FORM 10-K
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>
CROSS REFERENCE SHEET
The following table indicates the headings in the 1994 Proxy
Statement where the information required in Part III of Form 10-K
may be found.
Form 10-K Item No. and Caption Heading in 1994 Proxy Statement
10. "Directors and Executive
Officers of the
Registrant" . . . . . . "Proposal No. 1 - Election
of Directors" and "Information
Concerning Directors (Classes I
and III)"
11. "Executive Compensation" . "Information Concerning
Executive Compensation,"
"Arrangements with Certain
Officers and Directors" and
"Compensation of Directors"
12. "Security Ownership of
Certain Beneficial
Owners and Management" . "Beneficial Ownership of Voting
Securities"
13. "Certain Relationships and
Related Transactions". . "Transactions with Management
and Others"
Copies of all documents incorporated by reference, other
than exhibits to such documents, will be provided without charge
to each person who receives a copy of this Form 10-K upon written
request to Rand C. Schmidt, Corporate Secretary, Valero Energy
Corporation, P.O. Box 500, San Antonio, Texas 78292.
<PAGE>
CONTENTS
PAGE
Cross Reference Sheet. . . . . . . . . . . . . .
PART I
Item 1. Business. . . . .. . . . . . . . . . . . . . . .
Recent Developments. . . . . . . . . . . . . . .
Proposal to Acquire the Partnership . . . . .
Convertible Preferred Stock Offering. . . . .
Decline of Crude Oil and Refined Product
Prices . . . . . . . . . . . . . . . . . .
Refinery Facilities Additions . . . . . . . .
MTBE Plant in Mexico. . . . . . . . . . . . .
Petroleum Refining and Marketing . . . . . . . .
Refining Operations . . . . . . . . . . . . .
Feedstock Supply. . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . .
Factors Affecting Operating Results . . . . .
Other Projects. . . . . . . . . . . . . . . .
Valero Natural Gas Partners, L.P.. . . . . . . .
Natural Gas Operations. . . . . . . . . . . .
Natural Gas Liquids Operations. . . . . . . .
Other Natural Gas Operations . . . . . . . . . .
Governmental Regulations . . . . . . . . . . . .
Texas Regulation. . . . . . . . . . . . . . .
Federal Regulation. . . . . . . . . . . . . .
Environmental Matters. . . . . . . . . . . . . .
Competition. . . . . . . . . . . . . . . . . . .
Employees. . . . . . . . . . . . . . . . . . . .
Executive Officers of the Registrant . . . . . .
Item 2. Properties . . . . . . . . . . . . . . . . . . .
Item 3. Legal Proceedings. . . . . . . . . . . . . . . .
Item 4. Submission of Matters to a Vote of Security
Holders . . . . . . . . . . . . . . . . . . .
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters . . . . . . . . .
Item 6. Selected Financial Data. . . . . . . . . . . . .
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations. . . . . . . . . . . . . . . . . .
Item 8. Financial Statements and Supplementary Data. . .
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure. . . .
PART III
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K . . . . . . . . . . . . .
<PAGE>
PART I
ITEM 1. BUSINESS
Valero Energy Corporation was incorporated under the
laws of the State of Delaware in 1955 and became a publicly held
corporation in 1979. Its principal executive offices are located
at 530 McCullough Avenue, San Antonio, Texas 78215 (telephone
number 210/246-2000). Unless otherwise required by the context,
the term "Energy" as used herein refers to Valero Energy
Corporation, and the term "Company" refers to Energy and its
consolidated subsidiaries individually and collectively.
The Company's principal business is petroleum refining
and marketing. Valero Refining Company ("VRC"), a wholly owned
subsidiary of Valero Refining and Marketing Company ("VRMC"),
owns a specialized petroleum refinery in Corpus Christi, Texas
(the "Refinery") and engages in petroleum refining and marketing
operations. VRMC is a wholly owned subsidiary of Energy. VRMC
and VRC are collectively referred to herein as "Refining."
The Company also owns an approximate 49% effective
equity interest in Valero Natural Gas Partners, L.P. and its
subsidiaries, which own and operate natural gas pipeline systems
serving Texas intrastate and certain interstate markets. Valero
Natural Gas Partners, L.P. and its subsidiaries also process
natural gas for the extraction of natural gas liquids ("NGL").
See "Valero Natural Gas Partners, L.P." Unless otherwise
required by the context, the term "VNGP, L.P." as used herein
refers to Valero Natural Gas Partners, L.P. and the term
"Partnership" refers to VNGP, L.P. and its consolidated
subsidiaries individually and collectively. The Company's
investment in and equity in earnings of the Partnership are shown
separately in the accompanying consolidated financial statements.
In addition to its interest in the Partnership, the Company owns
a natural gas processing plant, a natural gas pipeline and
certain natural gas liquids fractionation facilities that the
Company leases to the Partnership. The Company also owns two
additional natural gas processing plants, related gathering lines
and a natural gas liquids line that the Partnership operates for
a fee. See "Other Natural Gas Operations."
For additional financial and statistical information
regarding the Company's operations, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations"
and Note 10 of Notes to Consolidated Financial Statements. For
information regarding cash flows provided by and used in the
Company's operations, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations - Liquidity and
Capital Resources."
RECENT DEVELOPMENTS
Proposal to Acquire the Partnership
Effective December 20, 1993, Energy, VNGP, L.P. and
Valero Natural Gas Company ("VNGC"), the general partner of VNGP,
L.P., entered into an agreement of merger (the "Merger
Agreement") providing for the merger of VNGP, L.P. with a wholly
owned subsidiary of Energy (the "Merger"). In the Merger, the
9.7 million issued and outstanding common units of limited
partner interests ("Common Units") in VNGP, L.P. held by persons
other than the Company (the "Public Unitholders") will be
converted into a right to receive cash in the amount of $12.10
per Common Unit, and VNGP, L.P. will become a wholly owned
subsidiary of Energy. A special committee of outside directors
(the "Special Committee") of VNGC, appointed to consider the
fairness of the transaction to the Public Unitholders, has
received an opinion from its independent financial advisor that
the consideration to be received by the Public Unitholders in the
transaction is fair from a financial point of view. The Special
Committee has determined that such transaction is fair to, and in
the best interest of, the Public Unitholders. The Board of
Directors of VNGC has unanimously recommended that the Public
Unitholders vote in favor of the Merger. The transaction is
subject, among other things, to: (i) approval by the holders of a
majority of the issued and outstanding Common Units; (ii)
approval by the holders of a majority of the Common Units held by
the Public Unitholders and voted at a special meeting to be
called for the purpose of considering the Merger; (iii) receipt
of satisfactory waivers, consents or amendments to certain of the
Company's financial agreements; and (iv) completion of an
underwritten public offering of preferred stock by Energy. See
"Recent Developments - Convertible Preferred Stock Offering." A
proposal to approve the Merger will be submitted to the holders
of Common Units at the special meeting of Unitholders tentatively
scheduled to be held during the second quarter of 1994. The
Company owns approximately 47.5% of the outstanding Common Units
and intends to vote its Common Units in favor of the Merger.
There can be no assurance, however, that the Merger will be
completed. The foregoing discussion of the Merger omits certain
information contained in the Merger Agreement. Statements in this
Report concerning the Merger Agreement are not necessarily
complete, and are qualified by and are made subject to the Merger
Agreement filed as an exhibit to this Report.
The Company believes that the natural gas and NGL
industries are undergoing a period of restructuring and
consolidation that may create opportunities for expansions,
acquisitions or strategic alliances which, if the Partnership
could take advantage of them, could enable the Partnership to
compete more effectively in the competitive natural gas
environment. Because of Federal Energy Regulatory Commission
("FERC") Order No. 636 ("Order 636") which requires interstate
pipeline companies to offer services on an unbundled,
nondiscriminatory basis, the Company believes that intrastate
pipelines such as the Partnership may enjoy increased
opportunities to compete for interstate business. In addition,
an emerging trend of west-to-east movement of gas may provide
beneficial transportation opportunities for the Partnership if
the Partnership were able to make the necessary capital
expenditures for added west-to-east capacity on its pipeline
system. However, the Partnership's competitive position could be
eroded if the Partnership is unable to respond effectively to the
changing dynamics of the industry. The Merger was proposed
because the Company believes that the Partnership has
insufficient financial flexibility to participate fully in
opportunities that may arise in the natural gas and NGL
industries. The Company believes that the ability of the
Partnership to compete effectively in these businesses will be
enhanced through the Merger. The Company also believes that
potential conflicts of interest between the Partnership and the
Company can be eliminated through the Merger.
Convertible Preferred Stock Offering
During the fourth quarter of 1993, Energy filed a
registration statement on Form S-3 (as amended, the "Registration
Statement"), registering for issuance and sale in an underwritten
public offering (the "Public Offering") $150 million (up to
$172.5 million with underwriters' over-allotments) of a series of
Energy's authorized but unissued Preferred Stock. Energy intends
to offer for sale up to 3,000,000 shares (3,450,000 shares with
underwriters' over-allotments) of convertible preferred stock in
the Public Offering (the "New Preferred Stock"). Energy intends
to use a portion of the proceeds from the Public Offering to fund
the cash payment to the Public Unitholders contemplated by the
Merger. See "Recent Developments - Proposal to Acquire the
Partnership." Any remaining proceeds will be used to pay
expenses of the Merger and for general corporate purposes,
including the reduction of existing indebtedness under the
Company's bank credit agreements. If the Merger is not
consummated, the proceeds from the Public Offering will be added
to the Company's funds and used for general corporate purposes,
including repayment of indebtedness, financing of capital
projects and additions to working capital. Offers to sell or the
solicitation of offers to buy shares of the New Preferred Stock
will be made exclusively by means of a prospectus complying in
all respects with the Securities Act of 1933, as amended. The
description of the New Preferred Stock herein is not and shall
not be construed as an offer to sell or the solicitation of an
offer to buy any shares of the New Preferred Stock.
Decline of Crude Oil and Refined Product Prices
Beginning in November 1993, crude oil prices fell
significantly and have not recovered to prior levels. During the
November 1993 meeting of the Organization of Petroleum Exporting
Countries ("OPEC"), the member countries declined to adopt any
cuts in crude oil production. This decision, combined with
increased production from non-OPEC regions, continued uncertainty
regarding Iraq's possible re-entry into world oil markets and
weakened global demand for energy, caused a precipitous drop in
crude oil prices to their lowest levels in five years. Refined
product and NGL prices fell in conjunction with the decline in
crude oil prices. Moreover, refined product and NGL prices were
further depressed due to continued high refinery-capacity
utilization rates and unusually high gasoline and NGL
inventories. These conditions caused a substantial decline in
refining margins and required the Company to write down the
carrying value of its refinery inventories as of December 31,
1993. See Note 1 of Notes to Consolidated Financial Statements.
The conditions causing the recent decline in crude oil, refined
product and NGL prices have continued in 1994. Although refined
product prices and refining margins have increased modestly since
late December 1993, the Company's operating income and net income
in the first quarter of 1994 are expected to be in the same
range as operating income and net income for the fourth quarter
of 1993, excluding the effect of the write-down in the carrying
value of the Company's refinery inventories.
Refinery Facilities Additions
During 1993, the Company added certain facilities at the
Refinery to enable the Company to produce reformulated gasolines
containing the levels of oxygenates required by the Clean Air Act
Amendments of 1990 (the "Clean Air Act"). A facility to produce
methyl tertiary butyl ether ("MTBE") from butane feedstock (the
"Butane Upgrade Facility") was placed in service during the
second quarter of 1993. MTBE is a high-octane blendstock used to
manufacture oxygenated and reformulated gasolines. The Butane
Upgrade Facility can produce 15,000 barrels per day of MTBE. The
Company can blend the MTBE produced at the Refinery into the
Company's own gasoline cargos or sell the MTBE separately as a
gasoline blendstock. All the butane feedstocks required to
operate the Butane Upgrade Facility are available to the Company
through the Refinery's and the Partnership's operations.
In November 1993, the Company placed in service an
MTBE/TAME complex (the "MTBE/TAME Complex"). The MTBE/TAME
Complex converts streams currently produced at the Refinery's
heavy oil cracker into about 2,500 barrels per day of MTBE and
3,000 barrels per day of tertiary amyl methyl ether ("TAME").
TAME, like MTBE, is a high-octane, oxygen-rich gasoline
blendstock. The Butane Upgrade Facility and MTBE/TAME Complex
enable the Company to produce approximately 20,000 barrels per
day of oxygenates for gasoline blending.
During the fourth quarter of 1993, the Company also
placed in service a 25,000 barrel per day reformate splitter (the
"Reformate Splitter"). The Reformate Splitter extracts a benzene
concentrate stream from reformate produced at the Refinery's
naphtha reformer unit. The benzene concentrate stream may be
shipped to other refineries that can recover and purchase the
benzene at market prices and then return the balance of the
concentrate stream to the Company for gasoline blending or for
sale as a petrochemical feedstock. The 1993 facilities additions
enable the Company to produce all of its gasoline as reformulated
gasoline and represent investments totalling approximately
$300 million.
MTBE Plant in Mexico
Productos Ecologicos, S.A. de C.V., a Mexican
corporation ("Proesa"), has executed a Memorandum of
Understanding with Petroleos Mexicanos, the Mexican state-owned
oil company ("PEMEX"), to construct a MTBE plant in Mexico, and
has proposed a butane supply contract and MTBE sales contract
with PEMEX. Proesa is owned 35% by the Company; 10% by Dragados
y Construcciones, the largest construction company in Spain; and
55% by a corporation formed by Banamex, Mexico's largest bank,
and Groupo Infomin, a privately held Mexican company. Proesa has
also executed an option agreement for a plant site near the Bay
of Campeche. The proposed Mexican MTBE plant is expected to have
a capacity of approximately 15,000 barrels per day and to be
similar to the Refinery's Butane Upgrade Facility. The project
is expected to cost approximately $440 million and is subject to,
among other things, the arrangement of satisfactory financing.
Proesa has been advised by lenders with whom it is negotiating
for project financing that certain provisions will be required in
the proposed PEMEX contracts in order to secure satisfactory
financing for the project. Proesa has entered into negotiations
with PEMEX regarding such provisions.
As a result of delays incurred in completing financing,
Proesa has determined that the commencement of plant construction
will be delayed. If satisfactory financing is obtained,
construction of the MTBE plant could not begin before late 1994,
with approximately two years required for completion. As of
February 1994, no material amounts have been invested in the
project. The amount of the Company's equity contribution will
depend upon the level of debt financing obtained by Proesa and
the ultimate equity interest of each partner. Under the proposed
commercial contracts, PEMEX will purchase approximately 75% of
the MTBE plant's production, one-half at a formula price and
one-half at market-related prices, with the remainder of the
plant's production being sold to the Company at a formula price.
In addition, the butane feedstocks required by the plant will be
purchased from PEMEX at market-related prices. A subsidiary of
Energy has agreed to provide technical advice and assistance to
Proesa in connection with the design, engineering, construction
and operation of the MTBE plant. There can be no assurance that
financing for the project can be obtained or that the plant will
be constructed.
PETROLEUM REFINING AND MARKETING
Refining Operations
The Refinery is designed to process primarily high-
sulfur atmospheric tower bottoms, a type of residual fuel oil
("resid"), into a product slate of higher value products,
principally unleaded gasoline and middle distillates. The
Refinery also processes crude oil, butanes and other feedstocks.
The Refinery can produce approximately 140,000 barrels per day of
refined products, with gasoline and gasoline-related products
comprising approximately 85% of the Refinery's throughput. The
remaining product slate from the Refinery is primarily middle
distillates. The Refinery has substantial flexibility to vary
its mix of gasoline products to meet changing market conditions.
Refining owns feedstock and product storage facilities with a
capacity of approximately 6.4 million barrels. Approximately
4.1 million barrels of storage capacity are heated tanks for
heavy feedstocks. During 1994, the Company anticipates having
approximately 850,000 barrels of fuel oil storage available under
lease in Malta. The Malta storage site will allow the Company to
accumulate small parcels of high-sulfur resid for shipment to the
Refinery. Refining also owns dock facilities that can
simultaneously unload two 150,000 dead weight ton capacity ships
and can dock larger crude carriers after partial unloading.
One of the Refinery's principal operating units is a
hydrodesulfurization unit ("HDS Unit"), which removes sulfur and
metals from resid, thereby improving its subsequent cracking
characteristics. The HDS Unit has a capacity of approximately
64,000 barrels per day. The Refinery's other principal unit is a
heavy oil cracking complex ("HOC"), which processes feedstock
primarily from the HDS Unit. The capacity of the HOC is
approximately 66,000 barrels per day. The Refinery also has a
hydrocracker with a capacity of approximately 34,000 barrels per
day (the "Hydrocracker"), a continuous catalyst regeneration
reformer with a capacity of approximately 31,000 barrels per day
(the "Reformer"), and a reformer feed hydrotreater, hydrogen
purification unit and related equipment (collectively, the "H/R
Units"). The Hydrocracker processes gas oil and distillate
streams from the Refinery to produce reformer feed naphtha. The
Hydrocracker naphtha and other naphtha streams produced at the
Refinery provide feed for the Reformer to produce reformate, a
high-octane, low vapor pressure gasoline blendstock, and other
products. The Refinery's other refining units include a
30,000 barrel per day crude unit and a 24,000 barrel per day
vacuum unit. In 1993, the Company added the Butane Upgrade
Facility, MTBE/TAME Complex and Reformate Splitter. See "Recent
Developments - Refinery Facilities Additions" for a discussion of
these facilities.
The HDS Unit was down 15 days for a scheduled
maintenance and catalyst change completed in December 1993. The
Refinery's principal refining units operated during 1991, 1992
and 1993 with no significant unscheduled downtime. The HOC is
scheduled for a turnaround in late 1994. For additional
information with respect to Refining's operating results for the
three years ended December 31, 1993, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
Feedstock Supply
The principal feedstock for the Refinery is resid
produced at refineries outside the United States. Most of the
large refineries in the United States are complex, sophisticated
facilities able to convert internally produced resid into higher
value products. Many overseas refineries are less sophisticated,
process smaller portions of resid internally and, therefore,
produce larger volumes of resid for sale. As a result, Refining
acquires and expects to acquire most of its resid in
international markets. A substantial portion of Refining's
feedstock supplies are obtained from Middle Eastern sources.
These supplies are loaded aboard chartered vessels at ports in
the Arabian Gulf and are subject to the usual maritime hazards.
Refining maintains insurance on its feedstock cargos.
Under a feedstock supply agreement with the Company,
Saudi Aramco (successor to the Saudi Arabian Marketing and
Refining Company "SAMAREC") has agreed to provide an average of
55,000 barrels per day of resid to the Company at market-related
prices. Deliveries under the agreement will continue through
1994 and provide approximately 75% of Refining's resid
requirements. During 1993, Refining also purchased approximately
11,000 barrels per day of South Korean resid at market-related
prices under an agreement which expires in the first quarter of
1994. The Company is negotiating to renew the agreement for
South Korean resid on pricing terms more favorable to the Company
than the existing contract. The Company also renewed a contract
for approximately 22,000 barrels of crude produced in the
People's Republic of China. Although the volume for this
contract has been committed to the Company, the price must be
renegotiated each quarter. The remainder of the Refinery's
feedstocks are purchased at market-based prices under short-term
contracts. The Company believes that if any of Refining's
existing feedstock arrangements were interrupted, adequate
supplies of feedstock could be obtained from other sources or on
the open market.
Resid generally sells at a discount to crude oil. In
recent years, however, developments in the market have reduced
this discount. The Company generally expects the long-term trend
in the relationship between the supply of and demand for resid to
be favorable, and expects resid to continue to sell at a discount
to crude oil. In the short term, other factors, including price
volatility and political developments, are likely to play an
important role in refining industry economics. See "Recent
Developments - Decline in Crude Oil and Refined Product Prices."
Sales
Set forth below is a summary of Refining's throughput
volumes per day, average throughput margin per barrel and sales
volumes per day for the three years ended December 31, 1993.
Average throughput margin per barrel is computed by subtracting
total direct product cost of sales from product sales revenues
and dividing the result by throughput.
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991(1)
<S> <C> <C> <C>
Throughput volumes (Mbbls per day). . 136 119 82
Average throughput margin per barrel. $5.99(2) $7.00 $8.84
Sales volumes (Mbbls per day) . . . . 133 123 97
<FN>
(1) The operating statistics for 1991 are for the HDS/HOC
complex which, prior to commencement of operations of the
H/R Unit in 1992, were the principal refining units located
at the Refinery. As a result, the throughput volumes and
margins are not totally comparable.
(2) Throughput margins for 1993 exclude a $.55 per barrel
reduction resulting from the effect of a $27.6 million
inventory write-down in the carrying value of the Company's
refinery inventories. See Note 1 of Notes to Consolidated
Financial Statements. For a discussion of the decline in
average throughput margin per barrel, see "Management's
Discussion and Analysis of Financial Condition and Results
of Operations."
</TABLE>
Refining sells refined products principally on a spot
and truck rack basis. A truck rack sale is a sale to a customer
that provides trucks to take delivery at loading facilities. In
1993, spot and truck rack sales volumes accounted for 79% and
21%, respectively, of combined gasoline and distillate sales.
Spot sales of Refining's products are made principally to larger
oil companies and gasoline distributors. The principal
purchasers of Refining's products from truck racks have been
wholesalers and jobbers in the southeastern and midwestern United
States. Refining's products are transported through
common-carrier pipelines, barges and tankers. Interconnects with
common-carrier pipelines give Refining the flexibility to sell
products to the midwestern or southeastern United States.
