-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, QyJyxI9vcZn+/5JuSP8j3sdjkM55Y6tzqWk0KfTHm2jxP3F2a70HsvAWdDaYQwFh +q28ybsR4wsDbsDG/PiSEw== 0000021271-94-000003.txt : 19940304 0000021271-94-000003.hdr.sgml : 19940304 ACCESSION NUMBER: 0000021271-94-000003 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940302 FILER: COMPANY DATA: COMPANY CONFORMED NAME: VALERO ENERGY CORP CENTRAL INDEX KEY: 0000021271 STANDARD INDUSTRIAL CLASSIFICATION: 2911 IRS NUMBER: 741244795 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 34 SEC FILE NUMBER: 001-04718 FILM NUMBER: 94514376 BUSINESS ADDRESS: STREET 1: 530 MCCULLOUGH AVE CITY: SAN ANTONIO STATE: TX ZIP: 78215 BUSINESS PHONE: 2102462000 FORMER COMPANY: FORMER CONFORMED NAME: COASTAL STATES GAS PRODUCING CO DATE OF NAME CHANGE: 19791115 10-K/A 1 AMENDMENT NO. 1 TO FORM 10-K FORM 10-K/A SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1993 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-4718 VALERO ENERGY CORPORATION (Exact name of registrant as specified in its charter) Delaware 74-1244795 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 530 McCullough Avenue 78215 San Antonio, Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code (210) 246-2000 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Common Stock, $1 Par Value New York Stock Exchange Preference Share Purchase Rights New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: NONE. Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value on February 14, 1994, of the registrant's Common Stock held by nonaffiliates of the registrant, based on the average of the high and low prices as quoted in the New York Stock Exchange Composite Transactions listing for such date, was approximately $966 million. The registrant also has outstanding 138,000 voting shares of its Preferred Stock, $8.50 Cumulative Series A, for which there is no readily ascertainable market value. As of February 14, 1994, 43,334,901 shares of the registrant's Common Stock, $1.00 par value, were issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE The Company intends to file with the Securities and Exchange Commission (the "Commission") in March 1994 a definitive Proxy Statement (the "1994 Proxy Statement") for the Company's Annual Meeting of Stockholders scheduled for April 28, 1994, at which directors of the Company will be elected. Portions of the 1994 Proxy Statement are incorporated by reference in Part III of this Form 10-K and shall be deemed to be a part hereof. CONTENTS PAGE PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) 1. Financial Statements- The following Consolidated Financial Statements of Valero Energy Corporation and its subsidiaries are included in Part II, Item 8 of this Form 10-K: Page Report of independent public accountants . . . . . . . . . Consolidated balance sheets as of December 31, 1993 and 1992 . . . . . . . . . . . . . . . . . . . . . . . . Consolidated statements of income for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . Consolidated statements of common stock and other stockholders' equity for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . . . . Consolidated statements of cash flows for the years ended December 31, 1993, 1992 and 1991 . . . . . . . . . Notes to consolidated financial statements . . . . . . . . 2. Financial Statement Schedules and Other Financial Information- (A) Schedules required to be furnished for the years ended December 31, 1993, 1992 and 1991- Schedule V-Property, plant and equipment. . . . . . . . . . . . . . . Schedule VI-Accumulated depreciation, depletion and amortization of property, plant and equipment. . . . . Schedule IX-Short-term borrowings. . . . All other schedules are not submitted because they are not applicable or because the required information is included in the financial statements or notes thereto. 3. Exhibits Filed as part of this Form 10-K are the following exhibits: 2.1 - Agreement of Merger, dated December 20, 1993, among Valero Energy Corporation, Valero Natural Gas Partners, L.P., Valero Natural Gas Company and Valero Merger Partnership, L.P.-- incorporated by reference from Exhibit 2.1 to Amendment No. 2 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-70454, filed December 29, 1993). 3.1 -- Restated Certificate of Incorporation of Valero Energy Corporation--incorporated by reference from Exhibit 4.1 to the Valero Energy Corporation Registration Statement on Form S-8 (Commission File No. 33-53796, filed October 27, 1992). 