ITEM 1. BUSINESS
Valero Natural Gas Partners, L.P. ("VNGP, L.P.") was established under the Delaware Revised Uniform Limited Partnership Act on January 28, 1987, and commenced actual operations on March 25, 1987, when Valero Energy Corporation and its subsidiaries restructured their natural gas and natural gas liquids operations by transferring such operations to the Partnership (defined herein). Unless otherwise required by the context, the term "Energy" as used herein refers to Valero Energy Corporation and its consolidated subsidiaries, both individually and collectively, and the term "Partnership" as used herein refers to VNGP, L.P. and its consolidated subsidiaries. VNGP, L.P.'s principal executive offices are located at 530 McCullough Avenue, San Antonio, Texas 78215 (telephone number (210) 246-2000).
VNGP, L.P. holds a 99% limited partner interest in Valero Management Partnership, L.P. (the "Management Partnership") and certain subsidiary partnerships established subsequent to the creation of the Partnership. The Management Partnership holds a 99% limited partner interest in eleven subsidiary operating partnerships which existed at the time VNGP, L.P. was established and one subsidiary operating partnership formed in 1992 (collectively, the "Subsidiary Operating Partnerships"). Valero Natural Gas Company ("VNGC"), a wholly owned subsidiary of Energy, is the general partner of both VNGP, L.P. and the Management Partnership (in such capacities, the "General Partner") and holds a 1% general partner interest in each partnership. Various subsidiaries of VNGC serve as general partners (in such capacities, the "Subsidiary General Partners") of and hold 1% general partner interests in each Subsidiary Operating Partnership. Unless the context otherwise requires, any references to VNGP, L.P., the Management Partnership or any of the original Subsidiary Operating Partnerships regarding any period prior to March 25, 1987, should be construed to refer, as appropriate, to Energy, VNGC or the corresponding subsidiaries of Energy or VNGC that transferred their natural gas and natural gas liquids operations to the Partnership; references to the Partnership with respect to such period should be construed to refer to VNGC and such subsidiaries. For additional information with respect to the 1987 restructuring, see Note 1 - "Organization and Control" of Notes to Consolidated Financial Statements.
The Partnership operates in two business segments: Natural Gas and Natural Gas Liquids. For additional operational, financial and statistical information regarding these operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4 of Notes to Consolidated Financial Statements. For information with respect to cash provided by and used in the Partnership's operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."
RECENT DEVELOPMENTS
Proposed Merger with Energy
In October 1993, Energy publicly announced its proposal to acquire the 9.7 million issued and outstanding common units of limited partner interests ("Common Units") in VNGP, L.P. held by persons other than Energy (the "Public Unitholders") pursuant to a merger of VNGP, L.P. with a wholly owned subsidiary of Energy (the "Merger"). The Board of Directors of VNGC appointed a special committee of outside directors (the "Special Committee") to consider the Merger and to determine the fairness of the transaction to the Public Unitholders. The Special Committee thereafter retained independent financial and legal advisors to assist the Special Committee. Upon the recommendation of the Special Committee, the Board of Directors of VNGC unanimously approved the Merger. Effective December 20, 1993, Energy, VNGP, L.P. and VNGC entered into an agreement of merger (the "Merger Agreement") providing for the Merger. In the Merger, the Common Units held by the Public Unitholders will be converted into the right to receive cash in the amount of $12.10 per Common Unit. As a result of the Merger, VNGP, L.P. would become a wholly owned subsidiary of Energy. There can be no assurance, however, that the Merger will be completed.
Consummation of the Merger is subject to, among other things, (i) approval of the Merger Agreement by the holders of a majority of the issued and outstanding Common Units; (ii) approval by a majority of the Common Units held by the Public Unitholders voted at a special meeting of holders of Common Units to be called to consider the Merger Agreement; (iii) satisfactory waivers, consents or amendments to certain of Energy's financial agreements; and (iv) completion of an underwritten public offering of convertible preferred stock by Energy. A proposal to approve the Merger Agreement will be submitted to the holders of Common Units at the special meeting of Unitholders expected to be scheduled during the second quarter of 1994. Prior to the special meeting, the holders of Common Units will receive a proxy statement fully describing the Merger and explaining the manner in which holders of Common Units may cast their votes (the "Proxy Statement"). Energy owns approximately 47.5% of the outstanding Common Units and intends to vote its Common Units in favor of the Merger. The foregoing discussion of the Merger omits certain information contained in the Merger Agreement and the Proxy Statement. Statements made in this Report concerning the Merger are qualified by and are made subject to the more detailed information contained in the Merger Agreement and the Proxy Statement.
Decline of Crude Oil and NGL Prices
Beginning in November 1993, crude oil prices fell significantly and have not recovered to prior levels. The price decline resulted from a number of factors including the decision by the Organization of Petroleum Exporting Companies ("OPEC") to forego cuts in crude oil production, weakened global demand for crude oil, increasing production from non-OPEC areas and concerns related to the re-entry of Iraq into world oil markets. Natural gas liquids ("NGL") prices also fell in conjunction with the decline in crude oil prices. Record-high NGL inventories also depressed NGL prices. Because of depressed NGL sales prices and the high cost of natural gas from which such liquids are extracted, NGL margins were very depressed in the fourth quarter of 1993, requiring the Partnership to cease operations for 20 days in December 1993 at one of its gas processing plants and to suspend the production of ethane for 28 days in December at two other plants due to lack of profitability. See "Natural Gas Liquids Operations - NGL Supply and Sales." The Partnership continues to monitor the market conditions affecting the profitability of its gas processing plants with a view to modifying as needed any operations that appear unprofitable. During the first quarter of 1994, NGL prices have increased modestly since late December 1993, but remain below first quarter 1993 levels. Concurrently, natural gas prices and resulting shrinkage costs have increased during the first quarter of 1994 compared to the same period in 1993. Accordingly, the Partnership's operating income is expected to be substantially lower in the first quarter of 1994 than in the first quarter of 1993.
NATURAL GAS OPERATIONS
General
The Partnership owns and operates natural gas pipeline systems principally serving Texas intrastate markets. Through interconnections with interstate pipelines, the Partnership also markets natural gas throughout the United States. The Partnership's natural gas pipeline and marketing operations consist principally of purchasing, gathering, transporting and selling natural gas to gas distribution companies, electric utilities, other pipeline companies and industrial customers, and transporting natural gas for producers, other pipelines and end users.
Pipeline Facilities
The Partnership's principal natural gas pipeline system is the intrastate gas system ("Transmission System") operated by Valero Transmission, L.P. ("Transmission") in the State of Texas. (References to Transmission prior to March 25, 1987 refer to Valero Transmission Company, a wholly owned subsidiary of VNGC, as the previous owner of the Transmission System. References to Transmission on or after March 25, 1987 refer to Valero Transmission, L.P., a Subsidiary Operating Partnership, as successor owner of the Transmission System.) The Transmission System generally consists of large diameter transmission lines which 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 Partnership's wholly owned, jointly owned and leased natural gas pipeline systems include approximately 7,200 miles of mainlines, lateral lines and gathering lines. These pipeline systems are located along the Texas Gulf Coast and throughout South Texas and extend westerly to near Pecos, Texas; northerly to near the Dallas-Fort Worth area, easterly to Carthage, Texas, near the Louisiana border and southerly into Mexico near Reynosa. The Partnership operates and jointly owns in equal portions with Texas Utilities Fuel Company ("TUFCO") a 395-mile pipeline extending from Waha, near Fort Stockton, Texas, to near Ennis, Texas, south of the Dallas-Fort Worth area. An addition to this line also extends 58 miles into East Texas from Ennis to Bethel, Texas, and is jointly owned 39% by TUFCO (which operates the line), 39% by Lone Star Gas Company and 22% by the Partnership. The Partnership also operates and jointly owns in equal portions with TECO Pipeline Company a 340-mile pipeline system and related facilities extending from Waha to New Braunfels, near San Antonio, Texas. The Partnership owns a 3.5-mile, 24-inch pipeline that connects the Partnership's pipeline near Penitas in South Texas to Petroleos Mexicanos's ("PEMEX") 42-inch pipeline outside Reynosa, Mexico. The Partnership leases and operates several pipelines, including approximately 240 miles of 24-inch pipeline leased from TUFCO that extends from near Dallas to near Houston, and approximately 105 miles of pipeline leased from Energy that extends the Partnership's North Texas pipeline further into East Texas from Bethel to Carthage (the "East Texas pipeline"). These integrated systems include 39 mainline compressor stations with a total of approximately 162,000 horsepower, together with gas processing plants, dehydration and gas treating plants and numerous measuring and regulating stations. The Partnership's pipeline systems have considerable flexibility in providing connections between many producing and consuming areas. The Partnership's owned and leased pipeline systems have 70 interconnects with 22 intrastate pipelines and 38 interconnects with 12 interstate pipelines.
The Partnership's pipeline systems are able to handle widely varying loads caused by changing supply and demand patterns. Annual average throughput was approximately 2.5 Bcf (1) per day in 1993, and has been in excess of 2 Bcf per day in recent years. The system has served peak demands at hourly rates of flow significantly in excess of these daily averages. Although capacity in the Partnership's pipeline systems is generally expected to be adequate for the foreseeable future, seasonal factors can significantly influence gas sales and transportation volumes.
[FN] (1) All volumes of natural gas referred to herein are stated at a pressure base of 14.65 pounds per square inch absolute and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. The term "Mcf" means thousand cubic feet, 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 term "MMBtu's" means million Btu's. The number of MMBtu's of total natural gas deliveries is approximately equal to the number of Mcf's of such deliveries.
Gas Sales
The Partnership's gas sales are made principally through the Subsidiary Operating Partnerships which operate special marketing programs ("SMPs"). The Subsidiary Operating Partnerships operating the SMPs are Reata Industrial Gas, L.P. ("Reata"), Valero Industrial Gas, L.P. ("Vigas") and VLDC, L.P. ("VLDC"). Reata buys its gas supply from producers, marketers and certain intrastate pipelines and resells the gas in the intrastate market on both a long-term basis and a short-term interruptible basis. Vigas acquires gas supply directly from gas producers and sells the gas on a short-term interruptible basis and a term basis to intrastate and interstate markets. VLDC serves short-term intrastate sales markets with supplies of both intrastate and interstate gas. In addition, some of the Partnership's gas sales are made by Valero Gas Marketing, L.P. ("Valero Gas Marketing"), Val Gas, L.P. ("Val Gas") and Rivercity Gas, L.P. ("Rivercity"). Valero Gas Marketing engages primarily in off-system sales. Val Gas primarily purchases and resells natural gas in interstate commerce. Rivercity sells gas on a short-term, interruptible basis. Most of the gas sold by Reata, Vigas, VLDC, Val Gas and Rivercity is transported through the Transmission System by Transmission. Transmission sells natural gas under long-term contracts to a few remaining intrastate customers. However, because of various factors described below, most of the industrial and other gas sales customers previously served by Transmission, including local distribution companies ("LDCs") and electric utilities, now purchase gas in the spot market, including purchases from the Subsidiary Operating Partnerships operating the SMPs, or have entered into gas transportation contracts with Transmission to transport gas acquired by the customers directly from producers or other suppliers. Accordingly, Transmission is primarily a transporter rather than a seller of natural gas. See "Natural Gas Operations - Gas Transportation and Exchange" below.
During 1993, the Partnership sold natural gas under hundreds of separate short-term and long-term gas sales contracts to numerous customers in both the intrastate and interstate markets. The Partnership's gas sales are made primarily to gas distribution companies, electric utilities, other pipeline companies and industrial users. The gas sold to distribution companies is resold to consumers in a number of cities including San Antonio, Dallas, Austin, Corpus Christi and Chicago. Although the expiration dates of the Partnership's gas sales contracts range from 1994 to 2001, many of the Partnership's short-term sales contracts have expired or will expire by their terms in 1994 or are terminable on a day-to-day, month-to-month or similar basis by either the Partnership or the party to whom gas is sold. The General Partner anticipates that most of these contracts will be renewed for an additional term or converted to transportation arrangements, or that the gas sold under these contracts will be marketed to other customers.
The Partnership's gas sales and transportation volumes (in MMcf per day) for the three years ended December 31, 1993, are as follows:
In 1993, the Partnership's ten largest gas sales customers accounted for approximately 33% of its total consolidated operating revenues and approximately 48% of its total consolidated daily gas sales volumes. During 1993, sales of natural gas accounted for approximately 38% of total daily Partnership gas throughput volumes. The Partnership's largest gas sales customer is San Antonio City Public Service ("CPS"). See "Natural Gas Operations - Gas Sales - Intrastate Sales."
Through the SMPs, the Partnership continues to emphasize sales under term contracts. During 1993, the Partnership continued to expand its term sales to LDCs who have been seeking to convert purchase obligations from interstate pipelines into firm transportation arrangements. In 1993, about 55% of the Partnership's gas sales were made under term contracts. Term contracts are becoming more prevalent in the industry and the Partnership's gas sales under term contracts are expected to increase over the next several years. See "Natural Gas Operations - Gas Sales - Interstate Sales" and "Competition - Natural Gas." The Partnership has also emphasized the transportation of natural gas for producers and sales customers. See "Natural Gas Operations - Gas Transportation and Exchange."
The Partnership's natural gas operations have been affected by an emerging trend of west-to-east movement of gas across the United States resulting from growing productive capacity in western supply basins, the completion of new pipeline capacity from such basins to the U.S. West Coast and increasing demand for power generation in the East and Southeast. The General Partner believes that in many of the pipelines serving this market, west-to-east capacity is becoming constrained. The General Partner believes that over time, improving transportation margins resulting from these capacity constraints may warrant additional west-to-east capacity additions and that the Partnership would be positioned to participate in such opportunities if it had the financial flexibility to make the necessary capital expenditures. See "Natural Gas Operations - Pipeline Facilities" and "Properties."
Under current regulations of the Railroad Commission of Texas (the "Railroad Commission"), Transmission, like other gas purchasers, is required to take ratably first casinghead gas (2) and certain special allowable gas (casinghead gas and special allowable gas that are the last to be shut in during periods of reduced market demand are referred to collectively as "high- priority" gas) produced from wells connected to Transmission's pipeline systems and, if Transmission's sales volumes exceed the amounts of such high-priority gas available, thereafter to take by specific category other gas, including gas well gas, from wells from which Transmission purchases gas on a ratable basis to the extent of market demand. See "Governmental Regulations - Texas Regulation." Most of the casinghead gas under contract to Transmission was acquired under older, long-term contracts which provided for relatively high prices, together with price escalation provisions under the Natural Gas Policy Act of 1978 (the "NGPA"). The majority of these contracts did not contain allowances for price reductions when market prices declined or contain so-called "market-out" provisions that permit a purchaser to terminate a contract if market conditions render the contract uneconomical. As a result, the cost of the high-priority gas connected to Transmission's system under its older contracts has remained substantially higher than the cost of alternative gas supplies. Accordingly, most of Transmission's major customers have switched upon contract expiration from the noninterruptible service provided by Transmission to alternative suppliers including the Subsidiary Operating Partnerships operating the SMPs, causing Transmission's sales to decline significantly. For additional information concerning Transmission's cost of gas and gas sales price, see "Management's Discussion and Analysis of Financial Condition and Results of Operations."
[FN] (2) The Partnership generally purchases "casinghead gas" (defined as gas produced from wells primarily producing oil) and "gas well gas" (defined as gas produced from wells primarily producing gas).
Intrastate Sales
In 1993, the Partnership sold approximately 699 MMcf per day of gas to its core intrastate market, representing approximately 71% of total daily gas sales volumes, compared to 630 MMcf per day (71%) in 1992 and 648 MMcf per day (64%) in 1991. The majority of the Partnership's daily intrastate sales are made through its SMPs (92%, 88% and 84% in 1993, 1992 and 1991, respectively) with the remainder made by Transmission. The Partnership's sales to CPS are made principally by Reata. Effective July 1, 1992, the Partnership was awarded a new contract with CPS to supply 100% of CPS's natural gas requirements. The contract is effective until 2002, subject to possible renegotiation of certain contract terms beginning in 1997. As a result of the CPS contract, the Partnership's gas sales volumes to CPS increased significantly in 1993. Natural gas sales to CPS in 1993 represented approximately 11% of the Partnership's total consolidated operating revenues and approximately 18% of the Partnership's total consolidated daily gas sales volumes. Except for the CPS contract, the Partnership's gas sales contracts between the SMPs and the Partnership's intrastate customers generally require the Partnership to provide a fixed and determinable quantity of gas rather than total customer requirements. The Partnership's gas sales contracts between Transmission and its intrastate customers generally provide for either maximum volumes or total requirements, subject to priorities and allocations established by the Railroad Commission.
Since December 31, 1979, Transmission's gas sales to its customers have been made at prices established by an order (the "Rate Order") of the Railroad Commission. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 6 of Notes to Consolidated Financial Statements for a discussion of Transmission's rates and the terms of the 1993 settlement of a customer's audit of Transmission's weighted average cost of gas. The price of natural gas sold under the SMPs is not currently regulated by the Railroad Commission, and the Subsidiary Operating Partnerships operating the SMPs may generally enter into any sales contract that they are able to negotiate with customers. See "Governmental Regulations - Texas Regulation."
Interstate Sales
In 1993, the Partnership sold, through its SMPs, approximately 281 MMcf per day of gas to interstate markets, representing approximately 29% of total daily gas sales volumes, compared to 259 MMcf per day (29%) in 1992 and 363 MMcf per day (36%) in 1991. The Partnership pursued opportunities resulting from favorable market fundamentals and the implementation of Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636") in 1993. The Partnership is continuing to emphasize diversification of its customer base through interstate sales and has enjoyed recent success in interstate markets, adding new term natural gas sales in 1993, mostly in the Midwest, Northeast and Western United States, which provide for deliveries of up to 260 MMcf per day. For information regarding Order 636, which has created new supply, marketing and transportation opportunities for the Partnership in the interstate market, see "Governmental Regulations - Federal Regulation" and "Competition - Natural Gas."