Factors Affecting Operating Results
Refining's results of operations are determined
principally by the relationship between refined product prices
and resid prices, which in turn are largely determined by market
forces. In recent years, the crude oil and refined product
markets have experienced periods of extreme price volatility.
During such periods, disproportionate changes in the prices of
refined products and resid usually occur. Such changes have
sometimes reduced margins, and, in some cases, such as in August
1990 at the beginning of the Arabian Gulf crisis, margins have
expanded significantly. During the fourth quarter of 1993,
however, refined product prices fell sharply, significantly
reducing margins and requiring a writedown of the carrying value
of the Company's Refinery inventories. See "Recent
Developments - Decline of Crude Oil and Refined Product Prices"
and Note 1 of Notes to Consolidated Financial Statements. The
potential impact of changing crude oil and refined product prices
on Refining's results of operations is further affected by the
fact that, on average, Refining buys its resid feedstock
approximately 40 days prior to processing it in the Refinery.
The Company believes that resid will continue to sell at
a discount to crude oil, and expects to continue to generate
higher margins in its refining operations than conventional
refiners that use crude oil as a principal feedstock. The future
price of resid will depend on the relationship between the growth
in crude oil demand (which generates more resid when processed)
and worldwide additions to resid conversion capacity (which has
the effect of reducing the available supply of resid). The
Company believes that industry-wide additions to resid conversion
capacity are not likely to exceed the expected increase in resid
availability caused by increasing crude runs, decreasing
environmentally permissible uses for resid and other factors.
Refined product prices are influenced principally by
factors of supply and demand. The Company expects that global
demand for light products, including gasoline, will continue to
increase in relation to the level of general economic activity,
while fuel oil demand will increase more slowly. Most of the
demand growth is expected to occur outside of the United States,
particularly in Asia. The supply of gasoline and other light
products is influenced by a variety of factors. Factors that may
reduce available supplies include refinery shutdowns, vapor
pressure reduction programs (which effectively remove butanes
from the gasoline supply pool), lead phase-out programs and
requirements for reformulated gasoline (which effectively remove
benzene and other aromatics from the gasoline supply pool).
Factors tending to increase supplies include imports, additions
of conversion capacity and requirements for oxygenated gasoline
under the Clean Air Act (which effectively adds oxygenates such
as MTBE and ethanol to the gasoline pool). Predictions of future
supply and demand are necessarily uncertain. However, the
Company believes that prior to 1995, conversion capacity
additions and projects to produce MTBE and other oxygenates are
likely to cause gasoline supplies to increase more rapidly than
demand. Thereafter, possible refinery closings and the more
prevalent use of reformulated gasolines may reduce gasoline
supplies and improve refining margins.
The anticipated growth in demand for MTBE may be
adversely affected by recent oxygenate proposals promulgated by
the EPA under the Clean Air Act. On December 15, 1993, the EPA
issued proposed reformulated gasoline regulations requiring that
at least 30% of the oxygenates used in reformulated gasolines
come from renewable sources such as corn, grain, wood, and
organic waste products. Ethanol and ether producers capable of
manufacturing ethanol-based ethyl tertiary butyl ether ("ETBE")
stand to benefit the most if the proposed oxygenate rules are
adopted due to the resulting, immediate increase in demand for
ethanol and ETBE likely to occur. The proposed mandate for
renewable oxygenates is generally disfavored by the fossil fuel-
based oxygenate industry, including producers of methanol and
manufacturers of MTBE. The EPA is expected to issue a final rule
on renewable oxygenates by June 1994.
Domestic gasoline production is supplemented with
foreign imports. However, the Company believes that the
availability of foreign gasoline supplies may decline because of
the implementation of lead phasedown programs in some countries
and a gradual increase in other environmental restrictions. The
Company also believes that beginning in 1995, United States
gasoline production capacity may become limited because of the
prohibitive costs of new refinery construction and the expense of
compliance for many older refineries with environmental
regulations, including the Clean Air Act. Under provisions of
the Clean Air Act, U.S. refineries must apply for new federal
operating permits in 1995. Because the Refinery was completed in
1984, the Company expects to be able to comply with present and
future environmental legislation more easily than older,
conventional refineries. See "Environmental Matters" for a
further discussion of the Clean Air Act and its impact on the
refining industry.
Other Projects
Through its wholly owned subsidiary, the Company is a
20% general partner in Javelina Company ("Javelina"), which
completed construction in 1991 of a plant in Corpus Christi (the
"Javelina Plant") to process waste gases from the Refinery and
other refineries in the Corpus Christi area and to extract
hydrogen, ethylene, propylene and NGLs from the gas stream. The
Company has made capital contributions and advances to Javelina
of approximately $19.3 million through December 31, 1993, for the
Company's proportionate share of capital expenditures and
operating expenses. Javelina maintains a term loan agreement and
a working capital and letter of credit facility which mature on
January 31, 1996. The Company's guarantees of these bank credit
agreements were approximately $19.6 million at December 31, 1993.
VALERO NATURAL GAS PARTNERS, L.P.
The Company holds an approximate 49% effective equity
interest in the Partnership, and various subsidiaries of Energy
serve as general partners of VNGP, L.P. and its subsidiary
partnerships. For information with respect to the Company's
investment in the Common Units of Limited Partner Interest
("Common Units") in VNGP, L.P., see Note 2 of Notes to
Consolidated Financial Statements.
Natural Gas Operations
The Partnership owns and operates natural gas pipeline
systems principally serving Texas intrastate markets. 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. The
Partnership also owns a 3.5-mile, 24-inch pipeline that connects
the Partnership's pipeline near Penitas in South Texas to PEMEX's
42-inch pipeline outside of Reynosa, Mexico. 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. The Partnership leases and operates
several natural gas pipelines, including approximately 240 miles
of 24-inch pipeline extending from near Dallas to near Houston
which the Partnership leases from a third party, and
approximately 105 miles of pipeline in East Texas extending to
Carthage, near the Louisiana border, which the Partnership leases
from the Company. 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 gas sales, including gas sales by
those subsidiaries operating the Partnership's special marketing
programs ("SMPs"), transportation volumes in million cubic feet
("MMcf") per day, average gas sales prices and average gas
transportation fees 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
Average gas sales price per Mcf. . . . . . $2.34 $2.11 $1.92
Average gas transportation fee per Mcf . . $.108 $.118 $.135
</TABLE>
The Partnership's natural gas operating results have
improved in 1993 as natural gas supply and demand have become
more balanced. Although increased industry competition will
continue to affect the Partnership's operating results from
natural gas operations, in 1993 the Partnership's natural gas
throughput benefitted from increased business opportunities
arising under FERC Order 636, a west-to-east shift in natural gas
supply patterns and the temporary shutdown of a nuclear power
plan in the Partnership's service area. See "Governmental
Regulations - Federal Regulation" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
Natural Gas Liquids Operations
The Partnership's NGL operations include the processing
of natural gas to extract a mixed stream of NGLs comprised of
ethane, propane, butanes and natural gasoline, the separation
("fractionation") of mixed NGLs into component products and the
transportation and marketing of NGLs. 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.
The Partnership owns or operates for its own account
nine gas processing plants including a plant near Thompsonville
in South Texas, which is leased by the Partnership from the
Company. The Partnership's owned and leased gas processing
plants are located in the western and southern regions of Texas
and process approximately 1.3 billion cubic feet of gas per day.
The Partnership's NGL production is sold primarily in the Corpus
Christi and Mont Belvieu (Houston) markets. A substantial
portion of the Partnership's butane production is sold to the
Company as a feedstock for the Refinery's Butane Upgrade
Facility.
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 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
<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 owns or leases approximately
375 miles of NGL pipelines and fractionation facilities at three
locations. 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. In addition, the
Partnership operates for a fee two NGL processing plants,
approximately 59 miles of NGL pipeline and 450 miles of gathering
lines owned by a subsidiary of Energy. See "Other Natural Gas
Operations."
Additional information regarding the Partnership is set
forth in the Partnership's Annual Report on Form 10-K (Commission
File No. 1-9433), which is separately filed with the Securities
and Exchange Commission (the "Commission"). Items 1 through 3 of
the Partnership's Annual Report on Form 10-K for the year ended
December 31, 1993, as filed with the Commission on March 1, 1994,
are filed as an Exhibit to this Report.
OTHER NATURAL GAS OPERATIONS
In addition to the natural gas and NGL operations
conducted through the Partnership, the Company, through its
wholly owned subsidiary Valero NGL Investments Company, owns
certain South Texas NGL assets including two natural gas
processing plants in Starr and Dimmit Counties, 450 miles of
associated natural gas gathering lines, a 59-mile NGL pipeline
and a 17.5% interest in a third gas processing plant in Nueces
County. The Partnership operates these facilities for a fee
under operating agreements with the Company. During 1993, these
plants produced a daily average of approximately 9,500 barrels
per day of NGLs. Prices realized from the sale of plant products
were comparable to those obtained by the Partnership for its own
production. See "Valero Natural Gas Partners, L.P. - Natural Gas
Liquids."
The Company leases certain assets to the Partnership
under capital leases. The leased assets include (i) a gas
processing plant near Thompsonville in South Texas and 48 miles
of NGL product pipeline (the "Thompsonville Project"), (ii) an
interest in approximately 105 miles of pipeline in East Texas
(the "East Texas pipeline"), and (iii) certain fractionation
facilities in Corpus Christi. The Thompsonville Project lease
commenced December 1, 1992, and has a term of 15 years. The East
Texas pipeline lease commenced February 1, 1991, and has a term
of 25 years. The lease for the fractionation facilities
commenced December 1, 1991, and has a term of 15 years. The rate
of return available to the Company from the leases is limited to
the lease payments specified in the respective leases plus any
related tax benefits. The Partnership has the right to purchase
all or any portion of the leased assets, subject to certain
restrictions, under purchase option provisions of the respective
lease agreements.
Effective September 30, 1993, the Company sold its stock
of Rio Grande Valley Gas Company ("RGV"), a wholly owned
subsidiary of Energy whose operations are included in "Other
Operations" of the Company, for cash in the amount of
approximately $31 million. The disposition of RGV resulted in an
after-tax gain, net of other nonoperating charges, of
approximately $5 million. RGV owns approximately 1,552 miles of
retail distribution lines, sells gas to approximately 75,000
retail customers in a number of communities in the Lower Rio
Grande Valley of Texas and transports gas for approximately
60 transportation customers. Pursuant to contracts with the
Partnership, RGV will continue to acquire all of its gas supply
from the Partnership through the year 2000. RGV had aggregate
gas sales and transportation volumes averaging approximately
14 MMcf per day in each of 1992 and 1991, and 15 MMcf per day for
the first nine months of 1993.
Val Gas Company ("Val Gas"), a wholly owned subsidiary
of VNGC, owns and operates several small gathering systems in
Texas that are subject to regulation by the FERC. See
"Governmental Regulations - Federal Regulation." Until
December 31, 1993, Valero Interstate Transmission Company
("Vitco"), an indirect wholly owned subsidiary of Energy,
operated a small interstate pipeline system in South Texas
comprised of approximately 240 miles of transmission and
gathering lines. Effective January 1, 1994, the FERC authorized
Vitco's abandonment of its pipeline system which is no longer
subject to FERC rate regulation.
GOVERNMENTAL REGULATIONS
Certain of the Company's subsidiaries 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
Natural Gas Policy Act ("NGPA"). In addition, certain activities
of Val Gas Company are subject to the regulations of the FERC
under the NGPA, the Department of Energy Organization Act of 1977
(the "DOE Act"), and the federal Natural Gas Act. The Company's
activities are also subject to various state and federal
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. During 1992, the Railroad Commission
revised its rules governing the production and purchase of
natural gas. As part of such revision, the Railroad Commission
adopted the gas proration rule (the "gas proration rule") to
prevent the production of gas in excess of market demand. The
gas proration rule requires producers to tender and deliver, and
gas purchasers, including pipelines and purchasers offering SMPs,
to take, only volumes of gas equal to 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 (defined as casinghead
gas, or gas from wells primarily producing oil, and certain
special allowable gas that are the last to be shut in during
periods of reduced market demand) having higher priority than gas
well gas (defined as gas from wells primarily producing gas),
notwithstanding any contractual commitments. The revised rules
are intended to simplify the previous system of nominations and
to bring production allowables in line with estimated market
demand.
Federal Regulation
In 1992, the FERC issued 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,
thus increasing competition in the natural gas industry. No
Company subsidiary or Partnership subsidiary operating
partnership is directly subject to Order 636. However, Order 636
is expected to create new supply, marketing and transportation
opportunities for the Partnership. See "Recent Developments -
Proposal to Acquire the Partnership."
The Natural Gas Act and DOE Act grant to the FERC the
authority to regulate rates and charges for natural gas
transported in interstate commerce or sold by natural gas
companies in interstate commerce for resale. Interstate natural
gas sales for resale are made at rates subject to FERC
regulation. Val Gas Company is subject to regulation as a
"natural gas company" under the Natural Gas Act.
ENVIRONMENTAL MATTERS
The Company's Refinery operations and natural gas and
NGL operations are subject to environmental regulation by federal
and state authorities, including the EPA, the Texas Natural
Resources Conservation Commission ("TNRCC"), the Texas General
Land Office and the Railroad Commission. Compliance with
regulations promulgated by these authorities increases the cost
of designing, installing and operating such facilities. The
regulatory requirements relate to water and storm water
discharges, waste management and air pollution control measures.
In 1993, Refining's capital expenditures attributable to
compliance with environmental regulations (exclusive of
expenditures for the Butane Upgrade Facility, MTBE/TAME Complex
and Reformate Splitter, for which the amount of expenditures
attributable to environmental regulation is not determinable)
were approximately $8 million and are currently estimated to be
approximately $6 million for 1994.
Under the Clean Air Act, U.S. refineries must apply for
new federal operating permits in 1995. Compliance with this and
other environmental requirements may prove difficult and
expensive for many older refineries. As a result, many
refineries during the next few years likely will focus their
capital expenditures on bringing their facilities into compliance
with environmental requirements, rather than adding to capacity.
Because of the Clean Air Act and other environmental regulations,
various U.S. refiners have announced their intention to sell or
close those refineries where capital expenditures needed to
ensure compliance are not economically feasible. Because the
Refinery was completed in 1984, it was built under more stringent
environmental requirements than most existing U.S. refineries.
Accordingly, the Company expects to be able to comply with the
Clean Air Act and future environmental legislation more easily
than older, conventional refineries.
The Company expects that the demand for oxygenates such
as MTBE will increase. (But see "Factors Affecting Operating
Results" for a discussion of recent regulations proposed by the
EPA that require the use of renewable oxygenates such as ethanol
and ETBE.) The increase in demand for oxygenates is expected not
only because of the mandates of the Clean Air Act for the use of
clean burning fuels, but also because of the expected election by
many areas to use reformulated gasolines even though not formally
required by the Clean Air Act. The Clean Air Act requires the 39
areas that have failed to attain carbon monoxide air quality
standards to use oxygenated gasolines during winter months.
Beginning in 1995, the Clean Air Act also requires the nine areas
that have the worst ozone air quality to use reformulated
gasoline throughout the year to decrease their emissions of
hydrocarbons and toxic pollutants. Also beginning in 1995,
another 87 areas that have failed to attain certain ozone
air-quality standards may elect to use reformulated gasolines
throughout the year to decrease their emissions of hydrocarbons
and toxic pollutants. Already, 43 of the 87 areas have notified
the EPA of their election to use reformulated gasolines. Recent
additions to the Refinery's facilities enable the Company to
produce all of its gasoline as reformulated gasoline. See
"Recent Developments - Refinery Facilities Additions."
During 1991, environmental legislation was passed in
Texas which conformed Texas law with the Clean Air Act to allow
Texas to administer the federal programs. The Company and the
Partnership have been and will continue to be affected by
provisions of these laws concerning control requirements for air
toxins and new operating permit requirements. The Company and
the Partnership also have been affected by the increasing
regulation of wastes by the Railroad Commission and the TNRCC and
the promulgation of EPA permitting requirements for storm water
discharges associated with industrial activities. Although these
new laws and requirements may increase operating costs, they are
not expected to have a material adverse effect on the Company's
or the Partnership's operations or financial condition.
The Oil Pollution Act of 1990 requires newly constructed
tank vessels carrying crude oil to U.S. ports to be equipped with
double hulls or double containment systems, and provides for a
phaseout of existing vessels without double hulls beginning in
1995. Although these requirements are expected to increase the
cost of transporting feedstocks to the Refinery, the staggered
phaseout of existing vessels is expected to give existing vessel
operators sufficient time to replace their fleets to provide
adequate shipping capability.
COMPETITION
The refining industry is highly competitive with respect
to both supply and markets. Refining competes with numerous
other companies for available supplies of resid and other
feedstocks and for outlets for its refined products. Prices of
feedstocks and refined products are established principally by
market conditions. Many of the companies with which Refining
competes obtain a significant portion of their feedstocks from
company-owned production and are able to dispose of refined
products at their own retail outlets. Competitors that have
their own production or retail outlets may be able to offset
losses from refining operations with profits from producing or
retailing operations and may be better positioned than the
Company to withstand periods of depressed refining margins. See
"Environmental Matters" for a discussion of the effects of
environmental regulations on refining competition.
The natural gas industry is and is expected to remain
highly competitive with respect to both gas supply and markets,
with no company or small group of companies being dominant.
Order 636 provides a mechanism for producers and marketers to
sell gas directly to end users, resulting in increased
competition for gas sales. See "Governmental Regulations -
Federal Regulation."
EMPLOYEES
As of December 31, 1993, the Company had approximately
1,740 employees.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of
December 31, 1993 regarding the present executive officers of
Energy. Each officer named in the following table has been
elected to serve until his successor is duly appointed and elected
or his earlier removal or resignation from office. No family
relationship exists among any of the executive officers,
directors or nominees for director of Energy. Similarly, there
is no arrangement or understanding between any executive officer
and any other person pursuant to which he was or is to be
selected as an officer.
<TABLE>
<CAPTION>
_____________________________________________________________________________________
Year First
Elected or
Appointed as Age
Energy Executive as of
Position and Officer December 31,
Name Office Held or Director 1993
_____________________________________________________________________________________
<S> <C> <C> <C>
William E. Greehey Director, Chairman of 1979 57
the Board and Chief
Executive Officer
Edward C. Benninger Director, Executive 1979 51
Vice President
Stan L. McLelland Executive Vice President 1981 48
and General Counsel
Don M. Heep Senior Vice President and 1990 44
Chief Financial Officer
Steven E. Fry Vice President Administration 1980 48
*E. Baines Manning Senior Vice President, 1992* 53
Valero Refining and
Marketing Company
*Martin P. Zanotti Executive Vice President, 1992* 61
Valero Refining and
Marketing Company
_____________________________________________________________________________________
<FN>
*Messrs. Manning and Zanotti have been designated by the
Energy Board of Directors as "executive officers" of the
Registrant in accordance with Rule 3b-7 under the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and will
be eligible for inclusion in the Summary Compensation Table in
the Proxy Statement.
</TABLE>
Mr. Greehey has served as Chief Executive Officer and as
a director of Energy since 1979 and as Chairman of the Board
since 1983. Mr. Greehey is also a director of Weatherford
International Incorporated and Santa Fe Resources, Inc., neither
of which are affiliated with the Company or the Partnership.
Mr. Benninger has served as a director of Energy since
1990. He was elected Executive Vice President in 1989 and served
as Chief Financial Officer from 1986 to 1992. In 1992, he was
elected Executive Vice President and Chief Operating Officer of
Valero Natural Gas Company.
Mr. McLelland was elected Executive Vice President and
General Counsel in 1989 and had served as Senior Vice President
and General Counsel of Energy since 1981.
Mr. Heep was elected Senior Vice President and Chief
Financial Officer of Energy in 1994, prior to which he served as
Vice President Finance since 1990. He has been employed by the
Company in various capacities since 1977.
Mr. Fry was elected Vice President Administration of
Energy in 1989 and served as Secretary of Energy from 1980 to
1992.
Mr. Zanotti has served as Executive Vice President of
VRMC since 1988 and as President and Chief Operating Officer of
VRC since 1990, and has served in other positions with the
Company since 1983.
Mr. Manning has served as Senior Vice President of VRMC
since 1986 and of VRC since 1987.
ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery
and related facilities, three natural gas processing plants, and
various natural gas and NGL pipelines, gathering lines and
related facilities, all located in Texas. The Company also
operates natural gas pipeline systems and NGL facilities,
processing plants, compressor stations, treating plants,
measuring and regulating stations, fractionation facilities,
underground natural gas storage caverns and other properties
owned or used by the Partnership, all of which are located in
Texas. Substantially all of Refining's fixed assets are pledged
as security under deeds of trust securing industrial revenue
bonds issued on behalf of Refining, while its inventories and
receivables are pledged as security under a bank credit agreement
providing working capital to Refining. See Note 4 of Notes to
Consolidated Financial Statements. The Partnership has pledged
substantially all of its gas systems and processing facilities,
except for certain pipeline, processing and fractionation assets
leased from the Company, as collateral for its First Mortgage
Notes. Reference is made to "Item 1. Business," which includes
detailed information regarding properties of the Company.
