West Texas and process approximately 1.3 Bcf of gas per day. Each of the Company's plants is situated along the Transmission System. The Company also owns approximately 444 miles of NGL pipelines, 460 miles of gathering lines, and fractionation facilities at five locations. The Company fractionated an average of 77,600 barrels per day in 1994, approximately 17% of which represented NGLs fractionated for third parties. The Company's NGL pipelines transport NGLs from gas processing plants to fractionation facilities. The NGL pipelines also connect with end users and major common-carrier NGL pipelines, which ultimately deliver NGLs to the principal NGL markets. The Company's NGL pipelines are located principally in South Texas and West Texas. In South Texas, the Company owns 200 miles of NGL pipelines that directly or indirectly connect five of the Company's processing plants and four processing plants owned by third parties to the Company's fractionation facilities near Corpus Christi.
The Company sells NGLs that have been extracted, transported and fractionated in the Company's facilities and NGLs purchased in the open market from numerous suppliers (including major refiners and natural gas processors) under long-term, short-term and spot contracts. The Company's contracts for the purchase, sale, transportation and fractionation of NGLs are generally with longstanding customers and suppliers of the Company. The Company's four largest NGL customers accounted for approximately 62% of the Company's 1994 NGL product sales revenues to nonaffiliates (although none of these customers accounted for 10% or more of the Company's total consolidated revenues). The petrochemical industry represents an expanding principal market for NGLs due to increasing market demand for ethylene-derived products. Both NGL demand and prices were benefitted by the start-up of a new ethylene plant and a new butane dehydrogenation MTBE plant along the Texas Gulf Coast region during the second quarter of 1994. These plants increased the NGL base demand by at least 30,000 barrels per day during 1994. In the first quarter of 1995, another new ethylene plant, together with expansions to existing ethylene plants along the Texas Gulf Coast, will have the potential to increase NGL demand by an additional 50,000 to 60,000 barrels per day.
The Company's ability to process natural gas attracts significant gas supplies to the Transmission System. In 1994, the Company secured approximately 800 BBtu per day of natural gas supplies from natural gas producers under agreements to process, transport or purchase their natural gas for terms ranging from two to ten years. Of these supplies, approximately 225 BBtu per day represent new natural gas supplies dedicated to the Company's pipeline system.
GOVERNMENTAL REGULATIONS
Texas Regulation
The Railroad Commission of Texas ("RRC") regulates the intrastate transportation, sale, delivery and pricing of natural gas in Texas by intrastate pipeline and distribution systems, including those of the Company. The RRC's gas proration rule prohibits the production of gas in excess of market demand, and permits producers to tender and deliver, and gas purchasers to take, only volumes of gas equal to their market demand. The gas proration rule requires purchasers to take gas by priority categories, ratably among producers without undue discrimination, with high-priority gas (defined as casinghead gas, 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 RRC rules are intended to bring production allowables in line with estimated market demand.
For pipelines, the RRC approves intrastate sales and transportation rates and all proposed changes to such rates. Changes in the price of gas sold to gas distribution companies are subject to rate determination in a rate case before the RRC. Under applicable statutes and current RRC practice, larger volume industrial sales and transportation charges may be changed without a rate case if the parties to the transactions agree to the rate changes and make certain representations. Since December 31, 1979, a portion of the Company's gas sales have been made at rates established by an order (the "Rate Order") of the RRC. However, the proportion of these sales to the Company's total gas sales has been decreasing because of various factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - 1994 Compared to 1993 - Segment Results - Natural Gas." Currently, the price of natural gas sold under a majority of the Company's gas sales contracts is not regulated by the RRC, and the Company may generally enter into any sales contract that it is able to negotiate with customers.
NGL pipeline transportation is also subject to regulation by the RRC. The RRC requires the filing of tariffs and compliance with environmental and safety standards. To date, the impact of this regulation on the Company's operations has not been significant. The RRC also has regulatory authority over gas processing operations, but has not exercised such authority.
Federal Regulation
The Company's refining operations are primarily subject to various federal and state environmental statutes and regulations. See "Environmental Matters." The Company's 8,000-mile pipeline system is an intrastate business not subject to direct regulation by the FERC. Although the Company's interstate sales and transportation activities are subject to specific FERC regulations, these regulations do not change the Company's overall regulatory status. The Company's natural gas operations are more significantly affected by the implementation of 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. This allows the Company to compete with interstate pipelines and other companies to provide these component services separately from the transportation provided by the interstate pipelines. The "unbundling" of services under Order 636 allows LDCs and other customers to choose the combination of services that best meet their needs at the lowest total cost, thus increasing competition in the interstate natural gas industry. As a result of Order 636, the Company can more effectively compete for sales of natural gas to LDCs and other natural gas customers located outside Texas.
COMPETITION
Refining and Marketing
The refining industry is highly competitive with respect to both supply and markets. The Company 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 the Company 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. The Company does not have retail gasoline operations. 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.
Within the next several years, all United States refineries must obtain operating permits under the Clean Air Act. Because the Refinery was completed in 1984, it was built under more stringent environmental requirements than many existing refineries. The Refinery currently meets EPA emissions standards requiring the use of "best available control technology," and is located in an area currently designated "attainment" for air quality. Accordingly, the Company expects to be able to comply with the Clean Air Act and future environmental legislation more easily than older, conventional refineries.
Natural Gas
The natural gas industry is and is expected to remain highly competitive with respect to both gas supply and markets. Changes in the gas markets during the recent period of deregulation under Order 636 have resulted in significantly increased competition. Despite the increased competition, the Company generally believes that it has been able to take advantage of the increased business opportunities resulting from the implementation of Order 636. Accordingly, the Company has not only maintained but has increased its throughput volumes since implementation of Order 636. Under Order 636, the Company can more effectively compete for sales of natural gas to LDCs and other customers located outside Texas. See "Governmental Regulations - Federal Regulation." Firm and term contracts have become more common in the industry in recent years. These contracts generally require gas suppliers to commit to specified deliveries of gas without the option of interrupting service and penalize gas suppliers for failure to perform in accordance with their contractual commitments. Because of Order 636, the Company now can guarantee long-term supplies of natural gas to be delivered to buyers at interstate locations. The Company can charge a fee for this guarantee, which together with transportation charges, can exceed the amount that the Company could receive for merely transporting natural gas. Because of Order 636 and the location of the Transmission System, the Company believes that the Company is able to compete for new gas supplies and new gas sales and transportation customers.
In recent years, certain intrastate pipelines with which the Company had traditionally competed have acquired or have been acquired by interstate pipelines. These combined entities generally have capital resources substantially greater than those of the Company and, notwithstanding Order 636's "open access" regulations, may realize economies of scale and other economic advantages in acquiring, selling and transporting natural gas. The acquisition of gas supply is capital intensive, as it frequently requires installation of new gathering lines to reach sources of gas. Additionally, the combination of intrastate and interstate pipelines within one organization may in some instances enable competitors to lower gas prices and transportation fees, and thereby increase price competition in the Company's intrastate and interstate markets.
The U.S.-Canada free trade agreement and changes in Canadian export regulations have increased Canadian natural gas imports into the United States. Under the North American Free Trade Agreement, Canadian natural gas imports into the United States are expected to continue. Canadian imports have increased competition in the interstate markets in which the Company competes for natural gas sales and have affected natural gas availability and prices in the Texas intrastate market. As a result, competition in the natural gas industry is expected to remain intense.
Natural Gas Liquids
The economics of natural gas processing depends principally on the relationship between natural gas costs and NGL prices. When this relationship has been favorable, the NGL processing business has been highly competitive. The Company believes that competitive barriers to entering the business are generally low. Moreover, improvements in NGL-recovery technology have improved the economics of NGL processing and have increased the attractiveness of many processing opportunities. In recent years, NGL margins have been subject to the extreme volatility of energy prices in general. The Company believes that the level of competition in NGL processing has increased over the past year and generally will become more competitive in the longer term as the demand for NGLs increases. The Company's South Texas gas processing plants, however, have direct access to many of the large petrochemical markets along the Texas Gulf Coast, which gives the Company a competitive advantage over many other NGL producers.
ENVIRONMENTAL MATTERS
The Company's refining, natural gas and NGL operations are subject to environmental regulation by federal, state and local authorities, including the EPA, the Texas Natural Resources Conservation Commission ("TNRCC"), the Texas General Land Office and the RRC. 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 1994, capital expenditures for the Company's refining operations attributable to compliance with environmental regulations were approximately $6 million and are currently estimated to be the same for 1995. These amounts are exclusive of any amounts related to constructed facilities for which the portion of expenditures relating to compliance with environmental regulations is not determinable. For a discussion of the effects of the Clean Air Act's oxygenated gasoline and RFG programs on the Company's refining operations, see "Recent Developments - Uncertainty in Gasoline Markets."
The Company's capital expenditures for environmental control facilities related to its natural gas and NGL operations were not material in 1994 and are not expected to be material in 1995. Currently, expenditures are made to comply with air emission regulations and solid waste management regulations applicable to various facilities. In 1991, environmental legislation was passed in Texas that conformed Texas law with the Clean Air Act to allow Texas to administer the federal programs. Upon interim approval by the EPA of the Texas Title V operating permit program, many of the Company's gas processing plants and gas pipeline facilities will be among the first facilities required to submit applications to the TNRCC for new operating permits, and may be subject to increased requirements for monitoring air emissions. Although new requirements may increase operating costs, they are not expected to have a material adverse effect on the Company's operations or financial condition.
The Oil Pollution Act of 1990 ("OPA 90") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and the assessment of liability for damages resulting from oil spills in U.S. territorial waters. Shipments of crude oil and resid within U.S. territorial waters are subject to the regulations promulgated under OPA 90. These regulations require tankers to comply with certain Certificate of Financial Responsibility ("COFR") requirements in order to ship within U.S. territorial waters. The Company's shippers have complied with the COFR requirements and the Company has not experienced any difficulty in obtaining tonnage to move its supplies to the Refinery. The OPA 90 regulations are not expected to have a material impact on operating results from the Company's refining and marketing operations.
EMPLOYEES
As of January 31, 1995, the Company had 1,658 employees.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of December 31, 1994 regarding the 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. 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 Energy Resources, Inc., neither of which are affiliated with the Company.
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.
Mr. Fry was elected Vice President Administration of Energy in 1989 and served as Secretary of Energy from 1980 to 1992.
Mr. Zanotti, until his retirement on December 31, 1994, served as Executive Vice President of Valero Refining and Marketing Company since 1988 and as President and Chief Operating Officer of Valero Refining Company since 1990.
Mr. Manning has served as Senior Vice President of Valero Refining and Marketing Company since 1986 and of Valero Refining Company since 1987.