Gas Transportation and Exchange
Gas transportation and exchange transactions (collectively referred to as "gas transportation" or "transportation") constitute the largest portion of the Partnership's natural gas throughput, representing 62%, 59% and 53% of total daily Partnership gas throughput volumes for 1993, 1992 and 1991, respectively. Gas transportation involves several types of transactions. The common element of a gas transportation transaction is that the gas is neither purchased nor sold by the Partnership; instead, the Partnership receives natural gas on a Btu basis at one point and redelivers an equivalent amount of gas on a Btu basis at another point for a negotiated fee and fuel allowance. See "Natural Gas Operations - Gas Sales" for a discussion of the emerging trend of west-to-east movement of gas across the United States.
The Partnership transports gas for third parties under hundreds of separate transportation contracts. The Partnership's transportation contracts generally limit the Partnership's maximum transportation obligation (subject to available capacity) but generally do not provide for any minimum transportation requirement. Although the expiration dates of the Partnership's transportation contracts range from 1994 to 2000, many of the Partnership's transportation contracts expire by their terms in 1994, or are terminable on a day-to-day, month-to-month or similar basis by the party for whom gas is being transported or exchanged. The General Partner anticipates that most of these transportation contracts will be renewed for additional terms or continued in effect on some other basis. See "Competition - Natural Gas."
The Partnership's transportation customers include major oil and natural gas producers and pipeline companies. In 1993, the Partnership's ten largest gas transportation customers accounted for approximately 3% of its total consolidated operating revenues and approximately 69% of its total consolidated daily transportation volumes. The Partnership's principal contracts with its largest transportation customer expire in 1998 and provide for dedication of volumes of approximately 200 MMcf per day.
The Partnership's delivery of natural gas to Mexico through the Partnership's connection to PEMEX's pipeline near Reynosa, Mexico decreased in 1993. Mexico generally decreased the amount of its natural gas imports in 1993. In December 1993, Mexico became a net exporter of natural gas to Texas through a pipeline connection with PEMEX owned by a competitor of the Partnership. The Partnership's total natural gas sales and transportation deliveries to Mexico were approximately 56 MMcf per day in 1993 compared to 75 MMcf per day in 1992 and 31 MMcf per day in 1991. The Partnership expects to receive authorization from the FERC in 1994 to operate the Partnership's pipeline connection to PEMEX for the purpose of importing natural gas from Mexico.
Gas volumes transported for or exchanged with others (in MMcf per day) by the Partnership and the Partnership's average transportation fee for the three years ended December 31, 1993, are as follows:
Gas Supply
Gas supplies available to the Partnership 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 Partnership and the Partnership does not own any gas reserves other than gas in underground storage, which comprises an insignificant portion of the Partnership's gas supplies. See "Natural Gas Operations - Gas Storage Facilities." Because of recent changes in the natural gas industry, gas supplies have become increasingly subject to shorter term contracts, rather than long-term dedications.
During 1993, the Partnership purchased natural gas under hundreds of separate contracts. Surplus gas supplies, if available, may be purchased to supplement the Partnership's delivery capability during peak use periods. These contractual relationships usually are supplemented by a physical interconnection between the Partnership's pipeline system and either the wellhead, field gathering system or other delivery point. A majority of the Partnership's gas supplies are obtained from sources with multiple connections. In such instances, the Partnership frequently competes on a monthly basis for available gas supplies. Purchases from the Partnership's ten largest suppliers accounted for approximately 37% of total Partnership gas purchase volumes for 1993.
The Partnership's sources of gas supplies are located in most of the major producing areas of Texas but are concentrated primarily in the Delaware, Midland and Val Verde basins of West Texas, the Maverick basin of South-Central Texas, the Texas Gulf Coast and the East Texas basin. Because of the extensive coverage within the State of Texas by the Partnership's pipeline systems, the General Partner believes that the Partnership can access a number of supply areas. While there can be no assurance that the Partnership will be able to acquire new gas supplies in the future as it has in the past, the General Partner believes that Texas will remain a major producing state, and that for the foreseeable future the Partnership will be able to compete effectively with other producers and to connect sufficient new gas supplies in order to meet customer demand.
Gas Storage Facilities
Valero Gas Storage Company ("Gas Storage"), a wholly owned subsidiary of VNGC, operates an underground gas storage facility (the "Wilson Storage Facility") in Wharton County, Texas. The current storage capacity of the Wilson Storage Facility is approximately 7.2 Bcf of gas available for withdrawal. Natural gas can be continuously withdrawn from the facility at initial rates of up to approximately 800 MMcf of gas per day and at declining delivery rates thereafter until the inventory is depleted. See Note 5 of Notes to Consolidated Financial Statements for a discussion of the Partnership's use of the Wilson Storage Facility through certain lease and other agreements. To meet new Order 636 term business, the Partnership supplemented its own natural gas storage capacity by securing during 1993 an additional 6 Bcf of third-party storage capacity for the 1993-94 winter heating season.
NATURAL GAS LIQUIDS OPERATIONS
General
The Partnership's NGL operations include the processing of natural gas to extract a mixed NGL stream of ethane, propane, butanes and natural gasoline conducted by Valero Hydrocarbons, L.P. ("Hydrocarbons"), and the separation ("fractionation") of mixed NGLs into component products and the transportation and marketing of NGLs conducted by Valero Marketing, L.P. ("Marketing"). Extracted NGLs are transported to downstream fractionation facilities and end-use markets through NGL pipelines owned or leased by the Partnership and certain common carrier NGL pipelines. Extraction is the process of removing NGLs from the gas stream, thereby reducing the Btu content and volume of incoming gas (referred to as "shrinkage"). In addition, some gas from the gas stream is consumed as fuel during processing.
The Partnership receives revenues from the extraction of NGLs principally through the sale of NGLs extracted in its owned and leased gas processing plants and the collection of processing fees charged for the extraction of NGLs owned by others. The Partnership 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 primary markets for NGLs are petrochemical plants (all NGLs), refineries (butanes and natural gasoline), and domestic fuel distributors (propane). Because of these uses, NGL prices are generally set by or in competition with prices for refined products in the petrochemical, fuel and motor gasoline markets.
Gas Processing Facilities
The Partnership currently owns eight gas processing plants. In addition, the Partnership operates and leases from Energy a 200-million cubic foot per day turboexpander gas processing plant in South Texas near Thompsonville. See Note 5 of Notes to Consolidated Financial Statements. These owned and leased plants are located in the western and southern regions of Texas and process approximately 1.3 Bcf of gas per day. During 1993, the Partnership sold its only off-system gas processing plant in West Texas. Accordingly, each of the Partnership's owned or leased plants is now situated along the Transmission System. The Partnership's NGL production is sold primarily in the Corpus Christi, Texas and Mont Belvieu (Houston) markets. A substantial portion of the Partnership's butane production is sold to Energy as feedstock for Energy's refinery in Corpus Christi (the "Refinery").
Of the eight gas processing plants owned by the Partnership, four are located on leased premises, although substantially all of the plant equipment is owned rather than leased. Leases for the premises expire on various dates from 1995 to 2006. One of the leases is renewable for an additional term. The nonrenewable leases do not expire until the years 2000, 2001 and 2006, respectively. The General Partner believes that the operations of the Partnership will not be materially affected by the expiration of the leases. In most cases, satisfactory arrangements can be made through the renewal of leases, the purchase of leased premises or the relocation of plant equipment.
In 1993, the Partnership achieved a record NGL production of approximately 24.8 million barrels for the year. Volumes of NGLs produced at the Partnership's owned and leased plants (in thousands of barrels per day) and the average market price per gallon and average gas cost per MMbtu for the three years ended December 31, 1993, are as follows:
The Partnership also operates for a fee two natural gas processing plants in South Texas owned by Energy under operating agreements with Energy. See Note 1 - "Transactions with Energy" of Notes to Consolidated Financial Statements. Total production at all plants operated by the Partnership, including both the Partnership's owned and leased plants and the two plants owned by Energy, averaged 77,400 barrels per day in 1993.
The Partnership and a major South Texas natural gas producer have executed a letter of intent which, subject to the execution of a binding contract and the closing of the transaction, provides for the processing, transportation and purchase of natural gas by the Partnership. Under the proposed agreement, the producer will dedicate up to 300 MMcf per day of natural gas production in South Texas to the Partnership for up to 10 years, beginning in June 1994. The Partnership currently processes approximately 150 MMcf per day of the producer's natural gas under arrangements that expire in 1994 and 1995. The General Partner anticipates that the Partnership will continue to pursue opportunities to expand its NGL operations in South Texas.
Fractionation and Other Facilities
The Partnership owns fractionation facilities located at the Partnership's Shoup gas processing plant near Corpus Christi, at the Partnership's Armstrong gas processing plant near Yoakum, Texas and at the Refinery. In addition, the Partnership leases from Energy a depropanizer constructed at the Shoup plant and a butane splitter constructed at the Refinery. See Note 5 of Notes to Consolidated Financial Statements. In 1993, the Partnership fractionated an average of 70,000 barrels per day compared to 68,000 barrels per day in 1992 and 51,000 barrels per day in 1991. Approximately 25%, 38% and 28% of the total volumes fractionated in 1993, 1992 and 1991, respectively, represented NGLs fractionated for third parties.
The Partnership also owns or leases approximately 375 miles of NGL pipelines that transport NGLs from gas processing plants to fractionation facilities. The NGL pipelines also connect with end users and major common-carrier NGL pipelines, which ultimately deliver NGLs to the principal NGL markets. The Partnership's NGL pipelines are located principally in South Texas and West Texas. In South Texas, the Partnership owns 200 miles of NGL pipelines that directly or indirectly connect four of the Partnership's owned processing plants and five processing plants owned by third parties to the Partnership's fractionation facilities near Corpus Christi. The South Texas system also delivers NGLs from the Corpus Christi fractionation facilities to end users and to a major common carrier NGL pipeline. Another important NGL pipeline owned by the Partnership is located in Southeast Texas and transports NGLs from the Partnership's Armstrong plant and fractionation facility near Yoakum to an end user. The Partnership leases from Energy 48 miles of NGL product pipeline that connects the Thompsonville plant to the Partnership's existing NGL pipeline in Freer, Texas. See Note 5 of Notes to Consolidated Financial Statements. The Partnership also operates a 59-mile NGL products pipeline in South Texas owned by Energy.
NGL Supply and Sales
The Partnership sells NGLs that have been extracted, transported and fractionated in the Partnership's facilities and NGLs purchased in the open market from numerous suppliers under long-term, short-term and spot contracts. The Partnership's largest NGL suppliers include major refineries and natural gas processors. Its ten largest suppliers accounted for approximately 63% of total NGL purchases in 1993. The Partnership markets substantially greater volumes of NGLs than it produces. During 1993, the Partnership sold to third parties on average 94,500 barrels of NGLs per day compared to an average of 93,600 barrels per day in 1992 and 75,600 barrels per day in 1991.
The Partnership's contracts for the purchase, sale, transportation and fractionation of NGLs both long-term and short-term are generally with longstanding customers and suppliers of the Partnership. The Partnership's long-term contracts generally provide for monthly pricing adjustments based on prices established in the principal NGL markets. The Partnership's principal source of gas for processing is from the Transmission System. To compensate Transmission's gas sales customers for Btu reductions associated with the extraction of NGLs from Transmission System gas, the Rate Order requires Transmission to adjust the calculation of its weighted average cost of gas to reflect the Btu shrinkage associated with customer gas. The Partnership obtains additional gas supplies from specific producers connected to the Transmission System through gas processing agreements having terms that vary from a few months to several years. Substantially all of the contracts with third parties under which Hydrocarbons processes gas may be suspended from month-to-month without advance notice at the option of Hydrocarbons and are subject to termination at the option of either party after short notice periods. The profitability of individual processing arrangements is regularly monitored so that action can be taken to terminate or modify any arrangements that appear unprofitable as a result of declining market conditions.
Because of various factors affecting the market price of NGLs and natural gas, there is for each hydrocarbon component found in any gas stream a price at which it is more profitable to leave the component in the natural gas stream rather than to extract the component and sell it separately as a NGL. Such prices may vary among processing plants depending on specific contractual arrangements, plant efficiencies and other factors. For example, the Partnership has elected at certain times to reduce the production of ethane by leaving ethane in the gas stream rather than selling it as a separate product. During 1992 and 1991, the Partnership elected to maximize ethane recoveries due to favorable market conditions that prevailed during such periods. However, for certain periods during the fourth quarter of 1993 and the first quarter of 1994, the Partnership temporarily ceased the production of ethane at certain of its gas processing plants because of the depressed market price for ethane during such periods.
The Partnership's largest NGL customers include petrochemical companies and major refiners, including Energy. The Partnership's ten largest NGL customers accounted for approximately 85% of the Partnership's total 1993 NGL product sales revenues (22% of which was attributable to Energy's refining operations). The petrochemical industry is a principal market for NGLs and is expanding due to increasing market demand for ethylene-derived products. As of the end of 1993, NGLs represented about 68% of the total feedstock to the ethylene crackers in the United States. During 1994, petrochemical industry demand for NGLs is expected to continue to expand. In the Partnership's immediate marketing area, additional NGL demand in 1994 is expected to come from the Refinery's butane upgrade facility and from the proposed start-up in early 1994 of an ethylene plant on the Texas Gulf Coast expected to increase the NGL base demand by approximately 30,000 to 40,000 barrels per day by the end of 1994. In the longer term, the petrochemical industry's increased requirements for NGLs are expected to establish higher floor prices that should continue to support profitable operation of gas processing facilities. In addition, NGL demand should continue to increase as a result of existing and future facilities that consume normal butane or isobutane.
GOVERNMENTAL REGULATIONS
Certain of the Partnership's subsidiaries, including Transmission, are subject to regulations issued by the Railroad Commission under the Cox Act, the Gas Utilities Regulatory Act ("GURA") and the Natural Resources Code, all of which are Texas statutes, and the federal NGPA. In addition, certain activities of Transmission and Val Gas are subject to the regulations of the FERC under the NGPA and the Department of Energy Organization Act of 1977 (the "DOE Act"). On January 1, 1993, all gas prices were deregulated pursuant to the Natural Gas Wellhead Decontrol Act of 1989. The Partnership's activities are also subject to various federal, state and local environmental statutes and regulations. See "Environmental Matters."
Texas Regulation
The Railroad Commission regulates the intrastate transportation, sale, delivery and pricing of natural gas in Texas by intrastate pipeline and distribution systems, including those of the Partnership. Transmission and VLDC are regulated by the Railroad Commission. The authority of the Railroad Commission to regulate the Partnership's SMPs is unclear, except with respect to conservation rules. Sales under the SMPs have not been regulated by the Railroad Commission to date.
During 1992, the Railroad Commission revised its rules governing the production and purchase of natural gas. The Railroad Commission's gas proration rule (the "gas proration rule") prohibits the production of gas in excess of market demand. Under the gas proration rule, producers may not tender and deliver volumes of gas in excess of their market demand. Similarly, gas purchasers, including pipelines and purchasers offering SMPs, may not take volumes of gas in excess of their market demand. The gas proration rule further requires purchasers to take gas by priority categories, ratably among producers, without undue discrimination, and with high-priority gas having higher priority than gas well gas, notwithstanding any contractual commitments. For a discussion of the effect of the gas proration rule on the operations of Transmission, see "Natural Gas Operations - Gas Sales" above. Such revised rules are intended to simplify the previous system of nominations and to bring production allowables in line with estimated market demand.
For pipelines, the Railroad Commission approves intrastate sales and transportation rates and all proposed changes to such rates. Changes in the price of gas sold to gas distribution companies are subject to rate determination in a rate case before the Railroad Commission. Under applicable statutes and current Railroad Commission practice, larger volume industrial sales and transportation charges may be changed without a rate case if the parties to the transactions agree to the rate changes and make certain representations. Rates for Transmission's sales customers are governed by the Rate Order. See "Management's Discussion and Analysis and Results of Operations."
A new rate case may be initiated at the request of any customer or by Transmission, or by the Railroad Commission on its own initiative. No rate case involving Transmission has taken place since the date of the Rate Order. The determination of any rate change would be based on cost-of-service rate regulation principles, including a return-on-rate base calculation and the recovery of certain operating costs and depreciation. While there can be no assurance in this regard, the General Partner believes that the results of any such rate proceeding would not materially adversely affect the Partnership's financial position or results of operations. See Note 6 of Notes to Consolidated Financial Statements for a discussion of the 1993 settlement of a certain customer's audit of Transmission's weighted average cost of gas.
NGL pipeline transportation is also subject to regulation by the Railroad Commission. The Railroad Commission requires the filing of tariffs and compliance with environmental and safety standards. To date, the impact of this regulation on the Partnership's operations has not been significant. The Railroad Commission also has regulatory authority over gas processing operations, but has not exercised such authority.
Federal Regulation
The Partnership's 7,200-mile pipeline system is an intrastate business not subject to direct regulation by the FERC. Although the Partnership's interstate sales and transportation activities are subject to specific FERC regulations, these regulations do not change the Partnership's overall regulatory status. The Partnership's operations are more significantly affected by the implementation of FERC Order 636 related to restructuring of the interstate natural gas pipeline industry. Order 636 requires pipelines subject to FERC jurisdiction to provide unbundled marketing, transportation, storage and load balancing services on a nondiscriminatory basis to producers and end users instead of offering only combined packages of services. This allows companies like the Partnership to provide these component services separately from the transportation provided by the interstate pipelines. The "unbundling" of services under Order 636 allows LDCs and other customers to choose the combination of services that best meet their needs at the lowest total cost, thus increasing competition in the interstate natural gas industry. As a result of Order 636, the Partnership can more effectively compete for sales of natural gas to LDCs and other natural gas customers located outside Texas. See "Competition - Natural Gas."