Management believes that the Company's facilities are
generally adequate for their respective operations, and that the
facilities of the Company are maintained in a good state of
repair. The Company and the Partnership are lessees under a
number of cancelable and noncancelable leases for certain real
properties. See Note 14 of Notes to Consolidated Financial
Statements.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to 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) (reported in the Company's Form
10-K for the year ended December 31, 1992 as Transamerican
Natural Gas Corporation v. The Coastal Corporation et al). 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
respective 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. The Valero Defendants' motion for summary
judgment on TANG's antitrust claim 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 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, 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 the Company or the Partnership.
Garcia, et al. v. Coastal Chemical Company, Inc., Valero
Refining Company, Javelina Company, et al., 347th Judicial
District Court, Nueces County, Texas (filed August 31, 1993).
This action was brought by certain residents of the Oak Park
Triangle area of Corpus Christi, Texas, against several
defendants including Valero Refining Company. All named
defendants are either refiners or gas processors having
facilities located at or near Up River Road in Corpus Christi.
Plaintiffs allege in general terms damages resulting from ground
water contamination and air pollution allegedly caused by the
operations of the defendants. Plaintiffs seek unspecified actual
and punitive damages.
The Long Trusts v. Tejas Gas Corporation, 123rd Judicial
District Court, Panola County, Texas (filed March 1, 1989).
Valero Transmission Company (an indirect wholly owned subsidiary
of Energy, "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 of approximately $30 million including interest
and an unspecified amount of punitive damages. The District
Court ruled on the plaintiff's motion for summary judgment,
finding that as a matter of law the three gas purchase contracts
at issue were fully binding and enforceable, that Tejas breached
the minimum take obligations under one of the contracts, that
Tejas is not entitled to claimed offsets for gas purchased by
third parties and that the "availability" of gas for take-or-pay
purposes is established solely by the delivery capacity testing
procedures in the contracts. Damages, if any, have not been
determined. Because of existing contractual obligations of
Valero Transmission, L.P. to Tejas, the lawsuit may ultimately
involve a contingent liability for Valero Transmission, L.P. The
Court recently granted Tejas's Motion for Continuance in
connection with the former January 10, 1994 trial date. 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 Energy's Form 10-K for
the fiscal year ended December 31, 1992). In a lawsuit filed in
1988, certain 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. The 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 a 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 nonparticipating 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 Company or the Partnership.
Valero Energy Corporation, et al. v. M.W. Kellogg
Company, et al., 117th Judicial District Court, Nueces County,
Texas (filed July 11, 1986). The Company claims that the
defendants are liable for breach of warranty, breach of contract,
negligence, gross negligence, breach of implied warranty of good
and workmanlike performance, breach of the Texas Deceptive Trade
Practices - Consumer Protection Act, breach of implied warranty
of fitness for ordinary purposes and strict liability in tort in
connection with services performed at the Refinery. The Company
claims actual damages in excess of $165 million plus exemplary
damages, statutory penalties, attorney's fees and costs of court.
In September 1991, the court considered motions for summary
judgment filed by the Company, Kellogg and Ingersoll-Rand,
another primary defendant. On October 25, 1991, the court
entered judgment which granted the motions of Kellogg and
Ingersoll-Rand for summary judgment in their entirety, denied the
motion for summary judgment filed by the Company and entered a
take nothing judgment dismissing all of the Company's claims with
prejudice. The Company appealed the trial court's decision to
the Thirteenth Court of Appeals, Corpus Christi, Texas. On June
30, 1993, the Court of Appeals affirmed the trial court's
decision. The Company has appealed the decision to the Texas
Supreme Court.
White, et al. v. Coastal Javelina, Inc., Valero Energy
Corporation, et al., 94th State District Court, Nueces County,
Texas (filed November 27, 1991). Plaintiffs, as owners of real
property situated near the Javelina Plant, have alleged that the
operation and maintenance of the Javelina Plant have (i)
interfered with their use and enjoyment of their property, (ii)
caused depreciation in the value of their property, (iii) caused
physical and mental injuries, (iv) damaged persons and property,
and (v) caused a nuisance. Plaintiffs seek unspecified actual
damages, punitive damages, prejudgment and postjudgment interest,
costs of the lawsuit and equitable relief.
Javelina Company Litigation. Valero Javelina Company, a
wholly owned subsidiary of Energy, is a general partner of
Javelina Company, a general partnership. See "Petroleum Refining
and Marketing - Other Projects" and Note 5 of Notes to
Consolidated Financial Statements. In addition to White and
Garcia (reported above), Javelina Company has been named as a
defendant in five other lawsuits filed since 1992 in state
district courts in Nueces County, Texas. Garcia and three other
suits include as defendants several other companies that own
refineries or other industrial facilities in Nueces County.
These suits were brought by a number of plaintiffs who reside in
neighborhoods near the facilities. The plaintiffs claim injuries
relating to alleged exposure to toxic chemicals, and generally
claim that the defendants were negligent, grossly negligent and
committed trespass. The plaintiffs claim personal injury and
property damages resulting from soil and ground water
contamination and air pollution allegedly caused by the
operations of the defendants. One of the suits seeks
certification of the litigation as a class action. The
plaintiffs seek an unspecified amount of actual and punitive
damages. White and two other suits were brought by plaintiffs
who either live or have businesses near the Javelina Company
plant. The suits allege claims similar to those described above.
These plaintiffs also fail to specify an amount of damages
claimed.
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 claimed that VTC owes to the City franchise fees and accrued
interest thereon aggregating approximately $13.5 million. In a
letter dated November 9, 1993, the City claimed an additional
$18 million in damages related to the City's allegations that VTC
engaged in unauthorized activities under the franchise agreement
by transmitting gas for resale and by transporting gas for third
parties on the franchised premises. 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 contracting practices in the natural gas
industry, numerous producers and other suppliers brought claims
against Transmission and Vitco asserting breach of contractual
provisions requiring that they take, or pay for if not taken,
certain volumes of natural gas. The Company and the Partnership
have settled substantially all of the significant take-or-pay
claims, pricing differences and contractual disputes heretofore
brought against them. In 1987, Transmission and a producer from
whom Transmission has purchased natural gas entered into an
agreement resolving certain take-or-pay issues between the
parties in which Transmission agreed to pay one-half of certain
excess royalty claims arising after the date of the agreement.
The royalty owners of the producer recently completed an audit of
the producer and have presented to the producer a claim for
additional royalty payments in the amount of approximately $17.3
million, and accrued interest thereon of approximately
$19.8 million. Approximately $8 million of the royalty owners'
claim accrued after the effective date of the agreement between
the producer and Transmission. The producer and Transmission are
reviewing the royalty owners' claims. No lawsuit has been filed
by the royalty owners. The Company 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 Company
believes that the Partnership and the Company have resolved
substantially all of the significant take-or-pay claims that are
likely to be made. The Company believes any remaining
take-or-pay claims can be resolved on terms satisfactory to the
Partnership and the Company. Any liability of Energy, VNGC or
VNGC's wholly owned subsidiaries with respect to take-or-pay
claims involving Transmission's intrastate pipeline operations
has been assumed by the Partnership. If the Partnership were
unable or otherwise failed to discharge any liability which it
assumed, the Company would remain ultimately liable for such
liability.
Conclusion. The Company is also a party to additional
claims and legal proceedings arising in the ordinary course of
business. The Company believes it is unlikely that the final
outcome of any of the claims or proceedings to which the Company
is a party including the claims and proceedings described
above would have a material adverse effect on the Company's
financial position or results of operations; however, due to the
inherent uncertainty of litigation, the range of possible loss,
if any, cannot be estimated with a reasonable degree of precision
and there can be no assurance that the resolution of any
particular claim or proceeding would not have an adverse effect
on the Company's results of operations for the fiscal period in
which such resolution occurred. As described above, the
Partnership has assumed the obligations and liabilities of the
Company with respect to certain claims. If the Partnership were
unable or otherwise failed to discharge any such obligation or
liability, the Company could remain ultimately liable for the
same.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders
during the fourth quarter of 1993.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
Energy's Common Stock is listed on the New York Stock
Exchange, which is the principal trading market for this
security. As of February 14, 1994, there were 8,095 holders of
record and an estimated 20,000 beneficial owners of Energy's
Common Stock.
The range of the high and low sales prices of the Common
Stock as quoted in The Wall Street Journal, New York Stock
Exchange-Composite Transactions listing, and the amount of per-
share dividends for each quarter in the preceding two years, are
set forth in the tables shown below:
<TABLE>
<CAPTION>
Common Stock
Dividends
1993 1992 Per Common Share
Quarter Ended High Low High Low 1993 1992
<S> <C> <C> <C> <C> <C> <C>
March 31. . . . $24 1/2 $20 7/8 $33 3/8 $27 7/8 $.11 $.09
June 30 . . . . 24 7/8 21 5/8 32 22 1/8 .11 .11
September 30. . 26 1/8 22 26 7/8 21 1/2 .11 .11
December 31 . . 26 1/8 19 5/8 25 1/2 19 1/2 .13 .11
</TABLE>
The Energy Board of Directors declared a quarterly
dividend of $.13 per share of Common Stock at its January 20,
1994 meeting. Dividends are considered quarterly by the Energy
Board of Directors and are limited by, among other things, the
Company's financing agreements. See Note 4 of Notes to
Consolidated Financial Statements.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year
ended December 31, 1993 is derived from the Company's
Consolidated Financial Statements contained elsewhere herein.
The selected financial data for the years ended prior to December
31, 1993 is derived from the selected financial data contained in
the Company's Annual Report on Form 10-K for the year ended
December 31, 1992.
The following summaries are in thousands of dollars
except for per share amounts:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991 1990 1989
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $1,222,239 $1,234,618 $1,011,835 $1,168,867 $ 941,258
OPERATING INCOME . . . . . . . . . . . . $ 75,504 $ 134,030 $ 119,266 $ 134,391 $ 69,679
EQUITY IN EARNINGS OF AND
INCOME FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . . $ 23,693 $ 26,360 $ 32,389 $ 29,161 $ 11,628
NET INCOME . . . . . . . . . . . . . . . $ 36,424 $ 83,919 $ 98,667 $ 94,693 $ 41,501
Less: Preferred and preference stock
dividend requirements . . . . 1,262 1,475 6,044 7,060 13,347
NET INCOME APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . $ 35,162 $ 82,444 $ 92,623 $ 87,633 $ 28,154
EARNINGS PER SHARE OF COMMON STOCK:
Assuming no dilution . . . . . . . . . $ .82 $ 1.94 $ 2.28 $ 2.31 $ .98
Assuming full dilution . . . . . . . . $ .82 $ 1.94 $ 2.28 $ 2.31 $ .95
NET CASH PROVIDED BY
OPERATING ACTIVITIES . . . . . . . . . $ 141,281 $ 152,511 $ 182,773 $ 196,383 $ 43,376
TOTAL ASSETS . . . . . . . . . . . . . . $1,764,437 $1,759,100 $1,502,430 $1,266,223 $1,019,551
LONG-TERM OBLIGATIONS AND
REDEEMABLE PREFERRED STOCK . . . . . . $ 499,421 $ 497,308 $ 395,948 $ 264,656 $ 240,310
DIVIDENDS PER SHARE OF COMMON
STOCK. . . . . . . . . . . . . . . . . $ .46 $ .42 $ .34 $ .26 $ .15
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
The following are the Company's financial and operating
highlights for each of the three years in the period ended
December 31, 1993. The Partnership operating income amounts
presented below represent 100% of the Partnership's operating
income by segment. The amounts in the following table are in
thousands of dollars, unless otherwise noted:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES:
Refining and marketing. . . . . . . . . . . . . . . . . $1,044,749 $1,056,873 $ 889,462
Other operations . . . . . . . . . . . . . . . . . . . 177,490 177,745 122,373
Total . . . . . . . . . . . . . . . . . . . . . . . . $1,222,239 $1,234,618 $1,011,835
OPERATING INCOME (LOSS):
Refining and marketing. . . . . . . . . . . . . . . . . $ 75,401 $ 137,187 $ 133,659
Other operations and corporate general and
administrative expenses . . . . . . . . . . . . . . . 103 (3,157) (14,393)
Total . . . . . . . . . . . . . . . . . . . . . . . $ 75,504 $ 134,030 $ 119,266
Equity in earnings of and income from Valero
Natural Gas Partners, L.P. . . . . . . . . . . . . . $ 23,693 $ 26,360 $ 32,389
Gain on disposition of assets and other income, net. . . . $ 6,209 $ 1,452 $ 7,252
Interest expense, net. . . . . . . . . . . . . . . . . . . $ (37,182) $ (30,423) $ (12,540)
Net income . . . . . . . . . . . . . . . . . . . . . . . . $ 36,424 $ 83,919 $ 98,667
Net income applicable to common stock. . . . . . . . . . . $ 35,162 $ 82,444 $ 92,623
Earnings per share of common stock . . . . . . . . . . . . $ .82 $ 1.94 $ 2.28
REFINING AND MARKETING OPERATING STATISTICS:
Throughput volumes (Mbbls per day) (1). . . . . . . . . 136 119 82
Average throughput margin per barrel (1)(2) . . . . . . $ 5.99 $ 7.00 $ 8.84
Sales volumes (Mbbls per day) . . . . . . . . . . . . . 133 123 97
PARTNERSHIP OPERATING INCOME:
Natural gas . . . . . . . . . . . . . . . . . . . . . . $ 53,458 $ 32,484 $ 37,140
Natural gas liquids . . . . . . . . . . . . . . . . . . 26,020 57,357 62,694
Total. . . . . . . . . . . . . . . . . . . . . . . . $ 79,478 $ 89,841 $ 99,834
<FN>
(1) Throughput volumes and margins for 1991 represent
statistics for the HDS/HOC complex which, prior to the
commencement of operations of the Hydrocracker/Reformer
Units in 1992, were the principal refining units located at
the refinery. As a result, the throughput volumes and
margins are not totally comparable.
(2) Throughput margin for 1993 excludes a $.55 per barrel
reduction resulting from the effect of a $27.6 million
write-down in the carrying value of the Company's refinery
inventories.
</TABLE>
<PAGE>
GENERAL
The Company reported net income of $36.4 million or $.82
per share for the year ended December 31, 1993, compared to $83.9
million or $1.94 per share, respectively, for 1992. Operating
income was $75.5 million in 1993 compared to $134 million in
1992. For the fourth quarter of 1993, the Company reported a net
loss of $15.2 million or $.36 per share compared to net income of
$8.2 million or $.18 per share for the same period in 1992.
Operating loss was $17.7 million for the fourth quarter of 1993
compared to operating income of $15.9 million for the same period
in 1992. The 1993 results were reduced by a $27.6 million, or
$17.9 million after-tax, write-down in the carrying value of the
Company's refinery inventories during the fourth quarter of 1993
to reflect existing market prices. Also affecting 1993 results
compared to 1992 were depressed refining margins and the
operation of the butane upgrade facility and other new refinery
units discussed below.
Crude oil, refined product prices and refining margins
were weak throughout 1993. During the November meeting of the
Organization of Petroleum Exporting Countries ("OPEC"), the
member countries decided to forego any cuts in production. This
decision, combined with increased production from the North Sea
region, continued uncertainty regarding Iraq's possible re-entry
into world oil markets and weak global demand for energy caused a
precipitous drop in crude oil prices to their lowest levels in
five years. Refined product prices decreased faster and further
than crude oil prices due to continuing high refinery capacity
utilization rates and high gasoline inventories. These
conditions resulted in a substantial decline in refining margins
and the write-down in the carrying value of the Company's
refinery inventories. Refined product prices and refining
margins have increased modestly since late December. The
Company's operating income and net income for the first quarter
of 1994, however, are expected to be in the same range as operating
income and net income for the fourth quarter of 1993, excluding
the effect of the write-down in the carrying value of the
Company's refinery inventories.
The following is a discussion of the Company's results
of operations first comparing 1993 to 1992 results and then
comparing 1992 to 1991 results:
1993 COMPARED TO 1992
Refining Operations
During 1993, the Company's specialized petroleum
refinery (the "Refinery") began operation of a butane upgrade
facility which converts butane into MTBE, a MTBE/TAME complex and
a reformate splitter. See Note 5 of Notes to Consolidated
Financial Statements. These projects have increased the
Refinery's production capacity to approximately 140,000 barrels
per day of refined products.
Refining's operating revenues were $1,044.7 million for
the year ended December 31, 1993 compared to $1,056.9 million for
1992. Operating revenues remained level as an 8% decrease in the
average sales price per barrel offset an 8% increase in sales
volumes. Increased production capacity resulting from operation
of the butane upgrade facility contributed to the increase in
sales and throughput volumes. Refining's cost of sales increased
$42.9 million to $910.2 million in 1993 compared to 1992. Cost
of sales increased due to the increase in throughput volumes and
the inventory write-down discussed above. Partially offsetting
the increase in cost of sales was a decrease in the average
feedstock cost per barrel. The average throughput margin per
barrel, before operating costs, for 1993 was $5.99 ($5.44,
including the effect of the inventory write-down) compared to
$7.00 for 1992. Both Refinery operating costs, which are
included in cost of sales, and depreciation expense increased for
1993 compared to 1992 due primarily to costs associated with
operation of the butane upgrade facility and other new Refinery
units. As a result of the above factors, Refining's operating
income decreased 45% to $75.4 million.
The Refinery's hydrodesulfurization unit (the "HDS
Unit") and heavy oil cracking unit (the "HOC Unit"), collectively
the HDS/HOC complex, process high-sulfur atmospheric tower
bottoms, a type of residual fuel oil ("resid") which normally
sells at a significant discount to crude oil, the conventional
feedstock for refineries. The remainder of the Refinery units
process crude oil, butanes, and other feedstocks. The Company
does not have retailing or crude oil producing operations.
Refining's operations and throughput margins continue to benefit
from the discount at which resid sells to crude oil. This
discount per barrel has averaged $4.43, $4.73 and $4.87 for the
years ended December 31, 1993, 1992, and 1991, respectively. The
discount at which resid sells to crude oil generally decreases
with decreases in crude oil prices due to price competition for
resid from natural gas and other markets. However, resid is
expected to continue to sell at a discount to crude. The Company
believes that the Refinery's ability to process resid, combined
with a product slate consisting primarily of unleaded gasoline
and related higher value products, positions the Company to
effectively compete in the emerging clean fuels marketplace.
Under a feedstock supply agreement with the Company,
Saudi Aramco (successor to the Saudi Arabian Marketing and
Refining Company "SAMAREC"), has agreed to provide an average of
55,000 barrels per day of resid to the Company at market-related
prices. Deliveries under the agreement will continue through
1994 and provide approximately 75% of Refining's resid
requirements. During 1993, Refining also purchased approximately
11,000 barrels per day of South Korean resid at market-related
prices under an agreement which expires in the first quarter of
1994. The Company is negotiating to renew this agreement for
South Korean resid on pricing terms more favorable to the Company
than the existing contract. The Company also renewed a contract
for approximately 22,000 barrels of crude produced in the
People's Republic of China. Although the volume for this
contract has been committed to the Company, the price must be
renegotiated quarterly. The remainder of the Refinery's
feedstocks are purchased at market-related prices under short-
term contracts. The Company believes that if any of Refining's
existing feedstock arrangements were interrupted, adequate
supplies of feedstock could be obtained from other sources or on
the open market.
Scheduled maintenance and catalyst changes of the HDS
Unit were completed in April 1991, October 1992 and December
1993, and a turnaround of the HOC was completed in November 1991.
The HOC is scheduled for a turnaround in late 1994.
Other Operations
The Company's other operations consist of certain minor
natural gas pipeline and natural gas distribution operations not
transferred to Valero Natural Gas Partners, L.P. ("VNGP, L.P." or
the "Partnership") and the natural gas liquids assets ("NGL
Assets") acquired from Oryx Energy in May 1992. Also included in
other operations are the Company's activities as the General
Partner of the Partnership and other miscellaneous revenues. The
Company receives a management fee, which is included in operating
revenues, equal to the direct and indirect costs incurred by it
on behalf of the Partnership.
Operating income from other operations for 1993
increased $3.3 million from the same period in 1992 primarily due
to an increase in operating income associated with the NGL Assets
attributable to the full period effect of those operations in
1993 and decreased corporate expenses borne by the Company. On
September 30, 1993, the Company sold Rio Grande Valley Gas
Company ("RGV"), its natural gas distribution subsidiary, for
approximately $31 million. The disposition of RGV resulted in an
after-tax gain, net of other nonoperating charges, of
approximately $5 million.
Partnership Operations
Effective December 20, 1993, Energy, Valero Natural Gas
Company and Valero Natural Gas Partners, L.P. entered into an
agreement of merger. In the merger, VNGP, L.P. will become a
wholly owned subsidiary of Energy, with the public holders of
common units receiving cash consideration of $12.10 per common
unit, or a total of approximately $117.5 million. Energy has
filed a registration statement with the Securities and Exchange
Commission (the "Commission") for the issuance of $150 million
(up to $172.5 million with underwriters' over-allotments) of
convertible preferred stock to finance the merger and to use for
general corporate purposes, including the reduction of existing
indebtedness under the Company's bank credit agreements. The
transaction is subject to approval by the holders of a majority
of the issued and outstanding common units, approval by the
holders of a majority of the common units held by the public
unitholders and voted at a special meeting to be called to
consider the merger, receipt of satisfactory waivers, consents or
amendments to certain of the Company's financial agreements and
completion of the offering of convertible preferred stock
discussed above. These financial agreements, which include a new
bank credit agreement as well as amendments to other financial
agreements, are in the process of being negotiated to provide for
the proposed merger. In the event that the proposed merger of
VNGP, L.P. with the Company is not ultimately consummated, the
proceeds from the offering would be added to the Company's funds
and used for general corporate purposes, including the repayment
of existing indebtedness, financing of capital projects and
additions to working capital. There can be no assurance,
however, that the merger can be completed.
