-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TSoHRbzskQ5dPbo5n3bZecweGq8vsGjnQfdzIOhB1M1pDWJRECSHvP/QGFUfCMTr y0REsC0Pnx2KHm8kHQ0akQ== 0000021271-97-000009.txt : 19970514 0000021271-97-000009.hdr.sgml : 19970514 ACCESSION NUMBER: 0000021271-97-000009 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970513 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: VALERO ENERGY CORP CENTRAL INDEX KEY: 0000021271 STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911] IRS NUMBER: 741244795 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-04718 FILM NUMBER: 97602257 BUSINESS ADDRESS: STREET 1: 530 MCCULLOUGH AVE CITY: SAN ANTONIO STATE: TX ZIP: 78215 BUSINESS PHONE: 2102462000 FORMER COMPANY: FORMER CONFORMED NAME: COASTAL STATES GAS PRODUCING CO DATE OF NAME CHANGE: 19791115 10-K405/A 1 FORM 10-K/A FORM 10-K/A SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [X] For the fiscal year ended December 31, 1996 OR [ ] For the transition period from __________ to __________ Commission file number 1-4718 VALERO ENERGY CORPORATION (Exact name of registrant as specified in its charter) Delaware 74-1244795 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 530 McCullough Avenue 78215 San Antonio, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code (210) 246-2000 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered __________________________________ _______________________ Common Stock, $1 Par Value New York Stock Exchange $3.125 Convertible Preferred Stock New York Stock Exchange Preference Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value on January 31, 1997, of the registrant's Common Stock, $1.00 par value ("Common Stock"), held by nonaffiliates of the registrant, based on the average of the high and low prices as quoted in the New York Stock Exchange Composite Transactions listing for that date, was approximately $1.3 billion. As of January 31, 1997, 44,273,350 shares of the registrant's Common Stock were issued and outstanding. CONTENTS PAGE PART I Item 1. Business. . . . .. . . . . . . . . . . . . . . . . Proposed Restructuring . . . . . . . . . . . . . . Refining and Marketing . . . . . . . . . . . . . . Refining Operations . . . . . . . . . . . . . . Sales . . . . . . . . . . . . . . . . . . . . . Feedstock Supply . . . . . . . . . . . . .. . . Factors Affecting Operating Results . . . . . . Natural Gas Related Services . . . . . . . . . . . Transmission System . . . . . . . . . . . . . . Sales and Marketing . . . . . . . . . . . . . . Transportation. . . . . . . . . . . . . . . . . Supply and Storage. . . . . . . . . . . . . . . Natural Gas Liquids . . . . . . . . . . . . . . Electric Power. . . . . . . . . . . . . . . . . Governmental Regulations . . . . . . . . . . . . . Federal Regulation. . . . . . . . . . . . . . . Texas Regulation. . . . . . . . . . . . . . . . Competition. . . . . . . . . . . . . . . . . . . . Refining and Marketing. . . . . . . . . . . . . Natural Gas Related Services. . . . . . . . . . Environmental Matters. . . . . . . . . . . . . . . Employees. . . . . . . . . . . . . . . . . . . . . Item 2. Properties . . . . . . . . . . . . . . . . . . . . Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . Item 6. Selected Financial Data. . . . . . . . . . . . . . Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . Item 8. Financial Statements . . . . . . . . . . . . . . . Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . PART III Item 10. Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . Directors of the Registrant. . . . . . . . . . . . Executive Officers of the Registrant . . . . . . . Section 16(a) Beneficial Ownership Reporting Compliance. . . . . . . . . . . . . . . . . . . Item 11. Executive Compensation . . . . . . . . . . . . . . Summary Compensation . . . . . . . . . . . . . . . Stock Option Grants and Related Information. . . . Retirement Benefits. . . . . . . . . . . . . . . . Compensation of Directors. . . . . . . . . . . . . Arrangements with Certain Officers and Directors . Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . Item 13. Certain Relationships and Related Transactions . . PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . . PART I 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. The Company is a diversified energy company engaged in the production, transportation and marketing of environmentally clean fuels and products. The Company's core businesses are specialized refining and natural gas related services. 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 ("RFG"), and markets those refined products. The Company also has a network of approximately 7,500 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 North America, and provides gas transportation and price risk management services to third parties. The Company also owns and operates eight natural gas processing plants and is a major producer and marketer of natural gas liquids ("NGLs"). The Company is also a marketer of electric power. 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 11 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." PROPOSED RESTRUCTURING On January 31, 1997, the Company announced that its Board of Director's had approved an agreement and plan of merger with PG&E Corporation ("PG&E") to combine the Company's natural gas related services business with PG&E following the spin-off of the Company's refining and marketing business to the Company's shareholders (the "Restructuring"). Under the terms of the merger agreement, the Company's natural gas related services business will be merged with a wholly owned subsidiary of PG&E. PG&E will acquire the Company's natural gas related services business for approximately $1.5 billion, plus adjustments for working capital and other considerations. PG&E will issue $722.5 million of common stock, subject to certain closing adjustments, in exchange for outstanding shares of Energy's common stock, and will assume certain outstanding debt and other liabilities. Each Energy shareholder will receive a fractional share of PG&E common stock (trading on the New York Stock Exchange under the symbol "PCG") for each Energy share; the amount of PG&E stock to be received will be based on the average price of the PG&E common stock during a period preceding the closing of the transaction and the number of Energy shares issued and outstanding at the time of the closing. Energy's shareholders will also receive one share of the spun-off refining and marketing company for each share of Energy common stock. The refining and marketing company will retain the Valero name and will apply to be listed on the New York Stock Exchange. The refining and marketing company expects to aggressively pursue acquisitions and strategic alliances in the refining and marketing industry. The spin-off of the refining and marketing business and the merger with PG&E are expected to be tax-free transactions. However, on February 6, 1997, President Clinton's budget recommendations to Congress called for new legislation that, if enacted, may require Energy to pay federal income tax upon the consummation of the Restructuring on the amount of gain equal to the excess of the value of the refining and marketing company stock distributed to Energy's stockholders over Energy's basis in such stock. Even though this legislation has not yet been introduced in Congress, the proposal would be effective for distributions after the date of first committee action. It is uncertain whether any such legislation ultimately will be enacted, whether its effective date provision may be modified, or when committee action in Congress may first occur. The Company believes it is likely that any legislation ultimately enacted will provide an exemption for transactions like the Restructuring for which definitive agreements were executed prior to introduction of the President's budget; however, if the proposal is enacted or pending prior to consummation of the Restructuring with an effective date provision that could cause Energy to be subject to tax, the tax opinions described below may not be available. The Restructuring transactions are subject to approval by the Company's shareholders, the Securities and Exchange Commission, and certain regulatory agencies as well as receipt of favorable tax opinions. The Company expects to hold a special meeting of stockholders (in lieu of an annual meeting) to consider the Restructuring transactions in June 1997. The Restructuring transactions are expected to be completed by mid-1997. However, there can be no assurance that the various approvals and opinions will be given or that the conditions to consummating the transactions will be met. REFINING AND MARKETING Refining Operations The Refinery processes high-sulfur atmospheric tower bottoms, a type of residual fuel oil ("resid"), and other feedstocks into a product slate of higher value products, principally RFG and middle distillates. The Refinery can produce approximately 171,500 barrels per day of refined products, with gasoline and gasoline-related products comprising approximately 85% of the Refinery's production, 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 refining and marketing operating results for the three years ended December 31, 1996, 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 the heavy oil cracking complex ("HOC"). The HDS Unit removes sulfur and metals from resid to improve the resid's subsequent cracking characteristics. The HDS Unit has a capacity of approximately 70,000 barrels per day. The HOC processes feedstock primarily from the HDS Unit, and has a capacity of approximately 74,000 barrels per day. The Refinery's other significant units include a 36,000 barrel-per-day "Hydrocracker" (which produces reformer feed naphtha from the Refinery's gas oil and distillate streams), a 36,000 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 31,000 barrel-per-day reformate splitter (which separates a benzene concentrate stream from reformate produced at the Reformer), a 30,000 barrel-per-day crude unit, and a 24,000 barrel-per-day vacuum unit. Also located at the Refinery are the Company's MTBE Plant (the "MTBE Plant") and "MTBE/TAME Unit." The MTBE Plant can produce approxi- mately 17,000 barrels per day of methyl tertiary butyl ether ("MTBE") from butane and methanol feedstocks. MTBE is an oxygen-rich, high-octane gasoline blendstock produced by reacting methanol and isobutylene, and is used to manufacture oxygenated and reformulated gasolines. The Company can blend the MTBE produced at the Refinery into the Company's own gasoline production or sell the MTBE separately. The Refinery's "MTBE/TAME Unit" converts certain streams produced by the HOC into MTBE and tertiary amyl methyl ether ("TAME"). TAME, like MTBE, is an oxygen-rich, high-octane gasoline blendstock. The MTBE Plant and MTBE/TAME Unit enable the Company to produce approximately 22,500 barrels per day of total oxygenates. Substantially all of the methanol feedstocks required for the production of oxygenates at the Refinery can be provided by a methanol plant owned by a joint venture between the Company and Hoechst Celanese Chemical Group, Inc. (the "Methanol Plant"). The Methanol Plant can produce approximately 13,000 barrels per day of methanol. In January 1997, the Company placed into service a "Xylene Fractionation Unit" which recovers xylenes from the Reformer's reformate stream. The fractionated xylene may be sold into the petrochemical feedstock market for use in the production of paraxylene. The Xylene Fractionation Unit can recover a mixed xylene stream of approximately 6,500 barrels per day. The MTBE Plant, MTBE/TAME Unit, Xylene Fractionation Unit and related facilities diversify the Company's product mix and enable the Company to pursue the higher margin product markets. In 1996, the Company completed scheduled turnarounds on its HDS Unit, Hydrocracker, Reformer, and MTBE Plant. The capacity of the MTBE Plant was increased by approximately 1,500 barrels per day. During the second quarter of 1996, the Company experienced unscheduled down time at the Refinery because of two power outages. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations." The Refinery's other principal refining units operated during 1996 without significant unscheduled down time. However, the Methanol Plant in Clear Lake suffered an explosion in early December. There were no injuries, but the Company's share of repair costs is estimated to be $2.5 million. The plant is expected to resume operations in late February 1997. The MTBE Plant was down for nine days in January 1997 to replace a portion of catalyst in the unit. During 1997, the HDS Unit is scheduled to be down for approximately 18 days in the fourth quarter to replace the catalyst in the unit. The crude unit is scheduled to be down for approximately 14 days in the second quarter of 1997 for a maintenance turnaround designed to increase the unit's capacity. 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, 1996. 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. Year Ended December 31, 1996 1995 1994 Throughput volumes (Mbbls per day). . . . 170 160 146 Average throughput margin per barrel. . . $5.29 $6.25 $5.36 Sales volumes (Mbbls per day) . . . . . . 291 231 140 [FN] Revised for 1995 to include sales volumes related to certain refining and marketing trading activities previously classified as a reduction of cost of sales. The Company sells refined products under term contracts as well as on a spot and truck rack basis. A truck rack sale is a sale to a customer that provides trucks to take delivery at loading facilities. In 1996, term, spot and truck rack sales volumes accounted for approximately 35%, 49% and 16%, respectively, of total gasoline and distillate sales. Sales of refined products under term contracts are made principally to large oil companies. 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 northeastern, midwestern or southeastern United States. The Company plans to continue to produce a high percentage of its refined products as RFG and focus marketing efforts on the RFG and oxygenate markets. Approximately 50% of the Company's RFG production is under contract to supply wholesale gasoline marketers in Texas at market-related prices; another 17% is under contract to gasoline marketers in the northeast United States, which is currently the largest RFG market in the United States. In 1996, the Company also supplied approximately 1.5 million barrels of "CARB II" gasoline in the West Coast markets in connection with the commencement of the California Air Resources Board's gasoline program. See "Refining and Marketing - Factors Affecting Operating Results." Feedstock Supply The predominant feedstock for the Refinery is resid produced at refineries outside the United States. Most of the large refineries in the United States are 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. These supplies are loaded aboard chartered vessels and are subject to the usual maritime hazards. The Company maintains insurance on its feedstock cargos. The Company has entered into several term agreements for the supply of approximately 58,000 barrels per day of resid feedstocks at market- related prices which provide for approximately 70% of the Company's estimated resid feedstock requirements for 1997. These supply agreements include an agreement with the Saudi Arabian Oil Company to provide an average of 36,000 barrels per day of A960 resid from its Ras Tanura refinery to the Company through mid-1998. The Company believes that if any of its existing feedstock arrangements were interrupted or terminated, supplies of resid could be obtained from other sources or on the open market; however, the Company could be required to incur higher feedstock costs or substitute other types of resid, thereby producing less favorable operating results. Over the past few years, demand for the type of resid feedstock now processed at the Refinery has increased in relation to the availability of supply. See "Refining and Marketing - Factors Affecting Operating Results." The Company also recently entered into term contracts for the supply of crude oil feedstocks for the Refinery's crude unit, including a contract for approximately 22,000 barrels per day of Daqing sweet crude oil for the first six months of 1997, and a contract for approximately 8,000 barrels per day of domestically produced crude extending through 1997. The remainder of the Refinery's resid and crude feedstocks are purchased at market-based prices under short-term contracts. All of the butane and methanol feedstocks required to operate the MTBE Plant are available through the Company's operations. The Company also supplies at least one-half of the Methanol Plant's natural gas feedstock requirements. The Company owns refining feedstock and product storage facilities with a capacity of approximately 6.9 million barrels. Approximately 4.4 million barrels of storage capacity are heated tanks for heavy feedstocks. The Company also leases fuel oil and refined product storage facilities in various locations, including approximately 600,000 barrels of gasoline storage in the Houston area. See Note 14 of Notes to Consolidated Financial Statements. The Company also owns dock facilities at the Refinery that can unload simultaneously two 150,000 dead-weight ton capacity ships and can dock larger crude carriers after partial unloading. Factors Affecting Operating Results The Company's refining and marketing operating results are affected by the relationship between refined product prices and resid prices, which in turn are largely determined by market forces. The price of resid is affected by the relationship between the growth in the demand for fuel oil and other products (which increases crude oil demand, thereby increasing the supply of resid when more crude oil is processed) and worldwide additions to resid conversion capacity (which has the effect of reducing the available supply of resid). The crude oil and refined products 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. Because the Refinery is more complex than many conventional refineries, and is designed principally to process resid rather than crude oil, its operating costs per barrel are generally higher than those of most conventional refineries. But because resid usually sells at a large enough discount to crude oil, the Company is generally able to recover its higher operating costs and generate higher margins than many conventional refiners that use crude oil as their principal feedstock. Moreover, through recent technology improvements, the Refinery has improved its ability to process different types of feedstocks, including synthetic domestic heavy oil blends that have been successfully processed in the HDS Unit. Saudi Arabian Oil Company has advised the Company that it plans to begin operation of certain new resid conversion units in 1998 at the Ras Tanura refining complex in Saudi Arabia. As a result, the production of resid at Ras Tanura for export is expected to be significantly reduced. The resid feedstock purchased by the Company from Saudi Arabian Oil Company is produced at Ras Tanura. Accordingly, a reduction in resid production at Ras Tanura could adversely affect the price or availability of resid feedstocks in the future. 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 crude distillation and 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. Because the Refinery is able to manufacture all of its gasoline as RFG and can produce approximately 22,500 barrels per day of total oxygenates, certain federal and state clean-fuels programs significantly affect the operations of the Company and the markets in which the Company sells its refined products. First, the EPA's oxygenated fuel program under the Clean Air Act Amendments of 1990 (the "Clean Air Act") requires for certain winter months that areas designated nonattainment for carbon monoxide use gasoline that contains a prescribed amount of clean burning oxygenates. Second, the EPA's RFG program under the Clean Air Act is required in areas designated "extreme" or "severe" nonattainment for ozone. In addition to these nonattainment areas, approximately 43 of the 87 areas that were designated as "serious," "moderate," or "marginal" nonattainment for ozone also "opted in" to the RFG program to decrease their emissions of hydrocarbons and toxic pollutants. In 1996, California adopted a state-wide, year-round program requiring the use of gasoline that meets more restrictive emissions specifications than the federally mandated RFG. Under the California gasoline program, areas not subject to either the federal oxygenated fuels program or the federal RFG program may use between zero and 2.7 percent oxygen by weight in their gasoline (sometimes known as "CARB II" gasoline) so long as the gasoline meets the California emissions standards. [FN] Oxygenates are liquid hydrocarbon compounds containing oxygen. Gasoline that contains oxygenates usually has lower carbon monoxide emissions than conventional gasoline. The Clean Air Act and certain state laws require oxygenated gasoline to have a minimum oxygen content of 2.7 percent by weight. As of September 1996, only 31 of the original 42 areas designated as nonattainment for carbon monoxide remain designated as nonattainment. As areas have come into "attainment," they generally have left the oxygenated fuels program. However, Minnesota elected to use oxygenated gasoline statewide and year-round beginning in 1997, and other states are considering similar requirements. The use of RFG reduces the emissions of ozone-forming compounds, carbon monoxide and air toxics such as benzene. RFG is manufactured in compliance with the EPA's "simple model" (i) by substantially reducing the amount of aromatics and benzene from gasoline, (ii) by adding an oxygenate (primarily MTBE or ethanol), and (iii) by reducing the vapor pressure of the gasoline during summer months. The oxygen content of RFG must average at least 2.1 percent by weight over the yearly reporting period. The benzene content must average less than 0.95 percent by volume over the yearly reporting period. The governor of Arizona recently petitioned the EPA to "opt-in" the Phoenix area into the RFG program. In 1998, RFG will be certified using the EPA's "complex model" which will evaluate a gasoline based on its overall quality and emissions performance rather than solely on discrete parameters. MTBE margins are affected by the price of the MTBE and its feedstocks, methanol and butane, as well as the demand for RFG, oxygenated gasoline, and premium gasoline. The worldwide movement to reduce lead in gasoline is expected to increase worldwide demand for oxygenates to replace the octane provided by lead-based compounds. The general United States growth in gasoline demand as well as additional "opt-ins" by certain areas into the EPA clean fuels programs are expected to continue to grow the demand for MTBE. NATURAL GAS RELATED SERVICES The Company's natural gas related services business is a midstream natural gas business offering value-added services and products to producers and end-users throughout North America. The Company owns and operates natural gas pipeline systems serving Texas intrastate markets, and the Company markets natural gas throughout North America through interconnections with interstate pipelines. The Company's natural gas pipeline and marketing operations consist principally of gathering, processing, storage and transportation of natural gas, and the marketing of 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 also owns and operates eight gas processing plants and is a major producer and marketer of NGLs. The Company's NGL operations include the gathering of natural gas, the extraction of NGLs from natural gas, the fractionation of mixed NGLs into component products (e.g., ethane, propane, butane, natural gasoline), and the transportation and marketing of NGLs. Through its natural gas related services business, the Company also markets electric power and engages in price-risk management activities to complement and enhance its merchant business. [FN] These operations are conducted primarily through Valero Natural Gas Partners, L.P. ("VNGP, L.P.") and its subsidiaries (the "Partnership"). These operations were acquired in connection with the 1994 merger described in Note 3 of Notes to Consolidated Financial Statements. 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. For comparability purposes, the information and statistics presented in this Part I for 1994 reflect the consolidation of the Partnership with Energy for all of such year on a pro forma basis. 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 7,500 miles of mainlines, lateral lines and gathering lines. The Transmission System is located primarily along the Texas Gulf Coast and throughout South Texas and is positioned to access most of the major producing and consuming regions in the United States. The Transmission System extends 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. The Transmission System includes 39 mainline compressor stations with a total of approximately 181,000 horsepower, together with gas processing plants, dehydration and gas treating plants and numerous measuring and regulating stations. The Transmission System is able to handle widely varying loads caused by changing supply and demand patterns. The Trans- mission System also supports the power generation grid in Texas, providing opportunities to trade these markets using gas and power interchangeably. The Transmission System's average annual throughput was approximately 2.8 Bcf per day in 1996. The Company's owned and leased pipeline systems have 74 interconnects with 21 intrastate pipelines, 43 interconnects with 14 interstate pipelines, and one interconnect with Pemex in South Texas. [FN] This amount includes gas sales and transportation volumes through the Transmission System in 1996, and does not include off-system sales of approximately 0.6 Bcf per day. Mcf (thousand cubic feet) 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. The term "Btu" means British Thermal Unit, a standard measure of heating value. The number of MMBtu's of total natural gas deliveries is approximately equal to the number of Mcf's of such deliveries. The terms MMBtu, BBtu and TBtu mean million Btu's, billion Btu's, and trillion Btu's, respectively. Sales and Marketing The following table sets forth the Company's gas sales volumes and average gas sales prices for the three years ended December 31, 1996. Year Ended December 31, 1996 1995 1994 Intrastate sales (MMcf per day) . . 700 656 633 Interstate sales (MMcf per day) . . 993 773 506 Total . . . . . . . . . . . . 1,693 1,429 1,139 Average gas sales price per Mcf . . $2.55 $1.74 $2.07 Sales of natural gas accounted for approximately 50%, 50% and 45% of the Company's total daily gas volumes for 1996, 1995 and 1994, 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 1996, the Company sold natural gas under hundreds of separate short- and long-term gas sales contracts. Total gas sales volumes made by the Company increased 77% over a four-year period from approximately 957 MMcf per day in 1992 to 1,693 MMcf per day in 1996. The Company's off-system marketing business, which increased from 70 MMcf per day of sales in 1992 to 599 MMcf per day in 1996, was a large contributor to this increase. The Company's gas sales are made primarily to gas distribution companies, electric utilities, gas marketers, other pipeline companies and industrial users. The Company's gas sales contracts with its intrastate customers generally require the Company to provide a fixed and determinable quantity of gas; however, certain gas sales contracts with intrastate customers provide for either maximum volumes or total customer requirements. The gas sold to local distribution companies ("LDCs") is resold to consumers in a number of cities including San Antonio, Dallas, Austin, Corpus Christi and Chicago. The Company continues to emphasize diversification of its customer base through interstate sales. By the end of 1996, the Company had secured contracts to provide gas supply and swing services to certain LDCs, electric utilities and industrial customers primarily in the midwest, northwest and western United States providing for deliveries of up to approximately 815 MMcf per day with terms ranging from one to three years. The Company has marketing offices located throughout Texas as well as in Los Angeles, Chicago, Louisville and Calgary, and offers a broad range of marketing and gas related services. - The Company's Market Center Services Program ("Market Center"), provides pricing and price-risk management services to both gas producers and end users. The Market Center uses financial instruments such as futures, swaps and options to manage the price- risk exposure within the Company, and to offer customized pricing arrangements with both the Company's suppliers and its customers. Activities of the Market Center have improved the Company's ability to capture and optimize gas transportation, storage and sales margins, as well as manage gas price volatility for the Company's gas processing business. See Note 6 of Notes to Consolidated Financial Statements. - In 1996, the Company formed its Midwest Retail Natural Gas Marketing Group to provide natural gas and related services to industrial and commercial customers in the greater Chicago area. This retail marketing group expands and complements the Company's wholesale gas marketing and power marketing businesses. - The Company operates the Waha Hub in West Texas. The Waha Hub serves as the designated delivery point for the Streamline electronic trading system and the futures contracts offered by the Kansas City Board of Trade. - "Velocity," the Company's intrastate electronic bulletin board, was introduced to customers in November 1995. Velocity is designed to improve communications between the Company and its customers and to enable customers to monitor and control their natural gas volumes in a more timely manner. - Valero Field Services Company was established in 1995 to provide gas gathering, compression, dehydration and treating services around the Transmission System and in those areas that are complemen- tary to the Company's anticipated growth. The field services unit seeks to build and diversify the Company's gas supply portfolio and create synergistic opportunities with the Company's other gas businesses. - In 1995, the Company expanded its marketing business into the electricity market. See "Natural Gas Related Services - Electric Power." Transportation The following table sets forth the Company's gas transportation volumes and average transportation fees for the three years ended December 31, 1996. Year Ended December 31, 1996 1995 1994 Transportation volumes (MMcf per day). . 1,665 1,430 1,398 Average transportation fee per Mcf . . . $.089 $.094 $.102 Gas transportation and exchange transactions (collectively referred to as "transportation") accounted for approximately 50%, 50% and 55% of the Company's total daily gas volumes for 1996, 1995 and 1994, respectively. The Company's natural gas operations have been positively 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. Transportation rates are often higher on eastbound transmission than on east-to-west transmission. The Company transports gas for third parties under hundreds of long-term, short-term and spot 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. 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. During 1996, the Company purchased natural gas under hundreds of separate contracts. A majority of the Company's gas supplies are obtained from sources with multiple connections, and the Company frequently competes on a monthly basis for available gas supplies. The Company's ability to process natural gas attracts significant gas supplies to the Transmission System. In 1996, the Company secured approximately 480 MMcf per day of natural gas supplies from natural gas producers under agreements to process, transport or purchase their natural gas for terms ranging generally from one to seven years. Because of the extensive coverage of the Transmission System, 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 approxi- mately 7.2 Bcf of gas available for withdrawal. Natural gas can be continuously withdrawn from the facility at initial rates of up to approxi- mately 850 MMcf per day. The facility has the ability to inject gas at initial rates of approximately 360 MMcf per day. The Company supplemented its own natural gas storage capacity by leasing during 1996 an additional 6.8 Bcf of third-party storage capacity for the 1996-97 winter heating season. Natural Gas Liquids The Company's NGL operations provide strong integration among the Company's core businesses. The Company's ability to process natural gas is a value-added service offered to producers and attracts additional quantities of gas throughput to the Transmission System. The principal source of gas for processing is from the Transmission System. Production from the Company's NGL plants provides butane feedstocks for the production of oxygenates (primarily MTBE) at the Refinery. The Company's NGL production for 1996 was approximately 29.6 million barrels, averaging 80,900 barrels per day. The 1996 NGL production represents the Company's seventh consecutive year for record production volumes. The Company sold two of its gas processing plants in West Texas effective August 1, 1995. Processing capacity lost by the sale of these plants was more than offset, however, by significant expansions and upgrading projects completed at certain of the Company's other plants. The table below sets forth production volumes, average NGL market prices, and average gas costs related to the Company's NGL plant production for the three years ended December 31, 1996. Year Ended December 31, 1996 1995 1994 NGL plant production (Mbbls per day) . 80.9 80.3 79.5 Average market price per gallon. . $.354 $.258 $.265 Average gas cost per Mcf . . . . . . . $1.93 $1.40 $1.75 [FN] Represents the average Houston area market prices, net of certain location differentials, for individual NGL products weighted by relative volumes of each product produced. 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. The Company's primary markets for NGLs are petrochemical plants and refineries. 