ITEM 2.
ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery and related facilities, 11 natural gas processing plants, and various natural gas and NGL pipelines, gathering lines, fractionation facilities, compressor stations, treating plants and related facilities, all located in Texas. Substantially all of the Company's refining fixed assets are pledged as security under deeds of trust securing industrial revenue bonds issued on behalf of Valero Refining and Marketing Company. Substantially all of the gas systems and processing facilities acquired by the Company in connection with the Merger are pledged as collateral for the First Mortgage Notes of Valero Management Partnership, L.P. See Note 4 of Notes to Consolidated Financial Statements. Reference is made to "Item 1. Business" which includes detailed information regarding properties of the Company. The Company believes that its 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 is the lessee under a number of cancelable and noncancelable leases for certain real properties. See Note 13 of Notes to Consolidated Financial Statements.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to the following proceedings:
Cook, et al. v. Shell Oil Company; Texaco, Inc.; Valero Management Company; et al., 172nd State District Court, Jefferson County, Texas (filed November 7, 1994). This lawsuit arises from the rupture of several pipelines and fire as a result of severe flooding of the San Jacinto River in Harris County, Texas on October 20, 1994. The plaintiffs are property owners in Highlands, Crosby, Baytown, and McNair, Texas, and surrounding areas. The plaintiffs allege that the defendant pipeline owners were negligent and grossly negligent in failing to bury the pipelines at a proper depth to avoid rupture or explosion and in allowing the pipelines to leak chemicals and hydrocarbons into the flooded area. The original plaintiffs and additional intervening plaintiffs make other similar assertions and seek certification as a class. The plaintiffs assert claims for property damage, costs for medical monitoring, personal injury and nuisance. Plaintiffs seek an unspecified amount of actual and punitive damages.
Harding, et al. v. Browning-Ferris Industries, Inc.; Valero Refining Company; et al. 229th State District Court, Duval County, Texas (filed March 1, 1994). In June 1994, Valero Refining Company ("VRC") was added as a defendant in a lawsuit filed by several hundred plaintiffs who are residents of San Patricio County, Texas. The suit was brought against numerous defendants whom the plaintiffs allege are either owners or operators of a landfill site in San Patricio County, or generators of hazardous wastes accepted into the landfill. VRC is named as a "generator" of hazardous wastes accepted into the landfill. The plaintiffs claim that hazardous wastes escaped from the landfill and were released into the surrounding ground, water and air, allegedly causing damages including bodily injury, emotional distress, costs for medical monitoring and devaluation of property. The plaintiffs seek an unspecified amount of actual and punitive damages. In January 1995, the parties reached a tentative settlement of the plaintiffs' claims against VRC on terms immaterial to VRC and the Company. The settlement of certain claims held by plaintiffs who are minors is subject to final approval by the court.
J.M. Davidson, Inc. v. Valero Energy Corporation; Valero Hydrocarbons, L.P.; et al., 229th State District Court, Duval County, Texas (filed January 21, 1993). Energy and Valero Hydrocarbons, L.P. were named as original defendants in the lawsuit filed in January 1993. Through the plaintiff's amended petitions, the lawsuit now includes several other subsidiaries of the Company as additional defendants. The lawsuit arises from construction work performed by the plaintiff at certain of the Partnership's gas processing plants in 1991 and 1992. The plaintiff alleges that it performed work for the defendants for which it was not compensated. The plaintiff's second amended petition, filed April 30, 1994, asserts claims for breach of contract and numerous tort claims. The plaintiff alleges actual damages of approximately $9.7 million and punitive damages of $45.5 million. The defendants have filed a motion for partial summary judgment to dismiss the plaintiff's tort claims.
The Long Trusts v. Tejas Gas Corporation, 123rd Judicial District Court, Panola County, Texas (filed March 1, 1989). Valero Transmission Company ("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. ("VT, L.P.") upon formation of the Partnership in 1987 (the "Valero Contracts"). In turn, Tejas has entered into a series of gas purchase contracts between Tejas, as buyer, and certain trusts (the "Long Trusts"), as seller (the "Long Trusts Contracts"). The litigation originated in 1989 as a lawsuit by the Long Trusts against Tejas. In the Long Trusts' claims against Tejas, the Long Trusts claim that Tejas breached various minimum take, take-or-pay and other contractual provisions in connection with the Long Trusts Contracts, and seek alleged actual damages, including interest, of approximately $30 million. Neither VTC nor VT, L.P. was originally a party to the lawsuit. However, because of the relationship between the Valero Contracts and the Long Trusts Contracts, and in order to resolve existing and potential disputes, Tejas, VTC and VT, L.P. agreed in March 1991 to cooperate in the conduct of the litigation, and agreed that VTC and VT, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against Tejas. In January 1993, the District Court ruled on the Long Trusts' motion for summary judgment, finding that as a matter of law the Long Trusts Contracts 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 availability of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, were not determined. On April 15, 1994, the Long Trusts named VTC and VT, L.P. as additional defendants (the "Valero Defendants") to the lawsuit, alleging that the Valero Defendants maliciously interfered with the Long Trusts Contracts. In the Long Trusts' claim against the Valero Defendants, the Long Trusts seek unspecified actual and punitive damages. The Company believes that the claims brought by the Long Trusts have been significantly overstated, and that Tejas and the Valero Defendants have a number of meritorious defenses to the claims.
Ventura, et al. v. Valero Refining Company, 105th State District Court, Nueces County, Texas (filed June 17, 1994). This lawsuit was filed against VRC by certain residents of the Mobile Estate subdivision located near the Refinery in Corpus Christi, Texas, alleging that air, soil and water in the subdivision have been contaminated by emissions of allegedly hazardous chemicals and toxic hydrocarbons produced by Refining. The plaintiffs' claims include negligence, gross negligence, strict liability, nuisance and trespass. The plaintiffs seek certification as a class and an unspecified amount of damages based on an alleged diminution in the value of their property, loss of use and enjoyment of property, emotional distress and other costs.
Javelina Company Litigation. Valero Javelina Company, a wholly owned subsidiary of Energy, owns a 20 percent general partner interest in Javelina Company, a general partnership. See Note 6 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, and Duval County, Texas. Five 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 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. The other two 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 do not 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 statements; 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 interim period in which such resolution occurred.
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 1994.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Energy's Common Stock is listed under the symbol "VLO" on the New York Stock Exchange, which is the principal trading market for this security. As of February 14, 1995, there were approximately 7,500 holders of record and an estimated 19,000 additional 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 19, 1995 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, 1994 is derived from the Company's Consolidated Financial Statements contained elsewhere herein. The selected financial data for the years ended prior to December 31, 1994 is derived from the selected financial data contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1993.
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
ACQUISITION OF VNGP, L.P.
As described in Note 2 of Notes to Consolidated Financial Statements, the Merger of VNGP, L.P. with a wholly owned subsidiary of Energy was consummated on May 31, 1994. As a result of the Merger, VNGP, L.P. has become a wholly owned subsidiary of Energy. The accompanying consolidated statements of income of the Company for the years ended December 31, 1994, 1993 and 1992 include the Company's approximate 49% effective equity interest in the Partnership's operations for all periods prior to and including May 31, 1994 and include 100% of the Partnership's operations thereafter. Because 1994 results of operations for the Company's natural gas and natural gas liquids segments are not comparable to prior periods due to the Merger, the discussion of these operations which follows under "Results of Operations - 1994 Compared to 1993 - Segment Results" includes 100% of the Partnership's operations rather than only the Company's effective interest in the Partnership's operating results. Such discussion is based on pro forma operating results that reflect the consolidation of the Partnership with Energy for all of 1994 and 1993.
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, 1994. The 1993 and 1992 amounts of operating revenues and operating income (loss) by segment have been restated to conform to the 1994 segment presentation. The amounts in the following table are in thousands of dollars, unless otherwise noted:
1994 COMPARED TO 1993
Consolidated Results
The Company reported net income of $26.9 million, or $.40 per share, for the year ended December 31, 1994 compared to $36.4 million, or $.82 per share, for the year ended December 31, 1993. For the fourth quarter of 1994, net income was $3.9 million, or $.02 per share, compared to a net loss of $15.2 million, or $.36 per share, for the fourth quarter of 1993. The 1993 fourth quarter and total year results were adversely 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. See "Segment Results - Refining and Marketing" below. Although operating income increased during 1994 compared to 1993, a decrease in equity in earnings of and income from the Partnership, an increase in net interest and debt expense and the nonrecurring gain on disposition of the Company's natural gas distribution operations during the third quarter of 1993, partially offset by a decrease in income tax expense, resulted in a decrease in net income and earnings per share for the year. Earnings per share was also reduced by an increase in preferred stock dividend requirements resulting from the issuance in the first quarter of 1994 of 3.45 million shares of Energy's $3.125 Convertible Preferred Stock. See Note 8 of Notes to Consolidated Financial Statements.
Operating revenues increased $615.2 million, or 50%, during 1994 compared to 1993 due primarily to the inclusion in 1994 of operating revenues attributable to the Partnership beginning June 1, 1994, and to a lesser extent to an increase in operating revenues from refining and marketing operations which is explained below under "Segment Results." The increases attributable to these factors were partially offset by a decrease in management fees received from the Partnership resulting from the May 31, 1994 Merger and a decrease in natural gas sales and transportation revenues resulting from the 1993 disposition of the Company's natural gas distribution operations noted above.
Operating income increased $50.4 million, or 67%, during 1994 compared to 1993 due primarily to the inclusion of Partnership operating income for the seven months commencing June 1, 1994. Operating income also benefitted from the nonrecurring recognition in income at the time of the Merger of the $6.7 million remaining balance of deferred management fees. Such deferred management fees arose in connection with the formation of the Partnership in 1987 at which time the Company entered into a management agreement with the Partnership whereby the Company would provide, over a ten-year period, certain management services to the Partnership. The Company deferred a portion of the gain generated upon the Partnership formation which represented the profit element in providing such future services. At the time of the Merger, the remaining $6.7 million unamortized portion of such deferred gain was recognized.
The Company's equity in losses and income from the Partnership for the five months of 1994 preceding the Merger was $(10.7) million compared to equity in earnings and income from the Partnership of $23.7 million in 1993. Included in the 1994 amount was the Company's equity interest in the $14 million cost of a settlement among the Company, the Partnership and the City of Houston regarding a franchise fee dispute. For a discussion of the Company's natural gas and natural gas liquids operations, including 100% of the operations of the Partnership on a pro forma basis, see "Segment Results" below.