The Company believes that the natural gas and natural
gas liquids industries are undergoing a period of restructuring
and consolidation that may create opportunities for expansions,
acquisitions or strategic alliances which, if the Partnership
could take advantage of them, could enable the Partnership to
compete more effectively in the competitive natural gas
environment. Because of the Federal Energy Regulatory
Commission's Order No. 636 which requires interstate pipeline
companies to offer various services on an unbundled,
nondiscriminatory basis, the Company believes that intrastate
pipelines such as the Partnership may enjoy increased
opportunities to compete for interstate business. In addition,
an emerging trend of west-to-east movement of gas across the
United States may provide beneficial transportation opportunities
for the Partnership if the Partnership were able to make the
necessary capital expenditures for added west-to-east capacity on
its pipeline system. However, the Partnership's competitive
position could be eroded if the Partnership is unable to respond
effectively to the changing dynamics of the industry. The merger
was proposed because the Company believes that the Partnership
has insufficient financial flexibility to participate fully in
opportunities that may arise in the natural gas and natural gas
liquids ("NGL") industries. The Company believes that the
ability of the Partnership to compete effectively in these
businesses will be enhanced through the merger. The Company also
believes that potential conflicts of interest between the
Partnership and the Company can be eliminated through the merger.
For additional information regarding the proposed acquisition and
pro forma consolidated financial data, see Note 2 of Notes to
Consolidated Financial Statements.
During 1993, 1992 and 1991, the Company's equity in
earnings of the Partnership contributed $6.8 million, $10.5
million and $15 million, respectively, to the Company's net
income. The Company's equity in earnings of the Partnership
decreased in 1993 due primarily to a decrease in operating income
from the Partnership's NGL operations, partially offset by an
increase in operating income from the Partnership's natural gas
operations.
The profitability of the Partnership's NGL operations
depends principally on the margin between NGL sales prices and
the cost of the natural gas from which such liquids are extracted
("shrinkage cost"). Operating income from the Partnership's NGL
operations decreased $31.3 million, or 55%, in 1993 compared to
1992 due primarily to a decrease in NGL prices in the last six
months of 1993 resulting from continuing high levels of NGL
inventories and the significant decline in refined product prices
discussed above, combined with an increase in fuel and shrinkage
costs resulting from a 22% increase in the cost of natural gas.
The decline in NGL prices resulted in a $1.4 million operating
loss from NGL operations for the fourth quarter of 1993 compared
to operating income of $12.9 million for the fourth quarter of
1992. Also reducing fourth quarter 1993 operating results was an
increase in depreciation expense resulting from the recognition
in the 1992 period of a change in the estimated useful lives of
the majority of the Partnership's NGL facilities from 14 to 20
years retroactive to January 1, 1992.
Operating income from the Partnership's natural gas
operations increased $21 million, or 65%, for 1993 compared to
1992 due to a 10% increase in daily natural gas sales volumes and
a 12% increase in transportation revenues resulting from
continued strong demand for natural gas, certain favorable
measurement, fuel usage and customer billing adjustments and an
increase in income generated by the Partnership's Market Center
Services Program. The Market Center Services Program was
established in 1992 to provide price risk management services to
gas producers and end users through the use of forward contracts
and other tools which have traditionally been used in financial
risk management. The Partnership recognized gas cost reductions
and other benefits from this program of $18.7 million in 1993,
which represents an increase of $5.8 million from 1992.
Partially offsetting these increases in natural gas operating
income was a decrease in the recovery of Valero Transmission,
L.P.'s ("VT, L.P.", a subsidiary operating partnership) fixed
costs resulting from the settlement of a customer audit of VT,
L.P.'s weighted average cost of gas. For the fourth quarter of
1993, natural gas operating income increased $9.8 million to
$15.8 million compared to $6 million in the fourth quarter of
1992 due to the factors noted above.
During the first quarter of 1994, NGL prices have
increased modestly since late December 1993, but remain below
first quarter 1993 levels. Concurrently, natural gas prices and
resulting shrinkage costs have increased during the first quarter
of 1994 compared to the same period in 1993. As a result,
Partnership operating income and the Company's equity in earnings
of the Partnership are expected to be substantially lower in the
first quarter of 1994 compared to the fourth quarter of 1993.
Other
Interest and debt expense, net of capitalized interest,
increased due to the issuance of medium-term notes in 1992 (see
Note 4 of Notes to Consolidated Financial Statements) and
decreased capitalized interest primarily due to the placing in
service of the butane upgrade facility during the second quarter
of 1993.
Income tax expense decreased primarily due to a decrease
in pre-tax income. Partially offsetting this was the effect of a
federal tax rate increase due to the enactment of the Omnibus
Budget Reconciliation Act of 1993, which provides for an increase
in the corporate tax rate from 34% to 35%, retroactive to
January 1, 1993. As a result of this legislation, the Company
recorded a onetime, noncash charge to 1993 third quarter earnings
of $8.2 million related to deferred taxes as of the end of 1992.
1992 COMPARED TO 1991
Refining Operations
Refining's operating revenues were $1,056.9 million for
the year ended December 31, 1992, which represented a 19%
increase over the same period in 1991. The increase in operating
revenues was due to a 27% increase in sales volumes as a result
of the commencement of operations of the hydrocracker/reformer
units (the "H/R Units") during the early part of 1992, partially
offset by the effect of a 7% decrease in Refining's average sales
price per barrel in 1992. For 1992, Refining's operating income
was $137.2 million, which represented a 3% increase over 1991.
The average throughput margin for 1992 was $7.00 per barrel
compared to $7.31 per barrel for 1991, calculated using total
throughput volumes, or $8.84 per barrel for 1991, using only
HDS/HOC complex volumes. The decrease in average throughput
margin per barrel in 1992 compared to 1991 is primarily due to a
decrease in refined product sales prices. Operating income in
1991 also benefitted significantly from a forward sale in 1991 of
a significant portion of refined products at the higher prices
which prevailed prior to the Arabian Gulf crisis in January 1991.
Other Operations
Operating income from other operations for 1992
increased $11.2 million primarily due to the inclusion of $9.3
million of operating income associated with the NGL Assets.
Partnership Operations
The Company's equity in earnings of the Partnership
decreased in 1992 due to a decrease in operating income in both
the Partnership's natural gas and NGL operations and a decrease
in interest and other income.
Operating income from the Partnership's NGL operations
decreased $5.4 million, or 9%, during 1992 compared to 1991 due
to a decrease in the average NGL market price, higher shrinkage
costs and higher operating expenses. This was partially offset
by an increase in production, transportation and fractionation
volumes and a decrease in depreciation expense. Operating income
from the Partnership's natural gas operations decreased $4.6
million, or 12%, to $32.5 million during 1992 compared to 1991
due to a decrease in natural gas sales volumes, lower average
transportation fees and higher operating expenses, primarily due
to higher pipeline transportation expense and the charge from the
Company for the Partnership's allocable cost of the Company's
early retirement program. The decrease in operating income as a
result of these factors was partially offset by gas cost
reductions and other benefits of $12.9 million from its Market
Center Services Program.
Other
The Company's other income, net, decreased during 1992
due to decreased interest income caused by decreased average
investments resulting from the gradual utilization of proceeds
from the issuance of Energy's 10.58% Senior Notes in December
1990 and January 1991 and lower interest rates. Interest and
debt expense, net of capitalized interest, increased due to an
increase in interest incurred from substantially higher
borrowings outstanding to finance a portion of the Company's
capital expenditure program and decreased capitalized interest
primarily due to the completion of a major part of the Company's
capital expenditure program, the H/R Units, in early 1992,
partially offset by interest capitalized on the butane upgrade
facility and the Thompsonville gas processing plant (see Notes 2
and 5 of Notes to Consolidated Financial Statements). Income tax
expense was relatively unchanged primarily due to Texas franchise
taxes, which are based on income, offsetting the effect of
reduced income taxes attributable to lower pre-tax income. The
reporting of a portion of Texas franchise taxes as part of income
tax expense commenced in 1992 as a result of new state
legislation enacted during 1991. Preferred stock dividend
requirements decreased in 1992 due to the redemption of one-half
of the outstanding $68.80 Cumulative Preferred Stock, Series B
("Series B Preferred Stock") in September of 1991 and the
remainder in January of 1992. See Note 8 of Notes to
Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
During 1993, net cash provided by the Company's
operating activities totalled $141.3 million compared to $152.5
million during 1992. Net cash provided by operating activities
includes a $39 million favorable effect in 1993 and a $15.1
million unfavorable effect in 1992 from cyclical changes in
current assets and liabilities. These changes for 1993 include a
decrease in inventories compared to 1992, attributable to the
inventory write-down discussed above. The Company utilized the
cash provided by its operating activities, as well as bank
borrowings and proceeds from the disposition of RGV (described
above), to fund capital expenditures, deferred turnaround and
catalyst costs and investments in joint ventures, to pay
dividends and to repay principal on outstanding debt.
As described in Note 4 of Notes to Consolidated
Financial Statements, during February 1992, Energy filed with the
Commission a shelf registration statement to offer up to $150
million principal amount of medium-term notes (the "Medium-Term
Notes"), $116 million of which had been issued through January
1994 with a weighted average life of 8.5 years and a weighted
average interest rate of 8.56%. During March 1992, the Company
issued 2,610,000 shares of Energy common stock ("Common Stock")
at a price to the public of $30 per share which generated net
proceeds of approximately $75 million.
Refining currently maintains a $160 million revolving
credit and letter of credit facility that is available for
working capital purposes and matures September 30, 1996. Energy
has an unsecured $30 million revolving credit and letter of
credit facility which matures February 29, 1996. As of December
31, 1993, Refining and Energy had approximately $52 million and
$29 million, respectively, available under their committed bank
credit facilities for additional borrowings and letters of
credit. Energy also currently has $60 million of unsecured
short-term credit lines which are unrestricted as to use, of
which no amounts were outstanding at December 31, 1993. Total
borrowings under Energy's bank credit facility and short-term
lines are limited to $50 million.
Certain of the Company's financing agreements contain
various financial ratio requirements, including fixed charge
coverage and debt-to-capitalization and require each of the
Company and Refining to maintain a minimum consolidated net worth
and positive working capital (see Note 4 of Notes to Consolidated
Financial Statements). Certain of these financial ratio
requirements were amended, effective as of the fourth quarter of
1993, to improve the financial flexibility of the Company. Under
the most restrictive of the debt-to-capitalization tests, the
Company's indebtedness for borrowed money may not exceed 40% of
its capitalization. At December 31, 1993, this ratio, as
calculated under the most restrictive of the Company's financing
agreements, was 38% and would permit additional borrowings or
guarantees of $47 million. Increases or decreases in the
Company's stockholders' equity, such as those resulting from
incremental earnings or losses, cash dividends, stock issuances,
or stock redemptions or repurchases, will disproportionately
increase or decrease the amount of additional permitted
borrowings or guarantees. As described in Note 4 of Notes to
Consolidated Financial Statements, at December 31, 1993, the
Company had the ability to pay $47.6 million in Common Stock
dividends and other restricted payments under its principal bank
credit agreements, which were the most restrictive of its
provisions concerning restricted payments.
In September 1991 Energy redeemed one-half, and in
November 1991 called for redemption the other one-half, of its
Series B Preferred Stock for a total of $42.4 million. In June
1992, the Energy Board of Directors approved a stock repurchase
program of up to one million shares of Common Stock. Through
December 31, 1993, Energy had repurchased 455,000 shares at an
average price of $23.75 per share.
During 1993, the Company incurred $166 million for
capital expenditures, deferred turnaround and catalyst costs,
investments and related expenditures. Expenditures for 1993
included $149 million for Refinery expenditures, such as the
butane upgrade facility, the MTBE/TAME complex, the reformate
splitter and the scheduled maintenance and catalyst change for
the Refinery's HDS Unit completed in December 1993. Such amounts
include $37 million for capital expenditures incurred in 1993,
but not payable until 1994. For 1994, the Company currently
expects to incur approximately $80 million for capital
expenditures, deferred turnaround and catalyst costs, investments
and related expenditures. In addition, the Company expects to
pay approximately $117.5 million for an effective equity interest
of 51% in VNGP, L.P. as discussed above. The Partnership
currently expects to incur approximately $40 million in capital
expenditures in 1994, much of which would be incurred after the
expected merger date. The Company believes it has sufficient
funds from operations, the convertible preferred stock offering
discussed above, and to the extent necessary, from the public
markets and private capital markets, to fund its current and
ongoing operating requirements.
The Energy Board of Directors increased the quarterly
dividend on its Common Stock from $.11 per share to $.13 per
share at its September 1993 meeting, effective in the fourth
quarter of 1993. Dividends are considered quarterly by the
Energy Board of Directors, and may be paid only when approved by
the Board. The Company knows of no reason why Common Stock
dividends at the current levels could not be continued.
The Company's refining operations have a concentration
of customers in the spot and retail gasoline markets. These
concentrations of customers may impact the Company's overall
exposure to credit risk, either positively or negatively, in that
the customers may be similarly affected by changes in economic or
other conditions. However, the Company believes that its
portfolio of accounts receivable is sufficiently diversified to
the extent necessary to minimize any potential credit risk.
Historically, the Company has not had any significant problems
collecting its accounts receivable. The accounts receivable and
inventories of Refining are pledged as collateral under
Refining's bank credit agreement.
The Company is subject to environmental regulation at
both the federal and state level. The Company's expenditures for
environmental control and protection for its refining operations
are expected to be approximately $6 million in 1994 and totalled
approximately $8 million in 1993. These amounts are exclusive of
any amounts related to recently constructed facilities for which
the portion of expenditures relating to environmental
requirements is not determinable. The Refinery was completed in
1984 under more stringent environmental requirements than most
existing United States refineries, which are older and were built
before such environmental regulations were enacted. As a result,
the Company is able to more easily comply with present and future
environmental legislation. Under provisions of the Clean Air Act
Amendments of 1990 (the "Clean Air Act"), all U.S. refineries
must obtain new operating permits by 1995. However, the Clean
Air Act is not expected to have any significant adverse impact on
the Refinery's operations and the Company does not anticipate
that it will be necessary to expend any material amounts in
addition to those mentioned herein to comply with such
legislation. The Clean Air Act also has requirements for
oxygenated gasolines, which add oxygenates such as MTBE and
ethanol to the gasoline pool. Such requirements are expected to
increase the demand for MTBE. However, recent renewable
oxygenate rules proposed under the Clear Air Act may adversely
affect the anticipated growth in demand for MTBE. The Company is
not aware of any material environmental remediation costs related
to its operations. Accordingly, no amount has been accrued for
any contingent environmental liability.
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Valero Energy Corporation:
We have audited the accompanying consolidated balance
sheets of Valero Energy Corporation (a Delaware corporation) and
subsidiaries as of December 31, 1993 and 1992, and the related
consolidated statements of income, common stock and other
stockholders' equity and cash flows for each of the three years
in the period ended December 31, 1993. These financial
statements and the schedules referred to below are the
responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and
schedules based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to
above present fairly, in all material respects, the financial
position of Valero Energy Corporation and subsidiaries as of
December 31, 1993 and 1992, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1993, in conformity with generally accepted
accounting principles.
Our audits were made for the purpose of forming an
opinion on the basic financial statements taken as a whole. The
supplemental schedules V, VI and IX are presented for purposes of
complying with the Securities and Exchange Commission's rules and
are not part of the basic financial statements. These schedules
have been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required
to be set forth therein in relation to the basic financial
statements taken as a whole.
ARTHUR ANDERSEN & CO.
San Antonio, Texas
February 17, 1994
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
<CAPTION>
December 31,
1993 1992
A S S E T S
<S> <C> <C>
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . . . $ 7,252 $ 8,174
Receivables, less allowance for doubtful accounts of $359 (1993) and
$999 (1992). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64,521 99,755
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113,384 146,361
Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . . 12,304 13,959
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . 38,025 36,587
235,486 304,836
PROPERTY, PLANT AND EQUIPMENT - including construction in
progress of $10,158 (1993) and $198,496 (1992), at cost. . . . . . . . . . . 1,640,136 1,543,342
Less: Accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . 346,570 311,264
1,293,566 1,232,078
INVESTMENT IN AND LEASES RECEIVABLE FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130,557 125,285
INVESTMENT IN AND ADVANCES TO JOINT VENTURES . . . . . . . . . . . . . . . . . 28,343 24,809
DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . . . 76,485 72,092
$1,764,437 $1,759,100
L I A B I L I T I E S A N D S T O C K H O L D E R S' E Q U I T Y
CURRENT LIABILITIES:
Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . $ 28,737 $ 16,327
Notes payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 6,700
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90,994 113,512
Accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33,296 36,188
Income taxes payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 1,793
153,027 174,520
LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . . . 485,621 482,358
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232,564 226,206
DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . . 37,128 40,308
REDEEMABLE PREFERRED STOCK, SERIES A . . . . . . . . . . . . . . . . . . . . . 13,800 14,950
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY:
Preferred stock, $1 par value - 20,000,000 shares authorized:
Redeemable Preferred Stock, Series A, issued 1,150,000 shares,
outstanding 138,000 (1993) and 149,500 (1992) shares . . . . . . . . . . - -
Common stock, $1 par value - 75,000,000 shares authorized; issued
43,391,685 (1993) and 43,320,935 (1992) shares . . . . . . . . . . . . . . 43,392 43,321
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . 371,303 371,759
Unearned Valero Employees' Stock Ownership Plan Compensation . . . . . . . . (15,958) (18,085)
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 446,931 431,600
Treasury stock, 145,119 (1993) and 336,076 (1992) common shares, at cost . . (3,371) (7,837)
842,297 820,758
$1,764,437 $1,759,100
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $1,222,239 $1,234,618 $1,011,835
COSTS AND EXPENSES:
Cost of sales . . . . . . . . . . . . . . . . . . . . . 970,435 926,189 740,623
Operating expenses. . . . . . . . . . . . . . . . . . . 119,567 126,185 115,339
Depreciation expense. . . . . . . . . . . . . . . . . . 56,733 48,214 36,607
Total . . . . . . . . . . . . . . . . . . . . . . . . 1,146,735 1,100,588 892,569
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 75,504 134,030 119,266
EQUITY IN EARNINGS OF AND INCOME FROM VALERO
NATURAL GAS PARTNERS, L.P.. . . . . . . . . . . . . . . 23,693 26,360 32,389
GAIN ON DISPOSITION OF ASSETS AND OTHER INCOME, NET. . . . 6,209 1,452 7,252
INTEREST AND DEBT EXPENSE:
Incurred. . . . . . . . . . . . . . . . . . . . . . . . (49,517) (46,276) (37,948)
Capitalized . . . . . . . . . . . . . . . . . . . . . . 12,335 15,853 25,408
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 68,224 131,419 146,367
INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . . . 31,800 47,500 47,700
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 36,424 83,919 98,667
Less: Preferred stock dividend requirements. . . . . . 1,262 1,475 6,044
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . $ 35,162 $ 82,444 $ 92,623
EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . . . $ .82 $ 1.94 $ 2.28
DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . . . $ .46 $ .42 $ .34
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Dollars)
<CAPTION>
Series B
Preferred Number of Common Additional Unearned
Stock Common Stock Paid-in VESOP Retained Treasury
$1 Par Shares $1 Par Capital Compensation Earnings Stock
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, December 31, 1990 . . . $ 80 40,710,935 $40,711 $340,780 $(13,510) $291,028 $(1,013)
Net income . . . . . . . . . . - - - - - 98,667 -
Dividends on Series A
Preferred Stock. . . . . . . - - - - - (1,466) -
Dividends on Series B
Preferred Stock. . . . . . . - - - - - (5,160) -
Dividends on Common Stock. . . - - - - - (13,793) -
Redemption of Series B
Preferred Stock. . . . . . . (80) - - (39,920) - (2,360) -
Unearned Valero Employees' Stock
Ownership Plan compensation,
net. . . . . . . . . . . . - - - - (6,590) - -
Shares repurchased and shares
issued pursuant to employee
stock plans and other. . . . - - - (149) - - (690)
BALANCE, December 31, 1991 . . . - 40,710,935 40,711 300,711 (20,100) 366,916 (1,703)
Net income . . . . . . . . . . - - - - - 83,919 -
Dividends on Series A
Preferred Stock. . . . . . . - - - - - (1,368) -
Dividends on Common Stock. . . - - - - - (17,867) -
Unearned Valero Employees' Stock
Ownership Plan compensation. - - - - 2,015 - -
Sale of Common Stock, net. . . - 2,610,000 2,610 72,197 - - -
Shares repurchased and shares
issued pursuant to employee
stock plans and other. . . . - - - (1,149) - - (6,134)
BALANCE, December 31, 1992 . . . - 43,320,935 43,321 371,759 (18,085) 431,600 (7,837)
Net income . . . . . . . . . . - - - - - 36,424 -
Dividends on Series A
Preferred Stock. . . . . . . - - - - - (1,271) -
Dividends on Common Stock. . . - - - - - (19,822) -
Unearned Valero Employees' Stock
Ownership Plan compensation. - - - - 2,127 - -
Shares repurchased and shares
issued pursuant to employee
stock plans and other. . . . - 70,750 71 (456) - - 4,466
BALANCE, December 31, 1993 . . . $ - 43,391,685 $43,392 $371,303 $(15,958) $446,931 $(3,371)
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . $ 36,424 $ 83,919 $ 98,667
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation expense . . . . . . . . . . . . . . . . 56,733 48,214 36,607
Amortization of deferred charges and other, net. . . 22,766 20,117 18,091
Gain on disposition of assets, net of other
nonoperating charges . . . . . . . . . . . . . . . (6,878) - -
Changes in current assets and current liabilities. . 39,048 (15,123) (2,399)
Deferred income tax expense . . . . . . . . . . . . 15,300 26,200 45,500
Equity in earnings of Valero Natural Gas Partners,
L.P. in excess of distributions. . . . . . . . . . (4,970) (1,067) -
Prepaid contribution to Valero Employees' Stock
Ownership Plan . . . . . . . . . . . . . . . . . . - - (8,000)
Changes in deferred items and other, net . . . . . . (17,142) (9,749) (5,693)
Net cash provided by operating activities. . . . . 141,281 152,511 182,773
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions. . . . . . . . . . . . . . . . . . . . (136,594) (282,755) (229,747)
Deferred turnaround and catalyst costs . . . . . . . . . (23,054) (12,209) (41,692)
Assets leased to Valero Natural Gas Partners, L.P. . . . - (25,849) (16,262)
Distributions in excess of equity in earnings of Valero
Natural Gas Partners, L.P. . . . . . . . . . . . . . . - - 1,030
Investment in and advances to joint ventures . . . . . . (6,167) (8,649) (1,937)
Dispositions of property, plant and equipment. . . . . . 30,720 1,197 353
Principal payments received under capital lease
obligations. . . . . . . . . . . . . . . . . . . . . . 527 61 -
Other, net . . . . . . . . . . . . . . . . . . . . . . . 464 (528) 493
Net cash used in investing activities. . . . . . . . . (134,104) (328,732) (287,762)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt reduction, net. . . . . . . . . . . . . . (15,000) (756) (517)
Long-term borrowings, net. . . . . . . . . . . . . . . . 32,000 119,000 134,250
Increase (decrease) in notes payable . . . . . . . . . . (6,700) 6,700 -
Preferred stock dividends. . . . . . . . . . . . . . . . (1,271) (1,368) (6,626)
Common stock dividends . . . . . . . . . . . . . . . . . (19,822) (17,867) (13,793)
Issuance (repurchase) of common stock, net . . . . . . . 3,844 65,984 (2,699)
Repurchase of Series A Preferred Stock . . . . . . . . . (1,150) (1,150) (1,150)
Redemption of Series B Preferred Stock . . . . . . . . . - - (42,360)
Net cash provided by (used in) financing activities. . (8,099) 170,543 67,105
NET DECREASE IN CASH AND TEMPORARY CASH
INVESTMENTS. . . . . . . . . . . . . . . . . . . . . . . (922) (5,678) (37,884)
CASH AND TEMPORARY CASH INVESTMENTS AT
BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . 8,174 13,852 51,736
CASH AND TEMPORARY CASH INVESTMENTS AT
END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . $ 7,252 $ 8,174 $ 13,852
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements
include the accounts of Valero Energy Corporation ("Energy") and
subsidiaries (collectively referred to herein as the "Company").