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 1996, approximately 83% of the Company's butane production was used as a feedstock for the Refinery's MTBE Plant. The Company's gas processing plants are located primarily in South Texas and process approximately 1.4 Bcf of gas per day. Each of the Company's plants is situated along the Transmission System. The Company also owns and operates approximately 510 miles (350 miles of which are located in South Texas) of NGL pipelines and fractionation facilities at three locations including a facility in the Corpus Christi area. The Company fractionated an average of 83,000 barrels per day in 1996, including all of the NGL output from its processing plants, except for one. Approximately 9% of these volumes represented NGLs fractionated for third parties. In South Texas, the Company gathers NGLs from five of its processing plants and transports these NGLs through its own pipelines to its fractionation facilities in the Corpus Christi area. The Company's remaining NGL pipelines are used to deliver NGLs to end-users and major common-carrier NGL pipelines, which ultimately deliver NGLs to their principal markets. The Company sells NGLs that have been extracted, transported and fractionated in the Company's facilities as well as 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 petrochemical industry represents an expanding principal market for NGLs due to increasing market demand for ethylene-derived products. Petrochemical demand for NGLs is projected to remain strong through 1997 with the announcement of several expansions to existing petrochemical facilities and the start-up of new ethylene plants along the Texas Gulf Coast in the next few years. A majority of this incremental capacity is projected to be built by independent petro-chemical companies with little affiliated NGL production, which may improve market liquidity for NGLs and create market opportunities for major NGL producers. However, planned facilities additions may be delayed or canceled, and no assurances can be given that the proposed petrochemical facilities will be completed. Electric Power Deregulation of the electric utility and power industry also offers new opportunities for natural gas companies. In 1995, the Company formed Valero Power Services Company to provide risk management and marketing services to the electric power industry. The Company offers to wholesale customers hourly, daily and monthly energy trading services, transmission services, emissions allowances, generation capacity transactions including fuel-to-energy conversions, and fuel-to-energy swaps. In addition, wholesale customers are offered an array of risk management tools for managing their costs and reliability associated with power procurement. The Company's initial power marketing efforts are concentrated in the central United States. Valero Power Services Company is a member of the Western Systems Power Pool, the Southwest Power Pool, the Electric Reliability Council of Texas, the Mid-Continent Area Power Pool, the Southeastern Electric Reliability Council and the Mid-America Interconnected Network. The Company began trading power in January 1996, and marketed approximately 2 million megawatt hours during 1996. GOVERNMENTAL REGULATIONS Federal Regulation The Company's operations are subject to numerous federal and state environmental statutes and regulations. See "Environmental Matters." The Company's pipeline system is an intrastate business not subject to direct regulation by the Federal Energy Regulatory Commission ("FERC"). Although the Company's interstate gas sales and transportation activities are subject to specific FERC regulations, these regulations do not change the Company's overall regulatory status. FERC Order No. 636 ("Order 636") 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 are responsible for acquiring their own gas supplies, including managing their needs for swing, transportation and storage services. 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. 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, the Company can more effectively compete for sales of natural gas to LDCs and other customers outside Texas. 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 requires purchasers to take gas by priority categories, ratably among producers without undue discrimination, with high-priority gas (gas from wells primarily producing oil and certain special allowable gas) having higher priority than gas well gas (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. Under applicable statutes and current RRC practice, however, larger volume industrial sales and transportation charges may be changed without a rate case before the RRC if the parties to the transactions agree to the rate changes. 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 through the filing of tariffs and compliance with safety standards. To date, the impact of this regulation on the Company's operations has not been significant. 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. It obtains all of its resid feedstock from unaffiliated sources. Many of the Company's competitors 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 (and brand-name recognition) 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 or feedstock shortages. 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 should be able to comply with the Clean Air Act and future environmental legislation more easily than older refineries, and will not be required to spend significant additional capital for environmental compliance. In 1996, the Corpus Christi area was approved as a "flexible attainment region" ("FAR") by the EPA and the Texas Natural Resource Conservation Commission ("TNRCC"). Under the Clean Air Act, the FAR designation will allow local officials to design and implement an ozone prevention strategy customized for the community. This designation also prevents the EPA from designating the Corpus Christi area as "nonattainment" for a five-year period while agreed-upon control strategies are being initiated to reduce ozone formation. The FAR designation should provide greater flexibility to the Company with respect to future expansion projects at the Refinery. The Company produces enough oxygenates to blend all of its gasoline as RFG and to sell additional quantities of oxygenates to third parties who require oxygenates for blending. RFG generally sells at a premium over conventional gasoline. Most of the refining industry uses the conventional "3-2-1 crack spread" (which assumes the input of three parts of West Texas Intermediate crude oil and the output of two parts gasoline and one part diesel) as an approximation for gross margins; however, the Company produces premium products such as RFG and low-sulfur diesel and also produces a higher percentage of its refined products as gasoline. Thus, the Company's "85-15 clean fuels crack spread" (85% RFG, 15% low-sulfur diesel) has provided a wider margin than the typical crack spread experienced by a conventional refiner. Natural Gas Related Services The natural gas industry is expected to remain highly competitive with respect to both gas supply and markets. Changes in the gas markets during recent periods of deregulation have significantly increased competition. However, the Company has not only maintained but has increased its throughput volumes since implementation of Order 636. Because of Order 636, the Company now can guarantee long-term supplies of natural gas to be delivered to buyers at interstate locations. See "Governmental Regulations - Federal Regulation." The Transmission System has considerable flexibility in providing connections between many producing and consuming areas and is able to handle widely varying loads caused by changing supply and demand patterns. The Transmission System is well positioned to provide swing services both in and outside Texas because of its proximity to supply and its numerous interconnections with other pipeline systems. See "Natural Gas Related Services - Transmission System." In recent years, certain of the Company's intrastate pipeline competitors 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. 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. Consequently, the Company's competitors in the near future are likely to be a smaller number of larger energy service firms that can offer "one-stop shopping" for the customer's energy needs, whether the needs are physical, managerial, or financial for the respective energy commodity. The economics of natural gas processing depends principally on the relationship between natural gas costs and NGL prices. When this relationship is favorable, the NGL processing business is 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. The Company believes that the level of competition in NGL processing has increased over the past years 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. Moreover, the Company's NGL production and marketing operations complement its natural gas related services, enabling the Company to provide integrated processing, transportation, and marketing solutions to its producer clients, giving the Company a competitive advantage over NGL marketers and transporters that lack such capability. 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 TNRCC and the RRC. The regulatory requirements relate primarily to water and storm water discharges, waste management and air pollution control measures. In 1996, capital expenditures for the Company's refining operations attributable to compliance with environmental regulations were approximately $5 million and are currently estimated to be $7 million for 1997. 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 "Refining and Marketing - Factors Affecting Operating Results." The Company's capital expenditures for environmental control facilities related to its natural gas related services operations were not material in 1996 and are not expected to be material in 1997. Currently, expenditures are made to comply with regulations for air emissions, solid waste management and waste water 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. The EPA granted interim approval of the Texas Title V operating permit program in mid-1996, and many of the Company's gas processing plants and gas pipeline facilities became subject to requirements for submitting applications to the TNRCC for new operating permits. As required by applicable regulations, permit applications for 10% of the Company's gas processing plants and gas pipeline facilities that are subject to the regulations were filed in January 1997, with the balance to be filed in July 1997. Although proposed monitoring requirements may increase operating costs, they are not expected to have a material adverse effect on the Company's operations or financial condition. EMPLOYEES As of January 31, 1997, the Company had 1,673 employees. ITEM 2. PROPERTIES The Company's properties include a petroleum refinery and related facilities, eight 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 Company's gas systems and processing facilities are pledged as collateral for the First Mortgage Notes of Valero Management Partnership, L.P. See Note 5 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 14 of Notes to Consolidated Financial Statements. ITEM 3. LEGAL PROCEEDINGS Franchise Fee Litigation. City of Edinburg v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 92nd State District Court, Hidalgo County, Texas (filed August 31, 1995). The Company and Southern Union Company ("Southern Union") are defendants in a lawsuit brought by the City of Edinburg, Texas (the "City") regarding certain ordinances of the City that granted franchises to Rio Grande Valley Gas Company ("RGV") and its predecessors allowing RGV to sell and distribute natural gas within the City. On September 30, 1993, Energy sold the common stock of RGV to Southern Union. The City alleges that the defendants used RGV's facilities to sell or transport natural gas in Edinburg in violation of the ordinances and franchises granted by the City, and that RGV (now Southern Union) has not fully paid all franchise fees due the City. The City also alleges that the defendants used the public property of the City without compensating the City for such use, and alleges conspiracy and alter ego claims involving all defendants. The City seeks alleged actual damages of $50 million and unspecified punitive damages related to amounts allegedly due under the RGV franchise, City ordinances and state law. In addition, the City of Pharr, Texas, filed an intervention seeking certification of a class, with itself as class representative, consisting of all cities served by franchise by Southern Union. The court certified the class and severed the claims of the City of Pharr and the class from the original City of Edinburg lawsuit. The City of Pharr subsequently amended its petition deleting all Valero entities as defendants. The original trial judge was disqualified upon motion of the defendants (such disqualification was upheld on appeal), and a new trial judge has been assigned to preside over both the City of Edinburg and City of Pharr litigation. The City of Edinburg lawsuit is scheduled for trial on August 11, 1997. In 1996, the South Texas cities of Alton and Donna also independently intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State District Court in Hidalgo County. These lawsuits subsequently were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Donna are substantially similar to the Edinburg litigation claims. Damages are not quantified. Southern Union Cross-Claim. In connection with the City of Edinburg lawsuit, Southern Union filed a cross-claim against Energy, alleging, among other things, that Southern Union is entitled to indemnification pursuant to the purchase agreement under which Energy sold RGV to Southern Union. Southern Union also asserts claims related to a 1985 settlement among Energy, RGV and the Railroad Commission of Texas regarding certain gas contract pricing terms. This pricing claim was recently severed into a separate lawsuit. Southern Union's claims include, among other things, damages for indemnification, breach of contract, negligent misrepre- sentation and fraud. Newly Filed Franchise Fee Litigation. City of La Joya v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 92nd State District Court, Hidalgo County, Texas (filed December 27, 1996). City of San Benito, City of Primera, and City of Port Isabel v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 107th State District Court, Cameron County, Texas (filed December 31, 1996). City of San Juan, City of La Villa, City of Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern Union Company, et al., 93rd State District Court, Hidalgo County, Texas (filed December 27, 1996). Three additional lawsuits were filed in South Texas during December 1996 making allegations substantially similar to those in the City of Edinburg litigation. The City of La Joya lawsuit was brought as a class action on behalf of the City of La Joya and all similarly situated cities having ordinances or agreements with the defendants. In these three lawsuits, the defendants are alleged to have excluded certain revenues from their calculations of franchise taxes and are alleged to have provided unauthorized gas transportation services to third parties. Plaintiffs seek actual and exemplary, but as yet unspecified, damages. J.M. Davidson, Inc. v. Valero Energy Corporation; Valero Hydrocarbons, L.P.; et al., transferred to the 49th State District Court, Webb County, Texas (originally filed January 21, 1993 in Duval County). This lawsuit is based upon construction work performed by the plaintiff at one of the Company'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 asserts claims for breach of contract, quantum meruit, and numerous other contract and tort claims. The plaintiff seeks actual damages, on each of its causes of action, of approximately $1.25 million and punitive damages of at least four times the amount of actual damages. No trial date has been set. The Long Trusts v. Tejas Gas Corporation; Valero Transmission, L.P.; et al., 123rd Judicial District Court, Panola County, Texas (filed March 1, 1989). On April 15, 1994, certain trusts (the "Long Trusts") named certain subsidiaries of the Company as additional defendants (the "Valero Defendants") to a lawsuit filed in 1989 by the Long Trusts against Tejas Gas Corporation ("Tejas"), a supplier with whom the Valero Defendants have contractual relationships under gas purchase contracts. To resolve certain potential disputes with respect to the gas purchase contracts, the Valero Defendants agreed to bear a substantial portion of any settlement or nonappealable final judgment rendered against Tejas. In January 1993, the District Court ruled in favor of the Long Trusts' motion for summary judgment against Tejas. Damages, if any, were not determined. The Long Trusts seek $50 million in damages from the Company as a result of the Valero Defendants' alleged interference between the Long Trusts and Tejas, plus punitive damages in excess of treble the amount of actual damages proven at trial. The Long Trusts also seek approximately $56 million in take-or-pay damages from Tejas, and $70 million as damages for Tejas's failure to take the Long Trusts' gas ratably. 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. No trial date has been set. Mizel v. Valero Energy Corporation, Valero Natural Gas Company, and Valero Natural Gas Partners, L.P., removed to the United States District Court for the Western District of Texas (originally filed May 1, 1995 in the United States District Court for the Southern District of California). This is a federal securities fraud lawsuit filed by a former owner of limited partnership interests of VNGP, L.P. Plaintiff alleges that the proxy statement used in connection with the solicitation of votes for approval of the merger of VNGP, L.P. with the Company contained fraudulent misrepresen- tations. Plaintiff also alleges breach of fiduciary duty in connection with the merger transaction. The subject matter of this lawsuit was the subject matter of a prior Delaware class action lawsuit which was settled prior to consummation of the merger. The Company believes that plaintiff's claims have been settled and released by the prior class action settlement. Pending in the district court is the memorandum issued by the magistrate assigned to the case which recommends approval of the defendants' motion for summary judgment. Teco Pipeline Company v. Valero Energy Corporation, et al., 215th State District Court, Harris County, Texas (filed April 24, 1996). Energy and certain of its subsidiaries have been sued by Teco Pipeline Company ("Teco") regarding the operation of the Company's 340-mile West Texas pipeline. In 1985, a subsidiary of Energy sold a 50% undivided interest in the pipeline and entered into a joint venture through an ownership agreement and an operating agreement, each dated February 28, 1985, with the purchaser of the interest. In 1988, Teco succeeded to that purchaser's 50% interest. A subsidiary of Energy has at all times been the operator of the pipeline. Notwithstanding the written ownership and operating agreements, the plaintiff alleges that a separate, unwritten partnership agreement exists, and that the defendants have exercised improper dominion over such alleged partnership's affairs. The plaintiff also alleges that the defendants acted in bad faith by negatively affecting the economics of the joint venture in order to provide financial advantages to facilities or entities owned by the defendants and by allegedly usurping for the defendants' own benefit certain opportunities available to the joint venture. The plaintiff asserts causes of action for breach of fiduciary duty, fraud, tortious interference with business relationships, and other claims, and seeks unquantified actual and punitive damages. The Company's motion to compel arbitration was denied, but has been appealed. The Company has filed a counterclaim alleging that the plaintiff breached its own obligations to the joint venture and jeopardized the economic and operational viability of the pipeline by its actions. The Company is seeking unquantified actual and punitive damages. Sinco Pipeline Rupture Litigation. Adams, et al. v. Colonial Pipeline Company; Valero Transmission, L.P.; et al., 157th State District Court, Harris County, Texas (filed August 31, 1995). Aldridge, et al. v. Colonial Pipeline Company, Valero Management Company, et al., 295th State District Court, Harris County, Texas (filed October 18, 1996). American Plant Food Corporation, et al., v. Colonial Pipeline Company; Texaco, Inc.; Valero Energy Corporation; et al., 80th State District Court, Harris County, Texas (filed June 1, 1995). Anderson, et al. v. Colonial Pipeline Company, Valero Management Company, et al., 113th State District Court, Harris County, Texas (filed October 17, 1996). Barr, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 334th State District Court, Harris County, Texas (filed October 18, 1996). Benavides, et al. v. Colonial Pipeline Company; Valero Transmission, L.P.; et al., 93rd State District Court, Hidalgo County, Texas (filed August 31, 1995). Brackett, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 11th State District Court, Harris County, Texas (filed October 18, 1996). Brewer, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 133rd State District Court, Harris County, Texas (filed October 18, 1996). Hayward, et al. v. Colonial Pipeline Company, Valero Trans- mission, L.P., et al., 129th State District Court, Harris County, Texas (filed October 18, 1996). Hornbeck, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 56th State District Court, Galveston County, Texas (filed October 18, 1996). Johnson, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 333rd State District Court, Harris County, Texas (filed October 18, 1996). Layton, et al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 131st State District Court, Harris County, Texas (filed October 18, 1996). Navarro, et al. v. Colonial Pipeline Company, et al., 281st State District Court, Harris County, Texas (filed November 7, 1994). Durst, et al. (Intervenors) v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 281st State District Court, Harris County, Texas. Flores (Intervenor) v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 281st State District Court, Harris County, Texas. Approximately 15 lawsuits have been filed against various pipeline owners and other parties, including the Company, in connection with 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 surrounding areas who 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 plaintiffs assert claims for property damage, costs for medical monitoring, personal injury and nuisance. Plaintiffs seek an unspecified amount of actual and punitive damages. 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. Javelina Company has been named as a defendant in ten lawsuits filed since 1993 in state district courts in Nueces County, and Duval County, Texas. Eight 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. The plaintiffs seek an unspecified amount of actual and punitive damages. The remaining two suits were brought by plaintiffs who either live or have businesses near the Javelina plant. The plaintiffs in these suits allege claims similar to those described above and seek unspecified actual and punitive damages. 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the fourth quarter of 1996. PART II 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 January 31, 1997, there were approximately 6,240 holders of record and an estimated 18,000 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:
Common Stock Dividends 1996 1995 Per Common Share Quarter Ended High Low High Low 1996 1995 March 31 . . . . . . . $26 1/2 $22 1/8 $18 5/8 $16 $.13 $.13 June 30. . . . . . . . 29 24 1/2 22 7/8 17 3/4 .13 .13 September 30 . . . . . 25 1/2 20 1/4 25 5/8 19 5/8 .13 .13 December 31. . . . . . 30 21 7/8 25 7/8 22 1/2 .13 .13
The Energy Board of Directors declared a quarterly dividend of $.13 per share of Common Stock at its January 23, 1997 meeting. Dividends are considered quarterly by the Energy Board of Directors and may be paid only when approved by the Board. ITEM 6. SELECTED FINANCIAL DATA The selected financial data set forth below for the year ended December 31, 1996 is derived from the Company's Consolidated Financial Statements contained elsewhere herein. The selected financial data for the years ended prior to December 31, 1996 is derived from the selected financial data contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1995 except as noted below. The following summaries are in thousands of dollars except for per share amounts:
Year Ended December 31, 1996 1995 1994 1993 1992 OPERATING REVENUES . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440 $1,222,239 $1,234,618 OPERATING INCOME . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 125,925 $ 75,504 $ 134,030 EQUITY IN EARNINGS (LOSSES) OF AND INCOME FROM VALERO NATURAL GAS PARTNERS, L.P. . . . . . . . . . . . . $ - $ - $ (10,698) $ 23,693 $ 26,360 NET INCOME . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282 $ 36,424 $ 83,919 Less: Preferred stock dividend requirements. . . . . . . . . . . . 11,327 11,818 9,490 1,262 1,475 NET INCOME APPLICABLE TO COMMON STOCK . . . . . . . . . . . . . . . $ 61,374 $ 48,020 $ 7,792 $ 35,162 $ 82,444 EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . . . . . . $ 1.40 $ 1.10 $ .18 $ .82 $ 1.94 TOTAL ASSETS . . . . . . . . . . . . . . . . $3,134,774 $2,861,880 $2,816,558 $1,764,437 $1,759,100 LONG-TERM OBLIGATIONS AND REDEEMABLE PREFERRED STOCK . . . . . . . . $ 869,450 $1,042,541 $1,034,470 $ 499,421 $ 497,308 DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . . . . . . . . . . $ .52 $ .52 $ .52 $ .46 $ .42 Reflects the consolidation of the Partnership as of May 31, 1994. Revised to include revenues from certain refining and marketing trading activities previously classified as a reduction of cost of sales. Restated to reflect the effects of a prior period adjustment resulting in a charge to 1994 income for an acquisition expense accrual originally charged to property, plant and equipment. See "Restatement of Financial Information" in Note 1 of Notes to Consolidated Financial Statements.
See Notes to Consolidated Financial Statements. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS PROPOSED RESTRUCTURING On January 31, 1997, the Company announced that its Board of Directors had approved an agreement and plan of merger with PG&E Corporation ("PG&E") to combine the Company's natural gas related services business (see "Segment Reporting" below) with PG&E following the spin-off of the Company's refining and marketing business to the Company's shareholders (the "Restructuring"). The Restructuring was the result of a management recommendation announced in November 1996 to pursue strategic alternatives involving the Company's principal business activities. See "Liquidity and Capital Resources" below and Note 2 of Notes to Consolidated Financial Statements for additional information about the Restructuring. SEGMENT REPORTING Effective January 1, 1996, the Company's natural gas and natural gas liquids ("NGL") businesses were reported as one industry segment for financial reporting purposes (described herein as "natural gas related services") in recognition of the Company's increasing integration of these business activities due to the restructuring of the interstate natural gas pipeline industry in 1993 through FERC Order 636 and the resulting transformation of the U.S. natural gas industry into a more market and customer-oriented environment. The Company's ability to gather, transport, market and process natural gas, among other things, are value-added services offered to producers and attract additional quantities of gas to the Company's pipeline system and processing plants through integrated business arrangements. Prior to 1996, the Company's natural gas and NGL businesses were reported as separate industry segments. The primary effect of this change on the Company's segment disclosures was the elimination of volume, revenue and income amounts related to natural gas fuel and shrinkage volumes sold to and transported for the natural gas liquids segment by the natural gas segment. The Company's 1995 and 1994 financial and operating highlights which follow under "Results of Operations," and the discussion of the Company's natural gas and NGL businesses which follows under "Results of Operations - 1995 Compared to 1994 - Segment Results," have been revised from that contained in the Company's Annual Report on Form 10-K for the year ended December 31, 1995 to reflect this change in segment reporting. ACQUISITION OF VNGP, L.P. As described in Note 3 of Notes to Consolidated Financial Statements, the merger of VNGP, L.P. with Energy was consummated on May 31, 1994. As a result of such merger, VNGP, L.P. became a subsidiary of Energy. The accompanying consolidated statements of income of the Company for the years ended December 31, 1996, 1995 and 1994 reflect the Company's 100% interest in the Partnership's operations after May 31, 1994 and its effective equity interest of approximately 49% for all periods prior to and including May 31, 1994. Because 1994 results of operations for the Company's natural gas related services segment are not comparable to subsequent and prior periods due to the VNGP, L.P. merger, the discussion of this segment which follows under "Results of Operations - 1995 Compared to 1994 - Segment Results" is based on pro forma operating results for 1994 that reflect the consolidation of the Partnership with Energy for all of such year. The following discussion contains certain estimates, predictions, projections and other "forward-looking statements" (within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934) that involve various risks and uncertainties. While these forward-looking statements, and any assumptions upon which they are based, are made in good faith and reflect the Company's current judgment regarding the direction of its business, actual results will almost always vary, sometimes materially, from any estimates, predictions, projections, assumptions, or other future performance suggested herein. Some important factors (but not necessarily all factors) that could affect the Company's sales volumes, growth strategies, future profitability and operating results, or that otherwise could cause actual results to differ materially from those expressed in any forward-looking statement include the following: renewal or satisfactory replacement of the Company's residual oil ("resid") feedstock arrangements as well as market, political or other forces generally affecting the pricing and availability of resid and other refinery feedstocks, refined products, natural gas supplies or natural gas liquids; accidents or other unscheduled shutdowns affecting the Company's, its suppliers' or its customers' pipelines, plants, machinery or equipment; excess industry capacity; competition from products and services offered by other energy enterprises; changes in the cost or availability of third-party vessels, pipelines and other means of transporting feedstocks and products; state and federal environmental, economic, safety and other policies and regulations, any changes therein, and any legal or regulatory delays or other factors beyond the Company's control; execution of planned capital projects; weather conditions affecting the Company's operations or the areas in which the Company's products are marketed; adverse rulings, judgments, or settlements in litigation or other legal matters, including unexpected environmental remediation costs in excess of any reserves; the introduction or enactment of legislation, including tax legislation affecting the proposed merger with PG&E; and adverse changes in the credit ratings assigned to the Company's debt securities and trade credit. The Company undertakes no obligation to publicly release the result of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. 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, 1996. For 1995 and 1994, operating revenues and operating income (loss) by segment and certain natural gas related services operating statistics have been restated to conform to the 1996 presentation. The amounts in the following table are in thousands of dollars, unless otherwise noted:
Year Ended December 31, 1996 1995 1994 OPERATING REVENUES: Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . $2,757,801 $1,950,657 $1,090,368 Natural gas related services . . . . . . . . . . . . . . . . . . . . 2,445,504 1,396,468 784,287 Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 126 42,639 Intersegment eliminations . . . . . . . . . . . . . . . . . . . . . (212,747) (149,379) (79,854) Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440 OPERATING INCOME (LOSS): Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660 Natural gas related services . . . . . . . . . . . . . . . . . . . . 132,178 83,180 61,944 Corporate general and administrative expenses and other, net . . . . (41,315) (35,901) (14,679) Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 125,925 Equity in earnings (losses) of and income from: Valero Natural Gas Partners, L.P. . . . . . . . . . . . . . . . . . $ - $ - $ (10,698) Joint ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,899 $ 4,827 $ 2,437 Loss on investment in Proesa joint venture . . . . . . . . . . . . . . . . $ (19,549) $ - $ - (Provision for) reversal of acquisition expense accrual . . . . . . . $ 18,698 $ (2,506) $ (16,192) Other income, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,921 $ 5,248 $ 3,431 Interest and debt expense, net . . . . . . . . . . . . . . . . . . . . . . $ (95,177) $ (101,222) $ (76,921) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282 Net income applicable to common stock . . . . . . . . . . . . . . . . $ 61,374 $ 48,020 $ 7,792 Earnings per share of common stock . . . . . . . . . . . . . . . . . . $ 1.40 $ 1.10 $ .18 PRO FORMA OPERATING INCOME (LOSS) : Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660 Natural gas related services . . . . . . . . . . . . . . . . . . . . . . 132,178 83,180 69,769 Corporate general and administrative expenses and other, net . . . . . . (41,315) (35,901) (22,486) Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 125,943 OPERATING STATISTICS: Refining and marketing: Throughput volumes (Mbbls per day) . . . . . . . . . . . . . . . . . . 170 160 146 Average throughput margin per barrel . . . . . . . . . . . . . . . . . $ 5.29 $ 6.25 $ 5.36 Sales volumes (Mbbls per day) . . . . . . . . . . . . . . . . . . 291 231 140 Natural gas related services : Gas volumes (MMcf per day): Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,693 1,429 1,139 Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,665 1,430 1,398 Total gas volumes. . . . . . . . . . . . . . . . . . . . . . . . . 3,358 2,859 2,537 Average gas sales margin per Mcf . . . . . . . . . . . . . . . . . . . $ .146 $ .162 $ .184 Average gas transportation fee per Mcf . . . . . . . . . . . . . . . . $ .089 $ .094 $ .102 NGL plant production: Production volumes (Mbbls per day) . . . . . . . . . . . . . . . . . 80.9 80.3 79.5 Average NGL market price per gallon. . . . . . . . . . . . . . . . . $ .354 $ .258 $ .265 Average gas cost per Mcf . . . . . . . . . . . . . . . . . . . . . . $ 1.93 $ 1.40 $ 1.75 Average NGL margin per gallon. . . . . . . . . . . . . . . . . . . . $ .103 $ .080 $ .076 Revised for 1995 to include revenues and associated volumes related to certain refining and marketing trading activities previously classified as a reduction of cost of sales. Reflects the consolidation of the Partnership commencing June 1, 1994. Represents the Company's approximate 49% effective equity interest in the operations of the Partnership and interest income on certain capital lease transactions with the Partnership for the period prior to June 1, 1994. Operating income (loss) presented herein for 1994 represents pro forma amounts that reflect the consolidation of the Partnership with Energy for all of such year. Operating statistics for the natural gas related services segment for 1994 represent pro forma statistics that reflect such consolidation. Restated for 1994 to reflect the effects of a prior period adjustment resulting in a charge to income for an acquisition expense accrual originally charged to property, plant and equipment. See "Restatement of Financial Information" in Note 1 of Notes to Consolidated Financial Statements.