In 1988, the FERC issued Order No. 497 (amended in 1989 by Order 497-A), which addresses possible abuses in relationships between interstate natural gas pipelines and their marketing or brokering affiliates. This order contains standards of conduct and reporting requirements intended to prevent preferential treatment of an affiliated marketer by an interstate pipeline in providing transportation services. The General Partner believes that Order No. 497, as amended, has assisted the Partnership in competing for developing interstate markets.
ENVIRONMENTAL MATTERS
The Partnership's operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing natural gas and other products are subject to environmental regulation by federal, state and local authorities, including the Environmental Protection Agency ("EPA"), the Texas Natural Resource Conservation Commission ("TNRCC"), the Texas General Land Office and the Railroad Commission. Compliance with regulations promulgated by these various governmental authorities increases the cost of planning, designing, initial installation and operation of the Partnership's facilities. The regulatory requirements relate to water and storm water discharges, waste management and air pollution control measures.
Although the Partnership continues to monitor its compliance with environmental regulations through audits and other procedures, the Partnership's expenditures for environmental control facilities were not material in 1993 and are not expected to be material in 1994. Currently, expenditures are made to comply with air emission regulations and solid waste management regulations applicable to various facilities.
The Partnership will continue to be subject to regulations concerning wastes and air emissions, including new federal operating permit requirements for certain air emission sources. Proposed regulations regarding enhanced monitoring and other programs for the detection of certain releases may also affect the Partnership's operations. The Partnership anticipates increased regulation of wastes by the Railroad Commission, and increased control of air toxins together with additional permitting requirements from the EPA regarding storm water discharges from industrial and construction activities. However, the General Partner does not expect these requirements to have a material adverse effect on the Partnership's financial position or results of operations.
COMPETITION
Natural Gas
Changes in the gas markets during the recent period of deregulation under FERC Order 636 have resulted in significantly increased competition. Despite the increased competition, the Partnership generally has been able to take advantage of the increased business opportunities resulting from the implementation of Order 636. Accordingly, the Partnership has not only maintained but has increased its throughput volumes. Under Order 636, the Partnership can more effectively compete for sales of natural gas to LDCs and other customers located outside Texas. See "Governmental Regulations - Federal Regulation." Contracting practices in the natural gas industry generally are moving away from the spot, interruptible type of sales prevalent in recent years, and toward "firm" and term contracts that require gas suppliers to commit to specified deliveries of gas without the option of interrupting service and penalize gas suppliers for failure to perform in accordance with their contractual commitments. Because of Order 636, the Partnership now can guarantee long-term supplies of natural gas to be delivered to buyers at interstate locations. The Partnership can charge a fee for this guarantee, which together with transportation charges, can exceed the amount that the Partnership could receive for merely transporting natural gas. The Partnership has enjoyed recent success in entering into such contracts. See "Natural Gas Operations - Gas Sales - Interstate Sales." Because of the location of the Transmission System, the General Partner believes that the Partnership is able to compete for new gas supplies and new gas sales and transportation customers. The financial strength of potential suppliers will be an important consideration to LDCs and other customers when contracting for firm supplies of natural gas. Accordingly, the General Partner believes that substantial amounts of working capital and capital expenditures for gas inventories, storage, pipeline connections and financial hedging products (e.g., futures contracts) will be required to compete effectively for additional business under Order 636. See "Properties."
The General Partner believes that the natural gas and NGL industries are undergoing a period of reorganization and consolidation as major energy companies divest operations that are not part of their core operations and smaller entities combine to compete more effectively in the present natural gas environment. Through ongoing reorganizations and consolidations in the industry, certain assets may become available for acquisition by the Partnership including natural gas and NGL pipelines, gathering facilities, processing plants and NGL fractionation facilities. The General Partner believes that certain trends in the natural gas industry will create additional business opportunities and require additional capital expenditures for companies that wish to compete effectively in interstate natural gas markets. These trends include an emerging west-to-east movement of natural gas across the United States, the increasing importance of South Texas as a major natural gas supply area and opportunities created by Order 636.
Many of the market areas served by the Partnership's gas systems are also served by pipelines of other companies; however, the location of the Partnership's facilities in major producing and marketing areas is believed to provide a competitive advantage. Although gas competes with other fuels, gas to gas competition continues to set pricing levels. The Partnership does not anticipate that fuel oil pricing will reach parity with spot natural gas prices in the foreseeable future, rendering unlikely any significant switch to fuel oil or other alternate fuels by the Partnership's intrastate customers. Significant decreases in the price of fuel oil historically have led to some switching of load in the interstate market, although the impact on the Partnership has been indirect and immaterial. The Partnership's electric power generation and industrial customers have the ability to substitute alternate fuels for a portion of their current natural gas deliveries. This capability is generally reserved for periods of natural gas curtailment, as the continued disparity in price and the added cost of delivery, storage and handling of alternate fuels limit their long-term use. Demand for natural gas continues to be affected by the operation of various nuclear and coal power plants in the Partnership's service area. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
In recent years, certain intrastate pipelines with which the Partnership had traditionally competed have acquired or have been acquired by interstate pipelines. These combined entities generally have capital resources substantially greater than those of the Partnership and, notwithstanding Order 636's "open access" regulations, may realize economies of scale and other economic advantages in acquiring, selling and transporting natural gas. The acquisition of gas supply is capital intensive, as it frequently requires installation of new gathering lines to reach sources of gas. Additionally, the combination of intrastate and interstate pipelines within one organization may in some instances enable competitors to lower gas prices and transportation fees, and thereby increase price competition in the Partnership's intrastate and interstate markets.
The U.S.-Canada free trade agreement and changes in Canadian export regulations have increased Canadian natural gas imports into the United States. Under the recently adopted North American Free Trade Agreement, Canadian natural gas imports into the United States are expected to continue. Canadian imports have increased competition in the interstate markets in which the Partnership competes for natural gas sales and have affected natural gas availability and prices in the Texas intrastate market. As a result, competition in the natural gas industry is expected to remain intense.
Natural Gas Liquids
The consumption of NGLs marketed in the United States is divided among four distinct markets. NGLs are primarily consumed in the production of petrochemicals (mainly ethylene), followed by motor gasoline production, residential and commercial heating, and agricultural uses. Other hydrocarbon alternatives, primarily refinery-based products, are available for each NGL for most end uses. For some end uses, including residential and commercial heating, a conversion from NGLs to other natural hydrocarbon products requires significant expense or delay, but for others, such as ethylene and industrial fuel uses, a conversion from NGLs to other natural hydrocarbon products could be made without significant delay or expense.
Because certain NGLs are used in the production of motor gasoline and compete directly with other refined products in the fuel and petrochemical feedstock markets, NGL prices are set by or compete with petroleum-derived products. Consequently, changes in crude and refined product prices cause NGL prices to change as well. See "Recent Developments - Decline of Crude Oil and NGL Prices." The economics of natural gas processing depends principally on the relationship between natural gas costs and NGL prices. When this relationship has been favorable, the NGL processing business has been highly competitive. The General Partner believes that competitive barriers to entering the business are generally low. Moreover, improvements in NGL-recovery technology have improved the economics of NGL processing and have increased the attractiveness of many processing opportunities. In recent years, NGL margins have been subject to the extreme volatility of energy prices in general. The General Partner believes that the level of competition in NGL processing has increased over the past year and generally will become more competitive in the longer term as the demand for NGLs increases.
EMPLOYEES
The Partnership has no employees of its own.
ITEM 2.
ITEM 2. PROPERTIES
The Partnership owns natural gas pipeline systems and natural gas liquids facilities, processing plants, compressor stations, treating plants, measuring and regulating stations, fractionation facilities, warehouses and offices, all of which are located in Texas. The Partnership has pledged substantially all of its gas systems and processing facilities, except for certain natural gas pipeline, natural gas processing, NGL fractionation and NGL pipeline assets leased from Energy, as collateral for its First Mortgage Notes. The Partnership is a lessee under a number of cancelable and noncancelable leases for certain real properties. See Notes 3 and 5 of Notes to Consolidated Financial Statements. Reference is made to "Item 1. Business," which includes detailed information regarding the properties of the Partnership.
The General Partner believes that the Partnership's properties and facilities are generally adequate for their respective operations, and that the facilities of the Partnership are maintained in a good state of repair. However, the General Partner believes that the Partnership must continue to make substantial capital investments in facilities that will enable the Partnership to access gas supplies and markets and expand its NGL processing and transportation capabilities so that the Partnership may compete effectively in the current natural gas industry environment. The General Partner believes that the Partnership's lack of financial flexibility may impair its ability to make capital expenditures that will enable the Partnership to improve and expand its operations or to take full advantage of the opportunities that may arise in the natural gas and NGL businesses over the next several years. See "Governmental Regulations - Federal Regulation", "Competition - Natural Gas" and "Management's Discussion and Analysis of Financial Condition and Results of Operations."
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Partnership is involved in the following proceedings:
Coastal Oil and Gas Corporation v. TransAmerican Natural Gas Corporation ("TANG"), 49th State District Court, Webb County, Texas (filed October 30, 1991). In March 1993, Valero Transmission Company and Valero Industrial Gas Company were served as third party defendants in this lawsuit. In August 1993, Energy, VNGP, L.P., and certain of their subsidiaries were named as additional third-party defendants (collectively, including the original defendant subsidiaries, the "Valero Defendants"). In TANG's counterclaims against Coastal and third-party claims against the Valero Defendants, TANG alleges that it contracted to sell natural gas to Coastal at the posted field price of Valero Industrial Gas Company and that the Valero Defendants and Coastal conspired to set such price at an artificially low level. TANG also alleges that the Valero Defendants and Coastal conspired to cause TANG to deliver unprocessed or "wet" gas thus precluding TANG from extracting NGLs from its gas prior to delivery. TANG seeks actual damages of approximately $50 million, trebling of damages under antitrust claims, punitive damages of $300 million, and attorneys' fees. In the event of an adverse determination involving Energy, Energy likely would seek indemnification from the Partnership under terms of the partnership agreements and other applicable agreements between VNGP, L.P., its subsidiary partnerships and their respective general partners. The Valero Defendant's motion for summary judgment on TANG's antitrust claims was argued on January 24, 1994. The court has not ruled on such motion. The current trial setting for this case is March 14, 1994.
Toni Denman v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 15, 1993); Howard J. Vogel v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 15, 1993); 7547 Partners v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 19, 1993); Robert Endler Trust v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed October 27, 1993); Dorothy Real v. Valero Energy Corporation, Valero Natural Gas Company and Valero Natural Gas Partners, L.P., (filed November 4, 1993); Malcolm Rosenwald v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed November 9, 1993); Norman Batwin v. Valero Natural Gas Partners, L.P., Valero Natural Gas Company, Valero Energy Corporation, et al., (filed November 15, 1993) Court of Chancery, New Castle County, Delaware. Each of the foregoing suits was filed in response to the announcement by Energy on October 14, 1993, of Energy's proposal to acquire the publicly traded Common Units of VNGP, L.P. pursuant to a proposed merger of VNGP, L.P. with a wholly owned subsidiary of Energy. The suits were consolidated by the Court of Chancery on November 23, 1993. The plaintiffs sought to enjoin or rescind the proposed merger, alleging that the corporate defendants and the individual defendants, as officers or directors of the corporate defendants, have engaged in actions in breach of the defendants' fiduciary duties to the holders of the Common Units by proposing the merger. The plaintiffs alternatively sought an increase in the proposed merger consideration, compensatory damages and attorneys' fees. In December 1993, the parties reached a tentative settlement of the consolidated lawsuit. The terms of the settlement will not require a material payment by Energy or the Partnership.
The Long Trusts v. Tejas Gas Corporation, 123rd Judicial District Court, Panola County, Texas (filed March 1, 1989). Valero Transmission Company ("VTC"), as buyer, and Tejas Gas Corporation ("Tejas"), as seller, are parties to various gas purchase contracts assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. Tejas is also a party to a series of gas purchase contracts between Tejas, as buyer, and certain trusts ("The Long Trusts"), as seller, which are in litigation ("The Long Trusts Litigation"). Neither the Partnership nor VTC is a party to The Long Trusts Litigation or the Tejas/Long Trusts contracts. However, because of the relationship between the Transmission/Tejas contracts and the Tejas/Long Trusts contracts, and in order to resolve existing and potential disputes, Tejas, VTC and Valero Transmission, L.P. have agreed that Tejas, VTC and Valero Transmission, L.P. will cooperate in the conduct of The Long Trusts Litigation, and that VTC and Valero Transmission, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against Tejas. In The Long Trusts Litigation, The Long Trusts allege that Tejas has breached various minimum take, take-or-pay and other contractual provisions of the Tejas/Long Trusts contracts, and assert a statutory non-ratability claim. The Long Trusts seek alleged actual damages including interest of approximately $30 million and an unspecified amount of punitive damages. The District Court ruled on the plaintiff's motion for summary judgment, finding that as a matter of law the three gas purchase contracts at issue were fully binding and enforceable, that Tejas breached the minimum take obligations under one of the contracts, that Tejas is not entitled to claimed offsets for gas purchased by third parties and that the "availability" of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, have not been determined. Because of existing contractual obligations of Valero Transmission, L.P. to Tejas, the lawsuit may ultimately involve a contingent liability for Valero Transmission, L.P. The court recently granted Tejas's motion for continuance in connection with the former January 10, 1994 trial setting. The Long Trusts Litigation is not currently set for trial.
NationsBank of Texas, N.A., Trustee of The Charles Gilpin Hunter Trust, et al. v. Coastal Oil & Gas Corporation, Valero Transmission Company, et al., 160th State District Court, Dallas County, Texas (filed February 2, 1993) (formerly reported as "Williamson, et al. v. Coastal Oil & Gas Corporation, Valero Transmission Company, et al., 68th State District Court, Dallas County, Texas (filed June 30, 1988)" in the Partnership's Form 10-K for the fiscal year ended December 31, 1992). In a lawsuit filed in 1988, plaintiffs alleged that defendants Coastal Oil & Gas Corporation ("Coastal") and Energy, VTC, VNGP, L.P., the Management Partnership and Valero Transmission, L.P. (the "Valero Defendants") were liable for failure to take minimum quantities of gas, failure to make take-or-pay payments and other breach of contract and breach of fiduciary duty claims. Plaintiffs sought declaratory relief, actual damages in excess of $37 million and unquantified punitive damages. The lawsuit was settled on terms immaterial to the Valero Defendants, and the parties agreed to dismissal of the lawsuit. On November 16, 1992, prior to entry of an order of dismissal, NationsBank of Texas, N.A., as trustee for certain trusts (the "Intervenors"), filed a plea in intervention to intervene in the lawsuit. The Intervenors asserted that they held a non-participating mineral interest in the lands subject to the litigation and that their rights were not protected by the plaintiffs in the settlement. On February 4, 1993, the Court struck the Intervenors' plea in intervention. However, on February 2, 1993, the Intervenors had filed a separate suit in the 160th State District Court, Dallas County, Texas, against all prior defendants and an additional defendant, substantially adopting the allegations and claims of the original litigation. In February 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
Valero Transmission, L.P. v. J. L. Davis, et al., 81st District Court, Frio County, Texas (filed September 20, 1991). This lawsuit was commenced by Transmission as a suit for breach of contract against defendant. On January 11, 1993, defendant filed a cross action against Valero Transmission, L.P., Valero Industrial Gas, L.P., and Reata Industrial Gas, L.P., asserting claims for actual damages for failure to pay for goods and services delivered and various other cross-claims. In January 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
City of Houston Claim. In a letter dated September 1, 1993 from the City of Houston (the "City") to Valero Transmission Company ("VTC"), the City stated its intent to bring suit against VTC for certain claims asserted by the City under the franchise agreement between the City and VTC. VTC is the general partner of Valero Transmission, L.P. The franchise agreement was assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. In the letter, the City declared a conditional forfeiture of the franchise rights based on the City's claims. In a letter dated October 27, 1993, the City claims that VTC owes to the City franchise fees and accrued interest thereon aggregating approximately $13.5 million. In a letter dated November 9, 1993, the City claimed an additional $18 million in damages related to the City's allegations that VTC engaged in unauthorized activities under the franchise agreement by transmitting gas for resale and by transporting gas for third parties on the franchised premises. Any liability of VTC with respect to the City's claims has been assumed by the Partnership. The City has not filed a lawsuit.
Take-or-Pay and Related Claims. As a result of past market conditions and prior contracting practices in the natural gas industry, numerous producers and other suppliers brought claims against Valero Transmission, L.P. ("Transmission") asserting that it was in breach of contractual provisions requiring that it take, or pay for if not taken, certain specified volumes of natural gas. The Partnership has settled substantially all of the significant take-or-pay claims, pricing differences and contractual disputes heretofore brought against it. In 1987, Transmission and a producer from whom Transmission has purchased natural gas entered into an agreement resolving certain take-or-pay issues between the parties in which Transmission agreed to pay one-half of certain excess royalty claims arising after the date of the agreement. The royalty owners of the producer recently completed an audit of the producer and have presented to the producer claims for additional royalty payments in the amount of approximately $17.3 million, and accrued interest thereon of approximately $19.8 million. Approximately $8 million of the royalty owners' claim accrued after the effective date of the agreement between the producer and Transmission. The producer and Transmission are reviewing the royalty owners' claims. No lawsuit has been filed by the royalty owners. The General Partner believes that various defenses under the agreement may reduce any liability of Transmission to the producer in this matter.