All significant intercompany transactions have been eliminated in
consolidation. Energy conducts its refining operations through
its wholly owned subsidiary, Valero Refining and Marketing
Company ("VRMC"), and VRMC's principal operating subsidiary,
Valero Refining Company ("VRC") (collectively referred to herein
as "Refining"). Certain prior period amounts have been
reclassified for comparative purposes.
The Company accounts for its investment in Valero
Natural Gas Partners, L.P. ("VNGP, L.P.") and VNGP, L.P.'s
consolidated subsidiaries, including Valero Management
Partnership, L.P. (the "Management Partnership") and various
subsidiary operating partnerships ("Subsidiary Operating
Partnerships" or "SOPs") (collectively referred to herein as the
"Partnership") on the equity method of accounting. The
Partnership acquired substantially all of the Company's natural
gas and natural gas liquids operations in March 1987 in exchange
for cash and an effective equity interest in the Partnership of
approximately 49%. See Note 2 for a further discussion of the
Partnership. Income taxes on the Company's equity in earnings of
the Partnership are included in the provision for income taxes.
Statements of Cash Flows
In order to determine net cash provided by operating
activities, net income has been adjusted by, among other things,
changes in current assets and current liabilities, excluding
changes in cash and temporary cash investments, current
maturities of long-term debt and notes payable. Those changes
are shown in the following table as an (increase) decrease in
current assets and an increase (decrease) in current liabilities.
The Company's temporary cash investments are highly liquid low-
risk debt instruments which have a maturity of three months or
less when acquired and whose carrying amounts approximate fair
value. (Dollars in thousands.)
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Receivables, net . . . . . . . . . . . . . $31,854 $(43,486) $ 13,643
Inventories. . . . . . . . . . . . . . . . 32,977 38,494 (15,315)
Current deferred income tax assets . . . . 1,655 7,599 (9,318)
Prepaid expenses and other . . . . . . . . (1,911) (3,295) (9,523)
Accounts payable . . . . . . . . . . . . . (21,778) (19,437) 15,983
Accrued expenses . . . . . . . . . . . . . (1,956) 3,281 3,299
Income taxes payable . . . . . . . . . . . (1,793) 1,721 (1,168)
Total. . . . . . . . . . . . . . . . . . $39,048 $(15,123) $ (2,399)
</TABLE>
The following provides information related to cash
interest and income taxes paid by the Company for the periods
indicated (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Interest - net of amount capitalized of $12,335 (1993),
$15,853 (1992) and $25,408 (1991). . . . . . . . . . . $36,001 $25,850 $11,754
Income taxes . . . . . . . . . . . . . . . . . . . . . . 18,324 17,821 3,367
</TABLE>
Noncash investing and financing activities for the years
ended December 31, 1993, 1992 and 1991 include reductions of $1.3
million, $1.2 million and $1.1 million, respectively, of the
recorded guarantee by Energy of a $15 million long-term borrowing
by the Valero Employees' Stock Ownership Plan ("VESOP") to
purchase Common Stock. Such reductions were a result of debt
service by the VESOP. See Notes 4 and 12. Noncash investing and
financing activities for 1993 also include the reclassification
to property, plant and equipment of $5 million previously
included in deferred charges and other assets on the Consolidated
Balance Sheet. Noncash investing activities between Energy and
the Partnership include the East Texas pipeline and fractionation
facilities leases in 1991 and the Thompsonville Project lease in
1992 (see Note 2). Noncash financing activities for 1991 include
a benefit of $.9 million credited to stockholders' equity for
stock option exercises and represents the tax effect of the
difference between market value at date of grant and market value
at date of exercise for all options exercised during the period.
Inventories
Inventories are carried at the lower of cost or market
with cost determined primarily under the last-in, first-out
("LIFO") method of inventory costing. Inventories as of December
31, 1993 and December 31, 1992 were as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Refinery feedstocks and blendstocks. . . . . . . . $ 70,807 $102,722
Refined products . . . . . . . . . . . . . . . . . 42,577 43,639
$113,384 $146,361
</TABLE>
During the fourth quarter of 1993, Refining incurred a
charge to earnings of $27.6 million to write down the carrying
value of its inventories to reflect existing market prices. As a
result of the inventory write-down, the replacement cost of
Refining's inventories was approximately equal to its LIFO value
at December 31, 1993.
Property, Plant and Equipment
Property additions and betterments include capitalized
interest, and acquisition and administrative costs allocable to
construction and property purchases.
The costs of minor property units (or components
thereof), net of salvage, retired or abandoned are charged or
credited to accumulated depreciation. Gains or losses on sales
or other dispositions of major units of property are credited or
charged to income.
Provision for depreciation of property, plant and
equipment is made primarily on a straight-line basis over the
estimated useful lives of the depreciable facilities. The rates
for depreciation are as follows:
<TABLE>
<S> <C>
Refining and marketing . . . . 3 3/5%
Other operations . . . . . . . 2% - 20%
</TABLE>
Income Taxes
Effective January 1, 1992, the Company adopted Statement
of Financial Accounting Standards ("SFAS") No. 109, "Accounting
for Income Taxes." SFAS No. 109 superseded SFAS No. 96 which the
Company had adopted in 1987. These statements established
financial accounting and reporting standards for deferred income
tax liabilities that arise as a result of differences between the
reported amounts of assets and liabilities for financial
reporting and income tax purposes.
Deferred Charges
Catalyst and Refinery Turnaround Costs
Catalyst cost is deferred when incurred and amortized
over the estimated useful life of that catalyst, normally one to
three years. Refinery turnaround costs are deferred when
incurred and amortized over that period of time estimated to
lapse until the next turnaround occurs.
Other Deferred Charges
Other deferred charges consist of technological
royalties and licenses, debt issuance costs, and certain other
costs. Technological royalties and licenses are amortized over
the estimated useful life of each particular related asset. Debt
issuance costs are amortized by the effective interest method
over the estimated life of each instrument or facility.
Transactions with Affiliates
Transactions with affiliates primarily represent those
conducted with the Partnership. See Note 2.
Price Risk Management Activities
The Company periodically enters into exchange-traded
futures and options contracts and forward contracts to hedge
against a portion of the price risk associated with price
fluctuations from holding inventories of feedstocks and refined
products. Changes in the market value of such contracts are
accounted for as additions to or reductions in inventory.
Gains and losses resulting from changes in the market value
of such contracts are recognized when the related inventory
is sold. The Company also enters into futures and options
contracts that are not specific hedges and gains or losses
resulting from changes in the market value of these
contracts are recognized in income currently. As of
December 31, 1993 and 1992, the Company had outstanding contracts
for quantities totalling 2,700 thousand barrels ("Mbbls") and
2,260 Mbbls, respectively, for which the Company is the fixed
price payor and 2,615 Mbbls and 1,613 Mbbls, respectively, for
which the Company is the fixed price receiver. Such contracts
run for a period of approximately two to five months. A portion
of such contracts represented hedges of inventory volumes which
totalled approximately 8,082 Mbbls and 8,693 Mbbls at
December 31, 1993 and 1992, respectively. See "Inventories"
above. The Company's activities in both hedging and nonhedging
futures and options contracts were not material to the Company's
results of operations for the years ended December 31, 1993, 1992
and 1991.
Earnings Per Share
Earnings per share of common stock were computed, after
recognition of the preferred stock dividend requirements, based
on the weighted average number of common shares outstanding
during each year. Potentially dilutive common stock equivalents
and other potentially dilutive securities were not material and
therefore were not included in the computation. The weighted
average number of common shares outstanding for the years ended
December 31, 1993, 1992 and 1991 was 43,098,808, 42,577,368, and
40,570,798, respectively.
Accounting Change
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions." See Note 12.
Accrued Expenses
Accrued expenses for the periods indicated are as
follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Accrued taxes. . . . . . . . . . . . . . . . . . . . $10,133 $17,534
Other accrued employee benefit costs (see Note 12) . 7,043 3,307
Accrued pension cost (see Note 12) . . . . . . . . . 5,872 6,526
Accrued interest . . . . . . . . . . . . . . . . . . 5,063 5,185
Other. . . . . . . . . . . . . . . . . . . . . . . . 5,185 3,636
$33,296 $36,188
</TABLE>
2. VALERO NATURAL GAS PARTNERS, L.P.
The Company holds an effective equity interest of
approximately 49% in the Partnership at December 31, 1993,
consisting of general partner interests and common units of
limited partner interests (the "Common Units"). The remaining
equity interest in the Partnership consisting of publicly traded
common units of limited partner interests are referred to herein
as "Public Units" and holders of such units are referred to as
"Public Unitholders."
Components of the line items Investment in and Leases
Receivable from Valero Natural Gas Partners, L.P. in the
accompanying Consolidated Balance Sheets and Equity in Earnings
of and Income from Valero Natural Gas Partners, L.P. in the
accompanying Consolidated Statements of Income, are as follows
(in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Investment in Valero Natural Gas Partners, L.P.. . . . . $ 25,047 $ 20,077
Leases receivable from Valero Natural Gas Partners, L.P. 105,510 105,208
$130,557 $125,285
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Equity in earnings of Valero Natural Gas
Partners, L.P. . . . . . . . . . . . . . . . . $10,515 $15,974 $22,729
Interest income from capital lease transactions
with Valero Natural Gas Partners, L.P. . . . . 13,178 10,386 9,660
$23,693 $26,360 $32,389
</TABLE>
Summarized financial information for the Partnership for
each of the three years in the period ended December 31, 1993 is
as follows (in thousands, except per Unit amounts):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Income statement data:
Operating revenues. . . . . . . . . . . . . $1,326,458 $1,197,129 $1,144,001
Depreciation expense. . . . . . . . . . . . 36,446 34,404 39,231
Operating income. . . . . . . . . . . . . . 79,478 89,841 99,834
Net income. . . . . . . . . . . . . . . . . 14,447 24,986 37,036
General Partners' interest. . . . . . . . . 1,217 1,596 1,973
Net income allocable to Limited Partners. . 13,230 23,390 35,063
Net income per Limited Partner Unit . . . . .72 1.27 1.90
Statement of cash flows data:
Net cash provided by operating activities . $ 70,481 $ 77,886 $ 84,281
Capital expenditures. . . . . . . . . . . . 36,061 35,893 33,074
Partnership distributions . . . . . . . . . 10,420 29,532 48,036
Balance sheet data:
Total assets. . . . . . . . . . . . . . . . $1,045,082 $1,084,481 $1,061,490
First Mortgage Notes. . . . . . . . . . . . 534,286 559,643 582,500
Capital lease obligations . . . . . . . . . 104,838 104,839 77,542
Weighted average Units outstanding. . . . . . 18,487 18,487 18,487
</TABLE>
The Partnership is required to make quarterly cash
distributions with respect to all units in an amount equal to
"Distributable Cash Flow" as defined in the Second Amended and
Restated Agreement of Limited Partnership of VNGP, L.P.
Beginning with the second quarter of 1992, the quarterly cash
distributions were reduced from a rate of $.625 per unit to a
rate of $.125 per unit. On January 25, 1994, the Board of
Directors of VNGC declared a cash distribution of $.125 per unit
for the fourth quarter of 1993 that is payable March 1, 1994.
Net income is allocated to partners based on their
effective ownership interest in the Partnership, except that
additional depreciation expense pertaining to the excess of the
Partnership's acquisition cost over the Company's historical cost
basis in net property, plant and equipment and certain other
assets in which the Public Unitholders currently have an
ownership interest is allocated solely to the Public Unitholders
as a noncash charge to net income. The allocation of additional
depreciation expense to the Public Unitholders does not affect
the cash distributions with respect to the Public Units or to the
Company as holder of the Common Units.
The Company enters into transactions with the
Partnership commensurate with its status as the General Partner.
The Company charges the Partnership a management fee equal to the
direct and indirect costs incurred by it on behalf of the
Partnership that are associated with managing the Partnership's
operations. In addition, Refining purchases natural gas and NGLs
from the Partnership and sells NGLs to the Partnership. The
Company pays the Partnership a fee for operating the Company's
NGL Assets. In connection with the NGL Assets, the Company also
pays the Partnership a fee to process natural gas, buys natural
gas from and sells natural gas and NGLs to the Partnership. The
Company's retail natural gas distribution system operated by Rio
Grande Valley Gas Company, a wholly owned subsidiary of Energy
until its sale on September 30, 1993, purchases natural gas from
the Partnership. Also, the Company and the Partnership enter
into other operating transactions, including certain leasing
transactions which are described below. As of December 31, 1993
and 1992, the Company had recorded approximately $31.8 million
and $13.5 million, respectively, of accounts receivables, net of
accounts payables, due from the Partnership.
The following table summarizes transactions between the
Company and the Partnership for each of the three years in the
period ended December 31, 1993 (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
NGL purchases and services from the Partnership . $98,590 $96,696 $86,936
Natural gas purchases from the Partnership. . . . 59,735 50,991 38,072
Sales of NGLs and natural gas and transportation
and other charges to the Partnership . . . . . 38,868 54,674 19,752
Management fees billed to the Partnership for
direct and indirect costs. . . . . . . . . . . 80,727 82,024 73,324
</TABLE>
During 1992, the Partnership entered into a capital
lease with Energy to lease a 200-million cubic foot per day
turboexpander gas processing plant near Thompsonville in South
Texas and 48 miles of NGL product pipeline (the "Thompsonville
Project") which were constructed by Energy. The Thompsonville
Project lease commenced December 1, 1992 and has a term of 15
years. During 1991, the Company leased its interests in a newly
constructed 105-mile pipeline in East Texas (the "East Texas
Pipeline") and certain fractionation facilities in Corpus
Christi, Texas, to the Partnership under capital leases. The
fractionation facility lease, which commenced December 1, 1991,
has a term of 15 years. The East Texas Pipeline lease, which
commenced February 1, 1991, has a term of 25 years. Future
minimum lease payments to be received from the Partnership for
the years 1994 through 1998 are $12.9 million, $12.9 million,
$13.9 million, $15.1 million and $15.4 million, respectively.
Components of the Company's net investment in these
capital leases at December 31, 1993, which is included in
Investment in and Leases Receivable from Valero Natural Gas
Partners, L.P. in the accompanying Consolidated Balance Sheet,
are as follows (in thousands):
<TABLE>
<S> <C>
Minimum lease payments receivable . . . . . . . . . . . . $283,633
Estimated unguaranteed residual values of leased property 17,220
Less unearned income. . . . . . . . . . . . . . . . . . . (195,343)
Net investment in capital leases. . . . . . . . . . . . . $105,510
</TABLE>
Effective December 20, 1993, Energy, Valero Natural Gas
Company ("VNGC", a wholly owned subsidiary of Energy and general
partner of VNGP, L.P.,) and VNGP, L.P. entered into an agreement
of merger. In the merger, the 9.7 million issued and outstanding
Public Units will be converted into a right to receive cash
consideration of $12.10 per Common Unit, and VNGP, L.P. will
become a wholly owned subsidiary of Energy. A special committee
of outside directors (the "Special Committee") of VNGC, appointed
to consider the fairness of the transaction to the Public
Unitholders, has received an opinion from its independent
financial advisor that the consideration to be received by the
Public Unitholders in the transaction is fair from a financial
point of view. The Special Committee has determined that such
transaction is fair to, and in the best interest of, the Public
Unitholders. The Board of Directors of VNGC has unanimously
recommended that the Public Unitholders vote in favor of the
merger. The transaction is subject, among other things, to: (i)
approval by the holders of a majority of the issued and
outstanding Common Units, (ii) approval by the holders of a
majority of the Common Units held by the Public Unitholders and
voted at a special meeting to be called for the purpose of
considering such merger; (iii) receipt of satisfactory waivers,
consents or amendments to certain of the Company's financial
agreements; and (iv) completion of the offering of convertible
preferred stock (see Note 7 of Notes to Consolidated Financial
Statements). These financial agreements, which include a new
bank credit agreement as well as amendments to other financial
agreements, are in the process of being negotiated to provide for
the proposed merger. While Energy believes that it will obtain
satisfactory new agreements and amendments, there can be no
assurance in this regard. The Company currently owns
approximately 47.5% of the Common Units and intends to vote such
Common Units in favor of the transaction. A proposal to approve
the merger agreement will be submitted to the holders of Common
Units at a special meeting of unitholders tentatively scheduled
to be held during the second quarter of 1994. There can be no
assurance, however, that the merger can be completed.
The accompanying unaudited pro forma condensed
consolidated financial statements of Valero Energy Corporation
and subsidiaries give effect to the sale of $150 million of
convertible preferred stock and the utilization of approximately
$117.5 million of the net proceeds therefrom to fund the
acquisition by the Company of the Public Units. The remaining
net proceeds, estimated to be approximately $28.4 million, are
used to pay expenses of the proposed acquisition and reduce
outstanding indebtedness under bank credit lines. The
acquisition is accounted for as a purchase. The pro forma
condensed consolidated financial statements are based on the
historical consolidated financial statements of Valero Energy
Corporation and Valero Natural Gas Partners, L.P. after certain
adjustments as described below. The pro forma condensed
consolidated balance sheet assumes that the above described
transactions occurred on December 31, 1993. The pro forma
consolidated statement of income assumes that the above described
transactions occurred on January 1, 1993. Following these pro
forma financial statements are accompanying explanatory notes.
Such pro forma condensed consolidated financial statements are
not necessarily indicative of the results of future operations.