1996 COMPARED TO 1995 Consolidated Results The Company reported net income of $72.7 million, or $1.40 per share, for the year ended December 31, 1996 compared to $59.8 million, or $1.10 per share, for the year ended December 31, 1995. For the fourth quarter of 1996, net income was $18.8 million, or $.37 per share, compared to $12.9 million, or $.23 per share, for the fourth quarter of 1995. Net income and earnings per share increased during the 1996 fourth quarter and total year compared to the same periods in 1995 due primarily to a significant increase in operating income from the Company's natural gas related services business, partially offset by a decrease in refining and marketing operating income and an increase in corporate expenses. Lower net interest expense also contributed to the increase in net income and earnings per share, partially offset by higher income taxes. Operating revenues increased $1.8 billion, or 56%, to $5 billion during 1996 compared to 1995 due to an approximate $1 billion, or 75% increase in natural gas related services revenues and an approximate $800 million, or 41% increase in refining and marketing revenues. Operating income increased $12.1 million, or 6%, to $200.9 million during 1996 compared to 1995 due to a $49 million, or 59% increase in natural gas related services operating income, partially offset by a $31.5 million, or 22% decrease in refining and marketing operating income and a $5.4 million increase in corporate expenses resulting primarily from higher employee- related and other costs. Changes in operating revenues and operating income by business segment are explained below under "Segment Results." During the fourth quarter of 1996, the Company wrote off its investment in its joint venture project to design, construct and operate a plant in Mexico to produce methyl tertiary butyl ether ("MTBE") and accrued an estimate of additional liabilities associated with such investment resulting in a loss of $19.5 million (see Note 7 of Notes to Consolidated Financial Statements). Also in the fourth quarter of 1996, the Company recorded $16.6 million of income representing the reversal of the excess portion of an accrual established in May 1994 to cover expected costs related to the Company's acquisition of the publicly held units of VNGP, L.P. Net interest and debt expense decreased $6 million to $95.2 million during 1996 compared to 1995 due primarily to a decrease in bank borrowings and paydowns of certain outstanding nonbank debt, partially offset by the issuance of medium-term notes ("Medium-Term Notes") in the first half of 1995 (see "Liquidity and Capital Resources"). Income tax expense increased $5.7 million in 1996 compared to 1995 due primarily to higher pre-tax income. Segment Results Refining and Marketing Operating revenues from the Company's refining and marketing operations increased $807.1 million, or 41%, to $2.8 billion during 1996 compared to 1995 due primarily to a 26% increase in sales volumes and a 12% increase in the average sales price per barrel. The increase in sales volumes was due primarily to increased volumes from trading and rack marketing activities, and a 6% increase in average daily throughput volumes resulting from various unit improvements and enhancements made during 1995 and a reduced impact on production due to unit turnarounds which occurred in 1996 compared to 1995, partially offset by the effects of two second quarter 1996 power outages at the Refinery. The average sales price per barrel increased due primarily to higher gasoline and distillate prices which generally followed an increase in crude oil prices during 1996. Operating income from the Company's refining and marketing operations decreased $31.5 million, or 22%, to $110 million during 1996 compared to 1995 due primarily to a decrease in total throughput margins and higher operating expenses. The decrease in total throughput margins was due primarily to lower oxygenate margins resulting from higher butane feedstock costs, particularly in the fourth quarter, lower margins on sales of petrochemical feedstocks, and decreased results from price risk management activities. These decreases in throughput margins were partially offset by the increase in throughput volumes noted above, higher distillate margins, and an improvement in discounts on purchases of resid feedstocks. Operating expenses increased due primarily to costs associated with the methanol plant which was placed in service in late August 1995 and higher variable costs resulting from increased throughput at the Refinery. The Company has entered into various term feedstock supply agreements for approximately 58,000 barrels per day of resid which are based on market prices and extend through 1997, including an agreement with the Saudi Arabian Oil Company for approximately 36,000 barrels per day which extends through mid-1998. These agreements provide approximately 70% of the Refinery's estimated daily resid feedstock requirements for 1997. The Company believes that if any of its existing resid feedstock arrangements were interrupted or terminated, supplies of resid 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 few years, if any such interruptions or terminations did occur, the Company could be required to incur higher resid feedstock costs or substitute other types of resid, thereby producing less favorable operating results. The Company also has two agreements to supply feedstock for the Refinery's crude unit; one with the Chinese state-owned oil company for approximately 22,000 barrels per day of sweet crude oil extending through June 1997, and one with a domestic refiner for approximately 8,000 barrels per day of crude oil extending through the end of 1997. The remainder of the Refinery's resid and crude feedstocks are purchased at market-based prices under short-term contracts. Production from the Company's joint venture methanol plant normally provides all of the methanol feedstock presently required for the Refinery's production of oxygenates used in reformulated gasoline ("RFG"). In 1996, a maintenance turnaround and a catalyst change for the Refinery's hydrodesulfurization unit (the "HDS Unit") were completed in July, a turnaround of the Refinery's MTBE Plant was completed in September during which its capacity was increased by approximately 1,500 barrels per day, and turnarounds of the Refinery's hydrocracker and naphtha reformer units were completed in December. In early December, an explosion occurred at the methanol plant as it was being shut down for repairs. The Company's share of repair costs is estimated to be $2.5 million, and the plant is expected to resume operations in late February 1997. In 1995, a maintenance turnaround and a catalyst change for the HDS Unit and turnarounds of the hydrocracker and naphtha reformer units were all completed in April of that year. During 1997, the crude unit is scheduled for a maintenance turnaround in the second quarter designed to increase the unit's capacity, and the HDS Unit is scheduled for a maintenance turnaround and a catalyst change in the fourth quarter. The Company enters into various exchange-traded and over-the-counter financial instrument contracts with third parties to manage price risk associated with refining feedstock and fuel purchases, refined product inventories and refining operating margins. Although such activities are intended to limit the Company's exposure to loss during periods of declining margins, such activities could tend to reduce the Company's participation in rising margins. In 1996, refining throughput margins were reduced by $1.2 million as a result of hedging activities compared to a $12.8 million benefit in 1995. The 1995 benefit resulted primarily from favorable price swap contracts on methanol, as methanol prices dropped by over 70% during that year. In 1996 and 1995, the Company was also able to reduce its operating costs by $2.8 million and $1 million, respectively, as a result of hedges on refining natural gas fuel requirements. See Note 1 under "Price Risk Management Activities" and Note 6 of Notes to Consolidated Financial Statements. Natural Gas Related Services Operating revenues from the Company's natural gas related services operations increased $1 billion, or 75%, to $2.4 billion during 1996 compared to 1995 due primarily to a 47% increase in average natural gas sales prices, an 18% increase in natural gas sales volumes, primarily off-system sales, a 37% increase in average NGL market prices, and a 28% increase in NGL sales volumes. Natural gas sales prices and volumes were higher due to increased demand for natural gas to replenish low industry- wide natural gas storage inventories drawn down by extreme cold winter weather during the 1996 first quarter and which remained below 1995 levels during all of 1996. Natural gas demand also increased due to early cold weather during the 1996 fourth quarter. NGL market prices increased as a result of historically low NGL inventory levels, firm petrochemical and refining demand, and strong crude oil and refined product prices. NGL sales volumes were higher due primarily to an increase in NGL marketing activities. Operating income from the Company's natural gas related services operations increased $49 million, or 59%, to $132.2 million during 1996 compared to 1995 due primarily to higher margins on NGL production and to a lesser extent to increases in total gas sales margins, natural gas transportation revenues and income from NGL trading activities. Total margins on NGL production were higher due to the substantial increase in average NGL market prices noted above and to an approximate $16 million increase in benefits from price risk management activities which limited the increase in natural gas fuel and shrinkage costs. Total gas sales margins increased due primarily to the increase in off-system sales volumes noted above and increased benefits from price risk management activities, partially offset by an increase in fuel costs. Natural gas transportation revenues were higher due to a 16% increase in transportation volumes resulting from increased marketing activities, partially offset by a 5% decrease in average transportation fees. NGL trading income increased due primarily to the increase in NGL marketing activities noted above. NGL production volumes increased slightly in 1996 compared to 1995 as production increases at various plants resulting from the completion in 1995 and 1996 of certain operational improvements and production enhancements generally offset the effects of the sale of two West Texas processing plants in August 1995. Demand for natural gas continues to be affected by the operation of various nuclear and coal power plants in the Company's core service area. At full operation, the South Texas Project nuclear plant ("STP") in Bay City, Texas and the Comanche Peak nuclear plant near Ft. Worth, Texas displace approximately 650 MMcf per day and 600 MMcf per day of natural gas demand, respectively. In addition, coal-fired electrical generation facilities owned and operated by San Antonio City Public Service displace a portion of natural gas demand. 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 aggressive marketing efforts to increase gas sales and transportation volumes, particularly in its off-system marketing business with local distribution and industrial companies throughout the United States, and by the flexible use of its strategically located pipeline system. However, gas sales and transportation margins remain under intense pressure as the natural gas industry continues to adjust to deregulation and the customer-driven market that has developed since FERC Order 636 was enacted. 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 provide for the sale of gas at its weighted average cost, as defined ("WACOG"), plus a margin. 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. As a result of contracts expiring in 1998, the majority of storage costs previously included in WACOG (see Note 14 of Notes to Consolidated Financial Statements), will no longer be recovered through these gas sales rates. 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. Currently, approximately 93% of the Company's NGL production comes from plants in South Texas and the Texas Gulf Coast. 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. 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. The Company enters into various exchange-traded and over-the-counter financial instrument contracts with third parties to manage price risk associated with its natural gas storage, natural gas marketing and NGL operations. Such activities are intended to manage price risk but may result in gas, fuel and shrinkage costs either higher or lower than those that would have been incurred absent such activities. In 1996 and 1995, total gas sales margins benefitted from gas cost reductions of $23.4 million and $12 million, respectively, resulting from price risk management activities. Of these amounts, $12.6 million and $5.6 million, respectively, were recognized in each year's fourth quarter. In addition, in 1996 and 1995, total margins on NGL production benefitted from fuel and shrinkage cost reductions of $19.7 million and $4.1 million, respectively, resulting from price risk management activities. For all such activities, an additional $16.6 million and $3.8 million was deferred at December 31, 1996 and 1995, respectively, which is recognized as a reduction to cost of sales in the subsequent year. See Note 1 under "Price Risk Management Activities" and Note 6 of Notes to Consolidated Financial Statements. 1995 COMPARED TO 1994 Consolidated Results The Company reported net income of $59.8 million, or $1.10 per share, for the year ended December 31, 1995 compared to $17.3 million, or $.18 per share, for the year ended December 31, 1994. For the fourth quarter of 1995, net income was $12.9 million, or $.23 per share, compared to net income of $3.9 million, or $.02 per share, for the fourth quarter of 1994. Net income and earnings per share increased during 1995 compared to 1994 due primarily to a significant increase in operating income from the Company's refining and marketing operations, improved operating results from the Company's natural gas related services business, including the effect of the May 31, 1994 merger of VNGP, L.P. with Energy, and the nonrecurring recognition in expense in 1994 of an accrual for loss contingencies recorded in connection with the merger of VNGP, L.P. with Energy. The increases in net income and earnings per share resulting from these factors were partially offset by increases in corporate expenses, net interest expense and income tax expense and the nonrecurring recognition in income in 1994 of deferred management fees resulting from the VNGP, L.P. merger. The increase in earnings per share was also partially offset by an increase in preferred stock dividend requirements resulting from the issuance in March 1994 of 3.45 million shares of Energy's $3.125 Convertible Preferred Stock. See Note 9 of Notes to Consolidated Financial Statements. Operating revenues increased $1.4 billion, or 74%, to $3.2 billion during 1995 compared to 1994 due primarily to an increase in operating revenues from refining and marketing operations which is explained below under "Segment Results" and the inclusion of operating revenues attributable to Partnership operations in all of 1995 versus only the months of June through December in 1994. Other operating revenues decreased $42.5 million due to the elimination of management fee revenues received by the Company from the Partnership as a result of the VNGP, L.P. merger. Operating income increased $62.9 million, or 50%, to $188.8 million during 1995 compared to 1994 due primarily to an increase in operating income from refining and marketing operations and to the inclusion of Partnership operating income in all of 1995 versus only the months of June through December in 1994. Partially offsetting these increases in operating income was an increase in corporate expenses, net, resulting primarily from the nonrecurring recognition in income in 1994 of deferred management fees resulting from the VNGP, L.P. merger, the allocation of corporate expenses to the Partnership in 1994 for the periods prior to the VNGP, L.P. merger and an increase in compensation expense. As a result of the VNGP, L.P. merger and the Company's change in the method of accounting for its investment in the Partnership from the equity method to the consolidation method, the Company did not report equity in earnings (losses) of and income from the Partnership for 1995 and the months of June through December in 1994. See "Segment Results" below for a discussion of the Company's natural gas related services operations, including 100% of the operations of the Partnership on a pro forma basis for 1994. Equity in earnings of joint ventures increased $2.4 million to $4.8 million for 1995 compared to 1994 due to an increase in the Company's equity in earnings of Javelina. Javelina's earnings increased due primarily to higher product prices as a result of strong product demand from the petrochemical industry, as well as lower feedstock costs. Net interest and debt expense increased $24.3 million to $101.2 million during 1995 compared to 1994 due primarily to the inclusion of Partnership interest expense in all of 1995 versus only the months of June through December in 1994, and to a lesser extent to the issuance of Medium-Term Notes in December 1994 and the first half of 1995. Income tax expense increased $24.6 million to $35.3 million in 1995 compared to 1994 due primarily to higher pre-tax income. Segment Results Refining and Marketing Operating revenues from the Company's refining and marketing operations increased $860.3 million, or 79%, to $2 billion during 1995 compared to 1994 due primarily to a 65% increase in sales volumes and a 9% increase in the average sales price per barrel. The increase in sales volumes was due primarily to higher purchases for resale of conventional gasoline to supply rack customers as a result of the Company's conversion of its Refinery operations to produce primarily RFG beginning in the fourth quarter of 1994, a 10% increase in throughput volumes resulting from various unit improvements completed during the latter part of 1994 and first half of 1995, and additional sales volumes in 1995 related to increased fuel oil trading activities. The average sales price per barrel increased due to higher refined product prices, including higher prices received on sales of RFG and other higher-value products. Operating income from the Company's refining and marketing operations increased $62.8 million, or 80%, to $141.5 million during 1995 compared to 1994 due primarily to an increase in total throughput margins partially offset by an increase in operating and other expenses. Total throughput margins increased due to higher margins on sales of RFG, oxygenates and petrochemical feedstocks, the effects of the unit improvements noted above, and the nonrecurrence of a turnaround of the Refinery's heavy oil cracking complex completed during the latter part of 1994, net of the effect of unit turnarounds which occurred in 1995 as described below. The increase in total throughput margins resulting from these factors was partially offset by a decrease in conventional refined product margins ("crack spread") resulting primarily from depressed gasoline markets in early 1995 attributable to uncertainties pertaining to the general acceptance of RFG and oxygenates. Costs for the Company's resid feedstocks increased in 1995 compared to 1994 due to a continuing worldwide decrease in resid supplies resulting from the addition of new refinery upgrading capacity and increased production of light sweet crude oil in relation to heavy crude oil. However, the effect of such increased resid costs on throughput margins was more than offset by a decrease in other feedstock costs, including a $7.5 million increase in benefits from price risk management activities, approximately $7 million of which was attributable to fourth quarter operations. Although operating expenses increased approximately 4% due primarily to higher costs resulting from increased throughput, operating expenses per barrel decreased by approximately 5%. Selling and administrative expenses increased due to higher compensation and other expenses, while depreciation expense increased approximately 4% due to capital expenditures incurred during the latter part of 1994 and in 1995. In 1995 and 1994, refining feedstock costs were reduced by $12.8 million and $5.3 million, respectively, as a result of price risk management activities. In addition, in 1995 the Company was able to reduce its operating costs by $1 million as a result of such activities. In 1994, the effect of such activities on operating costs was not significant. Natural Gas Related Services Operating income from the Company's natural gas related services operations was $83.2 million for 1995 compared to pro forma operating income of $69.8 million for 1994. The $13.4 million, or 19%, increase was due primarily to an increase in total gas sales margins and other operating revenues, higher margins on NGL production, a decrease in NGL transportation and fractionation costs, and a decrease in operating, selling and administrative expenses. The increase in operating income resulting from these factors was partially offset by decreases in natural gas transportation revenues and NGL revenues from transportation and fractionation of third party plant production. Total gas sales margins increased due to a 25% increase in gas sales volumes, reductions in gas costs resulting from price risk management activities, and the nonrecurrence of certain settlements relating to measurement and customer billing differences which adversely affected 1994. The increase in total gas sales margins resulting from these factors was partially offset by reduced volumetric gains and lower unit margins due primarily to an increase in lower-margin spot and off-system sales. Total margins on NGL production were higher due to a decrease in fuel and shrinkage costs resulting from a 20% decrease in the average cost of natural gas, which more than offset a 3% decrease in the average NGL market price. Average natural gas costs decreased due to surplus industry capacity and benefits from price risk management activities, while average NGL prices decreased due to weak ethane prices resulting from above-normal inventory levels. The decrease in operating, selling and administrative expenses was due primarily to the nonrecurrence of certain adverse settlements in 1994, including $6.8 million related to a settlement with the City of Houston regarding a franchise fee dispute, partially offset by higher ad valorem tax, maintenance and compensation expenses. The decrease in transportation revenues was due primarily to an 8% decrease in average transportation fees. NGL production volumes increased slightly in 1995 compared to 1994 as volume increases in 1995 resulting from the addition of new natural gas supplies under processing agreements with natural gas producers and operational improvements and production enhancements at certain of the Company's NGL plants were mostly offset by volume decreases resulting primarily from the sale of two West Texas processing plants in August 1995. In 1995, total gas sales margins benefitted from gas cost reductions of $12 million resulting from price risk management activities, $5.6 million of which was recognized in the fourth quarter, compared to $2.1 million in 1994 on a pro forma basis. In addition, in 1995 total margins on NGL production benefitted from fuel and shrinkage cost reductions of $4.1 million resulting from price risk management activities. In 1994, the effect of such activities on fuel and shrinkage costs was not significant. For all such activities, an additional $3.8 million and $6.8 million was deferred at December 31, 1995 and 1994, respectively, which is recognized as a reduction to cost of sales in the subsequent year. Other Pro forma corporate general and administrative expenses and other, net, increased $13.4 million during 1995 compared to 1994 due primarily to the nonrecurring recognition in income in 1994 of deferred management fees resulting from the Merger, as noted above, and an increase in compensation expense. OUTLOOK Refining and Marketing Over the next few years, light product demand is expected to grow moderately and refining capacity in the U.S. is expected to remain tight. However, the ongoing restructuring of the refining industry to improve performance as a result of poor margins experienced in recent years will create an extremely competitive business environment. The Company entered into several new feedstock arrangements in 1996 and will continue to explore various opportunities, both domestically and abroad, to diversify its sources of feedstock supply. The Company expects resid to continue to sell at a discount to crude oil, but is unable to predict the amount of such discount or future relationships between the supply of and demand for resid. Domestic gasoline demand, which increased by 1%, 1.5% and 1.7% in 1996, 1995 and 1994, respectively, is expected to continue to grow over the next several years due to slowing gains in fuel efficiency for passenger cars, higher sales of light trucks and sport-utility vehicles which average fewer miles per gallon than passenger cars, higher speed limits and an increasing number of miles driven. The demand for RFG increased in 1996 to over 30% of the total demand for gasoline in the U.S. following the implementation of the California Air Resources Board's "CARB II" gasoline program, and may continue to increase if areas of the country whose ozone emissions exceed permitted levels are permitted and elect to "opt in" to the RFG program to reduce their emission levels. The demand for oxygenates, including MTBE, is expected to increase due to the future need to replace the octane displaced by the worldwide movement to reduce the use of lead in gasoline, and to growing demand for oxygenated gasolines. The Company's Refinery throughput volumes are expected to benefit from the full year effect of various unit improvements and enhancements made during 1996 and no significant unit turnarounds being scheduled in 1997. Natural Gas Related Services Due to its desirability as a clean-burning fuel, demand for natural gas has remained strong and is expected to continue to grow due primarily to increasing demand in utility and non-utility electric generation applications and in industrial, particularly cogeneration, applications. Natural gas supplies should be sufficient to meet the growth in natural gas demand due to anticipated increases in domestic productive and storage capacity and in Canadian imports. As a result of the implementation of FERC Order No. 636 in 1993 and other efforts to reduce regulation, the Company's natural gas related services business continues to adjust to the transformation of the U.S. natural gas industry into a more market-oriented environment where increasing competition and market efficiencies are pressuring margins for all categories of business. In response to such conditions, the Company is continuing to emphasize growth of off-system sales by diversification of its customer base through marketing offices located throughout the nation and in Canada, and to further develop and expand its slate of value-added services, such as gas gathering and related activities, gas processing, gas transportation, volume and capacity management, price risk management, power marketing, NGL marketing and beginning in 1996, retail gas marketing. To capitalize on the continuing growth of west-to-east movement of gas across the United States, the Company intends to further increase its capacity to move gas across Texas through pipeline debottlenecking and other projects. The demand for NGLs is expected to remain strong as a result of continued economic growth, petrochemical plant expansions and the addition of new independent petrochemical facilities, and increased production of oxygenated and reformulated gasolines. The Company is continuing 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. In order to accommodate an increase in natural gas supplies, the Company has increased and plans to further increase the processing capacity at certain of its NGL plants and fractionation facilities through various expansion projects. As a result of the development of the above-noted natural gas related services business opportunities, the Company believes that it should be able to increase its natural gas, NGL and power marketing volumes in 1997. Due to rapid consolidation taking place in the natural gas and power industries in an effort to lower fixed costs per unit and improve profits in an increasingly competitive environment, competitors to the Company's natural gas related services business were becoming larger and more sophisticated. As a result , the Company began exploring the possibility of its natural gas related services business becoming part of a larger organization to remain competitive in the future and announced in November 1996 that its Board of Directors had approved a management recommendation to pursue a strategic alliance for such operations. On January 31, 1997, the Company announced that its natural gas related services business would be merged with PG&E Corporation following the spin-off of the Company's refining and marketing business. See "Proposed Restructuring" above and Note 2 of Notes to Consolidated Financial Statements. LIQUIDITY AND CAPITAL RESOURCES PROPOSED RESTRUCTURING As described above, the Company's refining and marketing business, which is conducted through Valero Refining and Marketing Company ("VRMC"), a wholly owned subsidiary of Energy, is expected to be spun-off as a separate company to the Company's shareholders at the time of the Restructuring. Such refining and marketing business currently obtains working capital financing from Energy pursuant to Energy's $300 million revolving bank credit and letter of credit facility and certain uncommitted short-term bank credit lines and uncommitted