Although additional claims may arise under older contracts until their expiration or renegotiation, the General Partner believes that the Partnership has resolved substantially all of the significant take-or-pay claims that are likely to be made. Although the General Partner is currently unable to predict the amount Transmission or the Partnership ultimately may be required to pay in connection with the resolution of existing and potential take-or-pay claims, the General Partner believes any remaining claims can be resolved on terms satisfactory to the Partnership and that the resolution of such claims and any potential claims has not had and will not have a material adverse effect on the Partnership's financial position or results of operations. Any liability of Energy with respect to take-or-pay claims involving Transmission's intrastate pipeline operations has been assumed by the Partnership.
Conclusion. The Partnership is also a party to additional claims and legal proceedings arising in the ordinary course of business. The General Partner believes it is unlikely that the final outcome of any of the claims or proceedings to which the Partnership is a party including those listed above would have a material adverse effect on the Partnership's financial position or results of operations; however, due to the inherent uncertainties of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Partnership's results of operations for the fiscal period in which such resolution occurred.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the fourth quarter of 1993.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON UNITS AND RELATED SECURITY HOLDER MATTERS
The Partnership's Common Units are listed on the New York Stock Exchange, which is the principal trading market for these securities. At February 14, 1994, there were 2,361 holders of record and an estimated 15,000 beneficial owners of the Common Units.
The range of the high and low sales prices of the Common Units, as quoted in the New York Stock Exchange - Composite Transactions listing in The Wall Street Journal, and the amount of distributions per Common Unit declared for each quarter in the preceding two years, are set forth in the table below:
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year ended December 31, 1993 is derived from the Partnership's Consolidated Financial Statements contained elsewhere herein. The selected financial data for the years ended prior to December 31, 1993 is derived from the selected financial data contained in the Partnership's Annual Report on Form 10-K for the year ended December 31, 1992.
The following summaries are in thousands of dollars except for per Unit amounts:
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PROPOSED MERGER WITH ENERGY
As fully described in Item 1 - "Business-Recent Developments," in October 1993, Energy publicly announced its proposal to acquire the issued and outstanding Common Units in VNGP, L.P. held by the Public Unitholders and effective December 20, 1993, Energy, VNGP, L.P. and VNGC entered into the Merger Agreement providing for the merger of VNGP, L.P. with a wholly owned subsidiary of Energy subject to various conditions. The General Partner has approved the merger because it believes that the Partnership, in its present form, has insufficient financial flexibility to participate fully in opportunities that are expected to arise in the natural gas and NGL businesses, that the ability of the Partnership to compete effectively in these businesses will be enhanced through the merger and that the Partnership could lose its competitive position if it does not pursue such opportunities when and if they become available. The General Partner also believes that conflicts of interest between the Partnership and Energy can be eliminated and that administrative efficiencies can be realized through the merger. See "Results of Operations" and "Liquidity and Capital Resources" below.
On January 25, 1994, the VNGC Board of Directors declared a cash distribution of $.125 per Common Unit for the fourth quarter of 1993 that is payable March 1, 1994 to holders of record as of February 7, 1994. If the merger occurs after March 9, 1994, the General Partner intends and expects to declare and pay a pro rata distribution to holders of record of the Common Units on the effective date of the merger based upon the number of days elapsed between February 7, 1994 and such effective date.
RESULTS OF OPERATIONS
The following are the Partnership's financial and operating highlights for each of the three years in the period ended December 31, 1993 (in thousands of dollars, except as otherwise noted).
General
The Partnership's net income for 1993 decreased $10.5 million, or 42%, compared to 1992 due primarily to a $10.4 million, or 12% decrease in operating income. In the fourth quarter of 1993, a $4.5 million decrease in operating income resulted in a net loss of $2.1 million compared to net income of $2.3 million in the fourth quarter of 1992. Increased operating income from the Partnership's natural gas operations was more than offset by decreased operating income from the Partnership's natural gas liquids ("NGL") operations for both the annual and quarterly periods, as explained below.
The Partnership's natural gas operating results improved in 1993 due to, among other things, improvement in market fundamentals as natural gas supply and demand have become more balanced, and increased business opportunities resulting from the implementation of Federal Energy Regulatory Commission ("FERC") Order No. 636 ("Order 636"). Order 636 requires, among other things, that pipelines subject to FERC jurisdiction provide "unbundled" transportation, storage and load balancing services on a nondiscriminatory basis to producers and end users instead of offering only combined packages of services. This change has resulted in increased competition in the natural gas industry. Although no Subsidiary Operating Partnership is directly subject to Order 636, it has created new interstate supply, marketing and transportation opportunities for the Partnership. However, the General Partner believes that substantial amounts of working capital and capital expenditures for gas inventories, storage facilities, pipeline connections and related facilities, and for financial hedging products, such as gas futures contracts, will be required to compete effectively for additional business under Order 636. See "Governmental Regulations-Federal Regulation" and "Competition-Natural Gas" under Item 1 - "Business" for additional information regarding Order 636 and its effect on the Partnership's business.
In addition to the opportunities and challenges created by Order 636, the Partnership's natural gas operations have also been affected by an emerging trend of west-to-east movement of gas across the United States resulting from growing productive capacity in western supply basins, the completion of new pipeline capacity from such basins to the U.S. West Coast and increasing demand for power generation in the East or Southeast. The General Partner believes that this west-to-east shift in natural gas supply patterns is well underway, and that in many of the pipelines able to serve this market, including pipelines operated by the Partnership, west-to-east capacity is becoming constrained. The General Partner believes that, over time, these capacity constraints may warrant additional west-to-east capacity additions and that the Partnership would be positioned to participate in such opportunities. Because natural gas is a clean burning fuel, environmental concerns are expected to increase long-term demand for natural gas which should benefit the Partnership's natural gas throughput volumes.
The Partnership benefitted in 1993 from an increase in demand for natural gas resulting from the shutdown of both units of the South Texas Project nuclear plant ("STP") in Bay City, Texas during most of 1993 due to operational problems. At full operation, the STP displaces approximately 650 MMcf per day of natural gas demand. The Partnership currently expects that the STP will resume full operations in the second quarter of 1994, displacing a portion of the Partnership's gas sales volumes and reducing Partnership operating income. Demand for natural gas in the Partnership's core service area is also expected to be affected by the continued operation of other nuclear and coal- fired power plants. The first and second units of the Comanche Peak nuclear plant near Ft. Worth, Texas, both 1,150 megawatt ("MW") units, commenced operations in 1991 and 1993, respectively, and combine to displace approximately 600 MMcf per day of gas demand. In addition, San Antonio City Public Service, the Partnership's largest gas sales customer, commenced commercial operations in 1992 of a 500 MW coal-fired electrical generation facility which displaces a portion of the Partnership's gas sales volumes.
The Partnership's gas sales are made by (i) the Partnership's special marketing programs ("SMPs") and certain other subsidiary operating partnerships which are not SMPs and (ii) Valero Transmission, L.P. ("Transmission"). Gas transportation is conducted primarily by Transmission. Gas sales and transportation volumes (in MMcf per day), average gas sales prices and average gas transportation fees for the years ended December 31, 1993, 1992 and 1991 were as follows:
The Partnership's SMPs and other gas sales and transportation business are based primarily on competitive market conditions and contracts negotiated with individual customers. The Partnership has been able to mitigate, to some extent, the effect of competitive industry conditions by the flexible use of its strategically located pipeline system and its aggressive marketing efforts. Sales volumes in the SMPs and other's intrastate and interstate markets and total transportation volumes increased in 1993 compared to 1992 due to, among other things, aggressive efforts to generate business related to the implementation of FERC Order 636 and the west-to-east shift in natural gas supply patterns, and the shutdown of the STP during most of 1993. In 1992, the Partnership established a Market Center Services Program to provide price risk management services to gas producers and end users through the use of forward contracts and other tools which have traditionally been used in financial risk management. The General Partner believes that the "value-added" services provided through this program allow the Partnership to effectively compete in the post-Order 636 environment. The Partnership also utilizes such price risk management techniques to manage the cost of gas consumed in its NGL operations, and manage price risk associated with its natural gas storage and marketing activities. In 1993 and 1992, the Partnership recognized $18.7 million and $12.9 million, respectively, in gas cost reductions and other benefits from this program. An additional $5.1 million and $3.6 million in other reductions of cost of gas was generated by transactions entered into in 1993 and 1992, respectively, which is recognized in income in the subsequent year as the related gas is sold. The Market Center Services Program benefitted in 1993 and 1992 from the volatility of natural gas prices and the Partnership's successful anticipation of price movements. Increased stability in natural gas prices, however, could reduce the benefits generated by this program in 1994.
Transmission's sales are made to intrastate customers under contracts which originated in the 1960s and 1970s with 20- to 30-year terms. These contracts were full requirements, no- notice service contracts governed by a rate order (the "Rate Order") issued in 1979 by the Railroad Commission of Texas (the "Railroad Commission"). The Rate Order provides for Transmission to sell gas at its weighted average cost of gas, as defined ("WACOG"), plus a margin of $.15 per Mcf. In addition to the cost of gas purchases, Transmission's WACOG has included storage, gathering and other fixed costs totalling approximately $19 million per year (see customer audit settlement agreement discussed below for adjustments to such amount), and amortization of deferred gas costs related to the settlement of take-or-pay and related claims (see Note 1 - "Other Assets" and Note 6 of Notes to Consolidated Financial Statements). Transmission's gas purchases include high-cost casinghead gas and certain special allowable gas that Transmission is required to purchase contractually and under the Railroad Commission's priority rules. Transmission's sales volumes have been decreasing with the expiration of its sales contracts. As a result of these factors, Transmission's WACOG and gas sales price are substantially in excess of market clearing levels, as shown in the table above. In July 1992, a contract representing approximately 37% of Transmission's sales volumes for the first six months of 1992 expired by its own terms, reducing Transmission's and the Partnership's cash flow and income in 1992 and 1993.
Transmission's WACOG has been periodically audited by certain of its customers, as allowed under the Rate Order. One such customer (the "Customer") questioned the application of certain of Transmission's current rate policies to future periods in light of the decreases that have occurred in Transmission's throughput, and the Customer has recently completed its audit of Transmission's WACOG with respect thereto. For 1993, the Customer represented approximately 70% of Transmission's sales volumes and such percentage is expected to increase as other sales contracts expire and are not renewed. As a result of the Customer's audit, Transmission and the Customer entered into a settlement agreement which excludes certain of the fixed costs described above from Transmission's WACOG, effective with July 1993 sales, resulting in a reduction of the Partnership's annual net income by approximately $6 million. Upon the termination of Transmission's gas sales contract with the Customer in 1998, Transmission's fixed costs, including storage (see Note 5 of Notes to Consolidated Financial Statements), would be charged to income instead of recovered through its gas sales rates. Transmission expects to recover its deferred gas costs over a period of approximately eight years. The recovery of any additional payments made in connection with any future settlements would be limited.
In the course of making gas sales and providing transportation services to customers, Transmission experiences measurement and other volumetric differences related to the amounts of gas received and delivered. Transmission has in the past experienced overall net volume gains due to such differences and its Rate Order allows such volumes to be sold to its customers. Transmission historically has derived a substantial benefit from such sales. The amount included in operating income in 1993 was substantially the same as in 1992. However, the implementation of more precise gas measurement equipment and standards and the reduction in Transmission's total sales volumes, discussed above, is expected to reduce operating income from such sales in future periods.
The profitability of the Partnership's NGL operations depends principally on the margin between NGL sales prices and the cost of the natural gas from which such liquids are extracted ("shrinkage cost"). The Partnership's natural gas liquids operations were adversely affected in 1993 by a decrease in NGL market prices, particularly in the fourth quarter. Beginning in late November 1993, crude oil prices fell significantly resulting from a decision by the Organization of Petroleum Exporting Countries ("OPEC") at its November 23, 1993 meeting not to curtail members' production of crude oil, together with weak worldwide demand for crude oil, increasing production from non- OPEC areas and continuing discussions regarding the possibility of Iraq's re-entry into the world oil markets. In conjunction with the crude oil price decline, refined product and NGL prices also fell significantly. Strong natural gas prices throughout 1993 increased shrinkage costs, also adversely affecting NGL margins and operating results. Partially offsetting the effects of reduced NGL prices and high shrinkage costs in 1993 were higher production levels from the Partnership's owned and leased gas processing plants. The Partnership's processing capacity and production volumes increased in 1993 compared to 1992 due to a full year's production from various 1992 facility expansions and improvements, and various 1993 upgrades at certain processing plants. See Note 5 of Notes to Consolidated Financial Statements for a description of the Thompsonville gas processing plant leased by the Partnership from Energy effective December 1, 1992. The Partnership'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 methyl tertiary butyl ether ("MTBE"). MTBE is an oxygenate produced from butane feedstocks which can be used as a component of "reformulated" gasoline mandated by the Clean Air Act Amendments of 1990 (the "Clean Air Act"). The demand for NGLs, particularly natural gasoline, will continue to be affected seasonally, however, by Federal Environmental Protection Agency ("EPA") regulations limiting gasoline volatility during the summer months.
The Partnership's NGL operations benefit from the efficiency of its operations and 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 Partnership's natural gas and NGL operations. Approximately 80% of the Partnership's NGL production comes from plants in South Texas and the Texas Gulf Coast. However, as the Partnership's existing South Texas NGL pipeline and fractionation facilities are operating at or near capacity, the Partnership anticipates incurring either increased third-party transportation and fractionation fees or substantial capital expenditures in the future in order to develop incremental South Texas NGL production opportunities.
During the first quarter of 1994, NGL prices have increased modestly since late December 1993, but remain below first quarter 1993 levels. Concurrently, natural gas prices and resulting shrinkage costs have increased during the first quarter of 1994 compared to the same period in 1993. As a result, Partnership operating income is expected to be substantially lower in the first quarter of 1994 compared to the first quarter of 1993.
The General Partner believes that the natural gas and NGL industries are undergoing a period of consolidation and restructuring that may create opportunities to enhance the Partnership's operating results through acquisitions, strategic business alliances and the various natural gas and NGL business opportunities described above. However, the General Partner also believes that the Partnership will be unable to maintain its competitive position, resulting in adverse operating results, if it does not pursue such opportunities when and if they arise, and that currently, the Partnership does not have the financial flexibility to make the capital expenditures necessary to successfully pursue such opportunities. See "Liquidity and Capital Resources" for a discussion of current limitations on the Partnership's ability to make capital expenditures and incur additional financing and reasons why the General Partner believes that the proposed merger with Energy would, among other things, provide the financial flexibility necessary for the Partnership to pursue opportunities in the natural gas and NGL businesses that would otherwise be unavailable to it.
1993 Compared to 1992
Natural Gas
Operating revenues from the Partnership's natural gas operations increased $157.3 million, or 21%, during 1993 compared to 1992 due primarily to a 10% increase in daily natural gas sales volumes, an 11% increase in average natural gas sales prices and a 12% increase in transportation revenues. These increases were due to continued strong demand for natural gas resulting from tightening natural gas supplies, industry-wide replenishment of natural gas storage inventories and the shutdown of both units of the STP. For the fourth quarter of 1993, natural gas operating revenues increased $16.5 million, or 8%, compared to the same period in 1992 due primarily to a 19% increase in daily natural gas sales volumes, partially offset by a 9% decrease in average natural gas sales prices. Daily natural gas sales volumes increased due to the factors noted above, while gas sales prices decreased due primarily to a return of natural gas storage inventories to more normal levels in the 1993 fourth quarter compared to below normal levels in the 1992 period.
The above noted increase in transportation revenues for 1993 compared to 1992 was due to a 20% increase in daily transportation volumes which more than offset the effect of an 8% decrease in average transportation fees. The increase in daily transportation volumes resulted from the continued shutdown of the STP, increased west-to-east movement of gas across Texas, increased gas shrinkage volumes transported for the Partnership's NGL operations and increased volumes transported under settlements of take-or-pay and other claims at discounted rates. See Note 6 of Notes to Consolidated Financial Statements. Average transportation fees were adversely affected by intense industry competition and the increase in discounted transportation volumes noted above. In the fourth quarter of 1993, the effect on transportation revenues of a 4% increase in daily transportation volumes was substantially offset by a 3% decrease in average transportation fees compared to the fourth quarter of 1992.
Operating income from the Partnership's natural gas operations increased $21 million, or 65%, for 1993 compared to 1992 due to the increase in sales volumes and transportation revenues noted above, certain favorable measurement, fuel usage and customer billing adjustments and the increase in income generated by the Partnership's Market Center Services Program discussed above under "General." Partially offsetting these increases in natural gas operating income was a decrease in the recovery of Transmission's fixed costs resulting from the customer audit settlement also discussed above under "General." For the fourth quarter of 1993, natural gas operating income increased $9.8 million to $15.8 million compared to $6 million in the fourth quarter of 1992 due to the factors noted above.
Natural Gas Liquids
Operating revenues from the Partnership's NGL operations decreased $24.3 million, or 5%, in 1993 compared to 1992 due primarily to a decrease in average NGL market prices in the last six months of 1993 compared to the same period in 1992 resulting from the significant decline in refined product prices discussed above under "General" and continuing high levels of NGL inventories. NGL sales volumes for 1993 were flat compared to 1992 as a 19% increase in daily production volumes resulting from various 1992 facility expansions and improvements was offset by a 27% decrease in trading volumes.
Operating income from the Partnership's NGL operations decreased $31.3 million, or 55%, in 1993 compared to 1992 due to the sharp decline in NGL prices noted above and an increase in fuel and shrinkage costs resulting from a 22% increase in the cost of natural gas. The decline in NGL prices resulted in a $1.4 million operating loss from NGL operations for the fourth quarter of 1993 compared to operating income of $12.9 million for the fourth quarter of 1992. Also adversely affecting fourth quarter 1993 operating results compared to 1992 was a 4% decrease in NGL sales volumes and an increase in depreciation expense resulting from the recognition in the 1992 period of a change in the estimated useful lives of the majority of the Partnership's NGL facilities from 14 to 20 years retroactive to January 1, 1992.