<PAGE>
<TABLE>
Pro Forma Condensed Consolidated Balance Sheet
December 31, 1993
(Thousands of dollars)
(Unaudited)
<CAPTION>
VALERO
VALERO VNGP, ENERGY
ENERGY L.P. Pro Forma
ASSETS Historical Historical ADJUSTMENTS Consolidated
<S> <C> <C> <C> <C>
CURRENT ASSETS. . . . . . . . . . . . . . . . $ 235,486 $ 224,967 $ (46,717) (a) $ 413,736
PROPERTY, PLANT AND
EQUIPMENT, NET . . . . . . . . . . . . . . . 1,293,566 739,802 37,888 (b) 2,071,256
INVESTMENT IN AND LEASES
RECEIVABLE FROM VALERO
NATURAL GAS PARTNERS, L.P. . . . . . . . . . 130,557 - (130,557) (c) -
INVESTMENT IN AND ADVANCES TO
JOINT VENTURES . . . . . . . . . . . . . . . 28,343 - - 28,343
DEFERRED CHARGES AND OTHER
ASSETS . . . . . . . . . . . . . . . . . . . 76,485 80,313 (24,473) (b) 132,325
$1,764,437 $1,045,082 $(163,859) $2,645,660
LIABILITIES AND STOCKHOLDERS'
EQUITY/PARTNERS' CAPITAL
CURRENT LIABILITIES . . . . . . . . . . . . . $ 153,027 $ 273,272 $ (47,694) (a)(c) $ 378,605
LONG-TERM DEBT,
less current maturities. . . . . . . . . . . 485,621 506,429 (7,716) (b)(d) 984,334
CAPITAL LEASE OBLIGATIONS,
less current maturities. . . . . . . . . . . - 103,787 (103,787) (c) -
DEFERRED INCOME TAXES . . . . . . . . . . . . 232,564 - - 232,564
DEFERRED CREDITS AND
OTHER LIABILITIES. . . . . . . . . . . . . . 37,128 1,548 9,444 (b) 48,120
REDEEMABLE PREFERRED STOCK,
SERIES A . . . . . . . . . . . . . . . . . . 13,800 - - 13,800
STOCKHOLDERS' EQUITY. . . . . . . . . . . . . 842,297 - 145,940 (e) 988,237
PARTNERS' CAPITAL . . . . . . . . . . . . . . - 160,046 (160,046) (c) -
$1,764,437 $1,045,082 $(163,859) $2,645,660
</TABLE>
<PAGE>
<TABLE>
Pro Forma Consolidated Statement of Income
For the Year Ended December 31, 1993
(Thousands of Dollars, Except per Share Amounts)
(Unaudited)
<CAPTION>
VALERO
VALERO VNGP, ENERGY
ENERGY L.P. Pro Forma
Historical Historical ADJUSTMENTS Consolidated
<S> <C> <C> <C> <C>
OPERATING REVENUES. . . . . . . . . . . . . . $1,222,239 $1,326,458 $(273,366) (a)(b) $2,275,331
COSTS AND EXPENSES:
Cost of sales. . . . . . . . . . . . . . . . 970,435 1,090,363 (197,465) (a)(b) 1,863,333
Operating expenses . . . . . . . . . . . . . 119,567 120,171 (82,254) (a)(b) 157,484
Depreciation expense . . . . . . . . . . . . 56,733 36,446 (269) (b) 92,910
1,146,735 1,246,980 (279,988) 2,113,727
OPERATING INCOME. . . . . . . . . . . . . . . 75,504 79,478 6,622 161,604
EQUITY IN EARNINGS OF AND INCOME
FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . . . . . 23,693 - (23,693) (c) -
GAIN ON DISPOSITION OF ASSETS
AND OTHER INCOME, NET. . . . . . . . . . . . 6,209 1,263 214 (b) 7,686
INTEREST AND DEBT EXPENSE:
Incurred . . . . . . . . . . . . . . . . . . (49,517) (68,007) 13,684 (b)(c)(d) (103,840)
Capitalized. . . . . . . . . . . . . . . . . 12,335 1,713 - 14,048
INCOME BEFORE INCOME TAXES. . . . . . . . . . 68,224 14,447 (3,173) 79,498
INCOME TAX EXPENSE. . . . . . . . . . . . . . 31,800 - 3,900 (f) 35,700
NET INCOME. . . . . . . . . . . . . . . . . . 36,424 14,447 (7,073) 43,798
Less: preferred stock
dividend requirements. . . . . . . . . . . 1,262 - 9,750 (e) 11,012
NET INCOME APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . . . . $ 35,162 $ 14,447 $ (16,823) $ 32,786
EARNINGS PER SHARE OF COMMON
STOCK. . . . . . . . . . . . . . . . . . . . $ .82 $ .76
</TABLE>
[FN]
(a) Reflects the elimination of transactions between
the Company and VNGP, L.P., including product sales and
purchases, management fees billed by the Company to the
Partnership for direct and indirect costs, and accrued
interest receivable and payable on leases.
(b) Adjustment to fair value of the portion of VNGP,
L.P.'s assets acquired and liabilities assumed not currently held
by the Company and the related income statement effects. Also
included is the elimination of the noncurrent receivable and
payable between the Company and VNGP, L.P. for postretirement
benefits other than pensions.
(c) Reflects the elimination of the Company's
investment in and leases receivable from VNGP, L.P. and related
equity in earnings and interest income. The corresponding VNGP,
L.P. partners' capital and current and long-term portions of
VNGP, L.P.'s capital lease obligations to the Company and related
interest expense are also eliminated.
(d) Represents the repayment of $21.7 million of
indebtedness under bank credit lines with the excess of the net
proceeds of the offering over the acquisition cost of the limited
partner interests in VNGP, L.P. not currently held by the Company
and the expenses of the acquisition, which causes a decrease in
interest expense.
(e) Represents the net proceeds from the sale of $150
million of assumed 6.5% convertible preferred stock and the
related increase in preferred stock dividends. The preferred
stock is assumed to be convertible into Common Stock at a premium
of 25% above a Common Stock market price of $22 per share at the
date of issuance of the preferred stock. Conversion of the
convertible preferred stock into Common Stock is antidilutive to
earnings per share of common stock for the year ended December
31, 1993.
(f) Reflects the tax effects of the consolidation of
VNGP, L.P. into the Company, primarily the taxability of VNGP,
L.P.'s net income after its merger into the Company.
3. SHORT-TERM BANK LINES
At December 31, 1993, Energy maintained five separate
short-term bank lines of credit totalling $60 million, of which
no amounts were outstanding. One of these lines is payable on
demand, and the others mature at various times in 1994. These
short-term lines bear interest at each respective bank's quoted
money market rate, have no commitment or other fees or
compensating balance requirements and are unsecured and
unrestricted as to use. Total borrowings under these short-term
lines and Energy's bank credit facility described in Note 4 are
limited to $50 million.
4. LONG-TERM DEBT AND BANK CREDIT FACILITIES
Long-term debt balances were as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Valero Refining and Marketing Company:
Revolving credit and letter of credit facility, 6% at December 31, 1993
(interest fluctuates with prime rate), due September 30, 1996 . . . . . . $ 75,000 $ 43,000
Industrial revenue bonds:
Marine terminal and pollution control revenue bonds, Series
1987A bonds, 10 1/4%, due June 1, 2017. . . . . . . . . . . . . . . . . 90,000 90,000
Marine terminal revenue bonds, Series 1987B bonds, 10 5/8%,
due June 1, 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,500 8,500
Valero Energy Corporation:
Revolving credit and letter of credit facility, 6.25% at December 31, 1993
(interest fluctuates with prime rate), due February 29, 1996. . . . . . . - -
10.58% Senior Notes, due December 30, 2000. . . . . . . . . . . . . . . . . 200,000 200,000
12% Senior subordinated notes, Series A, redeemed September 30, 1993. . . . - 15,000
12 1/4% Senior subordinated notes, Series B, due September 30, 1994 . . . . 15,000 15,000
9.14% VESOP Notes, due February 15, 1999. . . . . . . . . . . . . . . . . . 9,858 11,185
Medium-Term Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116,000 116,000
Total long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . 514,358 498,685
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . 28,737 16,327
$485,621 $482,358
</TABLE>
The Company's bank credit agreements include a $160
million revolving credit and letter of credit facility for
Refining and a separate unsecured $30 million revolving credit
and letter of credit facility for Energy. Borrowings under
Refining's agreement bear interest, at Refining's option, at
either (i) the agent bank's prime rate, (ii) certain reference
banks' adjusted Eurodollar rate plus 3/4 of 1% or (iii) certain
reference banks' average CD rate plus 7/8 of 1%. Borrowings
under Energy's agreement bear interest, at its option, at either
(i) the agent bank's prime rate plus 1/4 of 1%, (ii) certain
reference banks' adjusted Eurodollar rate plus 1 3/8% or (iii)
certain reference banks' average CD rate plus 1 1/2%. The
Company is charged various fees in connection with the bank
credit agreements, including commitment fees based on the unused
portion of the commitments and various letter of credit and
facility fees. As of December 31, 1993, Energy and Refining had
approximately $29 million and $52 million, respectively,
available under their bank credit facilities for additional
borrowings and letters of credit.
Energy filed with the Commission a shelf registration
statement that became effective on February 28, 1992, and is
being used to offer up to $150 million principal amount of
Medium-Term Notes. Through January 1994, the Company has issued,
in ten separate series, $116 million principal amount of Medium-
Term Notes with a weighted average life of approximately 8.5
years and a weighted average interest rate of approximately
8.56%.
Certain of the Company's financing agreements contain
various financial ratio requirements including fixed charge
coverage and debt-to-capitalization and require each of the
Company and Refining to maintain a minimum consolidated net worth
and positive working capital. Certain of these financial ratio
requirements were amended, effective as of the fourth quarter of
1993, to improve the financial flexibility of the Company. Under
the fixed charge coverage ratio tests in the Company's principal
bank credit agreements, the ratio of the Company's earnings to
its fixed charges must be at least 2:1 during the most recent
four consecutive quarters; however, any fiscal quarter in which
one of the Refinery's major units is shut down for scheduled or
periodic maintenance for more than 14 days (a "turnaround
quarter") is excluded from such fixed charge coverage ratio
tests, provided that only one such quarter in each five quarter
period may be excluded. In addition, the Company's unsecured $30
million revolving credit and letter of credit facility requires
that the Company's ratio of earnings to fixed charges be at least
1.5:1 for each quarter (excluding a turnaround quarter). Under
the most restrictive of the debt-to-capitalization tests, the
Company's indebtedness for borrowed money may not exceed 40% of
its capitalization. At December 31, 1993, this ratio, as
calculated under the most restrictive of the Company's financing
agreements, was 38%, and would permit additional borrowings or
guarantees of $47 million. Increases or decreases in the
Company's stockholders' equity, such as those resulting from
incremental earnings or losses, cash dividends, stock issuances,
or stock redemptions or repurchases, will disproportionately
increase or decrease the amount of additional permitted
borrowings or guarantees.
The Company's principal bank credit agreements and
certain other financing agreements contain covenants limiting
Energy's ability to make certain "restricted payments," including
dividend payments on and redemptions or repurchases of its
capital stock and certain investments. Under its principal bank
credit agreements, which currently contain the most restrictive
of these covenants, Energy had the ability to pay $47.6 million
in Common Stock dividends and other restricted payments at
December 31, 1993. Under the Company's bank credit agreements,
the amount available for such payments is increased by an amount
equal to the Company's earnings, the net cash proceeds from any
issuance of capital stock and funded indebtedness, and by an
amount equal to the Company's depreciation and amortization
expense (including amortization of deferred turnaround and
catalyst costs), and is decreased by the amount of capital
expenditures, turnaround and catalyst costs, previous dividends,
investments (including advances to or assets leased to the
Partnership), and repayments of funded indebtedness (other than
under the Company's bank credit agreements). Certain of the
Company's financing agreements also contain various other
covenants, including capital expenditure limitations, limitations
on creating liens or guaranteeing the obligations of others,
limitations on additional debt and on certain transfers of
assets, limitations on entering into new leases, restrictions on
mergers or the acquisition of new subsidiaries or the capital
stock or assets of other companies, customary default provisions
and certain limitations on the businesses of the Company. Under
the bank credit agreements, Energy and VRMC have guaranteed the
obligations of Refining. The obligations of Refining are secured
by a pledge of all inventories and receivables of Refining. The
Company and Refining were in compliance with all required
covenants as of December 31, 1993.
Based on long-term debt outstanding at December 31,
1993, maturities of long-term debt, including sinking fund
requirements and excluding borrowings under bank credit
facilities, for the years ending December 31, 1995 through 1998
are approximately $31.9 million, $36.8 million, $37 million and
$37.2 million, respectively. Maturities of long-term debt under
bank credit facilities for the year ended December 31, 1996 are
$75 million, however it is expected that at such time these bank
credit facilities will be replaced with new bank credit
facilities on similar terms and conditions.
Based on the borrowing rates currently available to the
Company for long-term debt with similar terms and average
maturities, the fair value of the Company's long-term debt,
including current maturities, was $584 million at December 31,
1993. The fair value of the Company's long-term debt was
essentially equal to its carrying value at December 31, 1992.
5. INVESTMENTS AND CAPITAL EXPENDITURES
Refinery Projects
During the second quarter of 1993, the Refinery began
operation of a butane upgrade facility which converts butane into
MTBE, a high-octane blendstock used to manufacture oxygenated and
reformulated gasolines. Also, during the fourth quarter of 1993,
the Refinery placed in service a MTBE/TAME complex and a
reformate splitter. The MTBE/TAME complex converts streams
currently produced at the Refinery's heavy oil cracker into MTBE
and TAME. TAME, like MTBE, is a high-octane, oxygen-rich
gasoline blendstock. The reformate splitter extracts a benzene
concentrate stream from the reformate produced at the Refinery's
naphtha reformer unit. These projects, which represent
investments totalling approximately $300 million, have increased
the Refinery's production capacity to approximately 140,000
barrels per day of refined products.
Proesa
The Company holds a 35% interest in a Mexican
corporation, Productos Ecologicos, S.A. de C.V. ("Proesa").
Proesa has executed a Memorandum of Understanding with Petroleos
Mexicanos ("PEMEX") to construct a MTBE plant in Mexico, and has
proposed a butane supply contract and MTBE sales contract with
PEMEX. Proesa has also executed an option agreement for a plant
site near the Bay of Campeche. The proposed Mexican MTBE plant
is expected to have a capacity of approximately 15,000 barrels
per day and to be similar to the Refinery's butane upgrade
facility. The project is expected to cost approximately $440
million and is subject to, among other things, the arrangement of
satisfactory financing. Proesa has been advised by lenders with
whom it is negotiating for project financing that certain
provisions will be required in the proposed PEMEX contracts in
order to secure satisfactory financing for the project. Proesa
has entered into negotiations with PEMEX regarding such
provisions. However, as a result of delays incurred in
completing financing, Proesa has determined that the commencement
of plant construction will be delayed. If satisfactory financing
is obtained, construction of the MTBE plant could not begin
before late 1994, with approximately two years required for
completion. As of February 1994, no material amounts have been
invested in the project. The amount of the Company's equity
contribution will depend upon the level of debt financing
obtained by Proesa and the ultimate equity interest of each
partner. Under the proposed commercial contracts, PEMEX will
purchase approximately 75% of the MTBE plant's production, one-
half at a formula price and one-half at market-related prices,
with the remainder of the plant's production being sold to the
Company at a formula price. In addition, the butane feedstocks
required by the plant will be purchased from PEMEX at market-
related prices. A subsidiary of Energy has agreed to provide
technical advice and assistance to Proesa in connection with the
design, engineering, construction and operation of the MTBE
plant. There can be no assurance that financing for the project
can be obtained or that the plant will be constructed.
Javelina Partnership
Valero Javelina Company, a wholly owned subsidiary of
Energy, owns a 20% interest in Javelina Company ("Javelina"), a
general partnership. Javelina maintains a term loan agreement
and a working capital and letter of credit facility which mature
on January 31, 1996. Because the Company accounts for its
interest in Javelina on the equity method of accounting, its
share of the borrowings outstanding under such bank credit
agreements is not recorded on its Consolidated Balance Sheets.
The Company's guarantees of these bank credit agreements were
approximately $19.6 million at December 31, 1993.
At December 31, 1993, the Company's investment in
Javelina included its equity contributions and advances to
Javelina of approximately $19.3 million to cover its
proportionate share of expenditures in excess of the proceeds
available under Javelina's bank credit agreements, and
capitalized interest and overhead.
6. REDEEMABLE PREFERRED STOCK
Energy is required to redeem and, commencing in 1986,
has redeemed in December of each year its Cumulative Preferred
Stock, $8.50 Series A ("Series A Preferred Stock"), at $100 per
share at the rate of 11,500 shares annually ($1,150,000 per
year). The redemption requirement for the Series A Preferred
Stock for each of the five years following December 31, 1993 is
also $1,150,000 per year. Energy also has the option to redeem
shares of the Series A Preferred Stock at any time at $105.50 per
share until November 30, 1994, with such amount being reduced by
$.50 per share each year thereafter to $100 per share.
In the event of an involuntary liquidation, the holders
of the outstanding Series A Preferred Stock would be entitled,
after the payment of all debts, to $100 per share, plus any
accrued and unpaid dividends. In the event of a voluntary
liquidation, the holders of the outstanding Series A Preferred
Stock would be entitled to $100 per share, any applicable premium
Energy would have had to pay if it had elected to redeem the
Series A Preferred Stock at that time and any accrued and unpaid
dividends. In the event dividends on the Series A Preferred
Stock are six or more quarters in arrears, holders may vote to
elect two directors. No arrearages currently exist.
7. CONVERTIBLE PREFERRED STOCK
On October 18, 1993, Energy filed a registration
statement with the Commission covering the offering of 2,500,000
shares of convertible preference stock. Energy intends to file
an amended registration statement covering the offering of
3,000,000 shares (up to 3,450,000 shares with underwriters' over-
allotments) of convertible preferred stock in March 1994. The
proceeds from the offering would be utilized to fund the proposed
acquisition of the Partnership (see Note 2).
8. REDEMPTION OF SERIES B PREFERRED STOCK
On September 1, 1991, Energy redeemed one-half of its
1.6 million Depositary Preferred Shares ("Depositary Shares"),
each of which represented one-twentieth share of Energy's $68.80
Cumulative Preferred Stock, Series B, at a price of $26.475 per
Depositary Share representing a total expenditure of
approximately $21.2 million. On November 21, 1991, Energy called
the remaining half of the Depositary Shares for redemption on
January 15, 1992, also at a price of $26.475 per Depositary
Share.
9. PREFERENCE SHARE PURCHASE RIGHTS
On November 15, 1985, Energy's Board of Directors
declared a dividend distribution of one Preference Share Purchase
Right ("Right") for each outstanding share of Energy's Common
Stock. Until exercisable, the Rights are not transferable apart
from Energy's Common Stock. Each Right will entitle shareholders
to buy one-hundredth (1/100) of a share of a newly issued series
of Junior Participating Serial Preference Stock, Series II, at an
exercise price of $35 per Right.
10. INDUSTRY SEGMENT INFORMATION
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Operating revenues:
Refining and marketing. . . . . . . . . . . . . . . $1,044,749 $1,056,873 $ 889,462
Other operations. . . . . . . . . . . . . . . . . . 177,490 177,745 122,373
Total . . . . . . . . . . . . . . . . . . . . . . $1,222,239 $1,234,618 $1,011,835
Operating income (loss):
Refining and marketing. . . . . . . . . . . . . . . $ 75,401 $ 137,187 $ 133,659
Other operations and corporate general and
administrative expenses . . . . . . . . . . . . . 103 (3,157) (14,393)
Total . . . . . . . . . . . . . . . . . . . . . 75,504 134,030 119,266
Equity in earnings of and income from Valero Natural
Gas Partners, L.P.. . . . . . . . . . . . . . . . . 23,693 26,360 32,389
Gain on disposition of assets and other income, net . 6,209 1,452 7,252
Interest and debt expense, net. . . . . . . . . . . . (37,182) (30,423) (12,540)
Income before income taxes. . . . . . . . . . . . . . $ 68,224 $ 131,419 $ 146,367
Identifiable assets:
Refining and marketing. . . . . . . . . . . . . . . $1,407,221 $1,377,163 $1,233,318
Other operations. . . . . . . . . . . . . . . . . . 198,707 232,576 155,536
Investment in and leases receivable from
Valero Natural Gas Partners, L.P.. . . . . . . . . 130,557 125,285 96,682
Investment in and advances to joint ventures. . . . 28,343 24,809 16,954
Intersegment eliminations . . . . . . . . . . . . . (391) (733) (60)
Total . . . . . . . . . . . . . . . . . . . . . . $1,764,437 $1,759,100 $1,502,430
Depreciation expense:
Refining and marketing. . . . . . . . . . . . . . . $ 47,381 $ 40,241 $ 31,820
Other operations. . . . . . . . . . . . . . . . . . 9,352 7,973 4,787
Total . . . . . . . . . . . . . . . . . . . . . . $ 56,733 $ 48,214 $ 36,607
Capital expenditures:
Refining and marketing. . . . . . . . . . . . . . . $ 123,031 $ 194,207 $ 218,735
Other operations. . . . . . . . . . . . . . . . . . 13,563 88,548 11,012
Total. . . . . . . . . . . . . . . . . . . . . . . $ 136,594 $ 282,755 $ 229,747
</TABLE>
The Company is primarily engaged in the refining and
marketing of petroleum products. The Company's primary refining
activities involve the operation of its Refinery. Refining sells
refined products principally on a spot and truck rack basis.
Spot sales of Refining's products are made principally to larger
oil companies and gasoline distributors. The principal
purchasers of Refining's products from truck racks have been
wholesalers and jobbers in the southeastern and midwestern United
States. The Company has no foreign operations other than storage
facilities and no single customer accounts for more than 10% of
its operating revenues.
11. INCOME TAXES
Components of income tax expense attributable to
continuing operations are as follows (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Current:
Federal. . . . . . . . . . . . . . . . . . . $16,377 $20,392 $ 2,200
State. . . . . . . . . . . . . . . . . . . . 123 908 -
Total current . . . . . . . . . . . . . . 16,500 21,300 2,200
Deferred:
Federal. . . . . . . . . . . . . . . . . . . 17,892 23,608 45,500
State. . . . . . . . . . . . . . . . . . . . (2,592) 2,592 -
Total deferred. . . . . . . . . . . . . . 15,300 26,200 45,500
Total income tax expense . . . . . . . . . . . $31,800 $47,500 $47,700
</TABLE>
The Company has credited the tax benefit associated with
expenses for certain employee benefits recognized differently for
financial reporting and income tax purposes directly to
stockholders' equity. Such amounts (in thousands) were $903,
$1,758 and $915 for 1993, 1992 and 1991, respectively.