bank letter of credit facilities obtained by Energy as described below under "Current Structure." At the time of the spin off, the refining and marketing company expects to have established a separate unsecured five-year, $600 million revolving bank credit and letter of credit facility which can be used to fund working capital needs and other general corporate purposes, including the issuance of letters of credit and the funding of a dividend payable to Energy pursuant to the terms of the agreement and plan of merger with PG&E. Borrowings under this new facility are expected to bear interest at either LIBOR plus a margin, a base rate defined generally as the federal funds rate plus a margin, or a money-market rate. In addition, the refining and marketing company expects to pay various fees and expenses in connection with this new facility. The interest margins and fees are expected to fluctuate based upon the levels of certain financial ratios or the credit ratings assigned from time to time to the refining and marketing company's long-term debt and are expected to be comparable to those currently paid by Energy. The credit facility is expected to contain various covenants, which may include certain financial covenants such as a minimum fixed charge coverage ratio, a maximum permitted debt to capitalization ratio and a minimum net worth test. The refining and marketing company may also obtain short-term uncommitted revolving credit or letter of credit facilities, the lenders, issuers, amounts, terms and conditions of which cannot currently be determined. VRMC currently has outstanding $90 million of 10-1/4% industrial revenue refunding bonds and $8.5 million of 10-5/8% industrial revenue bonds issued in 1987. See Note 5 of Notes to Consolidated Financial Statements. The industrial revenue bonds may be called and redeemed on June 1, 1997 at 103% of their principal amount. VRMC intends to refund the existing industrial revenue bonds through issuance, prior to the June 1, 1997 redemption date, of four new series of refunding revenue bonds, having the same aggregate principal amount. VRMC expects to issue the new bonds on a floating rate basis and for the bonds to be secured by a letter of credit to be issued under the bank credit facility described above. Based on the currently existing interest rate environment and because the bonds will be issued as floating rate debt as opposed to fixed rated debt, the interest rates on the refunding revenue bonds will be substantially lower than the rates on the existing industrial revenue bonds. The refunding revenue bonds are expected to have a weighted average life of approximately 16 years from their date of issuance and to be subject to a mandatory sinking fund requirement. The Company believes that the spun-off refining and marketing company will have sufficient funds from operations, and to the extent necessary, from the public and private capital markets and bank markets, to fund its ongoing operating requirements. CURRENT STRUCTURE Net cash provided by the Company's operating activities increased $120 million to $275.8 million in 1996 compared to 1995 due primarily to the increase in income described above under "Results of Operations" and to the changes in current assets and current liabilities detailed in Note 1 of Notes to Consolidated Financial Statements under "Statements of Cash Flows." Included in such changes was a substantial increase in accounts payable in 1996 offset to a large extent by increases in accounts receivable and inventories. Accounts payable and accounts receivable increased in 1996 due to higher commodity prices and increased purchase and sales volumes of refined products, natural gas and NGLs. Refining inventories increased in 1996 due to increased rack and wholesale marketing activities, while refining inventories decreased in 1995 resulting from a decrease in volumes available under crude feedstock contracts, above-normal low-sulphur HOC feedstock inventories at the end of 1994 in anticipation of a turnaround of the HDS Unit in the first quarter of 1995, and above-normal refined product inventories at the end of 1994 attributable to uncertainties related to the implementation of the new RFG regulations. Prepaid expenses and other decreased in 1996 compared to an increase in 1995 due to lower commodity deposits and deferrals, while accrued interest decreased in 1996 compared to an increase in 1995 as a result of timing differences on interest payments for certain nonbank debt. During 1996, the Company utilized the cash provided by its operating activities, a portion of its existing cash balances, proceeds from issuances of common stock related to the Company's employee benefit plans, and proceeds from dispositions of various nonessential properties to fund capital expenditures and deferred turnaround and catalyst costs, reduce bank debt, repay principal on certain outstanding nonbank debt, pay common and preferred stock dividends, and redeem a portion of its outstanding Cumulative Preferred Stock, $8.50 Series A ("Series A Preferred Stock"). Energy currently maintains an unsecured $300 million revolving bank credit and letter of credit facility that is available for general corporate purposes including working capital needs and letters of credit. Borrowings under this facility bear interest at either LIBOR plus .50% (inclusive of a facility fee), prime or a competitive money market rate. The Company is also charged various fees, including various letter of credit fees. As of December 31, 1996, Energy had approximately $273 million available under this committed bank credit facility for additional borrowings and letters of credit. Energy also has $190 million of uncommitted short-term bank credit lines and $170 million of uncommitted bank letter of credit facilities, of which $108 million and $129 million, respectively, were available as of December 31, 1996 for additional borrowings and letters of credit. The Company was in compliance with all covenants contained in its various debt facilities as of December 31, 1996. See Notes 4 and 5 of Notes to Consolidated Financial Statements. In the first quarter of 1995, the Securities and Exchange Commission declared effective Energy's shelf registration statement to offer up to $250 million principal amount of additional debt securities, including Medium- Term Notes, $96.5 million of which were issued in 1995. The net proceeds were used for general corporate purposes, including the repayment of existing indebtedness, financing of capital projects and additions to working capital. See Note 5 of Notes to Consolidated Financial Statements. No additional Medium-Term Notes have been issued since June 1995 and none are expected to be issued in the future. The Company's ratio of earnings to fixed charges, as computed based on rules promulgated by the Commission, was 1.98 for the year ended December 31, 1996. During 1996, the Company expended approximately $165 million for capital investments, including capital expenditures and deferred turnaround and catalyst costs. Of this amount, $93 million related to refining and marketing operations while $66 million related to natural gas related services operations. Included in the refining and marketing amount was $36 million for turnarounds of the Refinery's HDS Unit, MTBE Plant, and hydrocracker and naphtha reformer units. For 1997, the Company currently expects to incur approximately $175 million for capital expenditures and deferred turnaround and catalyst costs. During 1996, the Company entered into a sublease agreement for unused space in its corporate headquarters office complex. The sublease has a primary term of 20 years, with the sublessee having an option to terminate the lease after 10 years. The sublessee is scheduled to occupy the premises in phases, with full occupancy currently expected in 1997. The sublease reduced the Company's rent expense in 1996 by $.5 million and is expected to reduce future rent expense by approximately $2.1 million per year once fully occupied. Dividends on Energy's Common Stock are considered quarterly by the Energy Board of Directors, and may be paid only when approved by the Board. The current quarterly dividend rate on Energy's Common Stock of $.13 per share has remained unchanged since the fourth quarter of 1993. 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 markets, to fund its ongoing operating requirements. The Company expects that to the extent necessary, it can raise additional funds from time to time through equity or debt financings; however, except for borrowings under bank credit agreements, 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 related services operations have a concentration of customers in the natural gas transmission and distribution, and 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 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 $5 million in 1996 and are expected to be approximately $7 million in 1997. 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 related services operations have not been material to date and are not expected to be material in 1997. 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 federal 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. In June 1996, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," which establishes new accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. The statement is effective for transactions occurring after December 31, 1996. Based on information currently known by the Company, this statement will not have a material effect on the Company's consolidated financial statements. 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, 1996 and 1995, 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, 1996. 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. As explained in Note 1 to the financial statements, the Company has restated its consolidated balance sheets as of December 31, 1996 and 1995, its consolidated statements of common stock and other stockholders' equity for each of the three years in the period ended December 31, 1996, and its consolidated statements of income and cash flows for the year ended December 31, 1994, to change the accounting for a contingency which was recorded in conjunction with the acquisition of Valero Natural Gas Partners, L.P. in May of 1994. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP San Antonio, Texas February 14, 1997 (except with respect to the matters discussed in Notes 1, 2 and 3, as to which the date is May 9, 1997) VALERO ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Thousands of Dollars)
December 31, A S S E T S 1996 1995 CURRENT ASSETS: Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . . . $ 19,847 $ 28,054 Cash held in debt service escrow . . . . . . . . . . . . . . . . . . . . . . 37,746 36,627 Receivables, less allowance for doubtful accounts of $1,624 (1996) and $1,193 (1995). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 566,088 339,189 Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212,134 140,822 Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . . 22,408 29,530 Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . 29,946 47,321 888,169 621,543 PROPERTY, PLANT AND EQUIPMENT - including construction in progress of $45,824 (1996) and $37,472 (1995), at cost . . . . . . . . . . . 2,787,431 2,682,694 Less: Accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . 708,352 622,123 2,079,079 2,060,571 INVESTMENT IN AND ADVANCES TO JOINT VENTURES . . . . . . . . . . . . . . . . . 29,192 41,890 DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . . . 138,334 137,876 $3,134,774 $2,861,880 L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y CURRENT LIABILITIES: Short-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 82,000 $ - Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . 72,341 81,964 Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 661,273 312,672 Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,082 31,104 Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,458 42,542 875,154 468,282 LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . . . 868,300 1,035,641 DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279,938 270,813 DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . . 34,407 56,031 REDEEMABLE PREFERRED STOCK, SERIES A, issued 1,150,000 shares, outstanding 11,500 (1996) and 69,000 (1995) shares . . . . . . . . . . . . . 1,150 6,900 COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY: Preferred stock, $1 par value - 20,000,000 shares authorized including redeemable preferred shares: $3.125 Convertible Preferred Stock, issued and outstanding 3,450,000 (1996 and 1995) shares ($172,500 aggregate involuntary liquidation value) . . . . . . . . . . . . . . . . . . . . 3,450 3,450 Common stock, $1 par value - 75,000,000 shares authorized; issued 44,185,513 (1996) and 43,739,380 (1995) shares . . . . . . . . . . . . . 44,186 43,739 Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . 540,133 530,177 Unearned Valero Employees' Stock Ownership Plan Compensation . . . . . . . . (8,783) (11,318) Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 496,839 458,343 Treasury stock, -0- (1996) and 6,904 (1995) common shares, at cost . . . . . - (178) 1,075,825 1,024,213 $3,134,774 $2,861,880 See Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (Thousands of Dollars, Except Per Share Amounts)
Year Ended December 31, 1996 1995 1994 OPERATING REVENUES . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440 COSTS AND EXPENSES: Cost of sales and operating expenses. . . . . . . . 4,606,320 2,830,636 1,561,225 Selling and administrative expenses . . . . . . . . 81,665 78,120 66,258 Depreciation expense. . . . . . . . . . . . . . . . 101,787 100,325 84,032 Total . . . . . . . . . . . . . . . . . . . . . . 4,789,772 3,009,081 1,711,515 OPERATING INCOME . . . . . . . . . . . . . . . . . . . 200,909 188,791 125,925 EQUITY IN EARNINGS (LOSSES) OF AND INCOME FROM: Valero Natural Gas Partners, L.P. . . . . . . . . . - - (10,698) Joint ventures. . . . . . . . . . . . . . . . . . . 3,899 4,827 2,437 LOSS ON INVESTMENT IN PROESA JOINT VENTURE . . . . . . (19,549) - - (PROVISION FOR) REVERSAL OF ACQUISITION EXPENSE ACCRUAL 18,698 (2,506) (16,192) OTHER INCOME, NET. . . . . . . . . . . . . . . . . . . 4,921 5,248 3,431 INTEREST AND DEBT EXPENSE: Incurred. . . . . . . . . . . . . . . . . . . . . . (99,505) (105,921) (79,286) Capitalized . . . . . . . . . . . . . . . . . . . . 4,328 4,699 2,365 INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . 113,701 95,138 27,982 INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . 41,000 35,300 10,700 NET INCOME . . . . . . . . . . . . . . . . . . . . . . 72,701 59,838 17,282 Less: Preferred stock dividend requirements. . . . 11,327 11,818 9,490 NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . $ 61,374 $ 48,020 $ 7,792 EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . $ 1.40 $ 1.10 $ .18 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (in thousands). . . . . . . . . . . . . 43,926 43,652 43,370 DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . $ .52 $ .52 $ .52 See Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (Thousands of Dollars)
Convertible Preferred Number of Common Additional Unearned Stock Common Stock Paid-in VESOP Retained Treasury $1 Par Shares $1 Par Capital Compensation Earnings Stock BALANCE, December 31, 1993 . . $ - 43,391,685 $43,392 $371,303 $(15,958) $446,931 $(3,371) Net income . . . . . . . . . - - - - - 17,282 - Dividends on Series A Preferred Stock. . . . . . - - - - - (1,173) - Dividends on Convertible Preferred Stock. . . . . . - - - - - (7,427) - Dividends on Common Stock. . - - - - - (22,554) - Issuance of Convertible Preferred Stock, net . . . 3,450 - - 164,428 - - - Unearned Valero Employees' Stock Ownership Plan compensation . . . . . . . - - - - 2,252 - - Shares repurchased and shares issued pursuant to employee stock plans and other. . . . . . . . . - 72,184 72 882 - - 3,371 BALANCE, December 31, 1994 . . 3,450 43,463,869 43,464 536,613 (13,706) 433,059 - Net income . . . . . . . . . - - - - - 59,838 - Dividends on Series A Preferred Stock. . . . . . - - - - - (1,075) - Dividends on Convertible Preferred Stock. . . . . . - - - - - (10,781) - Dividends on Common Stock. . - - - - - (22,698) - Unearned Valero Employees' Stock Ownership Plan compensation . . . . . . . - - - - 2,388 - - Deficiency payment tax effect . . . . . . . . . . - - - (9,106) - - - Shares repurchased and shares issued pursuant to employee stock plans and other. . . . . . . . . - 275,511 275 2,670 - - (178) BALANCE, December 31, 1995 . . 3,450 43,739,380 43,739 530,177 (11,318) 458,343 (178) Net income . . . . . . . . . - - - - - 72,701 - Dividends on Series A Preferred Stock. . . . . . - - - - - (587) - Dividends on Convertible Preferred Stock. . . . . . - - - - - (10,781) - Dividends on Common Stock. . - - - - - (22,837) - Unearned Valero Employees' Stock Ownership Plan compensation . . . . . . . - - - - 2,535 - - Shares repurchased and shares issued pursuant to employee stock plans and other. . . . . . . . . - 446,133 447 9,956 - - 178 BALANCE, December 31, 1996 . . $3,450 44,185,513 $44,186 $540,133 $ (8,783) $496,839 $ - See Notes to Consolidated Financial Statements.
VALERO ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Thousands of Dollars)
Year Ended December 31, 1996 1995 1994 CASH FLOWS FROM OPERATING ACTIVITIES: Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation expense . . . . . . . . . . . . . . . . . . . . 101,787 100,325 84,032 Loss on investment in Proesa joint venture . . . . . . . . . 19,549 - - Provision for (reversal of) acquisition expense accrual. . . (18,698) 2,506 16,192 Amortization of deferred charges and other, net. . . . . . . 32,458 32,352 19,452 Changes in current assets and current liabilities. . . . . . 50,232 (31,636) (95,597) Deferred income tax expense . . . . . . . . . . . . . . . . 20,000 4,700 7,000 Equity in (earnings) losses in excess of distributions: Valero Natural Gas Partners, L.P.. . . . . . . . . . . . . - - 16,179 Joint ventures . . . . . . . . . . . . . . . . . . . . . . (3,899) (4,304) (2,437) Changes in deferred items and other, net . . . . . . . . . . 1,671 (7,959) 6,008 Net cash provided by operating activities. . . . . . . . . 275,801 155,822 68,111 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures . . . . . . . . . . . . . . . . . . . . . . (128,453) (124,619) (80,738) Deferred turnaround and catalyst costs . . . . . . . . . . . . . (36,389) (35,590) (21,999) Investment in and advances to joint ventures, net. . . . . . . . 1,197 (2,018) (9,229) Investment in Valero Natural Gas Partners, L.P.. . . . . . . . . - - (124,264) Assets leased to Valero Natural Gas Partners, L.P. . . . . . . . - - (1,886) Distributions from Valero Natural Gas Partners, L.P. . . . . . . - - 2,789 Dispositions of property, plant and equipment. . . . . . . . . . 6,834 13,531 4,504 Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 637 70 898 Net cash used in investing activities. . . . . . . . . . . . . (156,174) (148,626) (229,925) CASH FLOWS FROM FINANCING ACTIVITIES: Increase in short-term debt, net . . . . . . . . . . . . . . . . 82,000 - - Long-term borrowings . . . . . . . . . . . . . . . . . . . . . . 65,000 508,500 574,100 Long-term debt reduction . . . . . . . . . . . . . . . . . . . . (240,229) (473,357) (509,385) Increase in cash held in debt service escrow for principal . . . (1,875) (1,875) (22,768) Common stock dividends . . . . . . . . . . . . . . . . . . . . . (22,837) (22,698) (22,554) Preferred stock dividends. . . . . . . . . . . . . . . . . . . . (11,368) (11,856) (8,600) Issuance of Convertible Preferred Stock, net . . . . . . . . . . - - 167,878 Issuance of common stock . . . . . . . . . . . . . . . . . . . . 11,225 6,129 4,178 Purchases of treasury stock. . . . . . . . . . . . . . . . . . . (4,000) (4,445) (927) Repurchase of Series A Preferred Stock . . . . . . . . . . . . . (5,750) (5,750) (1,150) Net cash provided by (used in) financing activities. . . . . . (127,834) (5,352) 180,772 NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . . (8,207) 1,844 18,958 CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . 28,054 26,210 7,252 CASH AND TEMPORARY CASH INVESTMENTS AT END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . . $ 19,847 $ 28,054 $ 26,210 See Notes to Consolidated Financial Statements.
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 operating subsidiaries (collectively referred to herein as "Refining"). Prior to and including 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") (collectively referred to herein as the "Partnership") using the equity method of accounting. Effective May 31, 1994, the Company acquired through a 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 3). The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 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. Price Risk Management Activities The Company enters into various exchange-traded and over-the-counter financial instrument contracts with third parties to hedge the purchase costs and sales prices of inventories, operating margins and certain anticipated transactions. Such contracts are designated at inception as a hedge where 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. Hedges of inventories are accounted for under the deferral method with gains and losses included in the carrying amounts of inventories and ultimately recognized in cost of sales as those inventories are sold. Hedges of anticipated transactions are also accounted for under the deferral method with gains and losses on these transactions recognized in cost of sales when the hedged transaction occurs. Gains and losses on early terminations of financial instrument contracts designated as hedges are deferred and included in cost of sales in the measurement of the hedged transaction. 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. The Company also enters into various exchange-traded and over-the- counter financial instrument contracts with third parties for trading purposes. Contracts entered into for trading purposes are accounted for under the fair value method. Changes in the fair value of these contracts are recognized as gains or losses in cost of sales currently and are recorded in the Consolidated Balance Sheets in "Prepaid expenses and other" and "Accounts payable" 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 6. 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 the cost of feedstocks and produced products determined primarily under the last-in, first-out ("LIFO") method of inventory pricing and the cost of products purchased for resale determined under the weighted average cost method. The excess of the replacement cost of the Company's LIFO inventories over their LIFO values was approximately $51 million at December 31, 1996. 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, 1996 and 1995 were as follows (in thousands) (see Note 6): December 31, 1996 1995 Refinery feedstocks. . . . . . . . . . . $ 42,744 $ 48,295 Refined products and blendstocks . . . . 99,398 41,967 Natural gas in underground storage . . . 40,609 31,156 NGLs . . . . . . . . . . . . . . . . . . 5,190 3,280 Materials and supplies . . . . . . . . . 24,193 16,124 $212,134 $140,822 Refinery feedstock and refined product and blendstock inventory volumes totalled 7.4 million barrels ("MMbbls") and 6.2 MMbbls as of December 31, 1996 and 1995, respectively. Natural gas inventory volumes totalled approximately 10 billion cubic feet ("Bcf") and 11.7 Bcf as of December 31, 1996 and 1995, respectively. Prepaid Expenses and Other Prepaid expenses and other as of December 31, 1996 and 1995 were as follows (in thousands): December 31, 1996 1995 Commodity deposits and deferrals (see Note 6). . $18,914 $34,553 Prepaid insurance. . . . . . . . . . . . . . . . 6,737 8,663 Prepaid benefits expense . . . . . . . . . . . . 2,794 2,187 Other. . . . . . . . . . . . . . . . . . . . . . 1,501 1,918 $29,946 $47,321 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 under the composite method of depreciation. Gains or losses on sales or other dispositions of major units of property are credited or charged to income. Major classes of property, plant and equipment as of December 31, 1996 and 1995 were as follows (in thousands): December 31, 1996 1995 Refining and marketing - processing facilities. . $1,634,430 $1,596,832 Natural gas related services - transmission, gathering, processing and storage facilities . . 988,234 945,408 Other . . . . . . . . . . . . . . . . . . . . . . 118,943 102,982 Construction in progress. . . . . . . . . . . . . 45,824 37,472 $2,787,431 $2,682,694 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. During early 1996, a detailed study of the Company's fixed asset lives was completed by a third-party consultant for the majority of the Company's refining and marketing and natural gas related services assets. As a result of such study, effective January 1, 1996, the Company adjusted the weighted-average remaining lives of the assets subject to the study, utilizing the composite method of depreciation, to better reflect the estimated periods during which such assets are expected to remain in service. The effect of this change in accounting estimate on depreciation expense for 1996 was insignificant. A summary of the principal rates used in computing the annual provision for depreciation, primarily utilizing the composite method and including estimated salvage values, is as follows: Weighted Range Average Refining and marketing - processing facilities . . . . . . . . . . . . . . . . . 3.6% - 4.9% 4.4% Natural gas related services - transmission, gathering, processing and storage facilities . . . . . . . . . . . . . . . . . 4.3% - 5.3% 4.7% Other. . . . . . . . . . . . . . . . . . . . . 6% - 45% 25.3% 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 included in noncurrent other assets was $26 million as of December 31, 1996. Such amount is expected to be recovered over the next five years through natural gas sales rates charged to certain customers. Catalyst and Refinery Turnaround Costs Catalyst costs are 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, contract costs, debt issuance costs, and certain other costs. Technological royalties and licenses are amortized over the estimated useful life of each particular related asset. Contract costs are amortized over the term of the related contract. Debt issuance costs are amortized by the effective interest method over the estimated life of each instrument or facility. Other Accrued Expenses Other accrued expenses as of December 31, 1996 and 1995 were as follows (in thousands): December 31, 1996 1995 Accrued taxes. . . . . . . . . . . . . . . . . . . . .$19,633 $16,433 Other accrued employee benefit costs (see Note 13) . . 8,688 11,047 Current portion of accrued pension cost (see Note 13). 4,265 4,695 Accrued lease expense. . . . . . . . . . . . . . . . . 3,006 4,566 Other. . . . . . . . . . . . . . . . . . . . . . . . . 3,866 5,801 $39,458 $42,542 Fair Value of Financial Instruments The carrying amounts of the Company's financial instruments approximate fair value, except for long-term debt and certain financial instruments used in price risk management activities. See Notes 5 and 6. Earnings Per Share Earnings per share of common stock were computed, after recognition of preferred stock dividend requirements, based on the weighted average number of common shares outstanding during each year. For the years ended December 31, 1996, 1995 and 1994, the conversion of the Convertible Preferred Stock (see Note 9) 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, 1996, 1995 and 1994 was 43,926,026, 43,651,914 and 43,369,836, respectively. 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, short-term debt and current maturities of long-term debt. Also excluded are the Partnership's current assets and liabilities as of the acquisition date (see Note 3). The changes in the Company's 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. (Dollars in thousands.) Year Ended December 31, 1996 1995 1994 Cash held in debt service escrow for interest . . . . $ 756 $ 689 $(12,673) Receivables, net. . . . . . . (226,899) (106,916) (64,150) Inventories . . . . . . . . . (71,312) 41,267 (21,785) Prepaid expenses and other. . 17,375 (22,304) 142 Accounts payable. . . . . . . 344,418 38,825 (4,295) Accrued interest. . . . . . . (11,022) 11,411 3,901 Other accrued expenses. . . . (3,084) 5,392 3,263 Total . . . . . . . . . . . $ 50,232 $ (31,636) $(95,597) The following table provides information related to cash interest and income taxes paid by the Company for the periods indicated (in thousands): Year Ended December 31, 1996 1995 1994 Interest - net of amount capitalized of $4,328 (1996), $4,699 (1995) and $2,365 (1994). . . . . . . . . . . . $105,519 $86,553 $72,023 Income taxes . . . . . . . . . . . . . 