Net interest and debt expense increased $39.7 million in 1994 compared to 1993 due primarily to the inclusion of the Partnership's interest expense subsequent to the Merger and to a decrease in capitalized interest resulting from the placing in service at the Refinery of the MTBE Plant during the second quarter of 1993 and the MTBE/TAME Complex and Reformate Splitter during the fourth quarter of 1993. Income tax expense decreased in 1994 compared to 1993 due to lower pre-tax income and the nonrecurrence of the 1993 third quarter charge to earnings of $8.2 million resulting from the effect of a one-percent increase in the corporate income tax rate on the Company's December 31, 1992 balance of deferred income taxes.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and marketing operations increased $45.6 million, or 4%, during 1994 compared to 1993 due primarily to a 5% increase in average daily sales volumes. Sales and throughput volumes increased as a result of placing in service various new Refinery units in 1993, as discussed above. The average sales price per barrel in 1994 was basically unchanged from 1993 as the continued weakness in refined product prices was offset by a change in product mix resulting from increased sales of MTBE during 1994, due to a full year's operation of the MTBE Plant, and initial sales of higher- valued reformulated gasoline ("RFG") during November and December of 1994. Weak refined product prices during 1994 resulted from an increase in gasoline supply due to increased refinery upgrading capacity, high refinery utilization rates and increased gasoline imports.
Operating income from the Company's refining and marketing operations increased $3.3 million, or 4%, during 1994 compared to 1993 due primarily to the nonrecurrence of a write- down in the carrying value of refinery inventories during the fourth quarter of 1993 which reduced 1993 operating income by $27.6 million. Excluding the effect of the 1993 inventory write- down, refining and marketing operating income decreased $24.3 million, or 24%, in 1994 compared to 1993 due to a decrease in throughput margins resulting from narrower discounts for the Company's residual oil ("resid") feedstocks (which had an effect of approximately $30 million), lower margins between conventional refined product prices and crude oil (which had an effect of approximately $12 million), and lower margins on sales of MTBE due to higher costs for the Company's methanol feedstocks (which had an effect of approximately $7 million), which more than offset higher margins on sales of RFG and other premium products (which had an effect of approximately $21 million) and a 7% increase in average daily throughput volumes (which had an effect of approximately $19 million). The Company's resid discount, representing the average discount at which resid sells to crude oil, decreased from $4.43 per barrel in 1993 to $3.25 per barrel in 1994 due to a worldwide decrease in resid supplies resulting from increased refinery upgrading capacity, an increase in the proportion of light crude oil produced in relation to heavy crude oil, reduced resid exports from the former Soviet Union and strong demand for fuel oil in the Far East due to unusually hot weather. Methanol prices increased significantly during 1994 due to tight supplies and an anticipated increase in demand for oxygenates in connection with the start-up of the RFG program in late 1994. As a result of the above factors, the Refinery's average throughput margin per barrel, before operating costs and depreciation expense, decreased from $5.99 in 1993 (excluding the effect of the inventory write-down) to $5.36 in 1994. Operating costs and depreciation expense increased approximately $9 million and $6 million, respectively, in 1994 compared to 1993 due to placing in service various new Refinery units in 1993, as discussed above, although operating costs per barrel were basically unchanged due to increased throughput volumes.
During the fourth quarter of 1994, the Company negotiated a new resid feedstock supply agreement with Arabian American Oil Company ("Aramco") which became effective January 1, 1995 and will run for a period of two years. The new agreement provides for minimum deliveries of approximately 36,000 barrels per day at a market-based pricing formula that is subject to price renegotiation in the fourth quarter of 1995. Deliveries under this agreement provide approximately 45% of the Refinery's resid requirements. During the first quarter of 1995, the Company renewed for an additional year its contract to purchase 11,000 barrels per day of resid from South Korea at market-based prices. The Company believes that if either of the existing feedstock arrangements were interrupted, adequate supplies of feedstock could be obtained from other sources or on the open market. However, because the demand for the type of resid feedstock now processed at the Refinery has increased in relation to the availability of supply over the past year, the Company could be required to incur higher feedstock costs or substitute other types of resid, thereby producing less favorable operating results. The remainder of the Refinery's resid feedstocks are purchased at market-based prices under short-term contracts. On December 1, 1994, the Company formed a joint venture with Hoechst Celanese Chemical Group, Inc. ("Celanese") to renovate and operate a 13,000-barrel-per-day methanol plant. The Company's 50% share of methanol production from this plant is expected to provide substantially all of the methanol feedstock required for the Refinery's production of oxygenates used in RFG at a cost substantially lower than prevailing market prices. The refurbished methanol plant is estimated to be placed in service in the second quarter of 1995. See "Liquidity and Capital Resources."
Scheduled maintenance and catalyst changes of the Refinery's hydrodesulfurization unit (the "HDS Unit") were completed in October 1992 and December 1993, and a turnaround of the Refinery's heavy oil cracking complex (the "HOC") was completed in October 1994. During 1995, the Refinery's hydrocracker and naphtha reformer units are scheduled for turnarounds, while the HDS Unit is scheduled for maintenance and a catalyst change, all beginning in the first quarter.
Natural Gas
Pro forma operating income from the Company's natural gas operations decreased $42.6 million, or 58%, during 1994 compared to 1993 due to settlements of certain measurement, fuel usage and customer billing differences which benefitted 1993 by $11 million but negatively impacted 1994 by $3.1 million, lower gas sales margins, a decrease in transportation revenues, and an increase in operating and general expenses. Gas sales margins were lower due primarily to a $16.6 million decrease in gas cost reductions resulting from price risk management activities, reduced demand for natural gas and reduced recoveries of fixed costs, principally gas gathering costs, as a result of a customer audit settlement effective July 1, 1993. The decrease in transportation revenues was due primarily to a 5% decrease in average transportation fees also resulting from reduced gas demand. Operating and general expenses increased due primarily to the City of Houston settlement discussed above under "Consolidated Results."
As noted above, the Company's natural gas operations were negatively impacted in 1994 by a decrease in demand for natural gas resulting from unseasonably mild weather during the 1994 fourth quarter and the return to service of the South Texas Project nuclear plant ("STP") in Bay City, Texas during the 1994 second quarter. During most of 1993, both units of the STP were shut down due to operational problems. At full operation, the STP displaces approximately 650 BBtu per day of natural gas demand. Demand for natural gas in the Company's core service area is also affected by the operational status of other nuclear and coal-fired power plants, including the Comanche Peak nuclear plant near Ft. Worth, Texas and coal-fired electrical generation facilities owned and operated by San Antonio City Public Service.
The Company's gas sales and transportation businesses are based primarily on competitive market conditions and contracts negotiated with individual customers. The Company has been able to mitigate, to some extent, the effect of competitive industry conditions by the flexible use of its strategically located pipeline system and its aggressive marketing efforts. Sales and transportation volumes were flat in 1994 compared to 1993 as volume increases resulting from aggressive efforts to generate business related to the implementation of Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") and the west-to-east shift in natural gas supply patterns were offset by volume decreases resulting from the above-noted return to service of the STP in 1994 and unseasonably mild weather during the 1994 fourth quarter. The Company utilizes hedging techniques to manage the cost of gas consumed in its NGL operations, and manage price risk associated with its natural gas storage and marketing activities. Such activities are intended to manage price risk but may result in gas costs either higher or lower than those that would have been incurred absent such hedging activities. In 1994 and 1993, the Company recognized on a pro forma basis $2.1 million and $18.7 million, respectively, in gas cost reductions from price risk management activities. An additional $6.8 million and $5.1 million was deferred at December 31, 1994 and 1993, respectively, which is recognized as a reduction to the cost of gas in the subsequent year. See "Price Risk Management Activities" under Note 1 of Notes to Consolidated Financial Statements.
Gas sales are also made, to a significantly lesser extent, to intrastate customers under contracts which originated in the 1960s and 1970s with 20- to 30-year terms. These contracts were full requirements, no-notice service contracts governed by a rate order (the "Rate Order") issued in 1979 by the Railroad Commission of Texas (the "Railroad Commission"). The Rate Order provides for the sale of gas under such contracts at its weighted average cost, as defined ("WACOG"), plus a margin of $.15 per Mcf. WACOG includes purchases of high-cost casinghead gas and certain special allowable gas that is required to be purchased contractually and under the Railroad Commission's priority rules. In addition to the cost of gas purchases, WACOG has included storage, gathering and other fixed costs , including the amortization of deferred gas costs related to the settlement of take-or-pay and related claims. Sales volumes under these contracts have been decreasing as such contracts expire and are not renewed. As a result of these factors, the gas sales price for these contracts is substantially in excess of market clearing levels.
WACOG has been periodically audited by certain of the customers under the above noted contracts, as allowed under the Rate Order. As a result of an audit by one such customer (the "Customer"), the Company and the Customer entered into a settlement agreement which, among other things, excluded certain gas gathering costs from WACOG, effective with July 1993 sales, resulting in a reduction of annual operating income by approximately $6 million. In addition, beginning in 1998, the majority of storage costs previously included in WACOG, including the cost of the Company's natural gas storage facility (see Note 13 of Notes to Consolidated Financial Statements), will no longer be recovered through gas sales rates governed under the Rate Order.
In the course of making gas sales and providing transportation services to customers, the Company has in the past experienced overall net volumetric gains due to measurement and other volumetric differences related to the amounts of gas received and delivered, which during 1994 and 1993 resulted in increased gas sales revenues of approximately $20 million and $17 million, respectively. However, revenues resulting from such net volumetric gains are expected to be substantially reduced by the implementation of changes to measurement standards promulgated by the American Gas Association and now implemented by the Company, the expiration of certain gas purchase contracts in February 1995 and the further reduction in WACOG-based gas sales discussed above.
Natural Gas Liquids
Pro forma operating income from the Company's NGL operations decreased $1.4 million, or 3%, during 1994 compared to 1993 due to a decrease in revenues from transporting and fractionating volumes for third parties and an increase in transportation and fractionation expense, partially offset by a slight increase in NGL margins, a 3% increase in NGL production volumes and a decrease in operating and general expenses, primarily maintenance expense. NGL margins increased due to a decrease in fuel and shrinkage costs resulting from an 11% decrease in the average cost of natural gas, which more than offset a 6% decrease in the average NGL market price. Average natural gas costs decreased as a result of milder weather experienced during the fourth quarter of 1994, higher industry- wide natural gas storage inventories and the return to service of the STP during the 1994 second quarter, while average NGL prices decreased due to continued weak refined product prices during the first part of 1994.