Total income tax expense differs from the amount
computed by applying the statutory federal income tax rate to
income before income taxes. The reasons for these differences
are as follows (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Federal income tax expense at the statutory rate . . . . $ 23,900 $ 44,700 $ 49,800
Additional deferred income taxes due to increase in
federal income tax rate. . . . . . . . . . . . . . . . 8,200 - -
State income taxes, net of federal income tax benefit. . (1,600) 2,300 -
Other - net. . . . . . . . . . . . . . . . . . . . . . . 1,300 500 (2,100)
Total income tax expense . . . . . . . . . . . . . . . . $ 31,800 $ 47,500 $ 47,700
</TABLE>
The tax effects of significant temporary differences
representing deferred income tax assets and liabilities are as
follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Deferred income tax assets:
Tax credit carryforwards . . . . . . . . $ 67,693 $ 69,697
Other. . . . . . . . . . . . . . . . . . 29,479 21,574
Total deferred income tax assets . . . $ 97,172 $ 91,271
Deferred income tax liabilities:
Depreciation . . . . . . . . . . . . . . $(232,538) $(210,028)
Equity in earnings of partnerships . . . (73,107) (73,689)
Other. . . . . . . . . . . . . . . . . . (11,787) (19,801)
Total deferred income tax liabilities. $(317,432) $(303,518)
</TABLE>
At December 31, 1993, the Company had federal net
operating loss carryforwards of approximately $7 million, which
are available to reduce future federal taxable income and will
expire in 1997 if not utilized. In addition, the Company had
investment tax credit ("ITC"), Employee Stock Ownership Plan
("ESOP") tax credit and alternative minimum tax credit ("AMT")
carryforwards of approximately $71 million which are available to
reduce future federal income tax liabilities. The ITC and ESOP
tax credits of approximately $55 million expire between 1995 and
2001 if not utilized and the AMT credit of approximately $16
million has no expiration date. The Company did not record any
valuation allowances against deferred income tax assets at
December 31, 1993.
The Company's federal income tax returns have been
examined by the IRS for all taxable years through 1989. All
issues were resolved with the exception of one in which the
Company has petitioned the Tax Court. A decision from the Tax
Court is expected during 1994 . The Company believes that
adequate provisions for income taxes have been reflected in its
consolidated financial statements.
12. EMPLOYEE BENEFIT PLANS
Pension and Other Employee Benefit Plans
The following table sets forth for the pension plans of
the Company, the funded status and amounts recognized in the
Company's consolidated financial statements at December 31, 1993
and 1992 (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $55,836 (1993) and $37,587 (1992). . . . . . . . . $56,692 $38,459
Projected benefit obligation for services rendered to date . . . . $70,382 $71,911
Plan assets at fair value. . . . . . . . . . . . . . . . . . . . . 51,296 42,348
Projected benefit obligation in excess of plan assets. . . . . . . 19,086 29,563
Unrecognized net gain (loss) from past experience different
from that assumed. . . . . . . . . . . . . . . . . . . . . . . . 3,439 (2,851)
Prior service cost not yet recognized in net periodic
pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . (6,062) (7,474)
Unrecognized net asset at beginning of year. . . . . . . . . . . . 1,768 1,911
Additional minimum liability accrual . . . . . . . . . . . . . . . 1,000 315
Accrued pension cost . . . . . . . . . . . . . . . . . . . . . . $19,231 $21,464
</TABLE>
Net periodic pension cost for the years ended December
31, 1993, 1992 and 1991 included the following components (in
thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Service cost - benefits earned during the period . . $ 4,374 $ 4,770 $ 4,158
Interest cost on projected benefit obligation. . . . 5,258 4,925 3,941
Actual return on plan assets . . . . . . . . . . . . (3,450) (756) (11,452)
Net amortization and deferral. . . . . . . . . . . . 22 (2,434) 10,117
Net periodic pension cost. . . . . . . . . . . . . 6,204 6,505 6,764
Additional expense resulting from early retirement
program. . . . . . . . . . . . . . . . . . . . . . - 4,605 -
Curtailment gain resulting from RGV disposition. . . (1,650) - -
Total pension expense. . . . . . . . . . . . . . $ 4,554 $ 11,110 $ 6,764
</TABLE>
A participant in the Company's pension plan vests in
plan benefits after 5 years of vesting service or upon reaching
normal retirement date. The pension plan provides a monthly
pension payable upon normal retirement of an amount equal to a
set formula which is based on the participant's 60 consecutive
highest months of compensation during credited service under the
plan. The weighted-average discount rate used in determining the
actuarial present value of the projected benefit obligation was
7.2% and 8.3%, respectively, as of December 31, 1993 and 1992.
The rate of increase in future compensation levels used in
determining the projected benefit obligation as of December 31,
1993 was 4% for nonexempt personnel and 2% for exempt personnel,
while the 1992 projected benefit obligation was based on an
assumed overall 6.3% rate of compensation increase. The
expected long-term rate of return on plan assets was 9% and
10% as of December 31, 1993 and 1992, respectively.
Contributions, when permitted, are actuarially determined in an
amount sufficient to fund the currently accruing benefits and
amortize any prior service cost over the expected life of the
then current work force. The Company also maintains a
nonqualified Supplemental Executive Retirement Plan ("SERP")
which provides additional pension benefits to the executive
officers and certain other employees of the Company. The
Company's contributions to the pension plan and SERP in 1993,
1992 and 1991 were approximately $7.5 million, $7.5 million and
$8 million, respectively, and are currently estimated to be $5.9
million in 1994. The tables at the beginning of this note
include amounts related to the SERP.
The Company is the sponsor of the Valero Energy
Corporation Thrift Plan ("Thrift Plan") which is an employee
profit sharing plan. Participation in the Thrift Plan is
voluntary and is open to employees of the Company who become
eligible to participate following the completion of three months
of continuous employment. Participating employees may make a
base contribution from 2% up to 8% of their annual base salary,
depending upon months of contributions by a participant. Prior
to the establishment of the VESOP, 100% of these contributions
were matched by the Company. Subsequent to the establishment of
the VESOP, the Company has made contributions to the Thrift Plan
only to the extent employees' base contributions have exceeded
the amount of the Company's contribution to the VESOP for debt
service. In 1994, the Thrift Plan was amended to provide for a
total Company match in both the Thrift Plan and the VESOP
aggregating either 75% or 100% of employee base contributions,
subject to certain conditions. Participants may also make a
supplemental contribution to the Thrift Plan of up to an
additional 10% of their annual base salary which is not matched
by the Company. Company contributions to the Thrift Plan during
1993, 1992 and 1991 were approximately $660,000, $348,000 and
$1,027,000, respectively.
In February 1989, the Company established the VESOP
which is a leveraged employee stock ownership plan. Pursuant to
a private placement in March 1989, the VESOP issued notes in the
principal amount of $15 million, maturing February 15, 1999 (the
"VESOP Notes"). The net proceeds from this private placement
were used by the VESOP trustee to fund the purchase of Common
Stock. The Company makes semi-annual contributions of
approximately $1.16 million to the VESOP until maturity to fund
the debt service on the VESOP Notes, and, as explained above, the
Company's annual contribution to the Thrift Plan during such
period is reduced accordingly. During the third quarter of 1991,
the Company made an additional loan of $8 million to the VESOP
which was also used by the Trustee to purchase Common Stock.
This new VESOP loan matures on August 15, 2001. During 1993, the
Company contributed $3,596,000 to the VESOP, incurred $947,000 of
interest on the VESOP Notes and recognized $2,173,000 of
compensation expense. During 1992, the Company contributed
$3,596,000 to the VESOP, incurred $1,065,000 of interest on the
VESOP Notes and recognized $2,055,000 of compensation expense.
Such amounts for 1991 were $2,320,000, $1,172,000 and $1,448,000,
respectively. Dividends paid on Common Stock during 1993, 1992
and 1991 have not been used to reduce the VESOP obligation.
In addition to the above plans, the Company also
sponsors other employee benefit plans, including the Valero
Energy Corporation Employee's Stock Ownership Plan. During the
third quarter of 1991, the Company contributed $2.3 million to
the ESOP for investment tax credits claimed on Refining's
separate 1982 federal income tax return which had not been
utilized. The Company also sponsors the Executive Deferred
Compensation Plan, the Key Employee Deferred Compensation Plan
and the Excess Thrift Plan. At December 31, 1993 and 1992, the
amount recorded as deferred compensation on the consolidated
balance sheets under these plans was $4.9 million and $4.8
million, respectively.
The Company also provides certain health care and life
insurance benefits for retired employees, referred to herein as
"postretirement benefits other than pensions." Substantially all
of the Company's employees may become eligible for those benefits
if, while still working for the Company, they either reach normal
retirement age or take early retirement. Health care benefits
are provided by the Company through a self-insured plan while
life insurance benefits are provided through an insurance
company.
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions", which requires a change in the Company's
accounting for postretirement benefits other than pensions from a
pay-as-you-go basis to an accrual basis of accounting. The
Company is amortizing the transition obligation over 20 years,
which is greater than the average remaining service period until
eligibility of active plan participants. The Company continues
to fund its postretirement benefits other than pensions on a pay-
as-you-go basis. The adoption of this standard resulted in a
decrease to net income in 1993 of $1.7 million, or $.04 per
share, after allocation to the Partnership of its pro rata
portion of such costs.
The following table sets forth for the Company's
postretirement benefits other than pensions, the funded status
and amounts recognized in the Company's consolidated financial
statements at December 31, 1993 (in thousands):
<TABLE>
<S> <C>
Accumulated benefit obligation:
Retirees . . . . . . . . . . . . . . . . . . . . . . . . . . . . $10,314
Fully eligible active plan participants. . . . . . . . . . . . . 3,196
Other active plan participants . . . . . . . . . . . . . . . . . 11,706
Total accumulated benefit obligation . . . . . . . . . . . . . 25,216
Unrecognized net gain (loss) . . . . . . . . . . . . . . . . . . . (3,755)
Unrecognized transition obligation . . . . . . . . . . . . . . . . (18,014)
Accrued postretirement benefit cost. . . . . . . . . . . . . . . $ 3,447
</TABLE>
Net periodic postretirement benefit cost for the year ended
December 31, 1993 included the following components (in
thousands):
<TABLE>
<S> <C>
Service cost - benefits attributed to service during the period. . $ 1,011
Interest cost on accumulated benefit obligation. . . . . . . . . . 1,692
Amortization of unrecognized transition obligation . . . . . . . . 1,029
Net periodic postretirement benefit cost . . . . . . . . . . . . 3,732
Curtailment loss resulting from RGV disposition. . . . . . . . . . 616
Total postretirement benefit cost. . . . . . . . . . . . . . . . $ 4,348
</TABLE>
For measurement purposes, the health care cost trend rate
was 10% in 1993, decreasing gradually to 5.5% in 1998 and
remaining level thereafter. The health care cost trend rate
assumption has a significant effect on the amount of the
obligation and periodic cost reported. An increase in the
assumed health care cost trend rate by 1% in each year would
increase the accumulated postretirement benefit obligation as of
December 31, 1993 by $4.7 million and the aggregate of the
service and interest cost components of net periodic
postretirement benefit cost for the year then ended by $.6
million. The weighted-average discount rate used in determining
the accumulated postretirement benefit obligation as of December
31, 1993 was 7.2%.
Prior to 1993, the cost of providing health care and life
insurance benefits to retired employees was recognized as expense
as health care claims and life insurance premiums were paid.
These costs totaled approximately $675,000 and $700,000 for 1992
and 1991, respectively.
Stock Option and Bonus Plans
Energy has three non-qualified stock option plans, Stock
Option Plan No. 5, Stock Option Plan No. 4, and Stock Option Plan
No. 3, collectively referred to herein as the "Stock Option
Plans." The Stock Option Plans provide for the granting of
options to purchase shares of Energy's Common Stock. Such
options are granted to key officers, employees and prospective
employees of the Company. Under the terms of the Stock Option
Plans, the exercise price of the options granted will generally
not be less than 75% of the fair market value of Common Stock at
the date of grant. All stock options granted since 1990 contain
exercise prices equal to the market value at the date of grant.
Stock options become exercisable pursuant to the individual
written agreements between Energy and the participants in the
Stock Option Plans, which provide for options becoming
exercisable in three equal annual installments beginning one year
after the date of grant, with unexercised options expiring ten
years from the date of grant. The aggregate difference between
the market value of Common Stock at date of grant and the option
price is recorded as compensation expense during the exercise
period. At December 31, 1993, 1,261,624 options were
outstanding, at a weighted-average exercise price of $23.69 per
share, of which 357,258 options were exercisable at a weighted-
average exercise price of $20.88 per share. During 1993, 597,050
options were granted at a weighted-average exercise price of
$23.19, 140,588 options were exercised at a weighted-average
exercise price of $10.46 and 53,433 options were terminated
and/or forfeited. At December 31, 1993, there were 194,375
shares available for grant under these Stock Option Plans,
including shares transferred from previously terminated stock
option plans of the Company.
For each share of stock that can be purchased thereunder
pursuant to a stock option, Stock Option Plans No. 3 and 4
provide that a stock appreciation right ("SAR") may also be
granted. A SAR is a right to receive a cash payment equal to the
difference between the fair market value of Energy's Common Stock
on the exercise date and the option price of the stock to which
the SAR is related. SARs are exercisable only upon the exercise
of the related stock options. At the end of each reporting
period within the exercise period, Energy records an adjustment
to deferred compensation expense based on the difference between
the fair market value of Energy's Common Stock at the end of each
reporting period and the option price of the stock to which the
SAR is related. At December 31, 1993, 139,315 SARs were
outstanding, at a weighted-average exercise price of $14.52 per
share, of which 138,940 SARs were exercisable at a weighted-
average exercise price of $14.52 per share. During 1993, 113,999
SARs were exercised at a weighted-average exercise price of
$10.32 per share, and 1,466 SARs were terminated and/or
forfeited. Compensation expense recognized during 1993 in
connection with the grant of options and SARs under the Company's
Stock Option Plans was $110,000.
The Company maintains a Restricted Stock Bonus and
Incentive Stock Plan ("Bonus Plan") for certain key executives of
the Company. Under the Bonus Plan, 750,000 shares of Common
Stock were reserved for issuance. At December 31, 1993, there
were 18,927 shares available for award and 77,750 shares awarded
under this plan during 1993. The amount of Bonus Stock and terms
governing the removal of applicable restrictions, and the amount
of Incentive Stock and terms establishing predefined performance
objectives and periods, are established pursuant to individual
written agreements between Energy and each participant in the
Bonus Plan. Compensation expense recognized in connection with
the Bonus Plan for 1993 was $570,000. The Company also
maintains an executive incentive bonus plan (the "Incentive
Plan") for the purpose of providing bonus compensation to key
executive and managerial employees. During 1993, bonuses were
paid in cash and Common Stock. Compensation expense recognized
during 1993 in connection with the Incentive Plan was
approximately $2.4 million.
13. DEFERRED CREDITS AND OTHER LIABILITIES
Deferred credits and other liabilities are as follows
(in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Accrued pension cost (see Note 12) . . . . . . . . . . . $13,359 $14,938
Other employee related liabilities (see Note 12) . . . . 9,480 7,646
Deferred management fees . . . . . . . . . . . . . . . . 8,147 11,176
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 6,142 6,548
$37,128 $40,308
</TABLE>
Deferred management fees were recorded upon the
formation of the Partnership in March 1987 and are being
amortized over the ten-year period during which VNGC agreed not
to withdraw as General Partner of the Partnership.
14. LEASE AND OTHER COMMITMENTS
The Company has two major operating lease commitments in
connection with a gas storage facility leased to the Partnership
and its corporate headquarters office complex. The remaining
primary lease term for the gas storage facility is six years,
while the corporate headquarters lease has a primary term
remaining of three years with eight optional renewal periods of
five years each. The Company has the right to purchase the
office complex at any time after the end of the third renewal
period at the then determined fair market value. The Company
also has other noncancelable operating leases with remaining
terms ranging from one year to 7 years. The related future
minimum lease payments as of December 31, 1993 are as follows (in
thousands):
<TABLE>
(CAPTION>
Gas
Storage Office
Facility Complex Other
<S> <C> <C> <C>
1994 . . . . . . . . . . . . . . $10,438 $ 5,253 $ 3,865
1995 . . . . . . . . . . . . . . 10,438 5,253 4,694
1996 . . . . . . . . . . . . . . 10,438 5,254 4,668
1997 . . . . . . . . . . . . . . 9,832 - 2,928
1998 . . . . . . . . . . . . . . 10,156 - 1,172
Remainder. . . . . . . . . . . . 15,660 - 704
Total minimum lease payments . . $66,962 $15,760 $18,031
</TABLE>
The future minimum lease payments listed above under the
caption "Other" exclude certain operating lease commitments which
are cancelable by the Company upon notice of one year or less.
Consolidated rent expense amounted to $12,948,000, $12,643,000,
and $11,740,000 for 1993, 1992 and 1991, respectively, and
includes various month-to-month and other short-term rentals in
addition to rents paid and accrued under long-term lease
commitments. A portion of these amounts was charged to and
reimbursed by the Partnership for its proportionate use of the
Company's corporate headquarters office complex and for the
use of certain other properties managed by the Company.
The obligations of Valero Gas Storage Company ("Gas
Storage"), a wholly owned subsidiary of VNGC, under the gas
storage facility lease include its obligation to make scheduled
lease payments and, in the event of a declaration of default and
acceleration of the lease obligation, to make certain lump sum
payments based on a stipulated loss value for the gas storage
facility less the fair market sales price or fair market rental
value of the gas storage facility. Under certain circumstances,
a default by Energy or a subsidiary of Energy under its bank
credit facilities could result in a cross default under the gas
storage facility lease. The Company believes that it is unlikely
that a default by Energy or a subsidiary of Energy would result
in actual acceleration of the gas storage facility lease, and
further believes that such event, if it occurred, would not have
a material adverse effect on the Company or the Partnership. The
obligation of the Company to make certain payments to Gas Storage
equal to the amount of Gas Storage's required payments under the
gas storage facility lease has been assumed by the Partnership.
15. LITIGATION AND CONTINGENCIES
Partnership Related Claims
In 1987, VT, L.P. and a producer from whom VT, L.P. has
purchased natural gas entered into an agreement resolving certain
take-or-pay issues between the parties in which VT, L.P. agreed
to pay one-half of certain excess royalty claims arising after
the date of the agreement. The royalty owners of the producer
recently completed an audit of the producer and have presented to
the producer a claim for additional royalty payments in the
amount of approximately $17.3 million, and accrued interest
thereon of approximately $19.8 million. Approximately $8 million
of the royalty owners' claim accrued after the effective date of
the agreement between the producer and VT, L.P.. The producer
and VT, L.P. are reviewing the royalty owners' claims. No
lawsuit has been filed by the royalty owners. The Company
believes that various defenses under the agreement may reduce any
liability of VT, L.P. to the producer in this matter.
Seven lawsuits were filed in Chancery Court in Delaware
against VNGP, L.P., VNGC and Energy and certain officers and
directors of VNGC and/or Energy in response to the announcement
by Energy on October 14, 1993 of its proposal to acquire the
publicly traded Common Units of VNGP, L.P. pursuant to a proposed
merger of VNGP, L.P. with a wholly owned subsidiary of Energy.
See Note 2. The suits were consolidated into a single proceeding
by the Chancery Court on November 23, 1993. The plaintiffs
sought to enjoin or rescind the proposed merger, alleging that
the corporate defendants and the individual defendants, as
officers or directors of the corporate defendants, engaged in
actions in breach of the defendants' fiduciary duties to the
Public Unitholders by proposing the merger. The plaintiffs
alternatively sought an increase in the proposed merger
consideration, unspecified compensatory damages and attorneys'
fees. In December 1993, the parties reached a tentative
settlement of the consolidated lawsuit. The terms of the
settlement will not require a material payment by the Company or
the Partnership. However, there can be no assurance that the
settlement will be completed, or that it will be approved by the
Chancery Court.
In a letter dated September 1, 1993 from the City of
Houston (the "City") to Valero Transmission Company ("VTC"), an
indirect wholly owned subsidiary of Energy, 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 VT, L.P., an indirect subsidiary
partnership of VNGP, L.P. The franchise agreement was assigned
to and assumed by VT, L.P. upon formation of the Partnership in
1987. In the letter, the City also declared a conditional
forfeiture of the franchise rights based on the City's claims.
In a letter dated October 27, 1993, the City claimed that VTC
owes to the City franchise fees and accrued interest thereon
aggregating approximately $13.5 million. In a letter dated
November 9, 1993, the City claimed an additional $18 million in
damages relating to the City's allegations that VTC engaged in
unauthorized activities under the franchise agreement by
transmitting gas for resale and by transporting gas for third
parties on the franchised premises. The City has not filed a
lawsuit. While any liability of VTC with respect to the City's
claims has been assumed by the Partnership, if the proposed
merger with VNGP, L.P. is consummated, the Company's financial
position would necessarily reflect the full amount of any
Partnership liability. Additionally, in the event that the
Partnership failed to pay any such liability, the Company could
remain ultimately responsible. The Company believes that the
City's claims are significantly overstated, and that VTC has a
number of meritorious defenses to the claims.