1992 Compared To 1991
Natural Gas
Operating revenues from the Partnership's natural gas operations decreased $21.2 million, or 3%, during 1992 compared to 1991 due primarily to a decrease in natural gas sales revenues resulting from a 12% decrease in daily natural gas sales volumes, partially offset by a 10% increase in average natural gas sales prices. The increase in average gas sales prices was due to lower-than-normal inventories of natural gas in storage and a reduction in natural gas production resulting from the effects of Hurricane Andrew in the 1992 third quarter.
Transportation revenues were flat in 1992 compared to 1991 as a 15% increase in daily transportation volumes was largely offset by a 13% decrease in average transportation fees. Transportation volumes increased due to the commencement of operations of a pipeline crossing into Mexico in the third quarter of 1992, increased business generated through the East Texas pipeline leased from Energy and an increase in gas shrinkage volumes transported for the Partnership's NGL operations. Average transportation fees decreased due to market pressures and because of the expiration on September 30, 1991 of a transportation contract that provided for a quarterly reservation fee.
Operating income from the Partnership's natural gas operations decreased $4.6 million, or 12%, during 1992 compared to 1991 due to the factors discussed above and higher pipeline transportation expense related to higher total gas throughput volumes. Operating income for 1992 was also reduced by a fourth quarter charge of $3.0 million to natural gas operations representing its allocable portion of the cost of a voluntary early retirement program implemented by Energy during the last quarter of 1992.
Natural Gas Liquids
Operating revenues from the Partnership's NGL operations increased $75.3 million, or 19%, during 1992 compared to 1991 due to a 24% increase in daily NGL sales volumes as well as increased fees and revenues from processing, transporting and fractionating volumes for third parties. The increase in NGL sales volumes was due to a 13% increase in daily production volumes resulting from facility expansions and increased sales volumes related to the Partnership's NGL trading activities. The increase in operating revenues as a result of the above factors was partially offset by a 4% decrease in the average NGL market price resulting from lower refined product prices in the fourth quarter of 1992.
Operating income from the Partnership's NGL operations decreased $5.4 million, or 9%, during 1992 compared to 1991 due to a decrease in the average NGL market price, higher shrinkage costs and higher operating expenses due primarily to a $1.4 million charge to NGL operations for its allocable portion of the cost of Energy's early retirement program described above. The decrease in operating income as a result of these factors was partially offset by an increase in production, transportation and fractionation volumes and a $5.6 million decrease in depreciation expense resulting from the above noted increase in the estimated useful lives of the majority of the Partnership's NGL facilities from 14 to 20 years effective January 1, 1992.
Other
Other income, net, decreased $3.4 million during 1992 compared to 1991 due primarily to a decrease in interest earned on temporary cash investments resulting from lower balances of cash available for investment and lower interest rates. Interest and debt expense decreased in 1992 compared to 1991 due primarily to a decrease in the balance of First Mortgage Notes outstanding, a decrease in interest cost associated with the East Texas pipeline capital lease obligation to Energy resulting from the settlement of certain litigation and increased capitalized interest resulting from an increase in Partnership capital expenditures. These decreases were partially offset by an increase in interest cost associated with the fractionation facility and Thompsonville Project capital lease obligations to Energy.
LIQUIDITY AND CAPITAL RESOURCES
The Partnership in the past has generated cash through a combination of sources to meet its debt service requirements, make capital expenditures, pay cash distributions to partners and finance settlements of take-or-pay and related claims. These sources have included cash flow from operations, the issuance of additional First Mortgage Notes, financial support from Energy through capital lease financing and other transactions, reductions in working capital requirements, and asset sales.
In 1993, the Partnership's operating cash flow was reduced by depressed NGL product prices, higher natural gas shrinkage costs, continued intense competition in the natural gas industry and the reduction of Transmission's sales volumes. See "Results of Operations" above. These conditions are expected to continue into 1994 resulting in a reduction of the Partnership's cash flows from operations.
The Partnership, through the Management Partnership, issued $550 million principal amount of First Mortgage Notes in 1987 and an additional $75 million of First Mortgage Notes in 1988. However, under the terms of the Mortgage Indenture, the Management Partnership and the Subsidiary Operating Partnerships, the principal operating and asset ownership subsidiaries of the Partnership, are not permitted to issue any additional long-term debt without the issuance of additional partners' equity. The General Partner does not anticipate any such issuance as it believes that the partnership form of business organization does not allow for the raising of significant additional equity capital, and that issuance of any additional equity securities, if feasible, would likely have a negative impact on the existing holders of Common Units. Debt service on the First Mortgage Notes, including payments into escrow for both principal and interest, was $81 million, $80.6 million and $79.2 million for 1993, 1992 and 1991, respectively, and will be $81 million, $80.9 million, $80.4 million, $79.6 million and $75.9 million for the years 1994 through 1998, respectively. See Note 3 of Notes to Consolidated Financial Statements.
Commencing in 1991, the Partnership entered into a series of leasing transactions with Energy to provide financial support for certain Partnership capital expenditure projects that were approved by the Board of Directors of the General Partner. These projects, which had a total cost of approximately $101 million, consisted of the East Texas Pipeline Extension, the Fractionator Expansion Project and the Thompsonville Project and are being leased by Energy to the Partnership under capital leases. See Note 5 of Notes to Consolidated Financial Statements for additional information with regard to these leases and a schedule of minimum lease payments. The leasing transactions between the Partnership and Energy have enabled the Partnership to engage in capital expansions and business opportunities that would otherwise have been unavailable to it. However, the rate of return available to Energy from such transactions is limited to the lease payments specified in the lease and any related tax benefits. Additionally, in 1991, a Unitholder commenced a class action and derivative lawsuit against the General Partner, Energy and certain of their respective officers and directors relating, in part, to such leasing transactions. As a result of these and other factors, the Partnership and Energy do not intend to enter into any further significant leasing transactions.
In 1989, Energy purchased 400,000 Common Units directly from VNGP, L.P. for an aggregate of $6.5 million, or $16.24 per Common Unit, and made a simultaneous capital contribution to VNGP, L.P., thereby increasing its equity interest in the Partnership from approximately 48% to over 49%. However, Energy cannot purchase any significant number of additional Common Units without exceeding a 50% ownership interest in the Partnership and being required under applicable accounting rules to consolidate the operations and indebtedness of the Partnership for financial reporting purposes. Energy believes that it is not in the best interest of its shareholders to consolidate the operations and indebtedness of the Partnership without owning all of the Partnership's businesses and assets.
The Partnership and Energy also enter into various types of transactions in the normal course of business on market-related terms and conditions as described in Note 1 of Notes to Consolidated Financial Statements - "Transactions with Energy." To the extent that net amounts are payable by the Partnership to Energy from time to time, these transactions also constitute a type of working capital funding provided by Energy to the Partnership. The net amount owed by the Partnership to Energy was $31.8 million and $13.5 million at December 31, 1993 and 1992, respectively.
From time to time, the Partnership has generated cash to reinvest in its business through the sale of nonstrategic assets. In 1990 and 1991, the Partnership sold its interest in two off-system natural gas processing plants in Oklahoma and related contract rights and realized net cash proceeds of approximately $22 million. In 1993, the Partnership sold a small off-system gas processing plant in West Texas. The General Partner believed that the sale of these assets was desirable because the plants were located off-system and they were not a part of the Partnership's core businesses, and because the Partnership was able to sell the assets at a favorable price. However, the General Partner believes that sales of assets are not a dependable source of cash that can be relied upon in planning the Partnership's investment activities.
The Partnership has not historically required significant amounts of working capital because cash receipts on billings for sales and cash payments for purchases occur principally in the same month. Since the inception of the Partnership, the General Partner has significantly reduced the Partnership's working capital position (current assets less current liabilities) from a level of $29.5 million at March 31, 1987 to a negative $33 million at December 31, 1992 and a negative $48.3 million at December 31, 1993. The reduction in working capital requirements has generated a significant amount of cash, which the Partnership has been able to use for capital expenditures, debt service and cash distributions. However, the General Partner believes that, not only is a significant further reduction in the Partnership's working capital requirements unlikely to be realized, but that working capital requirements are likely to increase in the future due to increasing gas storage inventories resulting from the Partnership's efforts to compete for interstate sales under FERC Order 636. To the extent that the Partnership's negative working capital position results in a cash need, the General Partner anticipates that the Partnership will utilize its available short-term bank lines, among other things, to satisfy its short-term cash requirements.
As described in Note 2 of Notes to Consolidated Financial Statements, the Partnership, through the Management Partnership, currently has five short-term bank lines totalling $80 million. The Mortgage Note Indenture requires that at least $20 million of revolving credit agreements be maintained at all times; however, no more than $50 million of borrowings are permitted to be outstanding at any time. All of the bank lines mature at various times during 1994. If the proposed merger with Energy does not occur, the General Partner believes that these bank lines could be renewed or replaced with other short-term lines during 1994 on terms and conditions similar to those currently existing. If the proposed merger with Energy is completed, the General Partner anticipates that new bank credit agreements will be negotiated and that the Partnership's existing short-term bank lines will be cancelled. The Partnership had borrowings of as much as $39.9 million under its short-term bank lines during 1993. Although no borrowings were outstanding under these bank lines at December 31, 1993, the Partnership has incurred borrowings in 1994 of up to $42.9 million in order to fund increased working capital requirements. The Partnership's short-term bank lines are subject to a requirement, pursuant to the Mortgage Note Indenture, to have no balances outstanding for a period of 45 consecutive days during each 16 consecutive calendar months (referred to herein as a "clean-up period"). The Partnership completed a clean-up period during June 1993, and therefore will be required to complete another clean-up period by September 1994.
At the time of formation of the Partnership, the General Partner estimated that capital expenditures of approximately $30 million to $35 million would be sufficient to maintain the operations of the Partnership and that the operating cash flows of the Partnership would be sufficient to allow some additional level of capital expenditures to sustain, improve or expand operations. The Partnership Agreement currently provides that subject to certain exceptions, the General Partner will limit annual consolidated capital expenditures to the greater of $35 million or 30% of operating cash flow, and to the extent annual capital expenditures exceed such limits, the General Partner is required to use its best efforts to finance such excess. The Partnership's capital expenditures totalled $36.1 million in 1993, $35.9 million in 1992 and $33.1 million in 1991. In addition, as described above, lease transactions with Energy were entered into for certain facilities with approximate total costs of $75 million for leases commencing in 1991 and $26 million for leases commencing in 1992. The capital leases with Energy were necessary to permit the Partnership to undertake those capital projects and remain in compliance with the capital expenditure guidelines described above. The General Partner believes that, due to the Partnership's lack of financial flexibility as a result of the factors described above, the Partnership in its present form would not be able to continue making capital expenditures at these levels and, therefore, would likely be unable to participate fully in opportunities to improve and expand its operations or to take advantage of the types of opportunities, such as those described in "Results of Operations- General" above, that may arise in the natural gas and NGL businesses over the next several years. At the same time, the General Partner believes that the Partnership must continue to make substantial capital investments in facilities needed to access gas supplies and markets and expand its NGL processing and transportation capabilities in order for it to maintain its capacity to compete in the current industry environment. Subject to consummation of the proposed merger with Energy described above, Partnership capital expenditures are expected to be approximately $40 million in 1994.
When the Partnership was formed, the Partnership assumed Energy's liability with respect to a number of claims and lawsuits involving allegations that Transmission had failed to take, or pay for, natural gas under gas purchase contracts. The Partnership has settled substantially all of the take-or-pay claims previously brought against it, and believes that it has settled substantially all of the significant take-or-pay claims that are likely to be made. Amounts paid in settlement of take-or-pay claims are treated as deferred gas costs and are included in the Partnership's "deferred charges and other assets" until recovered through sales of gas by Transmission. However, the resolution of such claims resulted in deferred gas costs that were greater, and have been recovered more slowly through sales due to Transmission's decreasing sales volumes, than had been anticipated at the time of formation of the Partnership. At December 31, 1993, the unrecovered balance of deferred gas costs was $67 million, compared with $72 million at December 31, 1992. Additionally, during 1988, 1989 and the first half of 1990, the Partnership's operating income from NGL operations was substantially below prior (and subsequent) levels. As a result of these factors, capital that might otherwise have been available for capital projects has been used to make take-or-pay settlements and finance deferred gas costs. Accordingly, the ability of the Partnership to maintain, improve and expand the Partnership's business has been less than originally expected. In order to resolve certain contractual claims, the Partnership has also agreed to provide discounted gas transportation services to some customers in lieu of cash settlements. Certain of these arrangements will continue until the year 2000. The Partnership is currently involved, directly or indirectly, in various lawsuits and claims, which, if ultimately resolved in a manner adverse to the Partnership, could adversely affect the Partnership's cash flows from operations. For additional information regarding the above, see "Results of Operations" and Note 1 - "Other Assets" and Note 6 of Notes to Consolidated Financial Statements.
Quarterly cash distributions can be declared by the Partnership only after working capital and other operating requirements, capital expenditures, debt service and capital lease obligations are funded. As discussed in Note 1 of Notes to Consolidated Financial Statements - "Allocation of Net Income and Cash Distributions", the Preference Period for preferential cash distributions to holders of Preference Units ended with the cash distribution for the first quarter of 1992 which was paid in the second quarter. The quarterly cash distributions thereafter were reduced from $.625 per unit to $.125 per unit because of the reduction in the Partnership's available cash flows resulting from the various factors described above. Cash distributions totalled $10.4 million, $29.5 million and $48 million for the years ended December 31, 1993, 1992 and 1991, respectively. Future cash distributions to unitholders will depend upon the level of cash from operations and there is no assurance that cash distributions will continue into the future at the current level.
The General Partner expects that the Partnership's internally generated funds from operations will be sufficient in the first quarter of 1994 to fund debt service, lease obligations and minimum capital expenditure requirements. Cash requirements in excess of such amounts, such as cash distributions on the Common Units, any increases in working capital requirements and capital expenditures necessary to pursue possible industry opportunities, as described above, are expected to require supplemental funding, such as borrowings under the short-term credit lines described above. If the proposed merger with Energy does not occur, the General Partner believes that the above described clean-up requirement in 1994 can be achieved, but would require significant capital expenditure and working capital reductions, the elimination of cash distributions on the Common Units, the sale of core assets, or other measures likely to have adverse effects on the Partnership and the Unitholders. When and if the proposed merger with Energy is completed, the General Partner anticipates that distributions to Energy from the Partnership would be significantly reduced or eliminated, with such funds utilized for debt service including repayment of borrowings under the Partnership's short-term credit lines, working capital, capital expenditures or other Partnership purposes.
The Partnership is subject to environmental regulation at the federal, state and local level. During 1993, the Partnership submitted for approval various permitting matters to the Texas Natural Resource Conservation Commission with respect to air emissions at Transmission's compressor stations and Valero Hydrocarbons, L.P.'s gas processing plants. No such matters are currently pending. The Partnership's annual expenditures related to environmental remediation have not been significant to date. The General Partner does not expect that the Partnership will expend or be required to expend any significant amount on any environmental remediation matters, including polychlorinated biphenyls, which have affected certain natural gas pipeline companies. No amount has been accrued for any contingent environmental liability.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Valero Natural Gas Company as General Partner of Valero Natural Gas Partners, L.P. and to the Common Unitholders:
We have audited the accompanying consolidated balance sheets of Valero Natural Gas Partners, L.P. (a Delaware limited partnership) as of December 31, 1993 and 1992, and the related consolidated statements of income, partners' capital and cash flows for each of the three years in the period ended December 31, 1993. These financial statements and the schedules referred to below are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Valero Natural Gas Partners, L.P. as of December 31, 1993 and 1992, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules V, VI and IX are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
San Antonio, Texas February 17, 1994
VALERO NATURAL GAS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Control
Valero Natural Gas Partners, L.P. ("VNGP, L.P."), Valero Management Partnership, L.P. (the "Management Partnership") and various subsidiary operating partnerships (the "Subsidiary Operating Partnerships"), all Delaware limited partnerships, are the successors to substantially all of the natural gas and natural gas liquids businesses, assets and liabilities of substantially all of the subsidiaries of Valero Natural Gas Company ("VNGC") and the transmission division of Rio Grande Valley Gas Company ("Rio"). VNGC is, and Rio at the time of such succession was, a wholly owned subsidiary of Valero Energy Corporation (unless otherwise required by the context, the term "Energy" as used herein refers to Valero Energy Corporation and its consolidated subsidiaries, both individually and collectively). VNGC is the general partner of VNGP, L.P. and the Management Partnership (in such capacity, the "General Partner"), while subsidiaries of VNGC are general partners (the "Subsidiary General Partners") of the respective Subsidiary Operating Partnerships.
In March 1987, VNGP, L.P. sold in an underwritten public offering 9.5 million preference units of limited partner interests (the "Preference Units"), representing a 52% limited partner interest in VNGP, L.P. VNGP, L.P. concurrently issued approximately 8.6 million common units of limited partner interests (the "Common Units"), representing a 47% limited partner interest, to subsidiaries of Energy, and issued a 1% general partner interest in VNGP, L.P. to VNGC. Subsequent to March 1987, VNGP, L.P. issued .4 million additional Common Units to a subsidiary of Energy. In addition, approximately .2 million Common Units held by a subsidiary of Energy were transferred to employees of Energy and converted into Preference Units in connection with an employee benefit plan adopted by Energy. During 1992, all outstanding Preference Units were automatically converted into Common Units (see "Allocation of Net Income and Cash Distributions"). The original Common Units and former Preference Units converted into Common Units are collectively referred to herein as the "Units." Holders of the Units are referred to herein as the "Unitholders."