The Company's NGL operations benefit from the strategic location of its facilities in relation to natural gas supplies and markets, particularly in South Texas which is a core supply area for the Company's natural gas and NGL operations. Approximately 83% of the Company's NGL production comes from plants in South Texas and the Texas Gulf Coast. As the Company's existing South Texas NGL pipeline and fractionation facilities are operating at or near capacity, the Company anticipates incurring either increased third-party transportation and fractionation fees or additional capital expenditures in the future in order to develop incremental South Texas NGL production opportunities. The Company's NGL operations should benefit in the longer term from the expected continued growth in demand for NGLs as petrochemical feedstocks and in the production of MTBE. A substantial portion of the Company's butane production is processed internally as feedstock for the Refinery's MTBE Plant. The demand for NGLs, particularly natural gasoline, will continue to be affected seasonally, however, by Environmental Protection Agency ("EPA") regulations limiting gasoline volatility during the summer months.
Other
Other operating revenues consisted primarily of management fees received by the Company from the Partnership equal to the direct and indirect costs incurred by the Company on behalf of the Partnership that were associated with managing the Partnership's operations. As discussed above under "Consolidated Results," such management fee revenues decreased in 1994 compared to 1993 as a result of the May 31, 1994 Merger.
Pro forma corporate general and administrative expenses and other, net, decreased in 1994 compared to 1993 due to the recognition in income in 1994 of deferred management fees, as noted above, and a decrease in employee benefit expenses resulting from various cost containment measures implemented by the Company in 1994.
1993 COMPARED TO 1992
Consolidated Results
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, for the year ended December 31, 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 fourth quarter of 1992. The 1993 fourth quarter and total year results were adversely 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. See "Segment Results - Refining and Marketing" below. The decrease in net income and earnings per share for the year was due primarily to a decrease in operating income and to a lesser extent to a decrease in equity in earnings of and income from the Partnership and an increase in net interest expense. The decreases resulting from these factors were partially offset by the recognition in the third quarter of 1993 of an approximate $5 million after-tax gain, net of other nonoperating charges, related to the disposition of the Company's natural gas distribution operations and a decrease in income tax expense.
Operating revenues decreased $12.4 million, or 1%, during 1993 compared to 1992 due primarily to a $12.1 million decrease in operating revenues from the Company's refining and marketing operations and to a lesser extent to a decrease in operating revenues from the Company's natural gas operations, partially offset by an increase in operating revenues from the Company's NGL operations. Operating income decreased $58.5 million, or 44%, due primarily to a decrease in refining and marketing operating income, partially offset to a small extent by increases in operating income from the Company's natural gas and NGL operations and a decrease in corporate expenses. See "Segment Results" below.
The Company's equity in earnings of and income from the Partnership decreased $2.7 million, or 10%, in 1993 compared to 1992 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 and an increase in interest income earned by the Company on capital lease transactions with the Partnership resulting from the inception on December 1, 1992 of the Company's lease to the Partnership of a new gas processing plant near Thompsonville in South Texas.
Partnership operating income by segment for 1993 and 1992, based on 100% of the Partnership's operations, was as follows (in thousands):
Operating income from the Partnership's NGL operations decreased 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 a significant decline in refined product prices, 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 an operating loss from NGL operations for the fourth quarter of 1993 compared to operating income 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 in 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, the settlement of certain favorable measurement, fuel usage and customer billing differences and an increase in gas cost reductions resulting from price risk management activities. Partially offsetting these increases in natural gas operating income was a decrease in the recovery of Transmission's fixed costs resulting from the settlement of the customer audit of Transmission's weighted average cost of gas discussed above under "1994 Compared to 1993 - -Segment Results - Natural Gas." For the fourth quarter of 1993, natural gas operating income increased compared to the fourth quarter of 1992 due to the factors noted above.
Net interest and debt expense increased $6.8 million in 1993 compared to 1992 due primarily to the issuance of medium- term notes during the second and fourth quarters of 1992 and to a decrease in capitalized interest resulting from the placing in service of the MTBE Plant during the second quarter of 1993. Income tax expense decreased in 1993 compared to 1992 due primarily to a decrease in pre-tax income, partially offset by a one-time, noncash charge to 1993 third quarter earnings of $8.2 million resulting from the effect of a one percent increase in the corporate income tax rate, from 34% to 35%, on the Company's balance of deferred income taxes as of December 31, 1992.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and marketing operations decreased $12.1 million, or 1%, during 1993 compared to 1992 as an 8% decrease in the average sales price per barrel was basically offset by an 8% increase in sales volumes. The decrease in the average sales price per barrel was due primarily to the precipitous drop in crude oil and refined product prices beginning in November 1993 resulting from, among other things, the decision by the Organization of Petroleum Exporting Countries ("OPEC") at its November 1993 meeting to forego any cuts in production. Increased production capacity resulting from operation of the MTBE Plant contributed to the increase in sales and throughput volumes. Operating income decreased $61.8 million, or 45%, during 1993 compared to 1992 due primarily to the $27.6 million inventory write-down recognized in the fourth quarter of 1993, a decrease in throughput margins resulting from the significant drop in refined product prices noted above, and an increase in Refinery operating costs and depreciation expense due to costs associated with operation of the MTBE Plant and other new Refinery units, partially offset by a 14% increase in average daily throughput volumes. The Refinery's average throughput margin per barrel, before operating costs and depreciation expense, decreased from $7.00 in 1992 to $5.99 in 1993 ($5.44, including the effect of the inventory write-down).
Natural Gas
Operating revenues from the Company's natural gas operations decreased $.7 million, or 2%, during 1993 compared to 1992 due primarily to the sale on September 30, 1993 of Rio Grande Valley Gas Company ("RGV"), the Company's natural gas distribution subsidiary. Operating income increased $.4 million, or 17%, during 1993 compared to 1992 due primarily to a decrease in operating and general expenses, partially offset by a decrease in transportation revenues.
Natural Gas Liquids
Operating revenues and operating income from the Company's NGL operations increased $4 million, or 8%, and $.8 million, or 9%, respectively, during 1993 compared to 1992 due primarily to the full-year effect in 1993 of the NGL assets acquired from Oryx Energy in May 1992.
Other
Other operating revenues, consisting primarily of management fees received by the Company from the Partnership, decreased in 1993 compared to 1992 due primarily to reduced management fees resulting from the nonrecurrence of one-time charges related to the Company's 1992 early retirement program, partially offset by the inclusion in management fees of other postemployment benefit costs commencing in 1993 and an increase in the percentage of costs allocated to the Partnership resulting from the sale of RGV. Corporate general and administrative expenses and other, net, decreased in 1993 compared to 1992 due primarily to the effects of the early retirement program and increased allocation of costs to the Partnership discussed above, partially offset by the above noted incurrence of other postemployment benefit costs commencing in 1993.
OUTLOOK
Refining and Marketing
The worldwide decrease in resid supplies which caused a narrowing of the Company's resid discount in 1994 is expected to continue to affect the market in 1995. However, refining and marketing operations are expected to benefit in 1995 from the completion of the 50% owned methanol plant with Celanese which should reduce the cost of the Company's methanol feedstocks used in MTBE production. As a result of the completion of several major units at the Refinery during the last few years, the Company is currently able to produce all of its gasoline as RFG. Various uncertainties in the January 1, 1995 mandated transition from conventional gasoline to RFG under regulations promulgated under the Clean Air Act resulted in severe declines in prices for RFG and oxygenates, including MTBE, beginning in December 1994. Combined with continued high costs for the Company's methanol feedstocks used in MTBE production, such decline in RFG and MTBE prices negatively impacted the Refinery's throughput margins and resulted in the Company temporarily reducing its MTBE production by 37% in December 1994. During January 1995, the Company resumed production of MTBE at capacity levels due to an improvement in market conditions. As the industry adapts to the RFG program in the first quarter of 1995, demand levels and pricing relationships among RFG, methanol and MTBE are likely to become more firmly established.
Natural Gas
Subject to seasonal variations in weather, demand for natural gas has remained strong and is expected to increase in the long term due to its desirability as a clean-burning fuel, which should benefit the Company's natural gas throughput volumes. Currently, the Company's natural gas operations continue to adjust to the changes in the natural gas industry resulting from the implementation of FERC Order No. 636 in 1993 and the trend of west-to-east movement of gas across the United States. The required unbundling of individual natural gas services by pipelines subject to FERC jurisdiction under Order 636 has created new interstate supply, marketing and transportation opportunities for the Company, although in an extremely competitive environment. In response to Order 636, the Company is continuing to emphasize diversification of its customer base through interstate sales, and to develop and expand its slate of value-added services, such as gas gathering, volume and capacity management, and gas processing, which it offers to both upstream and downstream customers. To capitalize on the trend of west-to-east movement of gas across the United States caused by increased production in western supply basins, recent pipeline expansions from such basins and Canada to the United States West Coast, and growing natural gas demand in the eastern United States, the Company in 1994 added additional compression to its North Texas pipeline, increasing its capacity to move gas across Texas. In addition, to develop new opportunities anticipated in connection with the FERC's deregulation of the electric power generation industry, the Company secured a power marketing certificate from the FERC in 1994 in order to participate in the wholesale bulk power business. During 1995, the Company intends to further develop these and other opportunities in the natural gas industry and believes that as a result, it should be able to increase its natural gas volumes in 1995.
Natural Gas Liquids
The Company's NGL operations benefit from its strong integration with the Company's natural gas and refining and marketing operations. The ability to process natural gas is a value-added service offered to producers and attracts additional quantities of gas to the Company's pipeline system, while production from the Company's NGL plants provides butane feedstock for the production of oxygenates at the Company's refinery. The demand for NGLs is expected to increase as a result of continued economic growth, petrochemical plant expansions and increased production of oxygenated and reformulated gasolines. The Company continues to emphasize the addition of new natural gas supplies under processing agreements with natural gas producers and the development and expansion of market alternatives for its NGL production. The Company continuously makes operational improvements at its NGL plants, which during 1994 resulted in an increase in its NGL production volumes, and anticipates further plant expansions and improvements which will further increase production volumes.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by the Company's operating activities totalled $68.1 million during 1994 compared to $141.3 million during 1993. The decrease in 1994 from 1993 was due primarily to an increase in working capital requirements attributable to the inclusion of Partnership operations commencing June 1, 1994, and an increase in refining and marketing working capital requirements resulting primarily from $37 million of costs incurred in 1993 but not paid until 1994 related to capital projects placed in service in the latter part of 1993. During 1994, the Company utilized the cash provided by its operating activities, bank borrowings and proceeds from the issuance of medium-term notes ("Medium-Term Notes") and Convertible Preferred Stock to fund capital expenditures, deferred turnaround and catalyst costs and investments in joint ventures, to pay common and preferred stock dividends, to make principal escrow payments under Valero Management Partnership, L.P.'s (the "Management Partnership") First Mortgage Notes (the "First Mortgage Notes"), to repay principal on certain outstanding nonbank debt and to acquire the publicly traded Common Units of VNGP, L.P.
