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.
<PAGE>
CONTENTS
PAGE
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K . . . . . . . . . . . . .
<PAGE>
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.
<PAGE>
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
<PAGE>
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
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:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Transportation volumes . . . . . . . 1,566 1,301 1,132
Average transportation fee per Mcf . $.108 $.118 $.135
</TABLE>
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:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
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
<FN>
(3) Represents the average Houston area market prices for
individual NGL products weighted by relative volumes of each
product produced.
</TABLE>
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.