Under the partnership structure, VNGP, L.P. holds a 99% limited partner interest and VNGC holds a 1% general partner interest in the Management Partnership. The Management Partnership in turn holds a 99% limited partner interest and various wholly owned subsidiaries of VNGC each hold a 1% general partner interest in the various Subsidiary Operating Partnerships to which the acquired businesses, assets and liabilities were transferred. Valero Transmission, L.P. ("Transmission"), one of the Subsidiary Operating Partnerships, owns and operates the principal pipeline system of the Partnership. (References to Transmission prior to March 25, 1987 refer to Valero Transmission Company, a wholly owned subsidiary of VNGC, and after that date to its successor in interest, Valero Transmission, L.P.) Transmission is principally a transporter of natural gas as it transports gas for affiliates and third parties. Transmission also sells natural gas to intrastate customers under long-term contracts; however, most of the Partnership's gas sales are made through other Subsidiary Operating Partnerships which operate special marketing programs ("SMPs"). Subsequent to March 1987, VNGP, L.P. acquired a wholly owned subsidiary that makes certain intrastate gas sales, and formed certain subsidiary partnerships, one of which leases certain assets from Energy under capital leases as described in Note 5. Also, during 1992, an additional Subsidiary Operating Partnership was formed to make certain intrastate gas sales. VNGP, L.P., the Management Partnership, the original Subsidiary Operating Partnerships and the additional entities acquired or formed subsequent to March 1987 are collectively referred to herein as the "Partnership." As of December 31, 1993, Energy's total effective equity interest in the Partnership was approximately 49%.
In October 1993, Energy publicly announced its proposal to acquire the 9.7 million issued and outstanding Common Units in VNGP, L.P. held by persons other than Energy (the "Public Unitholders") pursuant to a merger of VNGP, L.P. with a wholly owned subsidiary of Energy. The Board of Directors of VNGC appointed a special committee of outside directors (the "Special Committee") to consider the merger and to determine the fairness of the transaction to the Public Unitholders. The Special Committee thereafter retained independent financial and legal advisors to assist the Special Committee. Upon the recommendation of the Special Committee, the Board of Directors of VNGC unanimously approved the merger. Effective December 20, 1993, Energy, VNGP, L.P. and VNGC entered into an agreement of merger (the "Merger Agreement") providing for the merger. In the merger, the Common Units held by the Public Unitholders will be converted into the right to receive cash in the amount of $12.10 per Common Unit. As a result of the merger, VNGP, L.P. would become a wholly owned subsidiary of Energy.
Consummation of the merger is subject to, among other things, (i) approval of the Merger Agreement by the holders of a majority of the issued and outstanding Common Units; (ii) approval by the holders of a majority of the Common Units held by the Public Unitholders and voted at a special meeting of holders of Common Units to be called to consider the Merger Agreement; (iii) receipt of satisfactory waivers, consents or amendments to certain of Energy's financial agreements; and (iv) completion of an underwritten public offering of convertible preferred stock by Energy. Energy currently owns approximately 47.5% of the outstanding Common Units and intends to vote its Common Units in favor of the merger.
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles and are not the basis for reporting taxable income to Unitholders. The consolidated financial statements include the accounts of VNGP, L.P. and its consolidated subsidiaries. All significant interpartnership transactions have been eliminated in consolidation.
Statements of Cash Flows
In order to determine net cash provided by operating activities, net income has been adjusted by, among other things, changes in current assets and current liabilities, excluding changes in cash and temporary cash investments, cash held in debt service escrow for principal (see Note 3), and current maturities of long-term debt and capital lease obligations. Those changes, shown as an (increase)/decrease in current assets and an increase/ (decrease) in current liabilities, are provided in the following table. Temporary cash investments are highly liquid low-risk debt instruments which have a maturity of three months or less when acquired and whose carrying amount approximates fair value. (Dollars in thousands.)
Cash interest paid by the Partnership (net of amounts capitalized) for the years ended December 31, 1993, 1992 and 1991 was $62.7 million, $66.4 million and $62.5 million, respectively. No cash payments for federal income taxes were made during these periods as the Partnership is not subject to federal income taxes (see "Income Taxes" below). Cash payments for state income taxes made during these periods were insignificant.
Noncash investing and financing activities for the years ended December 31, 1992 and 1991 included $26 million and $75 million, respectively, of various natural gas and natural gas liquids facilities acquired by the Partnership through capital lease transactions entered into with Energy. See Note 5.
Transactions with Energy
The Partnership enters into various types of transactions with Energy in the normal course of business on market-related terms and conditions. The Partnership is charged a management fee for the direct and indirect costs incurred by Energy on behalf of the Partnership that are associated with managing its operations. The Partnership sells natural gas and natural gas liquids ("NGLs") to, and purchases NGLs from, Energy's refining subsidiary. The Partnership sold natural gas to Energy's retail natural gas distribution business operated by Rio until September 30, 1993, when Rio was sold by Energy. The Partnership operates for a fee two natural gas processing plants and related facilities for Energy and sells natural gas to, purchases natural gas and NGLs from, and processes natural gas owned by Energy in connection with these NGL operations. The Partnership also enters into other operating transactions with Energy, including certain leasing transactions discussed in Note 5. As of December 31, 1993 and 1992, the Partnership had recorded approximately $31.8 million and $13.5 million, respectively, of accounts payable and accrued expenses, net of accounts receivable, due to Energy.
During the fourth quarter of 1992, the Partnership recognized a charge to earnings through the management fee billed by Energy of approximately $4.4 million, or $.23 per limited partner unit, representing the Partnership's allocable portion of the cost of a voluntary early retirement program implemented by Energy.
The following table summarizes transactions between the Partnership and Energy for the years ended December 31, 1993, 1992 and 1991 (in thousands):
The direct and indirect costs incurred by the General Partner on behalf of the Partnership that are charged to the Partnership through the management fee include, among other things, salaries and wages and other employee-related costs. Effective January 1, 1993, Energy adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards ("SFAS") No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." This statement requires a change in Energy's accounting for postretirement benefits other than pensions from a pay-as-you-go basis to an accrual basis of accounting. Energy is amortizing the transition obligation over 20 years, which is greater than the average remaining service period until eligibility of active plan participants. As a result of Energy's adoption of this statement, the Partnership's proportionate share of other postretirement employee benefits included in the management fee in 1993 increased by approximately $1.5 million and the Partnership's proportionate share of the total accumulated postretirement benefit obligation at December 31, 1993 was approximately $15 million. The adoption of this statement by Energy did not affect the Partnership's cash flows in 1993, nor is it expected to affect the Partnership's future cash flows, as Energy expects to continue to fund its postretirement benefits other than pensions, and require reimbursement from the Partnership for the Partnership's proportionate share of such funding, on a pay-as-you-go basis.
Gas Sales and Transportation
In the course of making gas sales and providing transportation services to customers, Transmission experiences measurement and other volumetric differences related to the amounts of gas received and delivered. Transmission has in the past experienced overall net volume gains due to such differences and its Rate Order allows such volumes to be sold to its customers. Transmission historically has derived a substantial benefit from such sales. The amount included in operating income in 1993 was substantially the same as in 1992. However, the implementation of more precise gas measurement equipment and standards and the reduction in Transmission's total sales volumes, discussed in Note 6 - "Customer Audit of Transmission", is expected to reduce operating income from such sales in future periods.
Inventories
Inventories are carried principally at weighted average cost not in excess of market. Inventories as of December 31, 1993 and 1992 were as follows (in thousands):
In addition to the above noted natural gas storage inventories, which are located at the Wilson Storage Facility in Wharton County, Texas (see Note 5), the Partnership also had natural gas in third-party storage facilities, available under exchange agreements, totalling $10.8 million and $1.2 million at December 31, 1993 and 1992, respectively. Such amounts are included in receivables in the accompanying consolidated balance sheets.
Property, Plant and Equipment
Property, plant and equipment at date of inception of the Partnership was increased by the excess of the acquisition cost of the holders of the Preference Units over VNGC's historical net cost basis. Accordingly, approximately 51% of property, plant and equipment was recorded at fair value reflecting the value attributable to the holders of the Preference Units while the remaining 49% was recorded at historical net book cost to reflect the value attributable to the General Partner and the holders of the original Common Units.
Property additions and betterments include capitalized interest and acquisition and administrative costs allocable to construction and property purchases. Assets under capital leases are included in property, plant and equipment and are recorded at the lesser of the fair value of the leased property at the inception of the lease or the present value of the related future minimum lease payments.
The costs of minor property units (or components thereof), net of salvage, retired or abandoned are charged or credited to accumulated depreciation. Gains or losses on sales or other dispositions of major units of property are credited or charged to income.
Provision for depreciation of property, plant and equipment is made primarily on a straight-line basis over the estimated useful lives of the depreciable facilities. Assets under capital leases are depreciated on a straight-line basis over the lease term. The rates for depreciation are as follows:
During the fourth quarter of 1992, the Partnership extended the estimated useful lives of the majority of its natural gas liquids facilities from 14 to 20 years to better reflect the estimated periods during which such assets are expected to remain in service. The effect of this change in accounting estimate, which was made retroactive to January 1, 1992, was to decrease depreciation expense and increase net income for 1992 by approximately $5.6 million, or $.29 per limited partner unit.
Other Assets
Payments made or agreed to be made in connection with the settlement of certain disputed contractual issues with gas suppliers of Transmission are initially deferred. The balance of such payments is subsequently reduced as recoveries are made through Transmission's rates. The balance of deferred gas costs of $67 million and $72 million at December 31, 1993 and 1992, respectively, is included in noncurrent other assets and is expected to be recovered over future periods. See Note 6 - "Customer Audit of Transmission."
Debt issuance costs are included in deferred charges and other assets and are amortized by the effective interest method over the term of each respective issue of the Management Partnership's First Mortgage Notes ("First Mortgage Notes"). See Note 3.
Income Taxes
Income and deductions of the Partnership for federal income tax purposes are includable in the tax returns of the individual partners. Accordingly, no recognition has been given to federal income taxes in the accompanying consolidated financial statements of the Partnership. At December 31, 1993 and 1992, the net difference between the tax bases and the reported amounts of assets and liabilities in the accompanying Consolidated Balance Sheets was $314 million and $322 million, respectively. Under the Revenue Act of 1987, certain publicly traded limited partnerships will be taxed as corporations after December 31, 1997 unless specifically exempted. This Act exempted natural resource partnerships including those dealing with natural gas transportation and processing of natural gas liquids, such as the Partnership, from its taxation provision.
Price Risk Management Activities
The Partnership, through its Market Center Services Program established in 1992, enters into exchange-traded futures and options contracts, forward contracts, swaps and other financial instruments with third parties to hedge natural gas inventories and certain anticipated natural gas purchase requirements in order to minimize the risk of market fluctuations. The Partnership also utilizes such price risk management techniques to provide services to gas producers and end users. Changes in the market value of these contracts are deferred until the gain or loss is recognized on the hedged transaction. As of December 31, 1993 and 1992, the Partnership had outstanding contracts for natural gas totalling approximately 15.0 billion cubic feet ("Bcf") and 4.8 Bcf, respectively, for which the Partnership is the fixed price payor and 27.1 Bcf and 10.0 Bcf, respectively, for which the Partnership is the fixed price receiver. Such contracts run for a period of one to twelve months. A portion of such contracts represented hedges of natural gas volumes in underground storage and in third-party storage facilities which totalled approximately 10.3 Bcf and 7.4 Bcf at December 31, 1993 and 1992, respectively. See "Inventories" above.
In 1993 and 1992, the Partnership recognized $18.7 million and $12.9 million, respectively, in gas cost reductions and other benefits from this program. An additional $5.1 million and $3.6 million in other reductions of cost of gas was generated by transactions entered into in 1993 and 1992, respectively, which is recognized in income in the subsequent year as the related gas is sold.
Allocation of Net Income and Cash Distributions
Net income is allocated to partners based on their effective ownership interest in the operating results of the Partnership, except that additional depreciation expense pertaining to the excess of the Partnership's acquisition cost over the historical cost basis in net property, plant and equipment and certain other assets in which the former holders of Preference Units have an ownership interest is allocated solely to such holders as a noncash charge to net income. The allocation of additional depreciation expense to the former holders of Preference Units does not affect the cash distributions with respect to the Units. Under the Partnership structure, the income of the Subsidiary Operating Partnerships is allocated to the Subsidiary General Partners, which hold a 1% general partner interest, and to the Management Partnership, which holds a 99% limited partner interest. As a result, net income allocable to the Subsidiary General Partners is not reduced by interest expense associated with the Management Partnership's First Mortgage Notes.
The Partnership is required to make quarterly cash distributions with respect to all Units in an amount equal to "Distributable Cash Flow" as defined in the Second Amended and Restated Agreement of Limited Partnership of VNGP, L.P. (the "Partnership Agreement") and as determined by the General Partner. With the payment on May 30, 1992 of the cash distribution of $.625 per Unit for the first quarter of 1992, the Partnership completed the payment of cumulative cash distributions of $12.50 per Preference Unit resulting in the termination of the period (the "Preference Period") during which the holders of Preference Units were entitled to a preferential distribution amount. As a result of the termination of the Preference Period, all outstanding Preference Units were automatically converted into Common Units in accordance with the terms of the Partnership Agreement. The Partnership subsequently reduced cash distributions to $.125 per Unit for the remaining quarters of 1992 and the first three quarters of 1993. On January 25, 1994, the VNGC Board of Directors declared a cash distribution of $.125 per Unit for the fourth quarter of 1993 that is payable March 1, 1994 to holders of record as of February 7, 1994. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of factors that have reduced the amount of cash available for distribution to Unitholders.
If the proposed merger with Energy described above under "Organization and Control" occurs after March 9, 1994, the General Partner intends and expects to declare and pay a pro rata distribution to holders of record of the Common Units on the effective date of the merger based upon the number of days elapsed between February 7, 1994 and such effective date.
2. SHORT-TERM BANK LINES
The Partnership, through the Management Partnership, currently maintains five separate short-term bank lines of credit totalling $80 million. In accordance with the terms of the indenture of mortgage and deed of trust pursuant to which the Management Partnership's First Mortgage Notes were issued (the "Mortgage Note Indenture"), at least $20 million of revolving credit agreements must be maintained at all times; however, no more than $50 million of borrowings are permitted to be outstanding at any time. See Note 3. The Partnership had borrowings of as much as $39.9 million under its short-term bank lines during 1993. No borrowings were outstanding under these lines at December 31, 1993 or 1992. The lines of credit mature at various times during 1994, bear interest at each respective bank's prime, quoted money market or Eurodollar rate and require commitment fees based on the unused amount of the credit. If the proposed merger with Energy does not occur, the General Partner believes that these short-term bank lines could be renewed or replaced with other short-term lines during 1994 on terms and conditions similar to those currently existing. If the proposed merger with Energy is completed, the General Partner anticipates that new bank credit agreements will be negotiated and that the Partnership's existing short-term bank lines will be cancelled.
3. LONG-TERM DEBT
Long-term debt balances were as follows (in thousands):
The First Mortgage Notes, which are currently comprised of eight remaining series due serially from 1994 through 2009, are secured by mortgages on and security interests in substantially all of the currently existing and after-acquired property, plant and equipment of the Management Partnership and each Subsidiary Operating Partnership and by the Management Partnership's limited partner interest in each Subsidiary Operating Partnership (the "Mortgaged Property"). As of December 31, 1993, the First Mortgage Notes have a remaining weighted average life of approximately 7.3 years and a weighted average interest rate of 10.12% per annum. Interest on the First Mortgage Notes is payable semiannually, but one-half of each interest payment and one-fourth of each annual principal payment are escrowed quarterly in advance. At December 31, 1993 and 1992, $34.2 million and $32.9 million, respectively, had been deposited with the Mortgage Note Indenture trustee ("Trustee") in an escrow account. The amount on deposit is classified as a current asset (cash held in debt service escrow) and the liability to be paid off when the cash is released by the Trustee from escrow is classified as a current liability.
The Mortgage Note Indenture contains covenants prohibiting the Management Partnership and the Subsidiary Operating Partnerships (collectively referred to herein as the "Operating Partnerships") from incurring additional indebtedness, including any additional First Mortgage Notes, other than (i) up to $50 million of indebtedness to be incurred for working capital purposes (provided that for a period of 45 consecutive days during each 16 consecutive calendar month period no such indebtedness will be permitted to be outstanding) and (ii) up to the amount of any future capital improvements financed through the issuance of debt or equity by VNGP, L.P. and the contribution of such amounts as additional equity to the Management Partnership. The Mortgage Note Indenture also prohibits the Operating Partnerships from (a) creating new indebtedness unless certain cash flow to debt service requirements are met; (b) creating certain liens; or (c) making cash distributions in any quarter in excess of the cash generated in the prior quarter, less (i) capital expenditures during such prior quarter (other than capital expenditures financed with certain permitted indebtedness), (ii) an amount equal to one-half of the interest to be paid on the First Mortgage Notes on the interest payment date occurring in or next following such prior quarter and (iii) an amount equal to one-quarter of the principal required to be paid on the First Mortgage Notes on the principal payment date occurring in or next following such prior quarter, plus cash which could have been distributed in any prior quarter but which was not distributed. The Operating Partnerships are further prohibited from purchasing or owning any securities of any person or making loans or capital contributions to any person other than investments in the Subsidiary Operating Partnerships, advances and contributions of up to $20 million per year and $100 million in the aggregate to entities engaged in substantially similar business activities as the Operating Partnerships, temporary investments in certain marketable securities and certain other exceptions.