As described in Note 2 of Notes to Consolidated Financial Statements, the Company used a portion of the approximate $168 million net proceeds from its March 1994 Convertible Preferred Stock issuance to fund the acquisition of the publicly traded Common Units of VNGP, L.P. and to pay expenses of the acquisition. The remaining proceeds were used to reduce bank borrowings.
In 1992, Energy filed with the Securities and Exchange Commission (the "Commission") a shelf registration statement for $150 million principal amount of Medium-Term Notes, $116 million of which had been issued as of December 31, 1993. During December 1994, Energy issued the remaining $34 million of Medium- Term Notes. Energy recently filed another shelf registration statement with the Commission to offer up to $250 million principal amount of additional debt securities, including Medium- Term Notes. The net proceeds from this offering will 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. See Note 4 of Notes to Consolidated Financial Statements. The Company's ratio of earnings to fixed charges, as computed based on rules promulgated by the Commission, was 1.74 and 1.30 on a historical and pro forma basis, respectively, for the year ended December 31, 1994.
Energy currently maintains an unsecured $250 million revolving bank credit and letter of credit facility which originally became effective upon the consummation of the Merger on May 31, 1994 and replaced all of the Company's and the Partnership's then existing bank credit facilities. Effective September 30, 1994, this facility was amended to provide for, among other things, a reduced interest rate on LIBOR advances, reduced commitment and utilization fees, elimination of sublimits for direct advances and letters of credit, and elimination of scheduled commitment reductions. As of December 31, 1994, Energy had approximately $85.7 million available under this committed bank credit facility for additional borrowings and letters of credit. Energy also has $130 million of unsecured short-term bank credit lines which are unrestricted as to use. Under the terms of Energy's $250 million credit facility, as amended, total borrowings under these short-term credit lines are limited to $100 million and any amounts outstanding under such short-term lines automatically reduce the availability under the $250 million credit facility. As of December 31, 1994, no amounts were outstanding under these short-term lines. Energy's revolving bank credit and letter of credit facility (which is the most restrictive of the Company's various financing agreements) contains various restrictive covenants, including restrictions on the ability of its subsidiaries to issue debt and on its ability to pay dividends and make certain other "restricted payments." Under the most restrictive of such covenants, the Company had the ability to pay approximately $36 million in common and preferred stock dividends and other restricted payments at December 31, 1994. In February 1995, Energy's bank credit facility was further amended to modify certain restrictive covenants resulting in increased financial flexibility for the Company. The Company's long-term debt includes the Management Partnership's First Mortgage Notes which were assumed by the Company in connection with the Merger, $506.4 million of which was outstanding at December 31, 1994. The indenture of mortgage and deed of trust pursuant to which the First Mortgage Notes were issued (the "Mortgage Indenture") also contains various restrictive covenants. The Company was in compliance with all bank credit and letter of credit facility and First Mortgage Note covenants as of December 31, 1994. Debt service on the Company's non-bank debt for both principal and interest, including payments into escrow for both principal and interest on the First Mortgage Notes, will be $153.2 million, $154.6 million, $150.8 million, $144.1 million and $138.6 million for the years 1995 through 1999, respectively. See Notes 3 and 4 of Notes to Consolidated Financial Statements.
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, 1994, Energy had repurchased 505,000 shares at an average price of $23.11 per share.
During 1994, the Company expended approximately $116 million for capital investments, including capital expenditures, deferred turnaround and catalyst costs and investments in and advances to joint ventures. Of this amount, $82 million related to refining and marketing operations including the turnaround of the HOC completed in October 1994, while $21 million related to the natural gas and NGL operations acquired in connection with the Merger. Included in the refining and marketing amount was a $15 million payment to the joint venture formed with Celanese in December 1994, to be used in renovating a 13,000-barrel-per-day methanol plant located in Clear Lake, Texas. The remaining $60 million of the Company's total $75 million commitment for the plant renovation will be paid in 1995. For 1995, the Company currently expects to incur approximately $160 million for capital expenditures, deferred turnaround and catalyst costs, and investments and related expenditures. Such amount includes the $60 million payment related to the methanol plant renovation discussed above, but excludes any expenditures related to the Company's investment in Proesa which is discussed separately below.
The Company currently owns a 35% interest in Productos Ecologicos, S.A. de C.V. ("Proesa"), a Mexican corporation which is involved in a project to design, construct and operate a plant in Mexico to produce MTBE. The plant, to be constructed at a site near the Bay of Campeche, has been estimated to cost approximately $450 million and to produce approximately 17,000 barrels of MTBE per stream day (based on an estimated 346 stream days per year). The Company has entered into a letter of understanding with Proesa's other shareholders under which the Company's ownership interest in Proesa would increase to 45%. Although this arrangement has not been formally documented and is subject to certain conditions, the Company has funded 45% of the project's costs since August 1994. At December 31, 1994, the Company had invested approximately $13.4 million in the project. The Company has also agreed to guarantee 45% of Proesa's obligation to a surety company related to an existing MTBE sales agreement between Proesa and Petroleos Mexicanos, S.A. ("Pemex"), the Mexican state-owned oil company. Based on the exchange rate at February 23, 1995, the Company's portion of such guarantee was approximately $3.3 million. Beginning in December 1994, the Mexican peso experienced substantial devaluation causing interest rates in Mexico to increase significantly and the Mexican stock market to experience a substantial decline in market value. In addition, current operating margins for MTBE are considerably lower than when the project was first conceived. Based on these and other factors, in January 1995, Energy's Board of Directors determined that the Company would suspend further investment in the project pending the resolution of certain key issues including, among other things, the renegotiation of purchase and sales agreements between Proesa and Pemex, the implementation of certain additional agreements with Pemex, a reevaluation of the economics of the project and the execution by Proesa's shareholders of a definitive agreement regarding their ownership interests in Proesa and their funding commitments to the project, including procedures for funding any possible cost overruns. If the foregoing matters can be satisfactorily resolved, the Company intends to proceed with the project. However, there can be no assurance that mutually satisfactory agreements can be reached between Proesa and Pemex or among Proesa's shareholders. The Company estimates that if the project is delayed and further expenditures are reduced to the minimum practicable level until resolution of the issues mentioned above, the Company will have a total investment in the project of approximately $18 million at the end of the first quarter of 1995, excluding any funding that may be required with respect to the guarantee of Proesa's obligation to a surety company discussed above. See Item 1. "Business -Recent Developments - Proesa MTBE Plant" and Note 6 of Notes to Consolidated Financial Statements.
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. Such dividend rate remained unchanged throughout 1994. Dividends are considered quarterly by the Energy Board of Directors, and may be paid only when approved by the Board. Because appropriate levels of dividends are determined by the Board on the basis of earnings and cash flows, the Company cannot assure the continuation of Common Stock dividends at any particular level.
The Company believes it has sufficient funds from operations, and to the extent necessary, from the public and private capital markets and bank market, to fund its current and ongoing operating requirements. The Company expects that it will raise additional funds from time to time through equity or debt financings, including borrowings under bank credit agreements; however, except for the $250 million debt securities shelf registration statement discussed above, the Company has no specific financing plans as of the date hereof.
The Company's refining and marketing operations have a concentration of customers in the oil refining industry and spot and retail gasoline markets. The Company's natural gas operations have a concentration of customers in the natural gas transmission and distribution industries while its NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact the Company's overall exposure to credit risk, either positively or negatively, in that the customers in each specific industry segment 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 potential credit risk. Historically, the Company has not had any significant problems collecting its accounts receivable. The Company's accounts receivable are generally not collateralized.
The Company is subject to environmental regulation at the federal, state and local levels. The Company's capital expenditures for environmental control and protection for its refining and marketing operations totalled approximately $6 million in 1994 and are expected to be approximately the same in 1995. These amounts are exclusive of any amounts related to constructed facilities for which the portion of expenditures relating to environmental requirements is not determinable. Capital expenditures for environmental control and protection for the Company's natural gas and NGL operations have not been significant to date and are not expected to be significant in 1995. The Refinery was completed in 1984 under more stringent environmental requirements than many existing United States refineries, which are older and were built before such environmental regulations were enacted. As a result, the Company believes that it may be able to more easily comply with present and future environmental legislation. Within the next several years, all U.S. refineries must obtain operating permits under provisions of the Clean Air Act Amendments of 1990 (the "Clean Air Act"). In addition, Clean Air Act provisions will require many of the Company's gas processing plants and gas pipeline facilities to obtain new operating permits. However, the Clean Air Act is not expected to have any significant adverse impact on the Company's operations and the Company does not anticipate that it will be necessary to expend any material amounts in addition to those mentioned above to comply with such legislation. 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
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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Antonio, Texas February 14, 1995
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. Certain prior period amounts have been reclassified for comparative purposes.
Energy conducts its refining and marketing 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"). Prior to May 31, 1994, the Company accounted for its effective equity interest of approximately 49% 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") using the equity method of accounting. Effective May 31, 1994, the Company acquired through a merger (the "Merger") the remaining effective equity interest of approximately 51% in the Partnership and changed the method of accounting for its investment in the Partnership to the consolidation method (see Note 2).
Revenue Recognition
Revenues generally are recorded when services have been provided or products have been delivered. Changes in the fair value of financial instruments related to trading activities are recognized in income currently. See "Price Risk Management Activities" below.
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, current deferred income tax assets, current maturities of long-term debt and short-term bank lines. Also excluded are the Partnership's current assets and liabilities as of the acquisition date (see Note 2). The changes in current assets and current liabilities, excluding the items noted above, 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 financing activities for the years ended December 31, 1994, 1993 and 1992 include reductions of $1.5 million, $1.3 million and $1.2 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 activities for 1994 include the remaining $60 million payment to be made in 1995 for the Company's interest in a methanol plant renovation project. Noncash investing activities for 1994 and 1993 also include the reclassification to property, plant and equipment and investment in and advances to joint ventures of $5.9 million and $5 million, respectively, previously included in deferred charges and other assets on the Consolidated Balance Sheets.
Inventories
The Company owns a specialized petroleum refinery (the "Refinery") in Corpus Christi, Texas. Refinery feedstocks and refined products and blendstocks are carried at the lower of cost or market with cost determined primarily under the last-in, first-out ("LIFO") method of inventory pricing. The excess of the replacement cost of such inventories over their LIFO values was approximately $26 million at December 31, 1994. 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 then existing market prices. Natural gas in underground storage, natural gas liquids ("NGLs") and materials and supplies are carried principally at weighted average cost not in excess of market. Inventories as of December 31, 1994 and December 31, 1993 are as follows (in thousands):
Refinery feedstock and refined product and blendstock inventory volumes totalled 8.9 million barrels ("MMbbls") and 8.1 MMbbls at December 31, 1994 and December 31, 1993, respectively. Natural gas inventory volumes totalled approximately 9.8 trillion British thermal units ("TBtus") at December 31, 1994.