19,043 23,935 3,931 Noncash investing activities for 1995 included the reclassification to "Deferred charges and other assets" of $12.1 million of contract costs, previously included in "Property, plant and equipment" on the Consolidated Balance Sheets. Noncash investing activities for 1994 included the accrual of the remaining $60 million payment made in 1995 for the Company's interest in a methanol plant renovation project. Accounting Changes In June 1996, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," which establishes new accounting and reporting standards for transfers and servicing of financial assets and extinguishments of liabilities. The statement is effective for transactions occurring after December 31, 1996. Based on information currently known by the Company, this statement will not have a material effect on the Company's consolidated financial statements. SFAS No. 123, "Accounting for Stock-Based Compensation," issued by the FASB in October 1995, encourages, but does not require companies to measure and recognize in their financial statements a compensation cost for stock-based employee compensation plans based on the "fair value" method of accounting set forth in the statement. The Company has chosen to continue to account for its employee stock compensation plans using the "intrinsic value" method of accounting set forth in Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the quoted market price of the Company's common stock at the date of the grant over the amount an employee must pay to acquire the stock. See Note 13 for the pro forma effects on net income and earnings per share had compensation cost for the Company's stock-based compensation plans been determined consistent with SFAS No. 123. Effective January 1, 1996, the Company adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." This statement establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles, and goodwill related to assets to be held and used, and for long-lived assets and certain identifiable intangibles to be disposed of. This statement is required to be applied prospectively for assets to be held and used, while its initial application to assets held for disposal is required to be reported as the cumulative effect of a change in accounting principle. Since adoption, no impairment losses have been recognized in the Company's consolidated financial statements. However, see Note 7 for a discussion of the Company's write-off in the fourth quarter of 1996 of its equity method investment in its Mexico joint venture project. Restatement of Financial Information The Company has restated its financial statements for the years ended December 31, 1996, 1995 and 1994. This action was taken to change the accounting for a contingency which was recorded in conjunction with the acquisition of VNGP, L.P. in May of 1994. For a further discussion of the nature of the contingency, see Note 3, "Acquisition of Valero Natural Gas Partners, L.P." As of the date of the acquisition of VNGP, L.P., the Company's management believed that it was probable that a liability had been incurred resulting from the acquisition. Although the specific amount of the contingency could not be determined as of the date of the acquisition, the Company believed that the liability would be within a range of amounts that could be reasonably estimated as of that date. Accordingly, the Company recorded a liability in the amount of $14.8 million, representing the minimum amount of the range determined by management. The liability was originally recorded as a cost of the acquisition. Since the contingency arose as a result of the acquisition and represented an obligation of the Company rather than an obligation of VNGP, L.P., the income statement for 1994 has been restated to charge the acquisition contingency to expense, rather than property, plant, and equipment, as of the date of the acquisition. As a result of this change, the balances of property, plant, and equipment, deferred income taxes, and retained earnings have been restated in the Consolidated Balance Sheets as of December 31, 1996 and 1995. The impact of this change on the Consolidated Statement of Income for the year ended December 31, 1994, is summarized below (dollars in thousands): Year Ended December 31, 1994 As Reported As Restated Income before income taxes. . . . . . . . $42,782 $27,982 Income tax expense. . . . . . . . . . . . 15,900 10,700 Net income. . . . . . . . . . . . . . . . 26,882 17,282 Net income applicable to common stock . . 17,392 7,792 Earnings per share of commong stock . . . .40 .18 2. SUBSEQUENT EVENTS Acquisition of Basis Petroleum, Inc. The Company and Salomon Inc ("Salomon") have entered into a stock purchase agreement pursuant to which Valero has acquired the stock of Basis Petroleum, Inc. ("Basis") from Salomon for $285 million, plus approximately $200 million for inventories and other working capital. Basis owns and operates three petroleum refineries located in Texas and Louisiana and markets refined products. The three refineries have a total crude oil processing capacity of about 310,000 barrels per day. The acquisition will be accounted for using the purchase method of accounting. Therefore, the results of operations of Basis will be included in the consolidated financial statements of the Company commencing on May 1, 1997. The stock purchase agreement provides for Salomon to receive up to 10 additional payments following each anniversary date of the closing of the acquisition. These annual earn-out payments would be based on the difference between a stated base refining "crack spread" and the theoretical spread computed using actual average quoted prices, and calculated using a nominal average annual throughput of 100 million barrels. These payments are limited to $35 million in any year and $200 million in the aggregate. Any such participation payments, if made, will be accounted for as an additional cost of the acquisition of Basis by the Company and will be depreciated over the remaining lives of the assets to which the additional cost is allocated. The purchase price was paid, in part, with 3,429,796 shares of Energy common stock having a fair market value of approximately $120 million, with the remainder paid in cash. Proposed Restructuring In November 1996, the Company publicly announced that its Board of Directors had approved a management recommendation to pursue strategic alternatives involving the Company's principal business activities. Such alternatives included seeking a strategic alliance for the Company's natural gas related services business and a spin-off of its petroleum refining and marketing operations. In response to the Company's solicitation for indications of interest, a number of companies submitted written proposals to engage in a strategic alliance with the Company, and the Company invited a final group of five companies to participate in a more extensive due diligence review. On January 31, 1997, the Company announced that its Board of Directors had approved an agreement and plan of merger with PG&E Corporation ("PG&E") to combine the Company's natural gas related services business with PG&E following the spin-off of the Company's refining and marketing business to the Company's shareholders (the "Restructuring"). Under the terms of the merger agreement, the Company's natural gas related services business will be merged with a wholly owned subsidiary of PG&E. PG&E will acquire the Company's natural gas related services business for approximately $1.5 billion, plus adjustments for working capital and other considerations. PG&E will issue $722.5 million of common stock, subject to certain closing adjustments, in exchange for outstanding shares of Energy's common stock, and will assume approximately $777.5 million of net debt and other liabilities. Each Energy shareholder will receive a fractional share of PG&E common stock (trading on the New York Stock Exchange under the symbol "PCG") for each Energy share; the amount of PG&E stock to be received will be based on the average price of the PG&E common stock during a period preceding the closing of the transaction and the number of Energy shares issued and outstanding at the time of the closing. Energy's shareholders will also receive one share of the spun-off refining and marketing company for each share of Energy common stock. The refining and marketing company will retain the Valero Energy Corporation name and will apply to be listed on the New York Stock Exchange. The refining and marketing company expects to aggressively pursue acquisitions and strategic alliances in the refining and marketing industry. The spin-off of the refining and marketing business and the merger with PG&E are expected to be tax-free transactions. However, on February 6, 1997, President Clinton's budget recommendations to Congress called for new legislation that, if enacted, may require Energy to pay federal income tax upon the consummation of the Restructuring on the amount of gain equal to the excess of the value of the refining and marketing company stock distributed to Energy's stockholders over Energy's basis in such stock. Even though this legislation has not yet been introduced in Congress, the proposal would be effective for distributions after the date of first committee action. It is uncertain whether any such legislation ultimately will be enacted, whether its effective date provision may be modified, or when committee action in Congress may first occur. The Company believes it is likely that any legislation ultimately enacted will provide an exemption for transactions like the Restructuring for which definitive agreements were executed prior to introduction of the President's budget; however, if the proposal is enacted or pending prior to consummation of the Restructuring with an effective date provision that could cause Energy to be subject to tax, the tax opinions described below may not be available. The Restructuring transactions are subject to approval by the Company's shareholders, the Securities and Exchange Commission, and certain regulatory agencies, and receipt of favorable tax opinions. The Company expects to hold a special meeting of stockholders (in lieu of an annual meeting) in June 1997 to consider the Restructuring transactions; such transactions are expected to be completed by mid-1997. However, there can be no assurance that the various approvals or opinions will be given or that the conditions to consummating the transactions will be met. 3. ACQUISITION OF VALERO NATURAL GAS PARTNERS, L.P. In March 1994, Energy issued Convertible Preferred Stock (see Note 9) 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 was accounted for as a purchase and the purchase price was allocated to the assets acquired and liabilities assumed based on estimated fair values resulting in part from an independent appraisal of the property, plant and equipment of the Partnership. The consolidated statements of income of the Company 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 for all periods thereafter. In conjunction with the acquisition of the Partnership by the Company, the Company recorded in 1994 a $14.8 million loss representing the Company's estimate of certain costs resulting from the acquisition of the Public Units of VNGP, L.P. See Note 1,"- Restatement of Financial Information." The reserve was established as a result of various claims and lawsuits filed against the Company to block the merger or to increase the price offered by the Company for the purchase of the outstanding Public Units, and the Company's determination that it was probable that losses were expected from successful assertion of claims relative to the acquisition. In late 1996, upon receipt by the Company of a favorable ruling by the magistrate hearing the sole remaining lawsuit related to the acquisition (as described in Note 15), the Company reversed all remaining reserves pertaining to the acquisition. The following unaudited pro forma financial information of Valero Energy Corporation and subsidiaries assumes that the above described transactions occurred for all of 1994. Such pro forma information is not necessarily indicative of the results of future operations. Year Ended December 31, 1994 (Thousands of dollars, except per share amounts) Operating revenues. . . . . . . . . . . . $2,333,982 Operating income. . . . . . . . . . . . . 125,943 Net income. . . . . . . . . . . . . . . . 9,789 Net loss applicable to common stock . . . (2,158) Loss per share of common stock. . . . . . (.05) 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. The following table summarizes transactions between the Company and the Partnership for the five months ended May 31, 1994 (in thousands): Five Months Ended May 31, 1994 NGL purchases and services from the Partnership . . . . $36,536 Natural gas purchases from the Partnership. . . . . . . 9,672 Sales of NGLs and natural gas, and transportation and other charges to the Partnership . . . . . . . . 11,385 Management fees billed to the Partnership for direct and indirect costs. . . . . . . . . . . . . . 34,299 Interest income from capital lease transactions . . . . 5,481 4. SHORT-TERM DEBT Energy currently maintains nine separate short-term bank lines of credit totalling $190 million, $82 million of which was outstanding at December 31, 1996 at a weighted average interest rate of 6.81%. Five of these lines are cancellable on demand, and the others expire at various times in 1997. 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. 5. LONG-TERM DEBT AND BANK CREDIT FACILITIES Long-term debt balances as of December 31, 1996 and 1995 were as follows (in thousands): December 31, 1996 1995 Valero Refining and Marketing Company: Industrial revenue bonds: Marine terminal and pollution control revenue bonds, Series 1987A bonds, 10 1/4%, due June 1, 2017. . . . . . . . . . . . . . . . . $ 90,000 $ 90,000 Marine terminal revenue bonds, Series 1987B bonds, 10 5/8%, due June 1, 2008 . . . 8,500 8,500 Valero Energy Corporation: $300 million revolving bank credit and letter of credit facility, 6% at December 31, 1996, due November 1, 2000. . . . 25,000 120,000 10.58% Senior Notes, due December 30, 2000. . . . 140,343 187,714 9.14% VESOP Notes, due February 15, 1999 (see Note 13) . . . . . . . . . . . . . . . . . 5,083 6,819 Medium-Term Notes . . . . . . . . . . . . . . . . 228,500 228,500 Valero Management Partnership, L.P. First Mortgage Notes. . . . . . . . . . . . . . . . . . 443,215 476,072 Total long-term debt . . . . . . . . . . . . . . 940,641 1,117,605 Less current maturities. . . . . . . . . . . . . 72,341 81,964 $ 868,300 $1,035,641 Energy currently maintains an unsecured $300 million revolving bank credit and letter of credit facility that is available for general corporate purposes including working capital needs and letters of credit. Borrowings under this facility bear interest at either LIBOR plus .50% (inclusive of a facility fee), prime or a competitive money market rate. The Company is also charged various fees, including various letter of credit fees. As of December 31, 1996, Energy had approximately $273 million available under this committed bank credit facility for additional borrowings and letters of credit. Energy also has $170 million of uncommitted bank letter of credit facilities, approximately $129 million of which were available as of December 31, 1996 for additional letters of credit. In 1992, Energy filed with the Securities and Exchange Commission (the "Commission") a shelf registration statement which was used to offer $150 million principal amount of Medium-Term Notes, $132 million of which were outstanding at December 31, 1996. In 1994, Energy filed another shelf registration statement with the Commission to offer up to $250 million principal amount of additional debt securities, including Medium-Term Notes, $96.5 million of which were issued and outstanding at December 31, 1996. As of December 31, 1996, Energy's outstanding Medium-Term Notes had a remaining weighted average life of approximately 7.5 years and a weighted average interest rate of approximately 8.3%. No Medium-Term Notes have been issued since June 1995 and none are expected to be issued in the future. The Management Partnership's First Mortgage Notes are currently comprised of five remaining series due serially from 1997 through 2009, and 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, 1996, the First Mortgage Notes had a remaining weighted average life of approximately 5.5 years and a weighted average interest rate of 10.13% 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, 1996, $37.7 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. 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 covenants contained in its various debt facilities as of December 31, 1996. Based on long-term debt outstanding at December 31, 1996, maturities of long-term debt, including sinking fund requirements and excluding borrowings under bank credit facilities, for the years ending December 31, 1998 through 2001 are approximately $75 million, $73.2 million, $85.6 million and $94.5 million, respectively. Maturities of long-term debt under Energy's revolving bank credit and letter of credit facility for the year ended December 31, 2000 are $25 million. 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 $1,039 million and $1,275 million at December 31, 1996 and 1995, respectively. 6. PRICE RISK MANAGEMENT ACTIVITIES Refining and Marketing Hedging Activities The Company uses over-the-counter price swaps, 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. Swaps, options and futures contracts at the end of 1996 and 1995 had remaining terms of less than one year. As of December 31, 1996 and 1995, 13% and 19%, respectively, of the Company's refining inventory position was hedged. The amount of deferred hedge losses included as an increase to refinery inventories was $.8 million and $1 million as of December 31, 1996 and 1995, respectively. The following is a summary of the contract amounts and range of prices of the Company's contracts held or issued to hedge refining inventories as of December 31, 1996 and 1995: 1996 1995 Payor Receiver Payor Receiver Swaps: Volumes (Mbbls). 497 497 - - Price (per bbl). $17.50-$17.57 $17.31-$17.38 - - Options: Volumes (Mbbls). - - - 150 Price (per bbl). - - - $24.36-$24.78 Futures: Volumes (Mbbls). - 981 250 1,327 Price (per bbl). - $24.87-$29.65 $22.71-$23.83 $17.57-$24.55 The Company also hedges anticipated transactions. Over-the-counter price swaps, options and futures are used to hedge refining operating margins for periods up to 12 months by locking in components of the margins, including the resid discount, the conventional crack spread and the premium product differentials. As of December 31, 1996 and 1995, less than 2% of the Company's anticipated 1997 and 1996 refining margin, respectively, were hedged. There were no significant explicit deferrals of hedging gains or losses related to these anticipated transactions as of either year end. The following table is a summary of the contract or notional amounts and range of prices of the Company's contracts held or issued to hedge refining margins as of December 31, 1996 and 1995. Volumes shown for swaps represent notional volumes which are used to calculate amounts due under the agreements and do not represent volumes exchanged. 1996 1995 Payor Receiver Receiver Swaps: Volumes (Mbbls). . 6,000 28,300 525 Price (per bbl). . $.53-$4.90 $.74-$3.55 $34.23-$35.81 Options: Volumes (Mbbls). . 750 - - Price (per bbl) . $25.00-$32.76 - - Futures: Volumes (Mbbls). . 1,312 1,410 14 Price (per bbl). . $26.46-$30.87 $21.74-$30.39 $18.95-$19.50 Natural Gas Related Services Hedging Activities The Company uses futures, price swaps and over-the-counter and exchange-traded options to hedge gas storage. These financial instrument contracts run for periods of up to three months. The Company also enters into basis swaps for location differentials at fixed prices which generally extend for periods up to three months. As of December 31, 1996 and 1995, 59% and 26%, respectively, of the Company's natural gas inventory position was hedged. The amount of deferred hedge gains (losses) included as a reduction (increase) of natural gas inventories was $(7.8) million and $.9 million as of December 31, 1996 and 1995, respectively. The following is a summary of the contract or notional amounts and range of prices of the Company's contracts held or issued to hedge natural gas inventories as of December 31, 1996 and 1995. Volumes shown for swaps and basis swaps represent notional volumes which are used to calculate amounts due under the agreements and do not represent volumes exchanged. 1996 1995 Payor Receiver Payor Receiver Swaps: Volumes (MMcf) . 8,155 9,155 1,000 1,000 Price (per Mcf). $3.20-$4.37 $2.72-$4.25 $1.91 $2.87-$3.45 Options: Volumes (MMcf) . 33,290 33,850 12,000 23,000 Price (per Mcf). $2.20-$2.60 $2.50-$3.30 $1.90-$2.50 $1.90-$2.50 Futures: Volumes (MMcf) . 31,710 36,970 17,480 15,430 Price (per Mcf). $2.12-$4.57 $2.08-$4.37 $1.77-$3.45 $1.75-$3.45 Basis Swaps: Volumes (MMcf) . 2,000 4,096 500 2,120 Price (per Mcf). $(.16)-$.32 $(.60)-$.19 $.63 $.13-$.85 The Company also uses futures, price swaps and over-the-counter and exchange-traded options to hedge certain anticipated transactions, including anticipated natural gas purchase requirements for NGL plant shrinkage and refining operations, natural gas liquids sales, and commitments to buy and sell natural gas at fixed prices. These financial instrument contracts extend through the year 2001. The Company also enters into basis swaps for location differentials at fixed prices which extend through the year 2001. As of December 31, 1996 and 1995, 12% and 29%, respectively, of the Company's anticipated annual NGL plant shrinkage requirements, and 11% and 29%, respectively, of Refining's anticipated annual natural gas requirements, were hedged. Explicitly deferred gains from hedges of these anticipated transactions of $24.4 million and $3.9 million, as of December 31, 1996 and 1995, respectively, will be recognized when the hedged transaction occurs. The following table is a summary of the contract or notional amounts and range of prices of the Company's contracts held or issued to hedge anticipated natural gas purchase requirements for NGL plant shrinkage and refining operations, natural gas purchase and sales commitments, and anticipated NGL production volumes as of December 31, 1996 and 1995. Volumes shown for swaps and basis swaps represent notional volumes which are used to calculate amounts due under the agreements and do not represent volumes exchanged.
Total Total Expected Maturity Date 1996 1995 1997 1998-2001 Balance Balance Payor Receiver Payor Receiver Payor Receiver Payor Receiver Swaps: Volumes (MMcf) . 28,353 13,327 14,422 - 42,775 13,327 55,277 26,111 Price (per Mcf).$1.54-$4.55 $1.65-$4.25 $2.06 - $1.54-$4.55 $1.65-$4.25 $1.31-$3.45 $1.71-$4.34 Volumes (Mbbls). 3,080 980 - - 3,080 980 - - Price (per bbl).$9.35-$28.77 $10.71-$20.37 - - $9.35-$28.77 $10.71-$20.37 - - Options: Volumes (MMcf) . 26,565 21,195 - - 26,565 21,195 10,340 9,073 Price (per Mcf).$1.66-$3.50 $1.61-$4.00 - - $1.66-$3.50 $1.61-$4.00 $1.66-$3.25 $1.50-$2.45 Volumes (Mbbls). 75 975 - - 75 975 - - Price (per bbl).$17.43 $14.07-$16.80 - - $17.43 $14.07-$16.80 - - Futures: Volumes (MMcf) . 90,810 82,200 740 - 91,550 82,200 105,020 52,680 Price (per Mcf).$1.72-$4.57 $1.75-$4.56 $2.35-$2.51 - $1.72-$4.57 $1.75-$4.56 $1.50-$3.45 $1.50-$3.61 Volumes (Mbbls). 1,223 1,803 - - 1,223 1,803 - - Price (per bbl).$14.99-$28.81 $15.33-$27.62 - - $14.99-$28.81 $15.33-$27.62 - - Basis Swaps: Volumes (MMcf) . 32,296 36,961 11,224 40,470 43,520 77,431 16,787 98,541 Price (per Mcf).$(.66)-$.24 $(.32)-$.35 $(.52)-$(.06) $(.30)-$(.26) $(.66)-$.24 $(.32)-$.35 $.06-$1.06 $.03-$.85
The following table discloses the carrying amount and fair value of the Company's refining, natural gas and NGL contracts held or issued for non-trading purposes as of December 31, 1996 and 1995 (dollars in thousands): 1996 1995 Assets (Liabilities) Assets (Liabilities) Carrying Fair Carrying Fair Amount Value Amount Value Swaps . . . . . . . $ 7,184 $13,853 $ 98 $1,557 Options . . . . . . . 1,101 (2,638) (91) 429 Futures . . . . . . . 21,116 21,116 217 217 Basis Swaps. . . . . . - 2,809 - 5,823 Total . . . . . . . $29,401 $35,140 $224 $8,026 Trading Activities The Company enters into transactions for trading purposes using its fundamental and technical analysis of market conditions to earn additional revenues. The types of instruments used include futures, price swaps, basis swaps and over-the-counter and exchange-traded options. Except in limited circumstances, these contracts run for periods of up to 12 months, with the exception of basis swaps which extend through the year 2000. The following table is a summary of the contract amounts and range of prices of the Company's contracts held or issued for trading purposes as of December 31, 1996 and 1995:
Total Total Expected Maturity Date 1996 1995 1997 1998-2000 Balance Balance Payor Receiver Payor Receiver Payor Receiver Payor Receiver Swaps: Volumes (MMcf) . 4,520 4,160 - - 4,520 4,160 23,430 24,950 Price (per Mcf).$3.25-$4.25 $3.15 -$4.25 - - $3.25 -$4.25 $3.15-$4.25 $1.79-$3.44 $1.71-$3.44 Volumes (Mbbls). 400 400 - - 400 400 2,925 2,250 Price (per bbl).$4.25-$4.55 $4.20-$4.72 - - $4.25-$4.55 $4.20-$4.72 $1.80-$4.14 $2.40-$4.18 Options: Volumes (MMcf) . 15,000 15,310 - - 15,000 15,310 36,100 18,000 Price (per Mcf).$2.10-$5.20 $1.65-$5.20 - - $2.10-$5.20 $1.65-$5.20 $1.60-$3.25 $1.60-$2.40 Volumes (Mbbls). - 275 - - - 275 - 150 Price (per bbl). - $25.20 - - - $25.20 - $17.50-$19.00 Futures: Volumes (MMcf) . 39,420 41,390 - - 39,420 41,390 63,650 59,280 Price (per Mcf).$1.87-$4.50 $2.09-$4.58 - - $1.87-$4.50 $2.09-$4.58 $1.64-$3.44 $1.67-$3.67 Volumes (Mbbls). - - - - - - 100 450 Price (per bbl). - - - - - - $23.42-$23.44 $18.24-$19.00 Basis Swaps: Volumes (MMcf) . 27,000 30,460 11,850 27,275 38,850 57,735 11,620 42,000 Price (per Mcf).$(.32)-$.38 $(.32)-$.40 $(.10)-$(.10) $(.08)-$(.05) $(.32)-$.38 $(.32)-$.40 $.07-$.47 $.03-$.22
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 periods ended December 31, 1996 and 1995 (dollars in thousands): Fair Value of Assets (Liabilities) Average Ending Net Gains(Losses) 1996 1995 1996 1995 1996 1995 Swaps. . . . .$ (102) $ (329) $ (560) $ 245 $ 613 $(2,143) Options. . . . (93) 1,026 (1,047) 297 8,270 (3,273) Futures. . . . 1,951 2,030 926 6,739 4,016 8,822 Basis Swaps. . 1,705 487 1,072 1,266 277 2,706 Total. . . .$3,461 $3,214 $ 391 $8,547 $13,176 $ 6,112 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. 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. 7. INVESTMENTS 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 (the "Project") to design, construct and operate a plant in Mexico to produce methyl tertiary butyl ether ("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"). Beginning in December 1994, the Mexican peso experienced substantial devaluation, interest rates in Mexico increased significantly and Mexican economic conditions deteriorated. Because of these factors, in January 1995 the Board of Directors of Energy determined that the Company would suspend further investment in the Project pending the resolution of certain key issues. During 1995 and continuing in 1996, the Project participants engaged in negotiations among themselves and with potential additional participants in an attempt to restructure the participants' ownership interests in Proesa and arrange funding for the Project. To date, financing on terms satisfactory to the participants has not been available. During the fourth quarter of 1996, the Company determined that it is unlikely that the Project can go forward. Accordingly, the Company wrote off its $16.5 million investment in Proesa and accrued a provision for additional liabilities associated with such investment of $3 million. 8. REDEEMABLE PREFERRED STOCK In December of 1996, Energy redeemed 57,500 shares ($5,750,000) of its Cumulative Preferred Stock, $8.50 Series A ("Series A Preferred Stock"), at $100 per share. The redemption of the remaining balance (11,500 shares or $1,150,000) is expected to occur prior to December 1, 1997. 9. 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 Energy common stock ("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. 10. PREFERENCE SHARE PURCHASE RIGHTS On November 25, 1995, Energy made a dividend distribution of one Preference Share Purchase Right ("Right") for each outstanding share of Common Stock, replacing similar expiring rights distributed on November 25, 1985. Until exercisable, the Rights are not transferable apart from 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 III, at an exercise price of $75 per Right. 11. INDUSTRY SEGMENT INFORMATION
Year Ended December 31, 1996 1995 1994 (Thousands of Dollars) Operating revenues: Refining and marketing. . . . . . . . . . . . . . . . . $2,757,801 $1,950,657 $1,090,368 Natural gas related services. . . . . . . . . . . . . . 2,445,504 1,396,468 784,287 Other . . . . . . . . . . . . . . . . . . . . . . . . . 123 126 42,639 Intersegment eliminations . . . . . . . . . . . . . . . (212,747) (149,379) (79,854) Total . . . . . . . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440 Operating income (loss): Refining and marketing. . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660 Natural gas related services. . . . . . . . . . . . . . 132,178 83,180 61,944 Corporate general and administrative expenses and other, net . . . . . . . . . . . . . . . (41,315) (35,901) (14,679) Total . . . . . . . . . . . . . . . . . . . . . . . 200,909 188,791 125,925 Equity in earnings (losses) of and income from: Valero Natural Gas Partners, L.P. . . . . . . . . . . . - - (10,698) Joint ventures. . . . . . . . . . . . . . . . . . . . . 3,899 4,827 2,437 Loss on investment in Proesa joint venture. . . . . . . . (19,549) - - (Provision for) reversal of acquisition expense accrual . 18,698 (2,506) (16,192) Other income, net . . . . . . . . . . . . . . . . . . . . 4,921 5,248 3,431 Interest and debt expense, net. . . . . . . . . . . . . . (95,177) (101,222) (76,921) Income before income taxes. . . . . . . . . . . . . . . $ 113,701 $ 95,138 $ 27,982 Identifiable assets: Refining and marketing. . . . . . . . . . . . . . . . . $1,621,998 $1,524,065 $1,528,621 Natural gas related services. . . . . . . . . . . . . . 1,366,050 1,162,724 1,119,347 Other . . . . . . . . . . . . . . . . . . . . . . . . . 145,248 150,141 149,688 Investment in and advances to joint ventures. . . . . . 29,192 41,890 41,162 Intersegment eliminations and reclassifications . . . . (27,714) (16,940) (22,260) Total . . . . . . . . . . . . . . . . . . . . . . . . $3,134,774 $2,861,880 $2,816,558 Depreciation expense: Refining and marketing. . . . . . . . . . . . . . . . . $ 52,680 $ 55,032 $ 52,956 Natural gas related services. . . . . . . . . . . . . . 44,211 40,881 26,636 Other . . . . . . . . . . . . . . . . . . . . . . . . . 4,896 4,412 4,440 Total . . . . . . . . . . . . . . . . . . . . . . . . $ 101,787 $ 100,325 $ 84,032 Capital additions: Refining and marketing. . . . . . . . . . . . . . . . . $ 56,673 $ 29,039 $ 119,748 Natural gas related services. . . . . . . . . . . . . . 65,671 33,489 18,860 Other . . . . . . . . . . . . . . . . . . . . . . . . . 6,109 2,091 2,130 Total . . . . . . . . . . . . . . . . . . . . . . . . $ 128,453 $ 64,619 $ 140,738