The Mortgage Note Indenture also prohibits the Operating Partnerships from consolidating with or conveying, selling, leasing or otherwise disposing of all or any material portion of their property, assets or business as an entirety to any other person unless the surviving entity meets certain net worth requirements and certain other conditions are met, or from selling or otherwise disposing of any part of the Mortgaged Property, subject to certain exceptions. The Mortgage Note Indenture also provides that it will be an event of default if VNGC withdraws as General Partner of the Management Partnership prior to 1997, if VNGC is removed as General Partner but the Subsidiary General Partners are not also removed, or if the General Partner or any Subsidiary General Partner withdraws or is removed and is not replaced within 30 days.
Maturities of long-term debt for the years ending December 31, 1995 through 1998 are $30.3 million, $32.9 million, $35.3 million and $37.9 million, respectively.
Based on the borrowing rates currently available to the Partnership for long-term debt with similar terms and average maturities, the fair value of the Partnership's First Mortgage Notes, including current maturities, at December 31, 1993 was approximately $562 million. At December 31, 1992, the fair value of the First Mortgage Notes was essentially equal to their carrying value.
4. INDUSTRY SEGMENT INFORMATION
The Partnership operates in the natural gas and natural gas liquids industry segments. The natural gas operations consist of purchasing, gathering, transporting and selling natural gas, principally to gas distribution companies, electric utilities, pipeline companies and industrial customers. The Partnership also transports gas for a fee for sales customers, other pipelines and end users and provides price risk management services to gas producers and end users through its Market Center Services Program. The natural gas liquids operations include the extraction of natural gas liquids, principally from natural gas throughput of the natural gas operations, and the fractionation and transportation of natural gas liquids. The primary markets for sales of natural gas liquids are petrochemical plants, refineries and domestic fuel distributors. Intersegment revenue eliminations relate primarily to transportation provided by the natural gas segment for the natural gas liquids segment. During 1993, natural gas sales and transportation revenues from San Antonio City Public Service accounted for approximately 11% of the Partnership's total consolidated operating revenues. No single unaffiliated customer accounted for more than 10% of the Partnership's total consolidated operating revenues during 1992 or 1991. Energy and its consolidated subsidiaries accounted for approximately 12%, 12% and 11% of the Partnership's total consolidated operating revenues during 1993, 1992 and 1991, respectively.
The Partnership's natural gas segment has a concentration of customers in the natural gas transmission and distribution industries while its natural gas liquids segment has a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact the Partnership's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, the General Partner believes that the Partnership's portfolio of accounts receivable is sufficiently diversified to the extent necessary to minimize any potential credit risk. Historically, the Partnership has not had any significant problems in collecting its accounts receivable. The Partnership's accounts receivable are generally not collateralized.
5. LEASE AND OTHER COMMITMENTS
Valero Gas Storage Company ("Gas Storage"), a wholly owned subsidiary of VNGC, is the lessee under an operating lease for a gas storage facility (the "Wilson Storage Facility"). Gas Storage and Valero Transmission Company had previously entered into a gas storage agreement ("Gas Storage Agreement") which required Valero Transmission Company to pay to Gas Storage amounts essentially equivalent to the lease payments and operating costs in connection with Valero Transmission Company's use of the Wilson Storage Facility. Upon formation of the Partnership, Valero Transmission Company assigned the Gas Storage Agreement to Valero Transmission, L.P., and Valero Transmission, L.P. assumed Valero Transmission Company's obligation to make such payments to Gas Storage. The remaining primary lease term for the Wilson Storage Facility is six years with options to renew at varying terms. The future minimum lease payments related to this lease are included in the table below. The Partnership has other noncancelable operating leases with remaining terms ranging generally from one year to 13 years.
During 1992, the Partnership entered into a capital lease with Energy to lease a gas processing plant near Thompsonville in South Texas and 48 miles of NGL product pipeline (the "Thompsonville Project"). The Thompsonville Project lease commenced December 1, 1992 and has a term of 15 years. During 1991, the Partnership entered into capital leases with Energy to lease an interest in an approximate 105-mile pipeline in East Texas (the "East Texas pipeline") and certain fractionation facilities in Corpus Christi, Texas. The East Texas pipeline lease commenced February 1, 1991 and has a term of 25 years while the lease for the fractionation facilities commenced December 1, 1991 and has a term of 15 years. As a result of the settlement and dismissal in 1992 of certain claims asserted in litigation filed against Energy and certain of its affiliates, officers and directors, Energy agreed to adjust the payments and certain other terms under these capital leases. Such adjusted payments are reflected in the table of future minimum lease payments shown below.
The assets and associated obligations related to the capital leases with Energy described above are not subject to the Mortgage Note Indenture. The Partnership has the right to purchase all or any portion of these assets, subject to certain restrictions, under purchase option provisions of the respective lease agreements. The total cost of these leased facilities, which is included in the accompanying consolidated balance sheets under property, plant and equipment, was approximately $101 million. Amortization of these capital leases, which is included in depreciation expense in the accompanying consolidated income statements, was $5.3 million, $3.5 million and $2.2 million for 1993, 1992 and 1991, respectively.
The related future minimum lease payments under the Partnership's capital leases and noncancelable operating leases as of December 31, 1993 are as follows (in thousands):
The future minimum lease payments listed above under the caption "Partnership Lease Commitments" exclude certain operating lease commitments which are cancelable by the Partnership upon notice of one year or less. Consolidated rent expense was approximately $698,000, $833,000 and $746,000 for the years ended December 31, 1993, 1992 and 1991, respectively, and excludes amounts billed by Energy to the Partnership for its proportionate use of Energy's corporate headquarters office complex and related charges which are included in the management fee charged to the Partnership. See Note 1 - "Transactions with Energy." Rentals paid of $10,438,000 per year for 1993, 1992 and 1991 in connection with the Wilson Storage Facility were included in the computation of Transmission's weighted average cost of gas.
The obligations of Gas Storage under the gas storage facility lease include its obligation to make scheduled lease payments and, in the event of a declaration of default and acceleration of the lease obligation, to make certain lump sum payments based on a stipulated loss value for the gas storage facility less the fair market sales price or fair market rental value of the gas storage facility. Under certain circumstances, a default by Energy or a subsidiary of Energy, including VNGC, with respect to its own indebtedness could result in a cross default under the gas storage facility lease. The General Partner believes that it is unlikely that a default by Energy or a subsidiary of Energy would result in acceleration of the gas storage facility lease, and further believes that such event, if it occurred, would not have a material adverse effect on the Partnership.
6. LITIGATION AND CONTINGENCIES
Take-or-Pay and Related Claims
As a result of past market conditions and contracting practices in the natural gas industry, numerous producers and other suppliers brought claims against Transmission asserting that it was in breach of contractual provisions requiring that it take, or pay for if not taken, certain specified volumes of natural gas. The Partnership has settled substantially all of the significant take-or-pay claims, pricing differences and contractual disputes heretofore brought against it. Although additional claims may arise under older contracts until their expiration or renegotiation, the General Partner believes that the Partnership has resolved substantially all of the significant take-or-pay claims that are likely to be made. As described below, Energy and/or the Partnership have agreed to bear a portion of certain potential liabilities that may be incurred by certain Partnership suppliers. Although the General Partner is currently unable to predict the total amount Transmission or the Partnership ultimately may pay or be required to pay in connection with the resolution of existing and potential take-or- pay claims, the General Partner believes that any remaining claims can be resolved on terms satisfactory to the Partnership and that the resolution of such claims and any potential claims has not had and will not have a material adverse effect on the Partnership's financial position or results of operations.
In 1987, Transmission and a producer from whom Transmission has purchased natural gas entered into an agreement resolving certain take-or-pay issues between the parties in which Transmission agreed to pay one-half of certain excess royalty claims arising after the date of the agreement. The royalty owners of the producer recently completed an audit of the producer and have presented to the producer a claim for additional royalty payments in the amount of approximately $17.3 million, and accrued interest thereon of approximately $19.8 million. Approximately $8 million of the royalty owners' claim accrued after the effective date of the agreement between the producer and Transmission. The producer and Transmission are reviewing the royalty owners' claims. No lawsuit has been filed by the royalty owners. The General Partner believes that various defenses under the agreement may reduce any liability of Transmission to the producer in this matter.
Valero Transmission Company and one of its gas suppliers are parties to various gas purchase contracts assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. The supplier is also a party to a series of gas purchase contracts between the supplier, as buyer, and certain trusts, as seller, which are in litigation. Neither the Partnership nor Valero Transmission Company is a party to this litigation or the contracts between Transmission's supplier and the trusts. However, because of the relationship between Transmission's contracts with the supplier and the supplier's contracts with the trusts, and in order to resolve existing and potential disputes, the supplier, Valero Transmission Company and Valero Transmission, L.P. have agreed that they will cooperate in the conduct of this litigation, and that Valero Transmission Company and Valero Transmission, L.P. will bear a substantial portion of the costs of any appeal and any nonappealable final judgment rendered against the supplier. In the litigation, the trusts allege that Transmission's supplier has breached various minimum take, take-or-pay and other contractual provisions, and assert a statutory nonratability claim. The trusts seek alleged actual damages, including interest, of approximately $30 million and an unspecified amount of punitive damages. The District Court ruled on the plaintiff's motion for summary judgment, finding, among other things, that as a matter of law the three gas purchase contracts at issue were fully binding and enforceable, the supplier breached the minimum take obligations under one of the contracts, the supplier is not entitled to claimed offsets for gas purchased by third parties and the "availability" of gas for take-or-pay purposes is established solely by the delivery capacity testing procedures in the contracts. Damages, if any, have not been determined. Because of existing contractual obligations of Valero Transmission, L.P. to its supplier, the lawsuit may ultimately involve a contingent liability for Valero Transmission, L.P. The General Partner believes that the claims brought against the supplier have been significantly overstated, and that the supplier has a number of meritorious defenses to the claims including various regulatory, statutory, contractual and common law defenses. The Court recently granted the supplier's Motion for Continuance of the former January 10, 1994 trial date. This litigation is not currently set for trial.
Payments that Transmission has made or agreed to make in connection with settlements to date are included in its deferred gas costs. The General Partner believes that the rate order under which Transmission currently operates (the "Rate Order"), issued in 1979 by the Railroad Commission of Texas (the "Railroad Commission," which regulates the sale and transportation of natural gas by intrastate pipeline systems in Texas), allows for the recovery of such costs. See Note 1 - "Other Assets" and "Customer Audit of Transmission" below. Certain take-or-pay and other claims have been resolved through the Partnership agreeing to provide discounted transportation services. These agreements do not involve a cash outlay by the Partnership but in certain cases have the effect of reducing transportation margins over an extended period of time.
Any liability of Energy with respect to take-or-pay claims involving Transmission's intrastate pipeline operations has been assumed by the Partnership. Based upon the General Partner's beliefs and rate considerations discussed above, no liabilities have been recorded for any unresolved take-or-pay claims.
Other Litigation
Seven lawsuits were filed in Chancery Court in Delaware against VNGP, L.P., VNGC and Energy and certain officers and directors of VNGC and/or Energy in response to the announcement by Energy on October 14, 1993 of its proposal to acquire the publicly traded Common Units of VNGP, L.P. pursuant to a proposed merger of VNGP, L.P. with a wholly owned subsidiary of Energy. See Note 1 - "Organization and Control." The suits were consolidated into a single proceeding by the Chancery Court on November 23, 1993. The plaintiffs sought to enjoin or rescind the proposed merger, alleging that the corporate defendants and the individual defendants, as officers or directors of the corporate defendants, engaged in actions in breach of the defendants' fiduciary duties to the Public Unitholders by proposing the merger. The plaintiffs alternatively sought an increase in the proposed merger consideration, unspecified compensatory damages and attorneys' fees. In December 1993, the parties reached a tentative settlement of the consolidated lawsuit. The terms of the settlement will not require a material payment by Energy or the Partnership. However, there can be no assurance that the settlement will be completed, or that it will be approved by the Chancery Court.
In March 1993, two indirect wholly owned subsidiaries of Energy serving as general partners of two of VNGP, L.P.'s principal Subsidiary Operating Partnerships were served as third- party defendants in a lawsuit originally filed in 1991 by a subsidiary of The Coastal Corporation ("Coastal") against TransAmerican Natural Gas Corporation ("TANG"). In August 1993, Energy, VNGP, L.P. and certain of their respective subsidiaries were named as additional third-party defendants (collectively, including the original defendant subsidiaries, the "Valero Defendants") in this lawsuit. In its counterclaims against Coastal and third-party claims against the Valero Defendants, TANG alleges that it contracted to sell natural gas to Coastal at the posted field price of one of the Valero Defendants and that the Valero Defendants and Coastal conspired to set the posted field price at an artificially low level. TANG also alleges that the Valero Defendants and Coastal conspired to cause TANG to deliver unprocessed or "wet" gas, thus precluding TANG from extracting NGLs from its gas prior to delivery. TANG seeks actual damages of approximately $50 million, trebling of damages under antitrust claims, punitive damages of $300 million, and attorneys' fees. The General Partner believes that the plaintiff's claims have been exaggerated, and that Energy and the Partnership have meritorious defenses to such claims. In the event of an adverse determination involving Energy, Energy likely would seek indemnification from the Partnership under terms of the partnership agreements and other applicable agreements between VNGP, L.P., its subsidiary partnerships and their respective general partners. The Valero Defendants' motion for summary judgment on TANG's antitrust claims was argued on January 24, 1994. The court has not ruled on such motion. The current trial setting for this case is March 14, 1994.
In September 1991, a lawsuit was filed by Valero Transmission, L.P. alleging breach of contract against a producer. On January 11, 1993, the defendant filed a cross- action against Valero Transmission, L.P., Valero Industrial Gas, L.P. and Reata Industrial Gas, L.P. The defendant asserted claims for actual damages for failure to pay for goods and services delivered. Additionally, the defendant asserted various other cross-claims, including conversion, breach of contract, breach of an alleged duty to market gas in good faith, tortious breach of a duty imposed by law and tortious negligence. The defendant sought actual damages aggregating not less than $1 million, injunctive relief, attorneys fees and costs, and exemplary damages in the amount of not less than $20 million. In January 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
The Partnership was a party to a lawsuit originally filed in 1988 in which Energy, Valero Transmission Company, VNGP, L.P., the Management Partnership and Valero Transmission, L.P. (the "Valero Defendants") and a subsidiary of Coastal were alleged to be liable for failure to take minimum quantities of gas, failure to make take-or-pay payments and other breach of contract and breach of fiduciary duty claims. The plaintiffs sought declaratory relief, actual damages in excess of $37 million and unspecified punitive damages. During the third quarter of 1992, the plaintiffs, Coastal and the Valero Defendants settled this lawsuit on terms which were not material to the Valero Defendants and on July 19, 1993, this lawsuit was dismissed. On November 16, 1992, prior to entry of the order of dismissal, NationsBank of Texas, N.A., as trustee for certain trusts (the "Intervenors"), filed a plea in intervention to intervene in the lawsuit. The Intervenors asserted that they held a non-participating mineral interest in the lands subject to the litigation and that their rights were not protected by the plaintiffs in the settlement. On February 4, 1993, the Court struck the Intervenors' plea in intervention. However, on February 2, 1993, the Intervenors had filed a separate suit in the 160th State District Court, Dallas County, Texas, against all prior defendants and an additional defendant, substantially adopting in form and substance the allegations and claims in the original litigation. In February 1994, the parties reached a tentative settlement of the lawsuit on terms immaterial to the Partnership.
City of Houston Franchise Fee Audit
In a letter dated September 1, 1993 from the City of Houston (the "City") to Valero Transmission Company ("VTC"), the City stated its intent to bring suit against VTC for certain claims asserted by the City under the franchise agreement between the City and VTC. VTC is the general partner of Valero Transmission, L.P. The franchise agreement was assigned to and assumed by Valero Transmission, L.P. upon formation of the Partnership in 1987. In the letter, the City declared a conditional forfeiture of the franchise rights based on the City's claims. In a letter dated October 27, 1993, the City claimed that VTC owes to the City franchise fees and accrued interest thereon aggregating approximately $13.5 million. In a letter dated November 9, 1993, the City claimed an additional $18 million in damages related to the City's allegations that VTC engaged in unauthorized activities under the franchise agreement by transmitting gas for resale and by transporting gas for third parties on the franchised premises. The City has not filed a lawsuit. The General Partner believes that the City's claims are significantly overstated and that VTC has a number of meritorious defenses to the claims. Any liability of VTC with respect to the City's claims has been assumed by the Partnership.
Customer Audit of Transmission
Transmission's Rate Order provides for Transmission to sell gas at its weighted average cost of gas, as defined ("WACOG"), plus a margin of $.15 per Mcf. In addition to the cost of gas purchases, Transmission's WACOG has included storage, gathering and other fixed costs totalling approximately $19 million per year, and amortization of deferred gas costs related to the settlement of take-or-pay and related claims (see Note 1 - "Other Assets" and "Take-or-Pay and Related Claims" above). Transmission's gas purchases include high-cost casinghead gas and certain special allowable gas that Transmission is required to purchase contractually and under the Railroad Commission's priority rules. Transmission's sales volumes have been decreasing with the expiration of its sales contracts including the July 1992 expiration of a contract representing approximately 37% of Transmission's sales volumes for the first six months of 1992. As a result of each of these factors, Transmission's WACOG and gas sales price are substantially in excess of market clearing levels.
Transmission's WACOG has been periodically audited by certain of its customers, as allowed under the Rate Order. One such customer (the "Customer") questioned the application of certain of Transmission's current rate policies to future periods in light of the decreases that have occurred in Transmission's throughput, and the Customer has recently completed its audit of Transmission's WACOG with respect thereto. For 1993, the Customer represented approximately 70% of Transmission's sales volumes and such percentage is expected to increase as other sales contracts expire and are not renewed. As a result of the Customer's audit, Transmission and the Customer entered into a settlement agreement which excludes certain of the fixed costs described above from Transmission's WACOG, effective with July 1993 sales, resulting in a reduction of the Partnership's annual net income by approximately $6 million. Upon the termination of Transmission's gas sales contract with the Customer in 1998, Transmission's fixed costs, including storage (see Note 5), would be charged to income instead of recovered through its gas sales rates. Transmission expects to recover its deferred gas costs over a period of approximately eight years. The recovery of any additional payments made in connection with any future settlements would be limited.