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 of property units), 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," which 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
Deferred Gas Costs
Payments made or agreed to be made in connection with the settlement of certain disputed contractual issues with natural gas suppliers are initially deferred. The balance of deferred gas costs of $42 million at December 31, 1994 is included in noncurrent other assets and is expected to be recovered over the next seven years through natural gas sales rates charged to certain customers.
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.
Price Risk Management Activities
The Company enters into various exchange-traded and other financial instrument contracts with third parties to hedge the purchase costs and sales prices of inventories, operating margins and certain anticipated purchases of natural gas to be consumed in operations. Such contracts are designated at inception as either a hedge when there is a direct relationship to the price risk associated with the Company's inventories or future purchases and sales of commodities used in the Company's operations, or as a speculative contract where there is no such relationship. Gains and losses on hedges of inventories are included in the carrying amounts of inventories and are ultimately recognized in income as those assets are sold. Gains and losses related to anticipatory transactions and purchase and sales commitments are also deferred and are recognized in income or as adjustments of carrying amounts when the hedged transaction occurs. Certain of the Company's hedging activities could tend to reduce the Company's participation in rising margins but are intended to limit the Company's exposure to loss during periods of declining margins. For those contracts that are not designated as hedges, changes in the fair value of those contracts are recognized as gains or losses in income currently and are recorded in the statement of financial position at fair value at the reporting date. The Company determines the fair value of its exchange-traded contracts based on the settlement prices for open contracts, which are established by the exchange on which the instruments are traded. The fair value of the Company's over-the-counter contracts is determined based on market-related indexes or by obtaining quotes from brokers. See Note 5.
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. For the year ended December 31, 1994, the conversion of the Convertible Preferred Stock (see Note 8) is not assumed since its effect would be antidilutive. Potentially dilutive common stock equivalents were not material and therefore were also not included in the computation. The weighted average number of common shares outstanding for the years ended December 31, 1994, 1993 and 1992 was 43,369,836, 43,098,808 and 42,577,368, respectively.
Accounting Change
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." See Note 12.
Other Accrued Expenses
Other accrued expenses for the periods indicated are as follows (in thousands):
2. ACQUISITION OF VALERO NATURAL GAS PARTNERS, L.P.
In March 1994, Energy issued Convertible Preferred Stock (see Note 8) to fund the Merger of VNGP, L.P. with a wholly owned subsidiary of Energy. On May 31, 1994, the holders of common units of limited partner interests ("Common Units") of VNGP, L.P. approved the Merger. Upon consummation of the Merger, VNGP, L.P. became a wholly owned subsidiary of Energy and the publicly traded Common Units (the "Public Units") were converted into the right to receive cash in the amount of $12.10 per Common Unit. The Company utilized $117.5 million of the net proceeds from the Convertible Preferred Stock issuance to fund the acquisition of the Public Units. The remaining net proceeds of $50.4 million were used to reduce outstanding indebtedness under bank credit lines and to pay expenses of the acquisition. As a result of the Merger, all of the outstanding Common Units are held by the Company.
The Merger has been accounted for as a purchase and the purchase price has been allocated to assets acquired and liabilities assumed based on estimated fair values. The consolidated statements of income of the Company for the year ended December 31, 1994 and 1993, reflect the Company's effective equity interest of approximately 49% in the Partnership's operations for periods prior to and including May 31, 1994, and reflect 100% of the Partnership's operations thereafter.
The following unaudited pro forma financial information of Valero Energy Corporation and subsidiaries assumes that the above described transactions occurred for all periods presented. Such pro forma information is not necessarily indicative of the results of future operations.
Prior to the Merger, the Company entered into transactions with the Partnership commensurate with its status as the General Partner. The Company charged the Partnership a management fee equal to the direct and indirect costs incurred by it on behalf of the Partnership. In addition, the Company purchased natural gas and NGLs from the Partnership and sold NGLs to the Partnership. The Company paid the Partnership a fee for operating certain of the Company's assets. Also, the Company and the Partnership entered into other transactions, including certain leasing transactions. As of December 31, 1993, the Company had recorded approximately $31.8 million of accounts receivables, net of accounts payables, and had also recorded $105.5 million of leases receivable, due from the Partnership.
The following table summarizes transactions between the Company and the Partnership for the five months ended May 31, 1994 and for the two years in the period ended December 31, 1993 (in thousands):
3. SHORT-TERM BANK LINES
At December 31, 1994, Energy maintained nine separate short-term bank lines of credit totalling $130 million, under which no amounts were outstanding. Three of these lines are cancellable on demand, and the others expire at various times in 1995. 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 are limited to $100 million and any amounts outstanding reduce the availability under the $250 million credit facility described in Note 4.
4. LONG-TERM DEBT AND BANK CREDIT FACILITIES
Effective September 30, 1994, Energy amended its unsecured $250 million revolving bank credit and letter of credit facility which is available for working capital and general corporate purposes. The bank credit facility originally became effective upon the consummation of the Merger on May 31, 1994 and replaced VRC's $160 million secured revolving credit facility, Energy's $30 million unsecured revolving credit facility, and all of the Partnership's committed unsecured revolving credit facilities. Among other things, the amendment to the bank credit facility extended the term one year, reduced the interest rate on LIBOR advances, reduced commitment and utilization fees, eliminated sublimits for direct advances and letters of credit and eliminated scheduled commitment reductions. Borrowings under the amended facility bear interest, at the Company's option, at LIBOR plus .75% or at the agent bank's prime rate. The Company is charged various fees, including commitment fees on the unutilized portion, and various letter of credit and facility fees. As of December 31, 1994, Energy had approximately $85.7 million available under this committed bank credit facility for additional borrowings and letters of credit.
The bank credit facility contains covenants limiting Energy's ability to make certain "restricted payments," including dividend payments on and purchases, redemptions or exchanges of its capital stock, to make certain "restricted disbursements," including the restricted payments described above plus capital expenditures and certain capital investments, and to make advances and capital contributions to the Partnership. In February 1995, the bank credit facility was amended to increase by $50 million through December 31, 1995, the amount of "restricted disbursements" payable by Energy. The facility also contains covenants that require Energy to maintain a minimum consolidated working capital and net worth and also contains various financial tests including debt-to-capitalization, fixed charge and earnings coverage ratios. Under the most restrictive of such covenants, Energy had the ability to pay approximately $36 million in common and preferred stock dividends and other "restricted payments" at December 31, 1994.
In 1992, Energy filed with the Commission a shelf registration statement which was used to offer $150 million principal amount of Medium-Term Notes. These Medium-Term Notes have a weighted average life of approximately 7.97 years and a weighted average interest rate of approximately 8.77%. Energy recently filed another shelf registration statement with the Commission to offer up to $250 million principal amount of additional debt securities, including Medium-Term Notes. Net proceeds from any debt securities issued pursuant to this shelf registration statement will 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.
The Company's long-term debt also includes the Management Partnership's First Mortgage Notes (the "First Mortgage Notes"). The First Mortgage Notes, which are currently comprised of eight remaining series due serially from 1995 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, 1994, the First Mortgage Notes have a remaining weighted average life of approximately 6.7 years and a weighted average interest rate of 10.16% 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, 1994, $35.4 million 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 indenture of mortgage and deed of trust pursuant to which the First Mortgage Notes were issued (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. Under provisions of Energy's $250 million bank agreement, such indebtedness for working capital purposes must be provided by Energy and not by a third party. 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 Company was in compliance with all bank credit and letter of credit facility and First Mortgage Note covenants as of December 31, 1994.
Based on long-term debt outstanding at December 31, 1994, maturities of long-term debt, including sinking fund requirements and excluding borrowings under bank credit facilities, for the years ending December 31, 1996 through 1999 are approximately $69.7 million, $72.4 million, $75.1 million and $73.2 million, respectively. Maturities of long-term debt under bank credit facilities for the year ended December 31, 1997 are $133 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 $1,126 million and $584 million at December 31, 1994 and 1993, respectively. As a result of the Merger, the 1994 amount includes the fair value of the Partnership's long-term debt.
5. PRICE RISK MANAGEMENT ACTIVITIES
Refinery Feedstock and Refined Products Hedging
The Company uses its price risk management activities to hedge various portions of the Company's refining operations. The Company uses options and futures to hedge refinery feedstock purchases and refined product inventories in order to reduce the impact of adverse price changes on these inventories before the conversion of the feedstock to finished products and ultimate sale. Options and futures contracts at the end of 1994 had remaining terms of up to three months. As of December 31, 1994, 1.1 MMbbls or 12% of the Company's refining inventory position of 8.9 MMbbls were hedged. The amount of deferred hedge losses included as an increase to refinery inventory was $.4 million at December 31, 1994. The following table is a summary of the Company's contracts held or issued to hedge inventories as of December 31, 1994:
The Company also hedges anticipated transactions. Over- the-counter price swaps and futures are used to hedge refining operating margins for periods up to 12 months in order to lock in components of the margins, including the resid discount, the conventional crack spread and the premium product differentials. As of December 31, 1994, the Company had established open price swap positions for one or more of such components with respect to an average of 1.3 million barrels of feedstock and refined products per month through December 31, 1995. Through these open price swap positions on components of refining's operating margin, approximately 10% of the Company's anticipated 1995 refining margin was hedged as of December 31, 1994. The amount of explicit deferrals of hedging gains related to these anticipated transactions was $.1 million as of December 31, 1994. The Company also enters into commitments to buy and sell refinery feedstocks and refined products at fixed prices. These commitments usually extend for a period of less than 30 days and are at current market prices. The following table is a summary of the Company's futures contracts held or issued to hedge refining margins and commitments to purchase and sell refinery feedstocks and refined products as of December 31, 1994:
Natural Gas Hedging
The Company uses its price risk management activities to hedge various portions of the Company's natural gas and natural gas liquids operations. In its natural gas operations, the Company uses futures to hedge gas storage. As of December 31, 1994, 2.2 TBtus or 22% of the Company's natural gas inventory position of 9.8 TBtus were hedged. These futures run for periods of up to 13 months. The amount of deferred hedge gains included as a reduction of natural gas inventories was $5.7 million at December 31, 1994. The following table is a summary of the Company's contracts held or issued to hedge inventory:
The Company also hedges anticipated natural gas purchase requirements, including plant shrinkage and natural gas used in refining operations, natural gas liquids sales, and commitments to buy and sell natural gas at fixed prices, using futures and price swaps extending for periods of up to 15 months. Volumes hedged as of December 31, 1994, represent 23% of the expected annual plant shrinkage and 36% of the expected natural gas requirements of the refining operations. Explicitly deferred gains from anticipated hedges of $1.1 million as of December 31, 1994 will be recognized in the month being hedged. The Company also enters into basis swaps for location differentials at fixed prices which generally extend for periods up to 15 months. The following table is a summary of the Company's contracts held or issued to hedge plant shrinkage, refinery operations and natural gas purchase and sales commitments as of December 31, 1994:
Trading Activities
The Company enters into limited speculative transactions using its fundamental and technical analysis of market conditions to earn additional revenues. The types of instruments used include futures, price swaps, and over-the-counter and exchange- traded options. These contracts run for periods of up to 13 months. The following table is a summary of the Company's contracts held or issued for trading purposes as of December 31, 1994:
The following table discloses the fair values of contracts held or issued for trading purposes and net gains (losses) from trading activities as of or for the period ended December 31, 1994 (dollars in thousands):
Market and Credit Risk
The Company's price risk management activities involve the receipt or payment of fixed price commitments into the future. These transactions give rise to market risk, the risk that future changes in market conditions may make an instrument less valuable. The Company closely monitors and manages its exposure to market risk on a daily basis in accordance with policies limiting net open positions. The Company also monitors credit risk, the risk of nonperformance by counterparties to its swaps and purchase and sales commitments. Concentrations of customers in the refining and natural gas industries may impact the Company's overall exposure to credit risk, in that the customers in each specific industry may be similarly affected by changes in economic or other conditions. The Company believes that its counterparties will be able to satisfy their obligations under contracts.