3.2 -- By-Laws of Valero Energy Corporation, as amended and restated October 17, 1991--incorporated by reference from Exhibit 4.2 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-45456, filed February 4, 1992). 3.3 -- Amendment to By-Laws of Valero Energy Corporation, as adopted February 25, 1993-- incorporated by reference from Exhibit 3.3 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). 4.1 -- Amended and Restated Rights Agreement, dated as of October 17, 1991, between Valero Energy Corporation and Ameritrust Texas, N.A., successor to Mbank Alamo, N.A., as Rights Agent --incorporated by reference from Exhibit 1 to the Valero Energy Corporation Current Report on Form 8-K (Commission File No. 1- 4718, filed October 18, 1991). 4.2 -- $200,000,000 Senior Notes Purchase Agreement dated as of December 19, 1990--incorporated by reference from Exhibit 4.2 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 21, 1992). 4.3 -- $160,000,000 Amended and Restated Credit Agreement, dated as of December 4, 1992, among Valero Refining Company, Bankers Trust Company, as Agent and certain other banks party thereto--incorporated by reference from Exhibit 4.3 to the Valero Energy Corporation Form 10-K (Commission File No. 1-4718, filed February 26, 1993). 4.4 -- First Amendment to Amended and Restated Credit Agreement, dated as of August 25, 1993-- incorporated by reference from Exhibit 4.5 to the Valero Energy Corporation Registration Statement on Form S-3 (Commission File No. 33-70454, filed October 18, 1993). *4.5 -- Second Amendment to Amended and Restated Credit Agreement, dated as of December 31, 1993. +10.1 -- Valero Energy Corporation Executive Deferred Compensation Plan, amended and restated as of October 21, 1986--incorporated by reference from Exhibit 10.16 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.2 -- Valero Energy Corporation Key Employee Deferred Compensation Plan, amended and restated as of October 21, 1986--incorporated by reference from Exhibit 10.17 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.3 -- Valero Energy Corporation Amended and Restated Restricted Stock Bonus and Incentive Stock Plan dated as of January 24, 1984 (as amended through January 1, 1988)--incorporated by reference from Exhibit 10.19 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1988). +10.4 -- Valero Energy Corporation Stock Option Plan No. 3, as amended and restated November 28, 1993--incorporated by reference from Exhibit 10.5 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed March 1, 1994). +10.5 -- Valero Energy Corporation Stock Option Plan No. 4, as amended and restated effective November 28, 1993--incorporated by reference from Exhibit 10.6 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed March 1, 1994). +10.6 -- Valero Energy Corporation 1990 Restricted Stock Plan for Non-Employee Directors, dated effective as of November 14, 1990--incorporated by reference from Exhibit 10.23 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1- 4718, filed February 26, 1991). +10.7 -- Valero Energy Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 1990--incorporated by reference from Exhibit 10.24 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1- 4718, filed February 26, 1991). +10.8 -- Valero Energy Corporation Executive Incentive Bonus Plan--incorporated by reference from Exhibit 10.9 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-4718, filed February 20, 1992). +10.9 -- Executive Severance Agreement between Valero Energy Corporation and William E. Greehey, dated December 15, 1982--incorporated by reference from Exhibit 10.11 to the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K (Commission File No. 1-9433, filed February 25, 1993). +10.10 -- Schedule of Executive Severance Agreements-- incorporated by reference from Exhibit 10.12 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). +10.11 -- Employment Agreement between Valero Energy Corporation and William E. Greehey, dated May 16, 1990--incorporated by reference from Exhibit 10.1 to the Valero Energy Corporation Quarterly Report on Form 10-Q (Commission File No. 1-4718, filed November 14, 1990). +10.12 -- Indemnity Agreement, dated as of February 24, 1987, between Valero Energy Corporation and William E. Greehey--incorporated by reference from Exhibit 10.16 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). +10.13 -- Schedule