The Partnership is also a party to additional claims and legal proceedings arising in the ordinary course of business. The General Partner believes it is unlikely that the final outcome of any of the claims or proceedings to which the Partnership is a party, including those described above, would have a material adverse effect on the Partnership's financial position or results of operations; however, due to the inherent uncertainties of litigation, the range of possible loss, if any, cannot be estimated with a reasonable degree of precision and there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Partnership's results of operations for the fiscal period in which such resolution occurred.
7. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended December 31, 1993 and 1992 were as follows (in thousands of dollars, except per Unit amounts):
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Neither VNGP, L.P., the Management Partnership nor any Subsidiary Operating Partnership has any officers, directors or employees of its own. Accordingly, the following information is provided with respect to the executive officers and directors of the General Partner.
The following table sets forth certain information as of December 31, 1993, regarding the present executive officers and directors of the General Partner. The term of each director expires at an annual meeting of the sole stockholder of the General Partner scheduled to be held on or about April 27, 1994. The General Partner is a wholly owned subsidiary of Energy. Each executive officer named in the following table has been elected to serve until his successor is duly appointed or elected or his earlier removal or resignation from office.
There is no family relationship among any of the executive officers or directors of the General Partner, and no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.
Mr. Benninger was elected Executive Vice President of VNGC in 1990 and as a director and Chief Operating Officer of VNGC in 1992. He served as Chief Financial Officer of VNGC from 1986 to 1992, as Senior Vice President of VNGC from 1987 to 1990 and as Vice President of VNGC from 1983 to 1987. Mr. Benninger also served as Treasurer of VNGC from its formation in 1982 to 1986. Mr. Benninger is also a director and the Executive Vice President of Energy and has served in various capacities with Energy since 1975.
Dr. Calgaard has served as a director of VNGC since 1987. He has also served as President of Trinity University, San Antonio, Texas, since 1979. Dr. Calgaard presently serves as a director of the Association of American Colleges, Southwest Research Institute and Rayco, Ltd. None of these entities is affiliated with the Partnership or the General Partner.
Mr. Escobedo has served as a director of VNGC since 1989. He is currently, and has been for the past five years, a senior partner of the independent public accounting firm of Ruben Escobedo & Co., Certified Public Accountants.
Mr. Greehey has served as Chief Executive Officer and a director of VNGC since its formation in 1982. Mr. Greehey is also Chairman of the Board and Chief Executive Officer of Energy and has been employed by Energy in various capacities since 1979. Mr. Greehey is also a director of Weatherford International Incorporated and Santa Fe Energy Resources, Inc., which are not affiliated with the Partnership or the General Partner.
Mr. McLelland was elected Executive Vice President of VNGC in 1990 and has served as General Counsel and a director of VNGC since its formation in 1982. Mr. McLelland served as Senior Vice President of VNGC from 1982 until his election as Executive Vice President. He also serves as Executive Vice President and General Counsel of Energy.
Mr. Wallace has served as a director of VNGC since 1987. He was engaged in the private practice of law with the firm Hughes & Luce, Austin, Texas, from 1987 to 1990 and currently serves as counsel to such firm. He previously served as a member and Chairman of the Railroad Commission of Texas from 1973 to 1987.
Mr. Heep was elected Senior Vice President and Chief Financial Officer in January 1994. Mr. Heep served as Vice President Finance of VNGC from 1990 until his election as Senior Vice President. He was first elected Vice President of VNGC in 1988. He also serves as Senior Vice President and Chief Financial Officer of Energy. He has been employed by Energy since 1977.
Mr. Fry was elected Vice President Administration of VNGC in 1990. He served as Secretary of VNGC since its formation in 1982 until 1992. He has been employed by Energy since 1978 and also serves as Vice President Administration of Energy.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following table sets forth information as to items of compensation paid to VNGC's Chief Executive Officer and its four other most highly compensated executive officers for services rendered in all capacities to Energy in 1991, 1992 and 1993. The Partnership has reimbursed the General Partner and its subsidiaries for approximately 60% of the aggregate amount of such 1993 compensation pursuant to the Partnership Agreement of VNGP, L.P. and the corresponding partnership agreements of the Management Partnership and Subsidiary Operating Partnerships (collectively the "Partnership Agreements"). See "Certain Relationships and Related Transactions."
Shown below is further information regarding the grants of stock options to the named executive officers reflected in the Summary Compensation Table.
Retirement Benefits
The following table shows, for purposes of illustration, the estimated annual gross benefits payable under Energy's Pension Plan ("Pension Plan") and Supplemental Executive Retirement Plan ("SERP") upon retirement at age 65 on the assumed compensation levels and years of service indicated, assuming an election to have payments continue for the benefit of the life of the participant only.
Energy maintains a noncontributory pension plan in which virtually all Energy employees are eligible to participate. The Pension Plan is a defined benefit plan funded by a method which determines contribution requirements in the aggregate for all participants. Accordingly, contributions for individual participants are not determinable. Accrued contributions to the Pension Plan in 1993 for the 1993 Pension Plan year were approximately 7.4% of total covered remuneration. The 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 under the Pension Plan.
Energy also maintains the SERP, a nonqualified supplemental retirement plan which provides additional pension benefits to the executive officers and certain employees of Energy. In December 1989, Energy funded its obligations through that date under the SERP through the contribution of Common Stock to a trust established as a vehicle to fund disbursements to SERP participants. No additional contributions were made to the SERP during 1993.
Compensation for purposes of the Pension Plan includes only annual salary as reported in the Summary Compensation Table and excludes cash bonuses. For purposes of calculating the amount payable under the SERP, the participant's most highly compensated consecutive 36 months of service (rather than 60 months) in the prior 10 years are considered, and bonuses are included in calculating covered compensation. Accordingly, the amounts reported as annual compensation in the Summary Compensation Table under the heading "Salaries" and "Bonus" constitute covered compensation for purposes of the SERP. Benefits listed in the Pension Table are not subject to any deduction for social security or other offset amounts.
Credited years of service for the period ending December 31, 1993, for the executive officers of VNGC named in the cash compensation table are as follows: Mr. Greehey - 30 years; Mr. Benninger - 19 years; Mr. McLelland -15 years; Mr. Heep - 16 years; and Mr. Fry - 15 years. The credited service for Mr. McLelland includes two years service credited pursuant to the terms of Mr. McLelland's employment by Energy and for which benefits are payable only from the SERP.
Executive Severance Program
The Board approved an executive severance program in 1982 administered by the Compensation Committee. Pursuant to this program, Energy has entered into agreements (the "Executive Severance Agreements") with Messrs. Greehey, Benninger, McLelland and Fry. The Executive Severance Agreements provide payments and other benefits to the executives in the event of termination of their employment with Energy under certain circumstances. The Executive Severance Agreements provide that if the executive leaves the employ of Energy for any reason other than death, disability or normal retirement within two years after a change of control of Energy, the executives will receive a lump sum cash payment equal to three times (for Messrs. Greehey and McLelland) and two times (for Messrs. Benninger and Fry) the highest compensation paid to the executive during any consecutive 12-month period prior to termination. The executive will also be entitled to accelerated exercise of stock options or SARs previously granted under Energy's stock option plans and held for more than six months. If the executive received a grant of Restricted Stock under Energy's Restricted Stock Plan or L.P. Units under Energy's Preference Unit Award Plan, any restrictions imposed by such plans on the vesting and sale of the stock or L.P. Units are removed. The Executive Severance Agreements also provide (i) special retirement benefits if the executive would have qualified for benefits under Energy's Pension Plan had the executive remained in the employ of Energy for the three-year period following termination, (ii) continuance of life insurance, (iii) health coverages, (iv) other fringe benefits previously provided to the executive for such three-year period, and (v) relocation assistance if the executive chooses to relocate after termination. Although Energy has entered into employment agreements with various executive officers, including certain executive officers of the General Partner, neither the General Partner nor the Partnership is a party to these arrangements or directly obligated thereunder.
Compensation of Directors
Each director of VNGC is reimbursed for the usual and ordinary expenses of meeting attendance. Directors who are employees of Energy receive no compensation (other than reimbursement of usual and ordinary expenses of meeting attendance) for serving as directors. The compensation of each nonemployee director of VNGC is a retainer fee of $18,000 per year, plus $1,000 for each Board and committee meeting attended ($500 for telephonic meetings).
Retirement Plan for Nonemployee Directors
Effective January 1, 1992, the General Partner adopted a retirement plan for nonemployee directors (the "Retirement Plan"). Under the Retirement Plan, a nonemployee director is entitled to a retirement benefit upon completion of five years of service on the Board of Directors of the General Partner. The annual benefit at retirement is equal to the product of 10% of the highest annual cash retainer paid to the nonemployee director during the director's service on the Board, multiplied by the number of full and partial years of service on the Board (not to exceed 10 years). Retirement benefits are paid for a period equal to the shorter of the nonemployee director's number of whole and partial years of service on the Board, 10 years, or the remainder of the director's life. The Retirement Plan does not provide survivor benefits. It is an unfunded plan, the benefits of which are paid from the general assets of Energy. Amounts paid under the Retirement Plan are borne by the Partnership pursuant to the Partnership Agreements.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of December 31, 1993, with respect to each person (including any group as that term is used in Section 13(d)(3) of the Securities Exchange Act of 1934, as amended; the "Exchange Act") known to the General Partner to be the beneficial owner of more than five percent of any class of VNGP, L.P.'s voting securities:
The General Partner is unaware of any other person or group (as such term is defined in Section 13(d)(3) of the Exchange Act) that beneficially owns more than five percent of any class of VNGP, L.P.'s voting securities.
Except as otherwise indicated, the following table sets forth information as of December 31, 1993, regarding Common Units beneficially owned (or deemed to be owned) by each current director and all current directors and executive officers of the General Partner as a group. The following information was furnished to the General Partner by the persons listed below and cannot be independently verified by the General Partner.
Section 16 Reporting
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires the General Partner's executive officers and directors, and persons who own more than ten percent of a registered class of the Partnership's equity securities, to file reports of ownership and changes in ownership with the SEC and the New York Stock Exchange. Officers, directors and greater than ten-percent shareholders are required by SEC regulation to furnish to the Partnership copies of all forms filed pursuant to Section 16(a). Based on a review of the copies of such forms received by the Partnership, and based on written representations from certain reporting persons that no Forms 5 were required for those persons, the General Partner believes that its executive officers, directors and greater than ten-percent beneficial owners were in compliance with applicable requirements of Section 16(a) during the year ended December 31, 1993.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the ordinary course of business, the Partnership engages in various transactions with subsidiaries of Energy. A summary of the transactions is set forth at Note 1 of Notes to Consolidated Financial Statements under the heading "Transactions with Energy," and such information is incorporated herein by reference. The General Partner believes that all such transactions were made upon terms which would be obtained in similar transactions between unaffiliated parties and were fair and reasonable to the Partnership.
Pursuant to the respective Partnership Agreements of VNGP, L.P., the Management Partnership and the Subsidiary Operating Partnerships, the General Partner and Subsidiary General Partners receive a management fee equal to all expenses, disbursements and advances made in connection with the organization of the partnerships, the offering of the Partnership's securities and the First Mortgage Notes, the qualification of such partnerships to do business, all direct expenses incurred on behalf of such partnerships and all direct and indirect administration and incidental expenses incurred by the general partner in operating the partnership's business. See Note 1 of Notes to Consolidated Financial Statements under the heading "Transactions with Energy." The portion of executive compensation (including contributions under employee benefit plans) reimbursed by the Partnership and disclosed in "Item 11. Executive Compensation" is included in the amounts used to calculate the management fee payable to the General Partner.
The law firm of Hughes & Luce, Austin, Texas, has provided and continues to provide various legal services to Energy. Legal fees paid to the firm totalled approximately $42,000 in 1993. A portion of these fees may be paid by the Partnership relating to litigation or other matters involving the Partnership. Mr. Wallace, a director of the General Partner, is of counsel to such firm and, as such, has an indirect interest in the foregoing fees. However, it is not practicable to determine the exact amount of such interest. The General Partner believes that the legal fees paid to Hughes & Luce are comparable to fees the Partnership would pay to comparable firms.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements-
The following Consolidated Financial Statements of Valero Natural Gas Partners, L.P. and its consolidated subsidiaries are included in Part II, Item 8 of this Form 10-K:
Page Report of independent public accountants . . . . . . . . . 34 Consolidated balance sheets as of December 31, 1993 and 1992 . . . . . . . . . . . . . . . . . . . . . . . . . . 35 Consolidated statements of income for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . 36 Consolidated statements of partners' capital for the years ended December 31, 1993, 1992 and 1991 . . . . . . 37 Consolidated statements of cash flows for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . 38 Notes to consolidated financial statements . . . . . . . . 39
2. Financial Statement Schedules and Other Financial Information-
(A) Schedules required to be furnished for the years ended December 31, 1993, 1992 and 1991- Schedule V - Property, plant and equipment . . . . . . . . . . . . . . . . 71 Schedule VI - Accumulated depreciation, depletion and amortization of property, plant and equipment . . . . . . 72 Schedule IX - Short-term borrowings . . . . 73
All other schedules are not submitted because they are not applicable or because the required information is included in the financial statements or notes thereto.
3. Exhibits
Filed as part of this Form 10-K are the following exhibits:
Exhibit No.
2.1 - Agreement of Merger, dated December 20, 1993, among Valero Natural Gas Partners, L.P., Valero Merger Partnership, L.P., Valero Natural Gas Company and Valero Energy Corporation-- 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 - Second Amended and Restated Agreement of Limited Partnership of the Partnership, dated effective March 25, 1987 - 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 August 14, 1990). 4.1 - 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). 4.2 - 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). 4.3 - 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). 4.4 - 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). 4.5 - 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). 4.6 - 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). 4.7 - 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 - Assignment and Assumption Agreement, dated as of March 25, 1987, from Valero Transmission Company to Valero Transmission, L.P. - incorporated by reference from Exhibit 19.1 to the Valero Energy Corporation Quarterly Report on Form 10-Q (Commission File No. 1-4718, filed May 15, 1987). +10.2 - 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). +10.3 - 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). +10.4 - Valero Energy Corporation Amended and Restated Restricted Stock Bonus and Incentive Stock Plan dated as of January 24, 1984 (as amended through January 1, 1988) - incorporated by reference from Exhibit 10.19 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +*10.5 - Valero Energy Corporation Stock Option Plan No. 3, as amended and restated effective November 28, 1993. +*10.6 - Valero Energy Corporation Stock Option Plan No. 4 as amended and restated effective November 28, 1993. +10.7 -- Valero Energy Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 1990--incorporated by reference from Exhibit 10.24 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1991). +10.8 - Valero Energy Corporation Executive Incentive Bonus Plan--incorporated by reference from Exhibit 10.9 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 20, 1992). +10.9 - Executive Severance Agreement between Valero Energy Corporation and William E. Greehey, dated December 15, 1982--incorporated by reference from Exhibit 10.11 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). +10.10 - Schedule of Executive Severance Agreements-- incorporated by reference from Exhibit 10.12 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). +10.11 - Indemnity Agreement, dated as of March 23, 1987, between Valero Natural Gas Company and William E. Greehey--incorporated by reference from Exhibit 10.13 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 Indemnity Agreements--incorporated by reference from Exhibit 10.14 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). 21.1 - Valero Natural Gas Partners, L.P. subsidiaries, including state or other jurisdiction of organization--incorporated by reference from Exhibit 22.1 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). *24.1 - Power of Attorney, dated March 1, 1994 is set forth at the signatures page of this Report on Form 10-K. _______________ * Filed herewith + Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K.
Copies of exhibits filed as a part of this Form 10-K may be obtained by Unitholders of record at a charge of $.15 per page, minimum $5.00 each request. Direct inquiries to Rand C. Schmidt, Corporate Secretary, Valero Natural Gas Company, P.O. Box 500, San Antonio, Texas 78292.
Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S-K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the Commission upon its request, copies of certain instruments, each relating to long- term debt not exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis.
(b) No reports on Form 8-K were filed during the fourth quarter of 1993.
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 NATURAL GAS PARTNERS, L.P. (Registrant) By Valero Natural Gas Company, its General Partner
By /s/ William E. Greehey (William E. Greehey) Chairman of the Board and Chief Executive Officer
Date: March 1, 1994
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints William E. Greehey, Stan L. McLelland and Rand C. Schmidt, or any of them, each with power to act without the other, his true and lawful attorney-in-fact and agent, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any or all subsequent amendments and supplements to this Annual Report on Form 10-K, and to file the same, or cause to be filed the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto each said attorney-in-fact and agent full power to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby qualifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof. ________________________ Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. All such capacities are with Valero Natural Gas Company, General Partner of the registrant.
Signature Title Date Director, Chairman of the Board and Chief Executive Officer (Principal /s/ William E. Greehey Executive Officer) March 1, 1994 (William E. Greehey)
Senior Vice President and Chief Financial Officer (Principal Financial and /s/ Don M. Heep Accounting Officer) March 1, 1994 (Don M. Heep)
/s/ Edward C. Benninger Director March 1, 1994 (Edward C. Benninger)
/s/ Ronald K. Calgaard Director March 1, 1994 (Ronald K. Calgaard)
/s/ Ruben M. Escobedo Director March 1, 1994 (Ruben M. Escobedo)
/s/ Stan L. McLelland Director March 1, 1994 (Stan L. McLelland)
/s/ Mack Wallace Director March 1, 1994 (Mack Wallace)