6. INVESTMENTS
Proesa
Productos Ecologicos, S.A. de C.V. ("Proesa"), a Mexican corporation, is involved in a project (the "Project") to design, construct and operate a plant (the "Plant") in Mexico to produce methyl tertiary butyl ether ("MTBE"). The Plant, to be constructed at a site near the Bay of Campeche, has been estimated to cost approximately $450 million and to produce approximately 17,000 barrels of MTBE per stream day. Proesa is currently owned 35% by the Company, 10% by Dragados y Construcciones, S.A., a Spanish construction company and 55% by a corporation formed by a subsidiary of Banamex, Mexico's largest bank, and Infomin, S.A. de C.V., a privately owned Mexican corporation. At December 31, 1994, the Company had invested approximately $13.4 million in the Project. The Company has entered into a letter of understanding with Proesa's other shareholders under which, subject to certain conditions, the Company's ownership interest in Proesa would increase to 45%. The Company has agreed to guarantee 45% of Proesa's obligation to a surety company related to an MTBE sales agreement between Proesa and Petroleos Mexicanos, S.A. ("Pemex"), the Mexican state-owned oil company. Based on the exchange rate at February 23, 1995, the Company's portion of the guarantee was approximately $3.3 million.
In January 1995, the Board of Directors of Energy determined that the Company would suspend further investment in the Project pending resolution of key issues related to the Project. In particular, the Board has required the renegotiation of purchase and sales agreements between Proesa and Pemex, the implementation of certain additional agreements with Pemex, and a reevaluation of the economics of the Project. Additionally, the Board has required that the Project participants reach definitive agreement regarding their ownership interests in Proesa and their funding commitments to the Project, including procedures for funding any possible cost overruns. The Company estimates that if the Project is delayed and further expenditures are reduced to the minimum practicable level until resolution of the issues mentioned above, the Company will have a total investment in the Project of approximately $18 million at the end of the first quarter of 1995, excluding any funding that may be required with respect to the guarantee of Proesa's obligation to a surety company discussed above.
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 $16.3 million at December 31, 1994.
At December 31, 1994, the Company's investment in Javelina included its equity contributions and advances to Javelina of approximately $20.2 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.
7. 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, 1994 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 per share until November 30, 1995, 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 voting as a class with holders of any other series of preferred stock also in arrears may vote to elect two directors. No arrearages currently exist.
8. CONVERTIBLE PREFERRED STOCK
In March 1994, Energy issued 3,450,000 shares of its $3.125 convertible preferred stock ("Convertible Preferred Stock") with a stated value of $50 per share and received cash proceeds, net of underwriting discounts, of approximately $168 million. Each share of Convertible Preferred Stock is convertible at the option of the holder into shares of Common Stock at an initial conversion price of $27.03. The Convertible Preferred Stock may not be redeemed prior to June 1, 1997. Thereafter, the Convertible Preferred Stock may be redeemed, in whole or in part at the option of Energy, at a redemption price of $52.188 per share through May 31, 1998, and at ratably declining prices thereafter, plus dividends accrued to the redemption date.
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's three core businesses are specialized refining, natural gas and natural gas liquids. Refining converts high-sulfur atmospheric residual oil into premium products, including reformulated and unleaded gasoline, at its refinery, and sells those products principally on a spot and truck rack basis and also through the use of term contracts. Spot and term 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 eastern and midwestern United States. Natural gas operations consist of purchasing, gathering, transporting and selling natural gas, principally to gas distribution companies, electric utilities, pipeline companies and industrial customers and transporting natural gas for producers, other pipelines and end users. 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 for 1994 relate primarily to the refining and marketing segment's purchases of feedstocks and fuel gas from the natural gas liquids and natural gas segments. The Company has no foreign operations other than petroleum storage facilities and no single customer accounts for more than 10% of its operating revenues. The foregoing segment information reflects the Company's effective equity interest of approximately 49% in the Partnership's operations for periods prior to and including May 31, 1994, and reflects 100% of the Partnership's operations thereafter (see Note 2). Capital additions include the remaining $60 million payment to be made in 1995 for the Company's interest in a methanol plant renovation project.
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 $30, $903 and $1,758 for 1994, 1993 and 1992, 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, 1994, 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 ("AMT") credit carryforwards of approximately $82 million which are available to reduce future federal income tax liabilities. The ITC and ESOP tax credits of approximately $54 million expire in the years 1995 ($6 million), 1996 ($23 million), 1997 ($12 million), 1998 ($7 million) and 1999 through 2001 ($6 million) if not utilized and the AMT credit of approximately $28 million has no expiration date. The Company did not record any valuation allowances against deferred income tax assets at December 31, 1994.
The Company's federal income tax returns have been examined by the IRS for all taxable years through 1990. All issues were resolved with the exception of one in which the Company has petitioned the U.S. Court of Appeals. 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, 1994 and 1993 (in thousands):
Net periodic pension cost for the years ended December 31, 1994, 1993 and 1992 included the following components (in thousands):
Participation in the pension plan for employees of the Company commences upon attaining age 21 and the completion of one year of continuous service. A participant 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 8.7% and 7.2%, respectively, as of December 31, 1994 and 1993. The rate of increase in future compensation levels used in determining the projected benefit obligation as of December 31, 1994 and 1993 was 4% for nonexempt personnel and was 3% and 2%, respectively for exempt personnel. The expected long-term rate of return on plan assets was 9.25% and 9% as of December 31, 1994 and 1993, 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 1994, 1993 and 1992 were approximately $5 million, $7.5 million and $7.5 million, respectively, and are currently estimated to be $4.3 million in 1995. 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. Thrift Plan participants are automatically enrolled in the VESOP (see below). The Company makes contributions to the Thrift Plan to the extent employees' base contributions exceed the amount of the Company's contribution to the VESOP for debt service. Prior to 1994, the Company matched 100% of the employee contributions. In 1994, the Thrift Plan was amended to provide for a total Company match in both the Thrift Plan and the VESOP aggregating 75% of employee base contributions, with an additional contribution of up to 25% 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 1994, 1993 and 1992 were approximately $42,000, $660,000 and $348,000, respectively.
In 1989, the Company established the VESOP which is a leveraged employee stock ownership plan. Pursuant to a private placement in 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. During 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 second VESOP loan matures on August 15, 2001. The number of shares of Common Stock released at any semi-annual payment date is based on the proportion of debt service paid during the year to remaining debt service for that and all subsequent periods times the number of unreleased shares then outstanding. As explained above, the Company's annual contribution to the Thrift Plan is reduced by the Company's contribution to the VESOP for debt service. During 1994, 1993 and 1992, the Company contributed $3,160,000, $3,596,000 and $3,596,000, respectively, to the VESOP, comprised of $819,000, $947,000 and $1,065,000, respectively, of interest on the VESOP Notes and $2,777,000, $2,649,000 and $2,531,000, respectively, of compensation expense. Compensation expense is based on the VESOP debt principal payments for the portion of the VESOP established in 1989 and is based on the cost of the shares allocated to participants for the portion of the VESOP established in 1991. Dividends on VESOP shares of Common Stock are recorded as a reduction of retained earnings. Dividends on allocated shares of Common Stock are paid to participants and dividends on unallocated shares were paid to participants during 1993 and 1992. However, the Company's contributions to the VESOP during 1994 were reduced by $436,000 of dividends paid on unallocated shares. VESOP shares of Common Stock are considered outstanding for earnings per share computations. As of December 31, 1994 and 1993, the number of allocated shares were 817,877 and 669,660, respectively, the number of committed-to-be-released shares were 62,922 and 62,922, respectively, and the number of suspense shares were 897,893 and 1,086,659, 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 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, 1994 and 1993 (in thousands):
Net periodic postretirement benefit cost for the years ended December 31, 1994 and 1993 included the following components (in thousands):
For measurement purposes, the assumed health care cost trend rate was 9% in 1994, 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, 1994 by $3.7 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $.5 million. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation as of December 31, 1994 and 1993 was 8.7% and 7.2%, respectively.
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 for 1992.
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, 1994, 2,575,902 options were outstanding, at a weighted-average exercise price of $21.51 per share, of which 708,055 options were exercisable at a weighted- average exercise price of $23.13 per share. During 1994, 1,343,919 options were granted at a weighted-average exercise price of $19.43 per share, 7,555 options were exercised at a weighted-average exercise price of $14.53 per share and 22,086 options were terminated and/or forfeited. At December 31, 1994, there were 27,561 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, 1994, 133,969 SARs were outstanding and exercisable, at a weighted-average exercise price of $14.52 per share. During 1994, 5,346 SARs were exercised at a weighted-average exercise price of $14.54 per share.
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, 1994, there were 15,927 shares available for award and 3,000 shares were awarded under this plan during 1994. 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.