The Company's core businesses are specialized refining and natural gas related services. Effective January 1, 1996, the Company's natural gas and NGL businesses were reported as one industry segment for financial reporting purposes (described herein as "natural gas related services") in recognition of the Company's increasing integration of these business activities due to the restructuring of the interstate natural gas pipeline industry in 1993 through FERC Order 636 and the resulting transformation of the U.S. natural gas industry into a more market and customer-oriented environment. The Company's ability to gather, transport, market and process natural gas, among other things, are value-added services offered to producers and attract additional quantities of gas to the Company's pipeline system and processing plants through integrated business arrangements. Prior to 1996, the Company's natural gas and NGL businesses were reported as separate industry segments. The primary effect of this change on the Company's segment disclosures was the elimination of volume, revenue and income amounts related to natural gas fuel and shrinkage volumes sold to and transported for the natural gas liquids segment by the natural gas segment. Amounts for 1995 and 1994 shown above have been restated to conform to the 1996 presentation. At its refinery in Corpus Christi, Refining converts high-sulfur atmospheric residual oil into premium products, primarily reformulated gasoline ("RFG"), and sells those products principally on a spot, truck rack and term contract basis. Spot and term sales of Refining's products are made principally to larger oil companies and gasoline distributors in the northeastern, midwestern and southeastern United States. In 1996, the Company also began sales of "CARB" gasoline into the West Coast market in connection with the startup of the California Air Resources Board's statewide CARB gasoline program. This program requires the use of gasoline which meets more restrictive air quality specifications than the federally mandated RFG. The principal purchasers of Refining's products from truck racks have been wholesalers and jobbers in the eastern and midwestern United States. The Company's natural gas related services business consists of: purchasing, gathering, processing, storing, transporting and selling natural gas, principally to gas distribution companies, electric utilities, pipeline companies and industrial customers; transporting natural gas for producers, other pipelines and end users in North America; extracting natural gas liquids, principally from natural gas throughput of the Company's pipeline operations; fractionating, transporting and selling natural gas liquids, principally to petrochemical plants, refineries and domestic fuel distributors in the Corpus Christi and Mont Belvieu (Houston) areas; and marketing electric power throughout the United States. Intersegment revenue eliminations relate primarily to the refining and marketing segment's purchases of feedstocks and fuel gas from the natural gas related services segment. In 1996, the Company had no significant amount of export sales and no significant foreign operations, and no single customer accounted for more than 10% of the Company's 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 3). Capital additions in 1994 include the accrual of the remaining $60 million payment made in 1995 for the Company's interest in a methanol plant renovation project. 12. INCOME TAXES Components of income tax expense were as follows (in thousands): Year Ended December 31, 1996 1995 1994 Current: Federal. . . . . . . . . . . $20,996 $29,674 $ 3,535 State. . . . . . . . . . . . 4 926 165 Total current . . . . . . 21,000 30,600 3,700 Deferred: Federal. . . . . . . . . . . 20,000 4,700 7,000 Total income tax expense. $41,000 $35,300 $10,700 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): Year Ended December 31, 1996 1995 1994 Federal income tax expense at the statutory rate. . . . $39,800 $33,300 $ 9,800 State income taxes, net of federal income tax benefit . - 600 100 Other - net. . . . . . . . . . 1,200 1,400 800 Total income tax expense . $41,000 $35,300 $10,700 The tax effects of significant temporary differences representing deferred income tax assets and liabilities are as follows (in thousands): December 31, 1996 1995 Deferred income tax assets: Tax credit carryforwards . . . . . . $ 21,835 $ 33,001 Other. . . . . . . . . . . . . . . . 43,214 25,570 Total deferred income tax assets . $ 65,049 $ 58,571 Deferred income tax liabilities: Depreciation . . . . . . . . . . . . $(291,315) $(262,700) Other. . . . . . . . . . . . . . . . (31,264) (37,154) Total deferred income tax liabilities. . . . . . . . . . . $(322,579) $(299,854) At December 31, 1996, the Company had an alternative minimum tax ("AMT") credit carryforward of approximately $21.3 million which is available to reduce future federal income tax liabilities. The AMT credit carryforward has no expiration date. The Company has not recorded any valuation allowances against deferred income tax assets as of December 31, 1996. The Company's taxable years through 1992 are closed to adjustment by the Internal Revenue Service. The Company believes that adequate provisions for income taxes have been reflected in its consolidated financial statements. 13. 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, 1996 and 1995 (in thousands): December 31, 1996 1995 Actuarial present value of benefit obligations: Accumulated benefit obligation, including vested benefits of $76,448 (1996) and $65,420 (1995). . . . . .$78,441 $66,085 Projected benefit obligation for services rendered to date .$99,435 $87,609 Plan assets at fair value. . . . . . . . . . . . . . . . . . 92,486 68,619 Projected benefit obligation in excess of plan assets. . . . 6,949 18,990 Unrecognized net gain from past experience different from that assumed. . . . . . . . . . . . . . . . . . . . . 5,700 2,335 Prior service cost not yet recognized in net periodic pension cost . . . . . . . . . . . . . . . . . . . . . . . (5,305) (5,033) Unrecognized net asset at beginning of year. . . . . . . . . 1,341 1,483 Additional minimum liability accrual . . . . . . . . . . . . - 1,948 Accrued pension cost . . . . . . . . . . . . . . . . . . .$ 8,685 $19,723 Net periodic pension cost for the years ended December 31, 1996, 1995 and 1994 included the following components (in thousands): Year Ended December 31, 1996 1995 1994 Service cost - benefits earned during the period . . . . . . . . . . . . . $ 4,622 $ 3,465 $ 3,981 Interest cost on projected benefit obligation . . . . . . . . . . . . . 6,309 5,455 4,990 Actual (return) loss on plan assets. . (12,424) (14,376) 1,820 Net amortization and deferral. . . . . 6,651 9,637 (6,135) Net periodic pension cost. . . . . $ 5,158 $ 4,181 $ 4,656 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 the latest 10 years of credited service under the plan. The weighted-average discount rate used in determining the actuarial present value of the projected benefit obligation was 7.25% as of December 31, 1996 and 1995. The rate of increase in future compensation levels used in determining the projected benefit obligation as of December 31, 1996 and 1995 was 4% for nonexempt personnel and 3% for exempt personnel. The expected long-term rate of return on plan assets was 9.25% as of December 31, 1996 and 1995. 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 1996, 1995 and 1994 were approximately $14.2 million, $4.3 million and $5 million, respectively, and are currently estimated to be $4.3 million in 1997. 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. There were no Company contributions to the Thrift Plan in 1996 or 1995, while approximately $42,000 was contributed during 1994. In 1989, the Company established the Valero Employees' Stock Ownership Plan ("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 1996, 1995 and 1994, the Company contributed $3,372,000, $3,170,000 and $3,160,000, respectively, to the VESOP, comprised of $525,000, $678,000 and $819,000, respectively, of interest on the VESOP Notes and $3,072,000, $2,918,000 and $2,777,000, respectively, of compensation expense. Compensation expense is based on the VESOP debt principal payments for the portion of the VESOP established in 1989 and 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. Dividends paid on unallocated shares were used to reduce the Company's contributions to the VESOP during 1996, 1995 and 1994 by $225,000, $426,000 and $436,000, respectively. VESOP shares of Common Stock are considered outstanding for earnings per share computations. As of December 31, 1996 and 1995, the number of allocated shares were 1,052,454 and 940,470, respectively, the number of committed-to-be-released shares were 62,918 and 62,918, respectively, and the number of suspense shares were 583,301 and 772,055, 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 offered by the Company through a self-insured plan and a health maintenance organization 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, 1996 and 1995 (in thousands): December 31, 1996 1995 Accumulated benefit obligation: Retirees. . . . . . . . . . . . . . . . . $11,930 $10,295 Fully eligible active plan participants . 390 331 Other active plan participants. . . . . . 17,571 13,504 Total accumulated benefit obligation. . 29,891 24,130 Unrecognized loss . . . . . . . . . . . . . (4,498) (4,586) Unrecognized prior service cost . . . . . . (3,909) - Unrecognized transition obligation. . . . . (10,334) (10,987) Accrued postretirement benefit cost . . . $11,150 $ 8,557 Net periodic postretirement benefit cost for the years ended December 31, 1996, 1995 and 1994 included the following components (in thousands): December 31, 1996 1995 1994 Service cost - benefits attributed to service during the period. . . . . . . . . . . . . . . . . . . . . $1,091 $ 860 $1,196 Interest cost on accumulated benefit obligation . . . 1,716 1,769 1,686 Amortization of unrecognized transition obligation. . 653 766 948 Amortization of prior service cost. . . . . . . . . . - - (84) Amortization of unrecognized net loss . . . . . . . . 110 - 75 Net periodic postretirement benefit cost. . . . . $3,570 $3,395 $3,821 For measurement purposes, the assumed health care cost trend rate was 7% in 1996, 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, 1996 by $5.2 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $.7 million. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation as of December 31, 1996 and 1995 was 7.25%. Stock Option and Bonus Plans As of December 31, 1996, the Company has various fixed and performance-based stock compensation plans which are described below. The Company applies APB Opinion No. 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its fixed stock option plans. The compensation cost reflected in net income for its stock-based compensation plans was $2.6 million and $1.7 million for 1996 and 1995, respectively. Had compensation cost for the Company's stock-based compensation plans been determined based on the fair value at the grant dates for 1996 and 1995 awards under those plans consistent with the method of SFAS No. 123, the Company's net income and earnings per share for the years ended December 31, 1996 and 1995 would have been reduced to the pro forma amounts indicated below: December 31, 1996 1995 Net Income . . . . . As Reported $72,701 $59,838 Pro Forma $70,427 $58,373 Earnings per share . As Reported $ 1.40 $ 1.10 Pro Forma $ 1.35 $ 1.07 Because the SFAS No. 123 method of accounting has not been applied to awards granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of that to be expected in future years. The Company's Executive Stock Incentive Plan (the "ESIP") authorizes the grant of various stock and stock-related awards to executive officers and other key employees. Awards available under the ESIP include options to purchase shares of Common Stock, stock appreciation rights ("SARs"), restricted stock, performance awards and other stock-based awards. A total of 2,100,000 shares may be issued under the ESIP, of which no more than 750,000 shares may be issued as restricted stock. Under the ESIP, 110,500 options, 97,000 shares of restricted stock and 64,830 shares under performance awards were granted during 1996, while 1,043,581 awards were available for grant as of December 31, 1996. In addition to options available under the ESIP, the Company also 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," and a non-employee director stock option plan. Awards under the Stock Option Plans are granted to key officers, employees and prospective employees of the Company. As of December 31, 1996, there were 46,705 and 48,000 shares available for grant under the Stock Option Plans and non-employee director plan, respectively. Under the terms of the ESIP, the Stock Option Plans and the non-employee director plan, the exercise price of the options granted will not be less than 100%, 75%, or 100%, respectively, of the fair market value of Common Stock at the date of grant. As of December 31, 1996, all outstanding options contain exercise prices not less than fair market value at date of grant. Stock options become exercisable pursuant to the individual written agreements between the Company and the participants, generally either at the end of a three-year period beginning on the date of grant or in three equal annual installments beginning one year after the date of grant, with unexercised options expiring ten years from the date of grant. A summary of the status of the Company's stock option plans, including options granted under the ESIP, the Stock Option Plans and the non-employee director plan, as of December 31, 1996, 1995, and 1994, and changes during the years then ended is presented in the table below:
1996 1995 1994 Weighted- Weighted- Weighted- Average Average Average Exercise Exercise Exercise Shares Price Shares Price Shares Price Outstanding at beginning of year. . . . . . . . . . 3,928,267 $20.69 2,575,902 $21.51 1,261,624 $23.69 Granted . . . . . . . . . . 757,920 27.44 1,599,463 18.99 1,343,919 19.43 Exercised. . . . . . . . . . (418,117) 19.28 (171,604) 17.08 (7,555) 14.53 Forfeited. . . . . . . . . . (38,978) 22.17 (74,428) 21.12 (22,086) 21.90 Expired . . . . . . . . . . - - (1,066) 18.36 - - Outstanding at end of year. . . . . . . . . . 4,229,092 22.02 3,928,267 20.69 2,575,902 21.51 Exercisable at end of year. . . . . . . . . . 2,525,957 21.71 1,531,718 22.30 708,055 23.13 Weighted-average fair value of options granted. . . . . . . . . . $6.25 $4.50 N/A
The following table summarizes information about stock options outstanding under the ESIP, the Stock Option Plans and the non-employee director plan as of December 31, 1996:
Options Outstanding Options Exercisable Range Number Weighted-Avg. Number of Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg. Exercise Prices at 12/31/96 Contractual Life Exercise Price at 12/31/96 Exercise Price $14.52-$21.88 2,460,074 7.5 years $19.02 1,499,074 $19.17 $22.13-$29.75 1,769,018 7.4 26.20 1,026,883 25.41 $14.52-$29.75 4,229,092 7.5 22.02 2,525,957 21.71
The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used for grants in 1996 and 1995, respectively: risk-free interest rates of 6.4 percent and 6.7 percent; expected dividend yields of 1.9 percent and 2.8 percent; expected lives of 3.1 years and 3.2 years; and expected volatility of 25.5 percent and 29.5 percent. 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 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 Common Stock on the exercise date and the option price of the stock to which the SAR is related. SARs under Stock Option Plans No. 3 and 4 are exercisable only upon the exercise of the related stock options. At the end of each reporting period within the exercise period, the Company records an adjustment to deferred compensation expense based on the difference between the fair market value of Common Stock at the end of each reporting period and the option price of the stock to which the SAR is related. As of December 31, 1996, 89,087 SARs were outstanding and exercisable, at a weighted-average exercise price of $14.52 per share. During 1996, 21,316 SARs were exercised at a weighted- average exercise price of $14.52 per share and 600 SARs were forfeited. 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. As of December 31, 1996, there were 6,927 shares available for award. No shares were awarded under this plan in 1996, while 9,000 and 3,000 shares were awarded under this plan during 1995 and 1994, respectively. 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. 14. LEASE AND OTHER COMMITMENTS The Company has major long-term operating lease commitments in connection with a gas storage facility, its corporate headquarters office complex and various facilities and equipment used to store, transport and produce refinery feedstocks and/or refined products. The gas storage facility lease has a remaining primary term of three years, and, subject to certain conditions, one eight-year optional renewal period during which the lease payments decrease by one-half and one or more additional optional renewal periods of five years each at fair market rentals. The corporate headquarters lease has a remaining primary term of 15 years with five optional renewal periods of five years each. In 1996, the Company entered into a sublease agreement for unused space in its corporate headquarters office complex. The sublease has a primary term of 20 years, with the sublessee having an option to terminate the lease after 10 years. The sublessee is occupying the premises in phases, with full occupancy currently expected in 1997. The Company's long-term refinery feedstock and refined product storage and transportation leases have remaining primary terms of up to 5.3 years with optional renewal periods of up to 10 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 of up to 10 years for significant leases. The related future minimum lease payments as of December 31, 1996, including amounts to be received under the corporate headquarters office complex sublease, are as follows (in thousands):
Gas Storage Office Facility Complex Refining Other Primary Lease Sublease 1997 . . . . . . . . . . . $ 9,832 $ 4,570 $ (2,088) $ 6,028 $1,502 1998 . . . . . . . . . . . 10,156 4,570 (2,088) 7,886 1,490 1999 . . . . . . . . . . . 10,438 4,570 (2,088) 7,761 966 2000 . . . . . . . . . . . 5,221 4,570 (2,088) 4,977 292 2001 . . . . . . . . . . . - 4,570 (2,088) 4,075 134 Remainder. . . . . . . . . - 40,771 (9,971) 1,359 616 Total minimum lease payments. . . . . . . . $35,647 $63,621 $(20,411) $32,086 $5,000
The future minimum lease payments listed above exclude operating leases having initial or remaining noncancelable lease terms of one year or less. Consolidated rental expense under operating leases, excluding amounts paid in connection with the gas storage facility and net of amounts related to the office complex sublease, amounted to approximately $31,663,000, $29,313,000, and $14,040,000 for 1996, 1995 and 1994 (including Partnership rents commencing June 1, 1994), 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 of VNGP, L.P. with Energy, 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 such merger. Gas storage facility rentals paid by the Partnership for the period prior to the VNGP, L.P. merger, and paid by the Company for the period subsequent to the such merger, totalling $10,438,000 per year for 1996, 1995 and 1994, 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. 15. LITIGATION AND CONTINGENCIES City of Edinburg and Related Litigation. The Company and Southern Union Company ("Southern Union") are defendants in a lawsuit brought by the City of Edinburg, Texas (the "City") regarding certain ordinances of the City that granted franchises to Rio Grande Valley Gas Company ("RGV") and its predecessors allowing RGV to sell and distribute natural gas within the City. RGV was formerly owned by Energy. On September 30, 1993, Energy sold the common stock of RGV to Southern Union. The City alleges that the defendants used RGV's facilities to sell or transport natural gas in Edinburg in violation of the ordinances and franchises granted by the City, and that RGV (now Southern Union) has not fully paid all franchise fees due the City. The City also alleges that the defendants used the public property of the City without compensating the City for such use, and alleges conspiracy and alter ego claims involving all defendants. The City seeks alleged actual damages of $50 million and unspecified punitive damages related to amounts allegedly due under the RGV franchise, City ordinances and state law. In addition, the City of Pharr, Texas, filed an intervention seeking certification of a class, with itself as class representative, consisting of all cities served by franchise by Southern Union. The court certified the class and severed the claims of the City of Pharr and the class from the original City of Edinburg lawsuit. The City of Pharr subsequently amended its petition deleting all Valero entities as defendants. The original trial judge was disqualified upon motion of the defendants (such disqualification was upheld on appeal), and a new trial judge has been assigned to preside over both the City of Edinburg and City of Pharr litigation. The City of Edinburg lawsuit is scheduled for trial on August 11, 1997. In 1996, the South Texas cities of Alton and Donna also independently intervened as plaintiffs in the Edinburg lawsuit filed in the 92nd State District Court in Hidalgo County. These lawsuits subsequently were severed from the Edinburg lawsuit. The claims asserted by the cities of Alton and Donna are substantially similar to the Edinburg litigation claims. Damages are not quantified. In connection with the City of Edinburg lawsuit, Southern Union filed a cross-claim against Energy, alleging, among other things, that Southern Union is entitled to indemnification pursuant to the purchase agreement under which Energy sold RGV to Southern Union. Southern Union also asserts claims related to a 1985 settlement among Energy, RGV and the Railroad Commission of Texas regarding certain gas contract pricing terms. This pricing claim was recently severed into a separate lawsuit. Southern Union's claims include, among other things, damages for indemnification, breach of contract, negligent misrepresentation and fraud. Three additional lawsuits were filed during December 1996 by certain other municipalities in South Texas making allegations substantially similar to those in the City of Edinburg litigation. In these three lawsuits, the defendants are alleged to have excluded certain revenues from their calculations of franchise taxes and are alleged to have provided unauthorized gas transportation services to third parties. The plaintiffs seek actual and exemplary, but as yet, unspecified, damages. Teco Pipeline Company. Energy and certain of its subsidiaries have been sued by Teco Pipeline Company ("Teco") regarding the operation of the Company's 340-mile West Texas pipeline. In 1985, a subsidiary of Energy sold a 50% undivided interest in the pipeline and entered into a joint venture through an ownership agreement and an operating agreement, each dated February 28, 1985, with the purchaser of the interest. In 1988, Teco succeeded to that purchaser's 50% interest. A subsidiary of Energy has at all times been the operator of the pipeline. Notwithstanding the written ownership and operating agreements, the plaintiff alleges that a separate, unwritten partnership agreement exists, and that the defendants have exercised improper dominion over such alleged partnership's affairs. The plaintiff also alleges that the defendants acted in bad faith by negatively affecting the economics of the joint venture in order to provide financial advantages to facilities or entities owned by the defendants and by allegedly usurping for the defendants' own benefit certain opportunities available to the joint venture. The plaintiff asserts causes of action for breach of fiduciary duty, fraud, tortious interference with business relationships, and other claims, and seeks unquantified actual and punitive damages. The Company's motion to compel arbitration was denied, but has been appealed. The Company has filed a counterclaim alleging that the plaintiff breached its own obligations to the joint venture and jeopardized the economic and operational viability of the pipeline by its actions. The Company is seeking unquantified actual and punitive damages. Sinco Pipeline Rupture Litigation. Approximately 15 lawsuits have been filed against various pipeline owners and other parties, including the Company, 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 Company is a defendant in 10 of these lawsuits. The plaintiffs are property owners in surrounding areas who 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 plaintiffs assert claims for property damage, costs for medical monitoring, personal injury and nuisance, and seek an unspecified amount of actual and punitive damages. J.M. Davidson, Inc. 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 one of the Company'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 asserts claims for fraud, quantum meruit, and numerous other tort claims. The plaintiff seeks actual damages, on each of its causes of action, of approximately $1.25 million, plus retainage, interest and attorneys fees, and punitive damages of at least four times the amount of actual damages. No trial date has been set. The Long Trusts. On April 15, 1994, certain trusts named certain subsidiaries of the Company as additional defendants (the "Valero Defendants") to a lawsuit filed in 1989 by the trusts against a supplier with whom the Valero Defendants have contractual relationships under gas purchase contracts. In order to resolve certain potential disputes with respect to the gas purchase contracts, the Valero Defendants agreed to bear a substantial portion of any settlement or any nonappealable final judgment rendered against the supplier. In January 1993, the District Court ruled in favor of the trusts' motion for summary judgment against the supplier. Damages, if any, were not determined. The trusts seek $50 million in damages from the Valero Defendants as a result of the Valero Defendants' alleged interference between the trusts and the supplier, plus punitive damages in excess of treble the amount of actual damages proven at trial. The trusts also seek approximately $56 million in take-or-pay damages from the supplier and $70 million as damages for the supplier's failure to take the trusts' gas ratably. 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. No trial date has been set. Mizel. A federal securities fraud lawsuit was filed against Energy and certain of its subsidiaries by a former owner of limited partnership interests of VNGP, L.P. The plaintiff alleges that the proxy statement used in connection with the solicitation of votes for approval of the Merger of the Company and VNGP, L.P. contained fraudulent misrepresentations. The plaintiff also alleges breach of fiduciary duty in connection with the merger transaction. The subject matter of this lawsuit was the subject matter of a prior Delaware class action lawsuit which was settled prior to consummation of the Merger. The Company believes that the plaintiff's claims have been settled and released by the prior class action settlement. Pending in the district court is a memorandum issued by the magistrate assigned to the case which recommends approval of the Company's motion for summary judgment. Javelina. Valero Javelina Company, a wholly owned subsidiary of Energy, owns a 20% general partner interest in Javelina Company ("Javelina"), a general partnership that owns a refinery off-gas processing plant in Corpus Christi. Javelina has been named as a defendant in ten lawsuits filed since 1993 in state district courts in Nueces County and Duval County, Texas. Eight 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. The plaintiffs seek an unspecified amount of actual and punitive damages. The remaining two suits were brought by plaintiffs who either live or have businesses near the Javelina plant. The plaintiffs in these suits allege claims similar to those described above and seek unspecified actual and punitive damages. 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. 16. QUARTERLY RESULTS OF OPERATIONS (Unaudited) The results of operations by quarter for the years ended December 31, 1996 and 1995 were as follows (in thousands of dollars, except per share amounts):
Operating Operating Net Earnings Per Share Revenues Income Income Of Common Stock 1996-Quarter Ended: March 31. . . . . . . . . . . . . $1,110,098 $ 52,238 $19,914 $ .39 June 30 . . . . . . . . . . . . . 1,152,737 54,433 20,841 .41 September 30. . . . . . . . . . . 1,123,527 40,025 13,146 .23 December 31 . . . . . . . . . . . 1,604,319 54,213 18,800 .37 Total . . . . . . . . . . . . . $4,990,681 $200,909 $72,701 $1.40 1995-Quarter Ended: March 31. . . . . . . . . . . . . $ 690,535 $ 28,667 $ 3,759 $ .02 June 30 . . . . . . . . . . . . . 775,822 54,953 20,522 .40 September 30. . . . . . . . . . . 803,670 57,781 22,630 .45 December 31 . . . . . . . . . . . 927,845 47,390 12,927 .23 Total . . . . . . . . . . . . . $3,197,872 $188,791 $59,838 $1.10 Revised from the amount shown in the Company's Form 10-Q for the three months ended March 31, 1996 to include revenues from certain NGL trading activities previously classified as a reduction of cost of sales. Revised to include revenues from certain refining and marketing trading activities previously classified as a reduction of cost of sales.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS OF THE REGISTRANT The following table sets forth information concerning the current directors of Energy. The information contained herein is based partly on data furnished by the directors and partly on the Company's records. There is no family relationship among any of the executive officers or directors of Energy, and, except for the entities bearing the "Valero" name, none of the organizations or corporations described in the biographical information in this Item 10 is an affiliate of Energy.