of Indemnity Agreements--incorporated by reference from Exhibit 10.17 to the Valero Energy Corporation Annual Report on Form 10-K (Commission File No. 1-4718, filed February 26, 1993). *11 -- Computation of Earnings Per Share. *21.1 -- Valero Energy Corporation subsidiaries, including state or other jurisdiction of incorporation or organization. *23.1 -- Consent of Arthur Andersen & Co., dated March 1, 1994. *24.1 -- Power of Attorney, dated March 1, 1994--set forth at the signatures page of this Form 10-K. *99.1 -- Items 1 through 3 of the Valero Natural Gas Partners, L.P. Annual Report on Form 10-K for the year ended December 31, 1993. ______________ * Filed herewith + Identifies management contracts or compensatory plans or arrangements required to be filed as an exhibit hereto pursuant to Item 14(c) of Form 10-K. Copies of exhibits filed as a part of this Form 10-K may be obtained by stockholders of record at a charge of $.15 per page, minimum $5.00 each request. Direct inquiries to Rand C. Schmidt, Corporate Secretary, Valero Energy Corporation, P.O. Box 500, San Antonio, Texas 78292. Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S- K, the registrant has omitted from the foregoing listing of exhibits, and hereby agrees to furnish to the Commission upon its request, copies of certain instruments, each relating to long- term debt not exceeding 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. (b) No reports on Form 8-K were filed during the three- month period ended December 31, 1993. For the purposes of complying with the rules governing Form S-8 under the Securities Act of 1933, the undersigned registrant hereby undertakes as follows, which undertaking shall be incorporated by reference into registrant's Registration Statements on Form S-8 No. 2-66297 (filed December 21, 1979), No. 2-82001 (filed February 23, 1983), No. 2-97043 (filed April 15, 1985), No. 33-23103 (filed July 15, 1988), No. 33-14455 (filed May 21, 1987), No. 33-38405 (filed December 3, 1990) and No. 33-53796 (filed October 27, 1992). Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized. VALERO ENERGY CORPORATION (Registrant) By /s/ Don M. Heep (Don M. Heep) Senior Vice President and Chief Financial Officer Date: March 2, 1994 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date Director, Chairman of the Board and Chief Executive Officer (Principal /s/ * Executive Officer) March 2, 1994 (William E. Greehey) Senior Vice President and Chief Financial Officer (Principal Financial /s/ * and Accounting Officer) March 2, 1994 (Don M. Heep) /s/ * Director March 2, 1994 (Edward C. Benninger) /s/ * Director March 2, 1994 (Robert G. Dettmer) /s/ * Director March 2, 1994 (A. Ray Dudley) /s/ * Director March 2, 1994 (James L. Johnson) /s/ * Director March 2, 1994 (Lowell H. Lebermann) /s/ * Director March 2, 1994 (Sally A. Shelton) Director (Philip K. Verleger, Jr.) * By: /s/ Rand C. Schmidt (Rand C. Schmidt) Attorney-in-Fact EX-99.1 2 ITEMS 1 THROUGH 3 OF VNGP. L.P. ANNUAL RPT ON FORM 10-K PART I 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 terms 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 fourth 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:
Year Ended December 31, 1993 1992 1991 Intrastate sales: SMPs and other . . . . . . . . . . 642 552 545 Transmission . . . . . . . . . . . 57 78 103 Total intrastate sales . . . . 699 630 648 Interstate sales . . . . . . . . . . 281 259 363 Total sales. . . . . . . . . . 980 889 1,011 Transportation . . . . . . . . . . . 1,566 1,301 1,132 Total gas throughput . . . . . 2,546 2,190 2,143
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:
Year Ended December 31, 1993 1992 1991 Transportation volumes . . . . . . . 1,566 1,301 1,132 Average transportation fee per Mcf . $.108 $.118 $.135
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:
Year Ended December 31, 1993 1992 1991 NGL plant production . . . . . . . . 67.9 57.2 50.5 Average market price per gallon (3). $.290 $.314 $.326 Average gas cost per MMbtu . . . . . $1.96 $1.61 $1.42 (3) Represents the average Houston area market prices for individual NGL products weighted by relative volumes of each product produced.
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. 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. 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 to 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. -----END PRIVACY-ENHANCED MESSAGE-----