13. LEASE AND OTHER COMMITMENTS
The Company has major operating lease commitments in connection with a gas storage facility, its corporate headquarters office complex and various facilities used to store refinery feedstocks and refined products. The gas storage facility lease has a remaining primary lease term of five years with one eight-year optional renewal period during which the lease payments decrease by one-half, and, subject to certain conditions, one or more additional optional renewal periods of five years each at fair market rentals. In February 1995, the Company renegotiated the terms of the corporate headquarters lease under which the lease payments were reduced beginning in 1995. The future minimum lease payments for the office complex noted in the table below reflect the terms of the renegotiated agreement. The Company has operating leases for various facilities used to store refinery feedstocks and refined products. These leases have primary terms ranging from three to seven years with optional renewal periods ranging from three to ten years and provide for various contingent payments based on throughput volumes in excess of a base amount, among other things. The Company also has other noncancelable operating leases with remaining terms ranging generally from one year to 12 years. The related future minimum lease payments as of December 31, 1994 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 $14,040,000, $12,948,000, and $12,643,000 for 1994 (including Partnership rents commencing June 1, 1994), 1993 and 1992, respectively, and includes various month-to-month and other short-term rentals in addition to rents paid and accrued under long-term lease commitments. For the period prior to the Merger, 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 for the period prior to the Merger. Gas storage facility rentals paid by the Partnership for the period prior to the Merger, and paid by the Company for the period subsequent to the Merger, totalling $10,438,000 per year for 1994, 1993 and 1992, were included in the cost of gas.
The obligations of the Company 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 credit facilities could result in a cross default under the gas storage facility lease. The Company believes that it is unlikely that such a default would result in actual acceleration of the gas storage facility lease, and further believes that the occurrence of such event would not have a material adverse effect on the Company.
14. LITIGATION AND CONTINGENCIES
A lawsuit was filed in November 1994 against a wholly owned subsidiary of Energy arising from the rupture of several pipelines and fire as a result of severe flooding of the San Jacinto River in Harris County, Texas on October 20, 1994. The plaintiffs are property owners in Highlands, Crosby, Baytown, and McNair, Texas, and surrounding areas. The plaintiffs allege that the defendant pipeline owners were negligent and grossly negligent in failing to bury the pipelines at a proper depth to avoid rupture or explosion and in allowing the pipelines to leak chemicals and hydrocarbons into the flooded area. The original plaintiffs and additional intervening plaintiffs make other similar assertions and seek certification as a class. The plaintiffs assert claims for property damage, costs for medical monitoring, personal injury and nuisance. Plaintiffs seek an unspecified amount of actual and punitive damages.
Energy and certain of its subsidiaries are defendants in a lawsuit originally filed in January 1993. The lawsuit is based upon construction work performed by the plaintiff at certain of the Partnership's gas processing plants in 1991 and 1992. The plaintiff alleges that it performed work for the defendants for which it was not compensated. The plaintiff's second amended petition, filed April 30, 1994, asserts claims for breach of contract and numerous other contract and tort claims. The plaintiff alleges actual damages of approximately $9.7 million and punitive damages of $45.5 million. The defendants have filed a motion for partial summary judgement in order to dismiss the plaintiff's tort claims.
In 1987, Valero Transmission, L.P. ("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 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, excluding interest, 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. VT, L.P. has received no indication that any lawsuit has been filed by the royalty owners. The Company believes that various defenses may reduce or eliminate any liability of VT, L.P. to the producer in this matter.
Valero Transmission Company ("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. In 1989, the trusts brought suit against the supplier, alleging breach of various minimum take, take-or-pay and other contractual provisions, and asserting a statutory nonratability claim. In the trusts' claims against the supplier, the trusts seek alleged actual damages, including interest, of approximately $30 million. Neither VTC nor VT, L.P. was originally a party to the lawsuit. However, because of the relationship between VTC and VT, L.P'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. agreed in March 1991 to cooperate in the conduct of the litigation, and agreed 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 January 1993, the District Court ruled on the trusts' motion for summary judgment, finding 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, were not determined. On April 15, 1994, the trusts named VTC and VT, L.P. as additional defendants (the "Valero Defendants") to the lawsuit, alleging that the Valero Defendants maliciously interfered with the trusts' contracts with the supplier. In the trusts' claim against the Valero Defendants, the trusts seek unspecified actual and punitive damages. The Company believes that the claims brought by the trusts have been significantly overstated, and that the supplier and the Valero Defendants have a number of meritorious defenses to the claims.
A lawsuit was filed against VRC in June 1994 by certain residents of the Mobile Estate subdivision located near the Refinery, alleging that air, soil and water in the subdivision have been contaminated by emissions of allegedly hazardous chemicals and toxic hydrocarbons produced by VRC. The plaintiffs' claims include negligence, gross negligence, strict liability, nuisance and trespass. The plaintiffs seek certification as a class and an unspecified amount of damages, based on an alleged diminution in the value of their property, loss of use and enjoyment of property, emotional distress and other costs.
Valero Javelina Company, a wholly owned subsidiary of Energy, owns a 20% general partner interest in Javelina Company, a general partnership. Javelina Company has been named as a defendant in seven lawsuits filed since 1992 in state district courts in Nueces County and Duval County, Texas. Five 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 two 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 do not 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 statements; 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 interim period in which such resolution occurred.
15. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended December 31, 1994 and 1993 were as follows (in thousands of dollars, except per share amounts):
The Company's results of operations by quarter for 1994 were affected by decreased equity in earnings of the Partnership prior to the May 31, 1994 Merger and by the consolidation of the Partnership's results of operations thereafter. See Note 2. 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 then existing market prices. This was due to a significant decline in feedstock and refined product prices.
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, 1994 and 1993. . . . . . . . . . . . . . . . . . . . . . Consolidated statements of income for the years ended December 31, 1994, 1993 and 1992 . . . . . . . . . Consolidated statements of common stock and other stockholders' equity for the years ended December 31, 1994, 1993 and 1992 . . . . . . . . . . . . Consolidated statements of cash flows for the years ended December 31, 1994, 1993 and 1992 . . . . . . Notes to consolidated financial statements . . . . . . . .
2. Financial Statement Schedules and Other Financial Information-
No financial statement schedules are submitted because either they are inapplicable or because the required information is included in the Consolidated 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 -- $250,000,000 Credit Agreement, dated as of March 31, 1994, among Valero Energy Corporation, Bankers Trust Company and Bank of Montreal as Managing Agents, and the banks and co-agents party thereto--incorporated by reference from Exhibit 10.1 to the Valero Energy Corporation Quarterly Report on Form 10-Q (Commission File No. 1-4718, filed May 12, 1994). 4.3 -- First Amendment to Credit Agreement, dated as of September 30, 1994--incorporated by reference from Exhibit 10.2 to the Valero Energy Corporation Quarterly Report on Form 10-Q (Commission File No. 1-4718, filed November 14, 1994). *4.4 -- Form of Second Amendment to Credit Agreement, dated as of February 27, 1995. 4.5 -- Form of Indenture of Mortgage and Deed of Trust and Security Agreement, dated as of March 25, 1987 (the "Indenture"), from Valero Management Partnership, L.P. to State Street Bank and Trust Company (successor to Bank of New England) and Brian J. Curtis, as Trustees - incorporated by reference from Exhibit 4.1 to the Valero Natural Gas Partners, L.P. Quarterly Report on Form 10-Q (Commission File No. 1-9433, filed May 15, 1987). 4.6 -- First Supplemental Indenture, dated as of March 25, 1987, to the Indenture - incorporated by reference from Exhibit 4.2 to the Valero Natural Gas Partners, L.P. Quarterly Report on Form 10-Q (Commission File No. 1-9433, filed May 15, 1987). 4.7 -- Second Supplemental Indenture, dated as of March 25, 1987, to the Indenture - incorporated by reference from Exhibit 4.1 to the Valero Natural Gas Partners, L.P. Quarterly Report on Form 10-Q (Commission File No. 1-9433, filed July 31, 1987). 4.8 -- Fourth Supplemental Indenture, dated as of June 15, 1988, to the Indenture - incorporated by reference from Exhibit 4.6 to the Valero Natural Gas Partners, L.P. Registration Statement on Form S-8 (Registration No. 33- 26554, filed January 13, 1989). 4.9 -- Fifth Supplemental Indenture, dated as of December 1, 1988, to the Indenture - incorporated by reference from Exhibit 4.7 to the Valero Natural Gas Partners, L.P. Registration Statement on Form S-8 (Registration No. 33-26554, filed January 13, 1989). 4.10 -- Seventh Supplemental Indenture, dated as of August 15, 1989, to the Indenture - incorporated by reference from Exhibit 4.6 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1- 9433, filed March 1, 1990). 4.11 -- Ninth Supplemental Indenture, dated as of October 19, 1990, to the Indenture - incorporated by reference from Exhibit 4.7 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1- 9433, filed February 25, 1991). +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. +10.11 -- Amended and Restated Employment Agreement between Valero Energy Corporation and William E. Greehey, dated November 1, 1993-- 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, 1994). *+10.12 -- Modification of Employment Agreement between Valero Energy Corporation and William E. Greehey, dated November 29, 1994. +10.13 -- 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). *+10.14 -- Schedule of Indemnity Agreements. *11.1 -- Computation of Earnings Per Share. *12.1 -- Computation of Ratio of Earnings to Fixed Charges. *21.1 -- Valero Energy Corporation subsidiaries, including state or other jurisdiction of incorporation or organization. *23.1 -- Consent of Arthur Andersen LLP, dated February 28, 1995. *24.1 -- Power of Attorney, dated February 28, 1995--set forth at the signatures page of this Form 10-K. **27.1 -- Financial Data Schedule. ______________ [FN] * 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. ** The Financial Data Schedule shall not be deemed "filed" for purposes of Section 11 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934, and is included as an exhibit only to the electronic filing of this Form 10-K in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T.
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, 1994.
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), No. 33-53796 (filed October 27, 1992), and No. 33-52533 (filed March 7, 1994).
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.
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, 1995
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, 1995 (William E. Greehey)
Senior Vice President and Chief Financial Officer (Principal Financial /s/ Don M. Heep and Accounting Officer) March 1, 1995 (Don M. Heep)
/s/ Edward C. Benninger Director March 1, 1995 (Edward C. Benninger)
/s/ Robert G. Dettmer Director March 1, 1995 (Robert G. Dettmer)
/s/ A. Ray Dudley Director March 1, 1995 (A. Ray Dudley)
/s/ Ruben M. Escobedo Director March 1, 1995 (Ruben M. Escobedo)
/s/ James L. Johnson Director March 1, 1995 (James L. Johnson)
/s/ Lowell H. Lebermann Director March 1, 1995 (Lowell H. Lebermann)
/s/ Susan Kaufman Purcell Director March 1, 1995 (Susan Kaufman Purcell)