_________________________________________________________________________________________________________ Age Executive as of Officer December Present Current Position(s) Held or Director 31, Term Director Name with Energy Since 1996 Expires Class _________________________________________________________________________________________________________ William E. Greehey Director, Chairman 1979 60 1998 III of the Board and Chief Executive Officer Edward C. Benninger Director, President 1979 54 1997 II Ronald K. Calgaard Director 1996 59 1999 I Robert G. Dettmer Director 1991 65 1998 III A. Ray Dudley Director 1988 72 1997 II Ruben M. Escobedo Director 1994 59 1998 III James L. Johnson Director 1991 69 1997 II Lowell H. Lebermann Director 1986 57 1998 III Susan Kaufman Purcell Director 1994 54 1999 I _________________________________________________________________________________________________________
Mr. Greehey has served as Chief Executive Officer and as a director of Energy since 1979 and as Chairman of the Board since 1983. He retired from his positions as President and Chief Executive Officer in June 1996. Upon request of the Board, Mr. Greehey resumed his position as Chief Executive Officer following the resignation of Mr. Becraft in November 1996. Mr. Greehey is also a director of Weatherford Enterra, Inc. and Santa Fe Energy Resources, Inc. Mr. Benninger has served as a director of Energy since 1990. He was elected President and Chief Financial Officer of Energy in 1996. He had served as Executive Vice President of Energy since 1989, and previously served as Chief Operating Officer of Valero Natural Gas Company from 1992 to 1995. He has served in various other capacities with the Company since 1975. Dr. Calgaard has been a director of Energy since 1996. He has served as President of Trinity University, San Antonio, Texas, since 1979. Dr. Calgaard previously served as a director of Valero Natural Gas Company from 1987 until 1994. Mr. Dettmer was elected as a director of Energy in 1991. He retired from PepsiCo, Inc. in 1996 after serving as Executive Vice President and Chief Financial Officer since 1986. Mr. Dudley has served as a director of Energy since 1988 and currently serves as an independent consultant in the petroleum industry. Mr. Dudley served in various capacities with Tenneco Oil Company from 1959 until his retirement in 1987. Mr. Escobedo was elected as a director of Energy in 1994. He has been with his own public accounting firm, Ruben Escobedo & Company, CPAs, in San Antonio, Texas since its formation in 1977. Mr. Escobedo also serves as a director of Frost National Bank of San Antonio, N.A. ("Frost Bank") and previously served as a director of Valero Natural Gas Company from 1989 to 1994. In its capacity as Trustee for certain employee benefit plans of Energy, Frost Bank shares voting and dispositive power with respect to a number of shares of Energy common stock. See "Item 12. Security Ownership of Certain Beneficial Owners and Management." Mr. Johnson has been a director of Energy since 1991. He previously served as Chairman and Chief Executive Officer of GTE Corporation from 1988 to 1992, and since 1992 has served as Chairman Emeritus. Mr. Johnson also serves as a director of CellStar Corporation, FINOVA Group, Inc., Harte-Hanks Communications, Inc., The Mutual Life Insurance Company of New York and Walter Industries, Inc. Mr. Lebermann was elected as a director of Energy in 1986, and previously served on Energy's Board from 1979 to 1983. Mr. Lebermann has been President of Centex Beverage, Inc., a beverage distributor, in Austin, Texas, since 1981. Mr. Lebermann is also a director of Station Casinos, Inc. and of Franklin Federal Bankcorp, a Federal Savings Bank, Austin, Texas. Dr. Purcell was elected as a director of Energy in 1994. She has served as Vice President of the Americas Society in New York, New York since 1989 and is also Vice President of the Council of the Americas. She is a consultant for several international and national firms and serves on the boards of several mutual funds, including The Argentina Fund, The Latin America Dollar Income Fund and Scudder World Income Opportunities Fund. EXECUTIVE OFFICERS OF THE REGISTRANT The following table sets forth certain information as of December 31, 1996 regarding the current 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. 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.
______________________________________________________________________________________________________ Energy Year First Elected Age as of Position and or Appointed as December 31, Name Office Held Officer or Director 1996 _______________________________________________________________________________________________________ William E. Greehey Director, Chairman of the Board 1979 60 and Chief Executive Officer Edward C. Benninger Director, President and 1979 54 Chief Financial Officer Stan L. McLelland Executive Vice President 1981 51 and General Counsel *E. Baines Manning Executive Vice President of 1992 56 Valero Refining and Marketing Company *Terrence E. Ciliske Executive Vice President of 1996 42 Valero Natural Gas Company Peter A. Fasullo Senior Vice President - 1996 43 Corporate Development Gregory C. King Vice President 1997 36 ______________________________________________________________________________________________________
[FN] * Mr. Manning and Mr. Ciliske have been designated by the Energy Board of Directors as "executive officers" of the Registrant in accordance with Rule 3b-7 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and will be eligible for inclusion in the Summary Compensation Table in the Proxy Statement. Biographical information for Mr. Greehey and Mr. Benninger is contained above under the caption "Directors of the Registrant." 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. McLelland also serves as a director of IGC Communications, Inc., which is not affiliated with the Company. Mr. Manning has served as Executive Vice President of Valero Refining and Marketing Company since 1995 and in various other capacities within the Company's refining division since 1986. Mr. Ciliske was elected Executive Vice President of Valero Natural Gas Company in 1996, prior to which he served in various other capacities within the Company's natural gas related services divisions since 1983. Mr. Fasullo was elected Senior Vice President - Corporate Development in 1996, prior to which he served in various other capacities within the Company since 1983. Mr. King was elected Vice President in 1997, and has served as Associate General Counsel since joining the Company in 1993. Prior to joining the Company, Mr. King was a partner at the law firm of Bracewell & Patterson, L.L.P., Houston, Texas, where he had been employed since 1985. SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE Section 16(a) of the Securities Exchange Act of 1934, as amended ("Exchange Act"), requires Energy's executive officers, directors, and greater than 10 percent to stockholders to file certain reports of ownership and changes in ownership. Based on a review of the copies of such forms received and written representations from certain reporting persons, Energy believes that, during the year ended December 31, 1996, its executive officers, directors and greater than 10 percent stockholders were in compliance with applicable requirements of Section 16(a). ITEM 11. EXECUTIVE COMPENSATION SUMMARY COMPENSATION The following table provides a summary of compensation paid to the persons serving as Energy's CEO, and to its four other most highly compensated executive officers, for services rendered in all capacities to the Company for the last three years. Benefits under health care, disability, term life insurance, vacation and other plans available to employees generally are not included herein.
Summary Compensation Table (1994-1996) ______________________________________________________________________________________________________________________________ Long-Term Compensation Restricted Securities Annual Compensation Stock Underlying All Other Name and Bonus Awards Options/ LTIP Compensation Position(s) Year Salary($) ($)(1) ($)(2) SARS(#) Payouts(3) ($)(4) ______________________________________________________________________________________________________________________________ C> William E. Greehey(5) 1996 $497,337 $670,739 $1,545,362 5,000 $325,000 $928,949 Director, Chairman 1995 684,540 560,000 431,250 0 0 73,007 of the Board and 1994 622,020 0 0 355,300 0 71,664 Chief Executive Officer of Energy F. Joseph Becraft(5) Director, President 1996 $450,030 $ 0 $276,250 40,000 $271,138 $4,252 and Chief Executive 1995 266,680 180,000 421,875 120,000 0 4,252 Officer of Energy Edward C. Benninger(5) 1996 $357,180 $335,370 $497,500 25,000 $ 93,698 $28,541 Director and President 1995 342,600 210,000 189,750 0 0 27,016 of Energy 1994 335,040 0 0 125,500 0 27,598 Stan L. McLelland Executive Vice 1996 $300,930 $111,812 $ 0 25,000 $ 70,200 $25,631 President and General 1995 278,700 162,000 138,000 0 0 23,313 Counsel of Energy 1994 262,380 0 0 82,600 0 23,836 E. Baines Manning(6) Executive Vice 1996 $253,230 $122,989 $ 0 18,000 $ 58,500 $18,758 President of Valero 1995 231,420 120,000 51,750 0 0 12,468 Refining and 1994 216,420 0 0 63,500 0 15,524 Marketing Company Terrence E. Ciliske(6) Executive Vice 1996 $180,156 $167,701 $ 51,000 3,400 $ 36,823 $10,670 President of Valero Natural Gas Company ______________________________________________________________________________________________________________________________
[FN] (1) In 1994, executives received no bonuses. For 1995, executives received bonuses payable 70% in cash and 30% in Common Stock. For 1996, executives received bonuses payable 25% in cash and 75% in Common Stock. (2) For each named executive officer, the number of shares of Restricted Stock held at December 31, 1996, and the value thereof, based on the closing market price of the Common Stock at December 31, 1996, was as follows: Mr. Greehey: 62,073 shares -- $1,776,840; Mr. Benninger: 27,333 shares -- $782,407; Mr. McLelland: 5,333 shares -- $152,667; Mr. Manning: 2,000 shares -- $57,250; and Mr. Ciliske: 3,400 shares -- $97,325. Dividends are paid on the Restricted Stock at the same rate as on Energy's unrestricted Common Stock. The grants of Restricted Stock to Messrs. Greehey and Benninger will vest upon completion of the Restructuring transaction or, if such transaction is not consummated, would vest in annual increments of 33 1/3% beginning on the first anniversary of the grant date. The grant of Restricted Stock to Mr. Becraft vested upon his resignation; Mr. Becraft did not hold Restricted Stock at December 31, 1996. (3) LTIP payouts are the number of performance share awards vested for 1996 multiplied by the market price per share on the vesting date. For more information see the notes following the table entitled "Long Term Incentive Plans-Awards in Last Fiscal Year." (4) Amounts include Company contributions pursuant to the Employee Stock Plans, and that portion of interest accrued under the Executive Deferred Compensation Plan which is deemed to be at "above-market" rates under applicable SEC rules. Messrs. Greehey, Becraft, Benninger, McLelland, Manning, and Ciliske were allocated $31,460, $10,975, $25,574, $21,074, $18,758, and $10,670, respectively, as a result of Company contributions to employee stock plans for 1996, and $9,066, $0, $2,967, $4,557, $0, and $0, respectively, as a result of "above-market" allocations to the Executive Deferred Compensation Plan for 1996. Messrs. Becraft, Manning and Ciliske do not participate in the Executive Deferred Compensation Plan. Amounts for Mr. Greehey also include executive insurance policy premiums with respect to cash value life insurance (not split-dollar life insurance) in the amount of $13,000 for 1994 and 1995 and $7,583 for 1996; such amounts for 1996 also include (i) consulting fees ($141,667), Board fees ($29,833), SERP payments ($278,862) and the interest component of deferred compensation plan payments ($27,648) made during the period following his retirement and prior to his reemployment, and (ii) payments made following his retirement for Excess Thrift Plan balances ($339,617) and unused vacation ($63,213). Payments received during Mr. Greehey's retirement directly from the Pension Plan are excluded. (5) Mr. Becraft was employed by the Company beginning May 1, 1995, and was elected President of Energy on January 1, 1996 and Chief Executive Officer of Energy on June 30, 1996. Mr. Greehey resigned from his position as Chief Executive Officer of Energy on June 30, 1996. Mr. Becraft resigned from his positions as President and Chief Executive Officer of Energy on November 20, 1996, whereupon Mr. Greehey was reappointed Chief Executive Officer of Energy. At that time, the Board also promoted Mr. Benninger from Executive Vice President to President of Energy. (6) The Board of Directors of Energy has determined to include Mr. Ciliske and Mr. Manning in the Summary Compensation Table in accordance with Rule 3b-7 under the Exchange Act. Mr. Ciliske was not an executive officer of Energy for any part of 1994 or 1995. STOCK OPTION GRANTS AND RELATED INFORMATION The following table provides further information regarding the grants of stock options to the named executive officers reflected in the Summary Compensation Table.
Option/SAR Grants in the Last Fiscal Year ______________________________________________________________________________________________________________________ Number of Percent of Securities Total Underlying Options/ Options/ SARs Granted Market SARs to Employees Exercise or Price at Grant Date Granted in Fiscal Base Price Grant Date Expiration Present Value $ Name (#)(1) Year (/$/Sh) ($/Sh) Date (2) ______________________________________________________________________________________________________________________ William E. Greehey 5,000 .69% $25.3125 $25.3125 07/01/2006 $ 29,580 F. Joseph Becraft 40,000 5.56% $27.5625 $27.5625 05/30/2006 259,440 Edward C. Benninger 25,000 3.47% $27.5625 $27.5625 05/30/2006 162,150 Stan L. McLelland 25,000 3.47% $27.5625 $27.5625 05/30/2006 162,150 E. Baines Manning 18,000 2.50% $27.5625 $27.5625 05/30/2006 116,748 Terrence E. Ciliske 7,500 1.04% $27.5625 $27.5625 05/30/2006 48,645 2,500 .35% $25.3125 $25.3125 07/01/2006 14,790 ______________________________________________________________________________________________________________________
[FN] (1) Options granted in 1996 vest (become exercisable and nonforfeitable) in equal increments over a three year period from the date of grant. In the event of a change of control of Energy (including stockholder approval of the Restructuring, such options would also become immediately exercisable pursuant to provisions of the plan or of an executive severance agreement. Under the terms of the plan, the exercise price and tax withholding obligations related to exercise may be paid by delivery of already owned shares or by offset of the underlying shares, subject to certain conditions. (2) A variation of the Black-Scholes option pricing model was used to determine grant date present value. This model is designed to value publicly traded options. Options issued under the Company's option plans are not freely traded, and the exercise of such options is subject to substantial restrictions. Moreover, the Black-Scholes model does not give effect to either risk of forfeiture or lack of transferability. The estimated values under the Black-Scholes model are based on assumptions as to variables such as interest rates, stock price volatility and future dividend yield. The estimated grant date present values presented in this table were calculated using an expected average option term of 3.32 years, a risk-free rate of return of 6.41%, an average volatility rate of 25.4% for the options expiring 5/30/2006 and 25.17% for the options expiring 7/01/2006, and a dividend yield of 1.88% for the options expiring 5/30/2006 and 2.04% for the options expiring 7/01/2006. The actual value of stock options could be zero; realization of any positive value depends upon the actual future performance of the Common Stock, the continued employment of the option holder throughout the vesting period and the timing of the exercise of the option. Accordingly, the values set forth in this table may not be achieved. The following table provides information regarding securities underlying options exercisable at December 31, 1996, and options exercised during 1996, for the executive officers named in the Summary Compensation Table:
Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values ______________________________________________________________________________________________________________________ Value of Unexercised Shares Number of Securities In-the-Money Acquired Value Underlying Unexercised Options/SARs at on Exercise Realized Options/SARs at FY-End(#) FY-End ($) (1) Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable ______________________________________________________________________________________________________________________ William E. Greehey - - 510,184 5,000 $4,522,154 $ 15,625 F. Joseph Becraft - - 160,000 - 1,167,500 - Edward C. Benninger - - 62,472 133,833 364,587 1,031,800 Stan L. McLelland - - 47,857 96,266 328,157 682,762 E. Baines Manning - - 38,217 72,833 270,792 524,300 Terrence E. Ciliske - - 24,019 25,400 158,628 155,588 ______________________________________________________________________________________________________________________
[FN] (1) Represents the dollar value obtained by multiplying the number of unexercised options/SARs by the difference between the stated exercise price per share of the options/SARs and the average market price per share of Energy's Common Stock on December 31, 1996. Long-Term Incentive Awards The following table provides information regarding long-term incentive awards made to the named executive officers reflected in the Summary Compensation Table.
Long-Term Incentive Plans - Awards in Last Fiscal year (1) ______________________________________________________________________________________________________________________________ Estimated Future Payouts Under Non-Stock Price-Based Plans Performance Number of or Other Period Shares, Units Until Maturation Threshold Target Maximum Name or Other Rights or Payout (# Shares) (# Shares) (# Shares) ______________________________________________________________________________________________________________________________ William E. Greehey 10,000 12/31/96 0 10,000 20,000 10,000 12/31/97 0 10,000 20,000 10,000 12/31/98 0 10,000 20,000 F. Joseph Becraft 3,634 12/31/96 0 3,634 7,268 3,633 12/31/97 0 3,633 7,266 3,633 12/31/98 0 3,633 7,266 Edward C. Benninger 2,884 12/31/96 0 2,884 5,768 2,883 12/31/97 0 2,883 5,766 2,883 12/31/98 0 2,883 5,766 Stan L. McLelland 2,160 12/31/96 0 2,160 4,320 2,160 12/31/97 0 2,160 4,320 2,160 12/31/98 0 2,160 4,320 E. Baines Manning 1,800 12/31/96 0 1,800 3,600 1,800 12/31/97 0 1,800 3,600 1,800 12/31/98 0 1,800 3,600 Terrence E. Ciliske 1,134 12/31/96 0 1,134 2,268 1,134 12/31/97 0 1,134 2,268 1,134 12/31/98 0 1,134 2,268 ______________________________________________________________________________________________________________________________
[FN] (1) Long-term incentive awards are grants of performance shares ("Performance Shares") made under the Executive Stock Incentive Plan. (2) Total shareholder return ("TSR") during a specified "performance period" was established as the performance measure for determining what portion of the 1996 Performance Share awards will vest. For purposes of the Performance Share awards, TSR is measured by dividing the sum of (a) the net change in the price of a share of Energy's Common Stock between the beginning of the performance period and the end of the performance period, and (b) the total dividends paid on the Common Stock during the performance period, by (c) the price of a share of Energy's Common Stock at the beginning of the performance period. Each 1996 Performance Share award is subject to vesting in three increments, based upon the Company's TSR during overlapping three-year periods, with the first such three-year period for the 1996 grants beginning January 1, 1994 and ending December 31, 1996. At the end of the three-year performance period, the Company's TSR is compared to the TSR for each company in a target group of approximately 16 companies. Energy and the companies in the target group are then ranked by quartile. At the end of each performance period, participants earn 0%, 50%, 100% or 150% of the initial grant amount for such period depending upon whether the Company's TSR is in the last, 3rd, 2nd or 1st quartile of the target group; 200% will be earned if the Company ranks highest in the group. Amounts not earned in a given three-year period can be carried forward for one additional three-year period and up to 100% of the carried amount can still be earned, depending upon the quartile achieved for such subsequent period. RETIREMENT BENEFITS The following table shows the estimated annual gross benefits payable under Energy's Pension Plan ("Pension Plan"), Supplemental Pension Plan and Supplemental Executive Retirement Plan ("SERP") upon retirement at age 65, based upon the assumed compensation levels and years of service indicated and assuming an election to have payments continue for the benefit of the life of the participant only.
Estimated Annual Pension Benefits at Age 65 _________________________________________________________________________________ Years of Service Covered _____________________________________________________________ Compensation 15 20 25 30 35 _________________________________________________________________________________ $ 200,000 $ 55,000 $ 73,000 $ 92,000 $110,000 $128,000 300,000 84,000 112,000 141,000 169,000 197,000 400,000 114,000 151,000 189,000 227,000 265,000 500,000 143,000 190,000 238,000 286,000 333,000 600,000 172,000 229,000 287,000 344,000 401,000 700,000 201,000 268,000 336,000 403,000 470,000 800,000 231,000 307,000 384,000 461,000 538,000 900,000 260,000 346,000 433,000 520,000 606,000 1,000,000 289,000 385,000 482,000 578,000 674,000 1,100,000 318,000 424,000 531,000 637,000 743,000 1,200,000 348,000 463,000 579,000 695,000 811,000 1,300,000 377,000 502,000 628,000 754,000 879,000 _________________________________________________________________________________
Energy maintains a noncontributory defined benefit Pension Plan in which virtually all employees are eligible to participate and under which contributions for individual participants are not determinable. Energy also maintains a noncontributory, nonqualified Supplemental Pension Plan which provides supplemental pension benefits to certain highly compensated employees to the extent that the pension benefits otherwise payable to such employees from the Pension Plan would exceed benefits permitted under applicable regulations to be paid from a tax-qualified defined benefits plan. Accrued contributions for the 1996 Pension Plan year were approximately 5.5% of total covered compensation. No contributions were made to the Supplemental Pension Plan. The Pension Plan (supplemented, as necessary, by the Supplemental Pension Plan) provides a monthly pension at normal retirement equal to 1.6% of the participant's average monthly compensation (based upon the participant's base earnings during the 60 consecutive months of the participant's credited service affording the highest such average) times the participant's years of credited service, plus .35% times the product of the participant's years of credited service (maximum 35 years) multiplied by the excess of the participant's average monthly compensation over the lesser of 1.25 times the monthly average (without indexing) of the social security wage bases for the 35-year period ending with the year the participant attains social security retirement age, or the monthly average of the social security wage base in effect for the year that the participant retires. Energy also maintains the SERP, a non-qualified plan providing additional pension benefits to certain executive officers and employees of the Company. Energy's obligations under the SERP are substantially fully funded through investments held in a trust established for the SERP under which Frost National Bank of San Antonio, N.A., serves as trustee. During 1996 contributions aggregating $9.2 million were made to the SERP Trust. Compensation for purposes of the Pension Plan and Supplemental Pension Plan includes only salary as reported in the Summary Compensation Table and excludes cash bonuses. For purposes of the SERP, the participant's most highly compensated consecutive 36 months of service during the participant's last 10 years of employment (rather than 60 months) are considered, and bonuses are included. Accordingly, the amounts reported in the Summary Compensation Table under the headings "Salary" and "Bonus" constitute covered compensation for purposes of the SERP. Pension benefits are not subject to any deduction for social security or other offset amounts. Credited years of service for the period ended December 31, 1996 for the executive officers named in the Summary Compensation Table are as follows: Mr. Greehey -- 33 years; Mr. Becraft -- 6 years; Mr. Benninger -- 22 years; Mr. McLelland -- 18 years; Mr. Manning -- 10 years, and Mr. Ciliske -- 13 years. The credited service for Mr. Becraft and Mr. McLelland includes five years and two years service, respectively, credited pursuant to the terms of their employment by the Company and for which benefits are payable only from the SERP. See also "Arrangements with Certain Officers and Directors." COMPENSATION OF DIRECTORS Non-employee directors receive a retainer fee of $18,000 per year, plus $1,000 for each Board and committee meeting attended ($500 for telephonic meetings). Each director is also reimbursed for expenses of meeting attendance. Directors who are employees of the Company receive no compensation (other than reimbursement of expenses) for serving as directors. Energy maintains the 1990 Restricted Stock Plan for Non-Employee Directors ("Director Stock Plan") and the Non-Employee Director Stock Option Plan ("Director Option Plan") to supplement the compensation paid to non-employee directors and increase their identification with the interests of Energy's stockholders through ownership of Common Stock ("Director Stock"). Under the Director Stock Plan, non-employee directors receive grants of Director Stock that vest (become nonforfeitable) in three equal annual installments. Upon election to the Board, each non-employee director receives a grant, the value of which is determined annually based on changes in the consumer price index and which is expected to be approximately $54,000 for 1997. Annual installments usually vest on or about the date of the annual meeting of stockholders. When all of the Director Stock previously granted to a director is fully vested and the director is reelected for an additional term, or his term of office otherwise continues after his Director Stock is fully vested, another similar grant is made. However, if a director is not eligible for reelection due to Energy's mandatory retirement policy or if a director does not intend to stand for reelection, the grant is reduced pro rata based on the number of years remaining to the end of that director's term. The Director Option Plan provides non-employee directors of Energy automatic annual grants of stock options for Energy's Common Stock. To the extent necessary, the plan is administered by the Compensation Committee of the Board of Directors. The plan provides that each new non-employee director elected to the Energy Board automatically receives an initial grant of 5,000 options. On the date of each subsequent annual meeting of stockholders of Energy, each non-employee director (other than new non-employee directors receiving their initial grant of 5,000 options) automatically receives a grant of 1,000 additional options. Stock options awarded under the Director Option Plan have an exercise price equal to the market price of the Common Stock on the date of grant. The initial grant of options to each non-employee director vests in three equal annual installments on each anniversary date of the grant. The subsequent annual grants of 1,000 options vest fully six months following the date of grant. All options expire ten years following the date of grant. Options vest and remain exercisable in accordance with their original terms in the case of a director retiring from the Board. In the event of a "Change of Control" as defined in the Director Option Plan, all options previously granted under the plan immediately become vested or exercisable upon the date of the Change of Control, except as otherwise provided in the plan. The Director Option Plan also provides for adjustment in the number of options to prevent dilution or enlargement of the benefits or potential benefits intended under the plan in the event the Compensation Committee determines that any dividend or other distribution, recapitalization, stock split, reverse stock split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase, or exchange of shares of Energy or other similar corporate transaction or event affects the common stock of Energy. Under the Retirement Plan for Non-Employee Directors ("Retirement Plan"), non-employee directors become entitled to a retirement benefit upon completion of five years of service. The annual benefit at retirement is equal to 10% of the highest annual cash retainer paid to the director during his or her service on the Board, multiplied by the number of full and partial years of service (not to exceed 10 years). Such benefit is then paid for a period equal to the shorter of the director's number of years of service or the director's lifetime, but in no event for longer than 10 years. The Retirement Plan provides no survivor benefits and is an unfunded plan paid from the general assets of the Company. ARRANGEMENTS WITH CERTAIN OFFICERS AND DIRECTORS Energy entered into an employment agreement with Mr. Greehey dated May 16, 1990 which expired June 9, 1995. The agreement provided that Mr. Greehey would be entitled to receive certain post-retirement benefits, including office facilities and secretarial support until age 69, transfer of certain club memberships, the vesting of previously granted stock option and restricted stock grants, certain medical and life insurance benefits and the right to certain supplemental amounts under the SERP. In November 1994, Energy's Board of Directors approved resolutions continuing such post-retirement benefits, notwithstanding the termination of such agreement. Effective upon his retirement from his positions as President and Chief Executive Officer in June 1996, the specified post-retirement benefits were provided to Mr. Greehey and he was requested to continue to serve as Chairman of the Board. Energy and Mr. Greehey also entered into a consulting agreement pursuant to which Mr. Greehey received compensation at the rate of $340,000 per annum for providing general advice and consulting services, as well as management services for particular projects. Mr. Greehey was reemployed by Energy on November 21, 1996, and the consulting agreement terminated at that time. In order to clarify Mr. Greehey's continuing benefit arrangements, the Board determined that, following Mr. Greehey's ultimate retirement from active employment, he will continue to be eligible to receive substantially the same office and secretarial support, medical and life insurance benefits and supplemental SERP benefits as were provided following his earlier retirement. Effective May 1, 1995, Energy entered into an employment agreement with Mr. Becraft expiring April 30, 2000. Under the agreement, Mr. Becraft was entitled to receive a minimum base salary of $400,000 per annum, and to participate in the Company's executive incentive bonus plan, restricted stock plans, option plans and SERP; for purposes of determining benefits payable under the SERP, Mr. Becraft's prior service from 1984-1989 was credited. Mr. Becraft was elected Chief Executive Officer of Energy effective July 1, 1996, and his base salary was increased to $500,000 at that time. Energy subsequently entered into a separation agreement with Mr. Becraft effective November 20, 1996. The separation agreement provided that, through April 30, 2000, Mr. Becraft will continue to receive his then-effective base salary. Additionally, the agreement provided for the immediate vesting of previously granted stock options, restricted stock and performance shares; office and secretarial support for a six-month period; transfer of a club membership; certain health benefits until the original expiration date of the employment agreement; assignment of a life insurance policy; and certain tax planning services. Energy has entered into agreements (the "Severance Agreements") with Messrs. Greehey, Benninger, McLelland and Manning which provide certain payments and other benefits in the event of their termination of employment under certain circumstances. The Severance Agreements provide that if the executive leaves the Company for any reason (other than death, disability or normal retirement) within two years after a "change of control," the executive will receive a lump sum cash payment equal to three times, in the cases of Messrs. Greehey and McLelland, and two times, in the cases of Messrs. Benninger and Manning, his highest compensation during any consecutive 12-month period in the prior three years. The executive will also be entitled to accelerated exercise of stock options and SARs and accelerated vesting of restricted stock previously granted. The agreements also provide for special retirement benefits if the executive would have qualified for benefits under the Pension Plan had he remained with the Company for the three-year period following such termination, for continuance of life and health insurance coverages and other fringe benefits for such three-year period and for relocation assistance. Messrs. Greehey, Benninger, McLelland and Manning have each executed waivers providing that the consummation of the transactions contemplated by the Merger Agreement will not constitute a "change of control" for purposes of such Severance Agreements. In connection with pursuing various strategic alternatives, including the Restructuring, Energy entered into Management Stability Agreements ("Stability Agreements") and Incentive Bonus Agreements ("Incentive Agreements") with various key executives, including Mr. Terrence E. Ciliske, Executive Vice President of Valero Natural Gas Company and Mr. Peter A. Fasullo, Senior Vice President-Corporate Development. These agreements are intended to assure the continued availability of Messrs. Ciliske and Fasullo in the event of certain transactions culminating in a "change of control" of Energy and/or a divestiture of one of the Company's principal businesses. Under the Stability Agreements, in the event either of such executive's employment is terminated within two years after a change of control or divestiture transaction has occurred, and termination is not voluntary or the result of death, permanent disability, retirement or certain other defined circumstances, the executive would be entitled to receive a lump sum cash payment equal to the sum of (i) two times the highest annual compensation paid to such executive during the prior three year period, plus an amount equal to the executive's average annual incentive bonus over the prior three years; the continuation of life, disability and health insurance coverages for two years; and certain relocation assistance. The executives would also be entitled to accelerated vesting of all previously granted stock options, SARs and restricted stock. Under the Incentive Agreements, if the executive continues to be employed by the Company and a merger or another qualifying transaction is accomplished, the executive will be entitled to receive a cash incentive bonus payment equal to one times the executive's highest annual base salary during the prior three year period. In the case of Mr. Ciliske, all of such payment is payable at the closing of the transaction, and in the case of Mr. Fasullo, 60% of such payment is payable at closing and 40% is payable six months following closing or, under certain circumstances, upon his earlier termination of employment. In connection with Mr. Greehey's then-pending retirement, in May 1996 the Compensation Committee approved special retirement arrangements that would be applicable to Messrs. Benninger and McLelland if they deferred their retirement from the Company to after June 30, 1996. Under these arrangements, upon their ultimate retirement, Messrs. Benninger and McLelland would each receive eight supplemental retirement "points," to be divided between age and credited service in such proportions as each shall elect at the time of retirement. In addition, for the year in which he retires each executive will be entitled to a prorated executive incentive bonus and tax preparation services. Each executive would also be entitled to accelerated vesting of all previously granted stock options and Restricted Stock, and Mr. Benninger's existing club membership would be transferred to him without cost. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth information as of December 31, 1996, with respect to each entity known to Energy to be the beneficial owner of more than five percent of its Common Stock, based solely upon a statement on Schedule 13G filed by such entity with the Securities and Exchange Commission ("SEC"):
______________________________________________________________________________________________ Shares Name and Address Beneficially Percent Title of Class of Beneficial Owner Owned of Class ______________________________________________________________________________________________ Common Stock Franklin Resources, Inc.(1) 6,366,167 14.4% 777 Mariners Island Blvd. San Mateo, CA 94404 Common Stock Merrill Lynch & Co., Inc.(2) 4,160,610 9.4% World Financial Center, North Tower 250 Vessey Street New York, NY 10281 Common Stock Frost National Bank of 4,027,492 9.1% San Antonio, N.A.(3) 100 West Houston Street San Antonio, TX 78205 Common Stock The Capital Group Companies, Inc.(4) 3,292,700 7.4% 75 State Street Boston, MA 02109 Common Stock Wellington Management Company(5) 2,841,946 6.4% 75 State Street Boston, MA 02109 ______________________________________________________________________________________________
[FN] (1) Franklin Resources, Inc. has reported that it and certain of its shareholders and subsidiaries have sole voting power with respect to 5,960,170 shares, shared voting power with respect to 459,997 shares and shared dispositive power with respect to 6,366,167 shares. (2) Merrill Lynch & Co., Inc. has reported that it has shared voting power with respect to 4,160,610 shares while certain of its subsidiaries have shared voting power and shared dispositive power with respect to up to 4,160,610 shares. (3) Frost National Bank of San Antonio, N.A. has reported that it has shared voting and dispositive power with respect to 4,027,492 shares in its capacity as Trustee for the Valero Energy Corporation Thrift Plan, Valero Energy Corporation Employees' Stock Ownership Plan, Valero Employees' Stock Ownership Plan, Valero Energy Corporation Benefits Trust and Valero Energy Corporation Supplemental Executive Retirement Plan. (4) The Capital Group Companies, Inc. has reported in a Schedule 13G that it and certain investment management subsidiaries have sole voting power with respect to 600 shares and sole dispositive power with respect to 3,292,700 shares. One such subsidiary, Capital Research and Management Company, has also reported that it has sole dispositive power with respect to 2,823,180 of such shares. (5) Wellington Management Company, LLP ("Wellington") has filed a Schedule 13G reporting shared dispositive power with respect to 2,841,946 shares and shared voting power with respect to 126,099 shares. In addition, all 11,500 outstanding shares of Series A Preferred Stock are held by American General Corporation, P.O. Box 3855, Houston, Texas 77253; no filing of Schedule 13G or 13D is required with respect thereto. Except as otherwise indicated, the following table sets forth information as of February 1, 1997, regarding Common Stock and $3.125 Convertible Preferred Stock beneficially owned (or deemed to be owned) by each current director, each executive officer named in the Summary Compensation Table, and all current directors and executive officers of Energy as a group. Such information has been furnished to Energy by such persons and cannot be independently verified by Energy. The $3.125 Convertible Preferred Stock has no ordinary voting rights.
_______________________________________________________________________________________________ Common Stock Shares $3.125 Percent Name of Beneficially Shares Under Convertible of Class Beneficial Owner (1) Owned Exercisable Preferred (Common (2)(3)(4) Options(5) Stock(2) Stock)(2) ________________________________________________________________________________________________ F. Joseph Becraft(6) 46,012 160,000 0 * Edward C. Benninger 127,864 70,805 1,000 * Ronald K. Calgaard 2,142 1,667 0 * Robert G. Dettmer(7) 5,877 3,000 0 * A. Ray Dudley 8,141 3,000 0 * Ruben M. Escobedo(8) 3,094 3,000 0 * William E. Greehey 383,161 510,184 4,385 2.02% James L. Johnson 3,852 3,000 0 * Lowell H. Lebermann 2,244 3,000 0 * E. Baines Manning 47,959 42,550 1,000 * Stan L. McLelland 109,120 53,532 0 * Susan Kaufman Purcell 2,289 3,000 0 * All executive officers and 803,276 908,092 6,385 3.87% directors as a group, including the persons named above (15 persons)(9) ______________________________________________________________________________________________
[FN] * Indicates that the percentage of beneficial ownership does not exceed 1% of the class. (1) The business address for all beneficial owners listed above is 530 McCullough Avenue, San Antonio, Texas 78215. (2) No executive officer or director of Energy owns any class of equity securities of Energy other than Common Stock and $3.125 Convertible Preferred Stock. Neither any such person, nor all such persons as a group, owns 1% or more of the $3.125 Convertible Preferred Stock. The calculation for Percent of Class includes shares listed under the captions "Shares Beneficially Owned" and "Shares Under Exercisable Options." (3) Includes shares allocated pursuant to various employee stock plans available to its employees generally (collectively, the "Employee Stock Plans"), as well as shares granted under Energy's Restricted Stock Bonus and Incentive Stock Plan (the "Restricted Stock Plan"), Executive Stock Incentive Plan ("ESIP") and the Director Plan. Except as otherwise noted, each person named in the table, and each other executive officer, has sole power to vote or direct the vote of all such shares beneficially owned by him or her. Except as otherwise noted, each person named in the table, and each other executive officer, has sole power to dispose or direct the disposition of shares beneficially owned by him or her. Common Stock granted under the Restricted Stock Plan, ESIP and the Director Plan ("Restricted Stock") may not be disposed of until vested. (4) Does not include shares that could be acquired under options, which information is set forth in the second column. (5) Includes shares subject to options that are exercisable within 60 days from February 1, 1997. Such shares may not be voted unless the options are exercised. Options that may become exercisable within such 60 day period only in the event of a change of control of Energy are excluded. None of the current executive officers or directors of Energy holds any rights to acquire Common Stock except through exercise of stock options. (6) Mr. Becraft resigned effective November 20, 1996. (7) Includes shares held by spouse. (8) Includes shares held by spouse and shares held in a trust. (9) Certain officers of Energy not designated as executive officers by the Board of Directors do not perform the duties of executive officers and are not classified as "executive officers" for purposes of this report. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company has invested through a subsidiary approximately $9.7 million in a program to drill coal seam gas wells in New Mexico. In order to share the drilling and other risks inherent in this project, various officers and employees of the Company were permitted to invest as general partners in a partnership to which the subsidiary's interest was assigned. The Board determined in 1992 that this transaction was fair to the Company. During 1992 and 1993 Messrs. Greehey, Benninger, McLelland and Manning invested approximately $207,000, $52,000, $156,000 and $104,000, respectively, to acquire respective interests of 2.0%, .50%, 1.5% and 1.0% in the project. No additional investments were made by these executive officers during 1994 or 1996. During 1995, a company owned by Mr. Manning purchased an additional .25% interest in the project from another investor. During 1996, Messrs. Greehey, Benninger, McLelland and Manning (including such company) received cash distributions of $45,680, $11,420, $34,260 and $28,550, respectively, attributable to their investments. Additionally, all investors in the project may be eligible to utilize certain federal income tax credits applicable to the project. Except as disclosed herein, no executive officer or director or director of Energy has been indebted to the Company, or has acquired a material interest in any transaction to which the Company is a party, during the last fiscal year. PART IV 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/A: Page Report of independent public accountants . . . . . Consolidated balance sheets as of December 31, 1996 and 1995 . . . . . . . . . . Consolidated statements of income for the years ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . Consolidated statements of common stock and other stockholders' equity for the years ended December 31, 1996, 1995 and 1994 . . . . . Consolidated statements of cash flows for the years ended December 31, 1996, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . 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/A or as part of Valero Energy Corporation's Form 10-K filed on February 27, 1997, are the following exhibits: *2.1 -- Agreement and Plan of Merger, dated as of January 31, 1997, among Valero Energy Corporation, PG&E Corporation, and PG&E Acquisition Corporation. The Company agrees to furnish supplementally any omitted schedule or exhibit to the Commission upon request. *2.2 -- Form of Agreement and Plan of Distribution to be executed by Valero Energy Corporation and Valero Refining and Marketing Company pursuant to the Agreement and Plan of Merger described in Exhibit 2.1 to this Form 10-K. The Company agrees to furnish supplementally any omitted schedule or exhibit to the Commission upon request. *2.3 -- Form of Employee Benefits Agreement to be executed by Valero Energy Corporation and Valero Refining and Marketing Company pursuant to the Agreement and Plan of Merger described in Exhibit 2.1 to this Form 10-K. The Company agrees to furnish supplementally any omitted schedule or exhibit to the Commission upon request. *2.4 -- Form of Tax Sharing Agreement to be executed by Valero Energy Corporation, Valero Refining and Marketing Company, and PG&E Corporation pursuant to the Agreement and Plan of Merger described in Exhibit 2.1 to this Form 10-K. The Company agrees to furnish supplementally any omitted schedule or exhibit to the Commission upon request. 2.5 -- 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 -- Rights Agreement, dated as of October 26, 1995, between Valero Energy Corporation and Harris Trust and Savings Bank, 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 27, 1995). 4.2 -- $300,000,000 Credit Agreement, dated as of November 1, 1995, among Valero Energy Corporation, Morgan Guaranty and Trust Company of New York as Administrative Agent, and Bank of Montreal as Syndication Agent and Issuing Bank, 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 November 9, 1995). 4.3 -- 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). 4.4 -- 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). 4.5 -- 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). 4.6 -- 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). 4.7 -- 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). 4.8 -- 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). 4.9 -- 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 Restricted Stock Bonus and Incentive Stock Plan, as amended and restated November 21, 1996. *+10.4 -- Valero Energy Corporation Stock Option Plan No. 3, as amended and restated August 22, 1996. *+10.5 -- Valero Energy Corporation Stock Option Plan No. 4, as amended and restated August 22, 1996. *+10.6 -- Valero Energy Corporation 1990 Restricted Stock Plan for Non-Employee Directors, as amended and restated August 22, 1996. *+10.7 -- Valero Energy Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 1996. *+10.8 -- Valero Energy Corporation Executive Incentive Bonus Plan, as amended and restated January 23, 1997. *+10.9 -- Valero Energy Corporation Executive Stock Incentive Plan, as amended and restated November 21, 1996. *+10.10 -- Valero Energy Corporation Non-Employee Director Stock Option Plan, as amended and restated November 21, 1996. +10.11 -- 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). *+10.12 -- Schedule of Executive Severance Agreements. +10.13 -- 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). +10.14 -- Modification of Employment Agreement between Valero Energy Corporation and William E. Greehey, dated November 29, 1994--incorporated by reference from Exhibit 10.12 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed March 1, 1995). +10.15 -- 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). *+10.16 -- Schedule of Indemnity Agreements. *+10.17 -- Incentive Bonus Agreement, dated as of November 21, 1996, between Valero Energy Corporation and Terrence E. Ciliske. *+10.18 -- Incentive Bonus Agreement, dated as of November 21, 1996, between Valero Energy Corporation and Peter A. Fasullo. *+10.19 -- Incentive Bonus Agreement, dated as of November 21, 1996, between Valero Energy Corporation and Gregory C. King. *+10.20 -- Management Stability Agreement, dated as of November 1, 1996, between Valero Energy Corporation and Terrence E. Ciliske. *+10.21 -- Management Stability Agreement, dated as of November 1, 1996, between Valero Energy Corporation and Peter A. Fasullo. *+10.22 -- Management Stability Agreement, dated as of November 1, 1996, between Valero Energy Corporation and Gregory C. King. *+10.23 -- Waiver and Agreement, dated as of November 21, 1996, between Valero Energy Corporation and William E. Greehey. *+10.24 -- Schedule of Waiver 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 May 13, 1997. *24.1 -- Power of Attorney, dated February 27, 1997 (set forth on the signatures page of Valero Energy Corporation's Form 10-K). **27.1 -- Financial Data Schedule (reporting financial information as of and for the year ended December 31, 1996). **27.2 -- Restated Financial Data Schedule (reporting financial information as of and for the year ended December 31, 1995). **27.3 -- Restated Financial Data Schedule (reporting financial information as of and for the year ended December 31, 1994). ________________ * Filed with Valero Energy Corporation's Form 10-K on February 27, 1997. + Identifies management contracts or compensatory plans or arrangements filed as an exhibit to Valero Energy Corporation's Form 10-K pursuant to Item 14(c) of Form 10-K. ** The Financial Data Schedule and Restated Financial Data Schedules 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 are included as exhibits only to the electronic filing of this Form 10-K/A in accordance with Item 601(c) of Regulation S-K and Section 401 of Regulation S-T. *** Filed herewith. Copies of exhibits filed as a part of this Form 10-K/A and Valero Energy Corporation's 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) Reports on Form 8-K. A report on Form 8-K dated November 21, 1996 was filed electronically on December 31, 1996, reporting Item 5. Other Events, in connection with the Board's approval to pursue a strategic transaction relating to the Company's principal business activities. 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. 33-14455 (filed May 21, 1987), No. 33-38045 (filed December 3, 1990), No. 33-53796 (filed October 27, 1992), No. 33-59040 (filed March 3, 1993), No. 33-52533 (filed March 7, 1994), No. 33-59217 (filed May 10, 1995), No. 33-63703 (filed October 26, 1995), and No. 333-02987 (filed April 3, 1996). 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/ Rand C. Schmidt (Rand C. Schmidt, Attorney-in-Fact) Date: May 13, 1997 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 William E. Greehey* Executive Officer) May 13, 1997 Director, President and Chief Financial Officer (Principal Financial Edward C. Benninger* and Accounting Officer) May 13, 1997 Ronald K. Calgaard* Director May 13, 1997 Robert G. Dettmer* Director May 13, 1997 A. Ray Dudley* Director May 13, 1997 James L. Johnson* Director May 13, 1997 Lowell H. Lebermann* Director May 13, 1997 Susan Kaufman Purcell* Director May 13, 1997 *By: /s/ Rand C. Schmidt (Rand C. Schmidt, Attorney-in-Fact) EX-11.1 2 COMPUTATION OF EARNINGS PER SHARE EXHIBIT 11.1 VALERO ENERGY CORPORATION AND SUBSIDIARIES COMPUTATION OF EARNINGS PER SHARE (Thousands of Dollars, Except Per Share Amounts)
Year Ending December 31, 1996 1995 1994 COMPUTATION OF EARNINGS PER SHARE ASSUMING NO DILUTION: Net income. . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282 Less: Preferred stock dividend requirements. . . . (11,327) (11,818) (9,490) Net income applicable to common stock . . . . . . . $ 61,374 $ 48,020 $ 7,792 Weighted average number of shares of common stock outstanding . . . . . . . . . . . . . . . . 43,926,026 43,651,914 43,369,836 Earnings per share assuming no dilution . . . . . . $ 1.40 $ 1.10 $ .18 COMPUTATION OF EARNINGS PER SHARE ASSUMING FULL DILUTION: Net income. . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282 Less: Preferred stock dividend requirements. . . (11,327) (11,818) (9,490) Add: Reduction of preferred stock dividends applicable to the assumed conversion of Convertible Preferred Stock . . . . . . . . . . 10,781 10,781 8,325 Net income applicable to common stock assuming full dilution. . . . . . . . . . . . . $ 72,155 $ 58,801 $ 16,117 Weighted average number of shares of common stock outstanding . . . . . . . . . . . . . . . 43,926,026 43,651,914 43,369,836 Weighted average common stock equivalents applicable to stock options . . . . . . . . . . 632,967 413,809 56,926 Weighted average shares issuable upon conversion of Convertible Preferred Stock . . . 6,381,798 6,381,798 4,948,079 Weighted average shares used for computation. . . 50,940,791 50,447,521 48,374,841 Earnings per share assuming full dilution . . . . $ 1.42 $ 1.17 $ .33 This calculation is submitted in accordance with paragraph 601(b)(11) of Regulation S-K although it is contrary to APB Opinion No. 15 because it produces an antidilutive result.
EX-12.1 3 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES EXHIBIT 12.1 VALERO ENERGY CORPORATION COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Dollars in Thousands)
Year Ended Year Ended Year Ended Year Ended December 31, December 31, 1994 December 31, 1993 December 31, 1996 1995 Pro Forma Historical Pro Forma Historical 1992 Pretax income from continuing operations . . . . . . . . . . . . . $113,701 $ 95,138 $ 16,489 $ 27,982 $ 76,698 $ 68,224 $131,419 Add (Deduct): Net interest expense . . . . . . . . 95,177 101,222 98,695 76,921 89,413 37,182 30,423 Amortization of previously capitalized interest . . . . . . . . . . . . . . . . 6,061 6,820 6,847 6,282 6,300 4,998 4,544 Interest portion of rental expense . 14,034 13,251 8,259 6,695 8,003 4,316 4,214 Distributions (less than)/in excess of equity in earnings of VNGP, L.P. . . - - - 18,968 - (4,970) (1,067) Distributions (less than) equity in earnings of joint ventures . . . . . (3,899) (4,304) (2,437) (2,437) - - - Earnings as defined. . . . . . . . . . . $225,074 $212,127 $127,853 $134,411 $180,414 $109,750 $169,533 Net interest expense . . . . . . . . . $ 95,177 $101,222 $ 98,695 $ 76,921 $ 89,413 $ 37,182 $ 30,423 Capitalized interest . . . . . . . . . . . 4,328 4,699 2,558 2,365 14,048 12,335 15,853 Interest portion of rental expense . . 14,034 13,251 8,259 6,695 8,003 4,316 4,214 Fixed charges as defined . . . . . . . . $113,539 $119,172 $109,512 $ 85,981 $111,464 $ 53,833 $ 50,490 Ratio of earnings to fixed charges . . . . 1.98x 1.78x 1.17x 1.56x 1.62x 2.04x 3.36x The pro forma computations reflect the consolidation of the Partnership with the Company for all of 1994 and 1993. The interest portion of rental expense represents one-third of rents, which is deemed representative of the interest portion of rental expense. Represents the Company's undistributed equity in earnings or distributions in excess of equity in earnings of the Partnership for the periods prior to and including May 31, 1994. On May 31, 1994, the Merger of the Partnership with the Company was consummated and the Partnership became a wholly owned subsidiary of the Company. The Company has guaranteed its pro rata share of the debt of Javelina Company, an equity method investee in which the Company holds a 20% interest. The interest expense related to the guaranteed debt is not included in the computation of the ratio as the Company has not been required to satisfy the guarantee nor does the Company believe that it is probable that it would be required to do so. The 1994 historical and pro forma amounts have been restated to reflect the effects of a prior period adjustment resulting in a charge to 1994 income for an acquisition expense accrual originally charged to property, plant and equipment.
EX-23.1 4 CONSENT OF ARTHUR ANDERSEN LLP EXHIBIT 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K/A into the Company's previously filed Registration Statements on Form S-8 (File Nos. 33-14455, 33-38045, 33-53796, 33-52533, 33-59040, 33-59217, 33-63703, 333-02987) and on Form S-3 (File No. 33-56441). /s/ ARTHUR ANDERSEN LLP San Antonio, Texas May 13, 1997 EX-27.1 5 FINANCIAL DATA SCHEDULE
5 THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1996 AND THE CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 12-MOS DEC-31-1996 DEC-31-1996 57,593 0 567,712 1,624 212,134 888,169 2,787,431 708,352 3,134,774 875,154 868,300 1,150 3,450 44,186 1,028,189 3,134,774 4,990,681 4,990,681 4,789,772 4,789,772 0 0 95,177 113,701 41,000 72,701 0 0 0 72,701 1.40 0
EX-27.2 6 RESTATED FINANCIAL DATA SCHEDULE
5 1,000 12-MOS DEC-31-1995 DEC-31-1995 64,681 0 340,382 1,193 140,822 621,543 2,682,694 622,123 2,861,880 468,282 1,035,641 6,900 3,450 43,739 977,024 2,861,880 3,197,872 3,197,872 3,009,081 3,009,081 0 0 101,222 95,138 35,300 59,838 0 0 0 59,838 1.10 0
EX-27.3 7 RESTATED FINANCIAL DATA SCHEDULE
5 1,000 12-MOS DEC-31-1994 DEC-31-1994 61,651 0 235,043 2,770 182,089 532,872 2,657,915 531,501 2,816,558 460,767 1,021,820 12,650 3,450 43,464 955,966 2,816,558 1,837,440 1,837,440 1,711,515 1,711,515 0 0 76,921 27,982 10,700 17,282 0 0 0 17,282 .18 0
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