VTC and one of its gas suppliers are parties to various
gas purchase contracts assigned to and assumed by VT, L.P. upon
formation of the Partnership in 1987. The supplier is also a
party to a series of gas purchase contracts between the supplier,
as buyer, and certain trusts, as seller, which are in litigation.
Neither the Partnership nor VTC is a party to this litigation or
the contracts between the supplier and the trusts. However,
because of the relationship between VTC's contracts with the
supplier and the supplier's contracts with the trusts, and in
order to resolve existing and potential disputes, the supplier,
VTC and VT, L.P. have agreed that they will cooperate in the
conduct of this litigation, and that VTC and VT, L.P. will bear a
substantial portion of the costs of any appeal and any
nonappealable final judgment rendered against the supplier. In
the litigation, the trusts allege that the supplier has breached
various minimum take, take-or-pay and other contractual
provisions and assert a statutory nonratability claim. The
trusts seek alleged actual damages, including interest, of
approximately $30 million and an unspecified amount of punitive
damages. The District Court ruled on the plaintiff's motion for
summary judgment, finding, among other things, that as a matter
of law the three gas purchase contracts at issue were fully
binding and enforceable, the supplier breached the minimum take
obligations under one of the contracts, the supplier is not
entitled to claimed offsets for gas purchased by third parties
and the "availability" of gas for take-or-pay purposes is
established solely by the delivery capacity testing procedures in
the contracts. Damages, if any, have not been determined.
Because of existing contractual obligations of the Partnership to
its supplier, the lawsuit may ultimately involve a contingent
liability for the Partnership. The Company believes that the
claims brought against the supplier have been significantly
overstated, and that the supplier has a number of meritorious
defenses to the claims, including various regulatory, statutory,
contractual and common law defenses. The Court recently granted
the supplier's Motion for Continuance of the former January 10,
1994 trial date. This litigation is not currently set for trial.
In March 1993, two indirect wholly owned subsidiaries of
Energy serving as general partners of two of the Partnership's
principal subsidiary operating partnerships were served as third-
party defendants in a lawsuit originally filed in 1991 by a
subsidiary of the Coastal Corporation ("Coastal") against
TransAmerican Natural Gas Corporation ("TANG"). In August 1993,
Energy, VNGP, L.P. and certain of their respective subsidiaries
were named as additional third-party defendants (collectively,
including the original defendant subsidiaries, the "Valero
Defendants") in this lawsuit. In its counterclaims against
Coastal and third-party claims against the Valero Defendants,
TANG alleges that it contracted to sell natural gas to Coastal at
the posted field price of one of the Valero Defendants and that
the Valero Defendants and Coastal conspired to set 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.
The Company believes that the plaintiff's claims have been
exaggerated, and that it has meritorious defenses to such claims.
In the event of an adverse determination involving the Company,
the Company likely would seek indemnification from the
Partnership under terms of the partnership agreements and other
applicable agreements between VNGP, L.P., its subsidiary
partnerships and their respective general partners. The Valero
Defendants' motion for summary judgment on TANG's antitrust
claims was argued on January 24, 1994. The court has not ruled
on such motion. The current trial setting for this case is March
14, 1994.
The Company was a party to a lawsuit originally filed in
1988 in which Energy, VTC, VNGP, L.P. and subsidiaries of VNGP,
L.P. (the "Valero Defendants") and a subsidiary of Coastal were
alleged to be liable for failure to take minimum quantities of
gas, failure to make take-or-pay payments and other breach of
contract and breach of fiduciary duty claims. The plaintiffs
sought declaratory relief, actual damages in excess of $37
million and unspecified punitive damages. During the third
quarter of 1992, the plaintiffs, Coastal and the Valero
Defendants settled this lawsuit on terms which were not material
to the Valero Defendants and on July 19, 1993, this lawsuit was
dismissed. On November 16, 1992, prior to entry of the order of
dismissal, NationsBank of Texas, N.A., as trustee for certain
trusts (the "Intervenors"), filed a plea in intervention to
intervene in the lawsuit. The Intervenors asserted that they
held a non-participating mineral interest in the lands subject to
the litigation and that their rights were not protected by the
plaintiffs in the settlement. On February 4, 1993, the Court
struck the Intervenors' plea in intervention. However, on
February 2, 1993, the Intervenors had filed a separate suit in
the 160th State District Court, Dallas County, Texas, against all
prior defendants and an additional defendant, substantially
adopting in form and substance the allegations and claims in the
original litigation. In February 1994, the parties reached a
tentative settlement of the lawsuit on terms immaterial to the
Company or the Partnership.
The Partnership has settled substantially all of the
significant take-or-pay claims, pricing differences and
contractual disputes heretofore brought against it. Although
additional take-or-pay claims may continue to be brought against
the Partnership, the Company believes that the Partnership has
resolved substantially all of the significant take-or-pay claims
that are likely to be made. Any liability of the Company with
respect to these claims has been assumed by the Partnership. No
provision has been made with respect to these claims because the
Company believes that the Partnership has valid defenses with
respect to such claims and because the Company believes that the
Partnership will fulfill its obligation to pay any such liability
as may ultimately be determined to exist.
The Company and the Partnership believe it is unlikely
that the final outcome of any of the claims or proceedings
described above would have a material adverse effect on either
the Company's or the Partnership's financial position or results
of operations; however, due to the inherent uncertainty of
litigation, the range of possible loss, if any, cannot be
estimated with a reasonable degree of precision and there can be
no assurance that the resolution of any of these claims or
proceedings would not have an adverse effect on either the
Company's or the Partnership's results of operations for the
fiscal period in which the resolution occurred.
Other Litigation
On August 31, 1993, suit was brought by certain
residents of the Oak Park Triangle area of Corpus Christi, Texas,
against several defendants including Valero Refining Company.
All named defendants are either refiners or gas processors having
facilities located at or near Up River Road in Corpus Christi.
Plaintiffs allege in general terms damages resulting from ground
water contamination and air pollution allegedly caused by the
operations of the defendants. Plaintiffs seek unspecified actual
and punitive damages. No provision has been made with respect to
the claims of the plaintiffs because the Company believes that
Valero Refining Company has meritorious defenses to the claims.
Valero Javelina Company, a wholly owned subsidiary of
Energy, owns a 20% general partner interest in Javelina Company,
a general partnership. See Note 5 of Notes to Consolidated
Financial Statements. Javelina Company has been named as a
defendant in seven lawsuits filed since 1992 in state district
courts in Nueces County, Texas. Four of the suits include as
defendants other companies that own refineries or other
industrial facilities in Nueces County. These suits were brought
by a number of plaintiffs who reside in neighborhoods near the
facilities. The plaintiffs claim injuries relating to an alleged
exposure to toxic chemicals, and generally claim that the
defendants were negligent, grossly negligent and committed
trespass. The plaintiffs claim personal injury and property
damages resulting from soil and ground water contamination and
air pollution allegedly caused by the operations of the
defendants. One of the suits seeks certification of the
litigation as a class action. The plaintiffs seek unspecified
actual and punitive damages. The other three suits were brought
by plaintiffs who either live or have businesses near the
Javelina Plant. The suits allege claims similar to those
described above. These plaintiffs also fail to specify an amount
of damages claimed.
The Company is also a party to additional claims and
legal proceedings arising in the ordinary course of business.
The Company believes it is unlikely that the final outcome of any
of the claims or proceedings to which the Company is a party,
including those described above, would have a material adverse
effect on the Company's financial position or results of
operations; however, due to the inherent uncertainty of
litigation, the range of possible loss, if any, cannot be
estimated with a reasonable degree of precision and there can be
no assurance that the resolution of any particular claim or
proceeding would not have an adverse effect on the Company's
results of operations for the fiscal period in which such
resolution occurred.
As is described above, the Partnership has assumed the
obligations and liabilities of the Company with respect to claims
relating to the business or properties transferred by the Company
to the Partnership in 1987. If the Partnership were unable or
otherwise failed to discharge any such liability of the Company
which it assumed, the Company could remain ultimately liable for
such liability.
16. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended
December 31, 1993 and 1992 were as follows (in thousands of
dollars, except per share amounts):
<TABLE>
<CAPTION>
Operating Net Earnings (Loss)
Operating Income Income Per Share
Revenues (Loss) (Loss) Of Common Stock
<S> <C> <C> <C> <C>
1993-Quarter Ended:
March 31. . . . . . . . . $ 295,762 $ 24,653 $15,611 $ .36
June 30 . . . . . . . . . 321,072 38,118 24,683 .56
September 30 . . . . . . 323,389 30,463 11,288 .26
December 31 . . . . . . . 282,016 (17,730) (15,158) (.36)
Total . . . . . . . . . $1,222,239 $ 75,504 $36,424 $ .82
1992-Quarter Ended:
March 31. . . . . . . . . $ 275,078 $ 32,716 $20,108 $ .48
June 30 . . . . . . . . . 319,084 45,172 27,446 .63
September 30. . . . . . . 336,734 40,231 28,119 .65
December 31 . . . . . . . 303,722 15,911 8,246 .18
Total . . . . . . . . . $1,234,618 $134,030 $83,919 $ 1.94
</TABLE>
For the fourth quarter of 1993, results of operations were
affected by a $27.6 million or $17.9 million after-tax ($.42 per
share) write-down in the carrying value of the Company's refinery
inventories to reflect existing market prices. This was due to a
significant decline in feedstock and refined product prices,
which were weak throughout 1993. Also affecting the decrease in
the Company's fourth quarter operating and net income compared to
the first three quarters of 1993 is the effect of seasonal market
conditions on the Company's refining operations. The Company's
refinery processes a type of residual fuel oil as a feedstock to
produce a product slate consisting primarily of unleaded
gasoline. The national demand for and price of gasoline is
typically lower in the fourth quarter compared to other quarters
due to the lower level of driving during the winter season.
Gasoline prices are typically higher during the second and third
quarters due to the increased demand related to the summer
driving season. In addition, demand for and the price of fuel
oils are typically higher in the fourth quarter because of the
approaching heating season; these factors tend to adversely
affect feedstock costs in the fourth quarter. A typical
combination of lower gasoline sales prices and higher feedstock
costs decreases refining throughput margins in the fourth
quarter. Quarterly results for 1992 were also affected by
seasonal market conditions.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. (DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT),
ITEM 11. (EXECUTIVE COMPENSATION), ITEM 12. (SECURITY OWNERSHIP
OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT) AND ITEM 13.
(CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS) ARE INCORPORATED
BY REFERENCE FROM THE COMPANY'S 1994 PROXY STATEMENT IN
CONNECTION WITH ITS ANNUAL MEETING OF STOCKHOLDERS SCHEDULED TO
BE HELD APRIL 28, 1994. SEE PAGE ii, SUPRA.
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 (Commission
File No. 1-9433, filed March 1, 1994).
______________
* 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>
<TABLE>
SCHEDULE V
VALERO ENERGY CORPORATION AND SUBSIDIARIES
PROPERTY, PLANT AND EQUIPMENT
(Thousands of Dollars)
<CAPTION>
Balance at Balance
Beginning Additions Other at End
Description of Period at Cost Retirements Changes(1) of Period
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1993
Refining and marketing . . $1,355,011 $123,031 $ 146 $4,983 $1,482,879
Other. . . . . . . . . . . 188,331 13,563 43,121 (1,516) 157,257
$1,543,342 $136,594 $43,267 $3,467 $1,640,136
Year Ended December 31, 1992
Refining and marketing . . $1,162,712 $194,207 $ 1,563 $ (345) $1,355,011
Other. . . . . . . . . . . 102,356 88,548 3,180 607 188,331
$1,265,068 $282,755 $ 4,743 $ 262 $1,543,342
Year Ended December 31, 1991
Refining and marketing . . $ 944,965 $218,735 $ 993 $ 5 $1,162,712
Other. . . . . . . . . . . 92,805 11,012 732 (729) 102,356
$1,037,770 $229,747 $ 1,725 $ (724) $1,265,068
<FN>
NOTE: See Note 1 of Notes to Consolidated Financial Statements
for disclosure of depreciation methods and rates.
(1) Reclassifications and other miscellaneous adjustments.
</TABLE>
<PAGE>
<TABLE>
SCHEDULE VI
VALERO ENERGY CORPORATION AND SUBSIDIARIES
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
(Thousands of Dollars)
<CAPTION>
Additions
Balance at Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Retirements Changes(1) of Period
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1993
Refining and marketing . . $264,138 $47,381 $ (83) $ - $311,602
Other. . . . . . . . . . . 47,126 9,352 20,681 (829) 34,968
$311,264 $56,733 $20,598 $(829) $346,570
Year Ended December 31, 1992
Refining and marketing . . $224,922 $40,241 $ 1,027 $ 2 $264,138
Other. . . . . . . . . . . 41,967 7,973 2,854 40 47,126
$266,889 $48,214 $ 3,881 $ 42 $311,264
Year Ended December 31, 1991
Refining and marketing . . $193,907 $31,820 $ 815 $ 10 $224,922
Other. . . . . . . . . . . 37,843 4,787 603 (60) 41,967
$231,750 $36,607 $ 1,418 $ (50) $266,889
<FN>
NOTE: See Note 1 of Notes to Consolidated Financial Statements
for disclosure of depreciation methods and rates.
(1) Reclassifications and other miscellaneous adjustments.
</TABLE>
<PAGE>
<TABLE>
SCHEDULE IX
VALERO ENERGY CORPORATION AND SUBSIDIARIES
SHORT-TERM BORROWINGS (1)
(Thousands of Dollars)
<CAPTION>
Maximum Average Weighted-
Category Weighted- Amount Amount Average
of Aggregate Balance at Average Outstanding Outstanding Interest Rate
Short-Term End of Interest During the During the During the
Borrowings Period Rate Period(2) Period(3) Period(4)
<S> <C> <C> <C> <C> <C>
Year Ended:
December 31, 1993. . . . $ - - % $40,000 $13,137 3.32%
December 31, 1992. . . . 6,700 3.72 20,000 3,404 3.78
December 31, 1991. . . . - - 13,000 158 5.05
<FN>
(1) See Note 3 of Notes to Consolidated Financial Statements
for a discussion of the terms and provisions of the
Company's short-term bank lines.
(2) The maximum amount outstanding occurred during August of
1993, September of 1992 and December of 1991,
respectively.
(3) Average amount outstanding during the period was determined
on a daily average basis.
(4) Weighted-average interest rate during the period was
computed by dividing total interest expense on all short-
term borrowings by the average amount outstanding during
the period.
</TABLE>
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Valero Natural Gas Company
as General Partner of Valero Natural Gas Partners, L.P.
and to the Common Unitholders:
We have audited the accompanying consolidated balance
sheets of Valero Natural Gas Partners, L.P. (a Delaware limited
partnership) as of December 31, 1993 and 1992, and the related
consolidated statements of income, partners' capital and cash
flows for each of the three years in the period ended December
31, 1993. These financial statements and the schedules referred
to below are the responsibility of the Partnership's management.
Our responsibility is to express an opinion on these financial
statements and schedules based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to
above present fairly, in all material respects, the financial
position of Valero Natural Gas Partners, L.P. as of December 31,
1993 and 1992, and the results of its operations and its cash
flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted
accounting principles.
Our audits were made for the purpose of forming an
opinion on the basic financial statements taken as a whole. The
supplemental schedules V, VI and IX are presented for purposes of
complying with the Securities and Exchange Commission's rules and
are not part of the basic financial statements. These schedules
have been subjected to the auditing procedures applied in the
audits of the basic financial statements and, in our opinion,
fairly state in all material respects the financial data required
to be set forth therein in relation to the basic financial
statements taken as a whole.
ARTHUR ANDERSEN & CO.
San Antonio, Texas
February 17, 1994
<PAGE>
<TABLE>
VALERO NATURAL GAS PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
<CAPTION>
December 31,
1993 1992
A S S E T S
<S> <C> <C>
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . $ 5,523 $ 6,598
Cash held in debt service escrow . . . . . . . . . . . . . . . . . . . . 34,186 32,864
Receivables, less allowance for doubtful accounts of $2,102 (1993)
and $633 (1992). . . . . . . . . . . . . . . . . . . . . . . . . . . . 154,503 171,660
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,434 35,080
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . 5,321 8,273
224,967 254,475
PROPERTY, PLANT AND EQUIPMENT-including construction in
progress of $16,728 (1993) and $14,341 (1992), at cost . . . . . . . . . 939,565 916,734
Less: Accumulated depreciation . . . . . . . . . . . . . . . . . . . . 199,763 173,518
739,802 743,216
DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . 80,313 86,790
$1,045,082 $1,084,481
L I A B I L I T I E S A N D P A R T N E R S' C A P I T A L
CURRENT LIABILITIES:
Current maturities of long-term debt and capital lease obligations . . . $ 28,908 $ 26,121
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216,953 237,176
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,692 16,710
Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . 8,719 7,422
273,272 287,429
LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . 506,429 534,286
CAPITAL LEASE OBLIGATIONS, less current maturities . . . . . . . . . . . . 103,787 104,075
DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . 1,548 2,672
LIMITED PARTNERS' CAPITAL. . . . . . . . . . . . . . . . . . . . . . . . . 158,448 154,461
GENERAL PARTNERS' CAPITAL. . . . . . . . . . . . . . . . . . . . . . . . . 1,598 1,558
$1,045,082 $1,084,481
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
VALERO NATURAL GAS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Per Unit Amounts)
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . $1,326,458 $1,197,129 $1,144,001
COSTS AND EXPENSES:
Cost of sales. . . . . . . . . . . . . . . . . . . 1,090,363 954,600 896,322
Operating expenses . . . . . . . . . . . . . . . . 120,171 118,284 108,614
Depreciation expense . . . . . . . . . . . . . . . 36,446 34,404 39,231
Total. . . . . . . . . . . . . . . . . . . . . . 1,246,980 1,107,288 1,044,167
OPERATING INCOME . . . . . . . . . . . . . . . . . . 79,478 89,841 99,834
OTHER INCOME, NET. . . . . . . . . . . . . . . . . . 1,263 624 4,013
INTEREST AND DEBT EXPENSE:
Incurred . . . . . . . . . . . . . . . . . . . . . (68,007) (66,679) (67,532)
Capitalized. . . . . . . . . . . . . . . . . . . . 1,713 1,200 721
NET INCOME . . . . . . . . . . . . . . . . . . . . . 14,447 24,986 37,036
Less: General Partners' interest . . . . . . . . . 1,217 1,596 1,973
NET INCOME ALLOCABLE TO LIMITED
PARTNERS . . . . . . . . . . . . . . . . . . . . . $ 13,230 $ 23,390 $ 35,063
NET INCOME PER LIMITED PARTNER
UNIT . . . . . . . . . . . . . . . . . . . . . . . $ .72 $ 1.27 $ 1.90
WEIGHTED AVERAGE LIMITED PARTNER
UNITS OUTSTANDING (in thousands) . . . . . . . . . 18,487 18,487 18,487
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
VALERO NATURAL GAS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(Thousands of Dollars)
<CAPTION>
Limited Partners' Capital General
Preference Common Preference Common Partners'
Units Units Total Unitholders Unitholders Total Capital
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE - December 31, 1990. . . 9,690,980 8,795,558 18,486,538 $ 151,436 $ 18,518 $169,954 $ 1,611
Net income . . . . . . . . . . - - - 14,307 20,756 35,063 1,973
Distributions. . . . . . . . . - - - (24,277) (21,939) (46,216) (1,820)
Conversion of Common Units
to Preference Units . . . . . 26,400 (26,400) - 35 (35) - -
BALANCE - December 31, 1991. . . 9,717,380 8,769,158 18,486,538 141,501 17,300 158,801 1,764
Net income . . . . . . . . . . - - - 231 23,159 23,390 1,596
Distributions. . . . . . . . . - - - (12,188) (15,542) (27,730) (1,802)
Conversion of Common Units
to Preference Units . . . . . 32,620 (32,620) - 54 (54) - -
Conversion of Preference Units
to Common Units upon termi-
nation of the Preference
Period . . . . . . . . . . . (9,750,000) 9,750,000 - (129,598) 129,598 - -
BALANCE - December 31, 1992. . . - 18,486,538 18,486,538 - 154,461 154,461 1,558
Net income . . . . . . . . . . - - - - 13,230 13,230 1,217
Distributions. . . . . . . . . - - - - (9,243) (9,243) (1,177)
BALANCE - December 31, 1993. . . - 18,486,538 18,486,538 $ - $158,448 $158,448 $ 1,598
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
VALERO NATURAL GAS PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 14,447 $ 24,986 $ 37,036
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation expense . . . . . . . . . . . . . . . . . . . 36,446 34,404 39,231
Amortization of deferred charges and other, net. . . . . . 2,459 3,520 3,075
Changes in current assets and current liabilities. . . . . 13,364 26,676 (1,336)
Changes in deferred items and other, net . . . . . . . . . 3,765 (11,700) 6,275
Net cash provided by operating activities. . . . . . . 70,481 77,886 84,281
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital additions. . . . . . . . . . . . . . . . . . . . . . . (36,061) (35,893) (33,074)
Dispositions of property, plant and equipment. . . . . . . . . 2,585 934 7,926
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . 334 1,493 269
Net cash used in investing activities. . . . . . . . . . . . (33,142) (33,466) (24,879)
CASH FLOWS FROM FINANCING ACTIVITIES:
Reduction of long-term debt and capital lease obligations. . . (26,119) (22,971) (17,500)
Increase in cash held in debt service escrow for principal . . (1,875) (1,875) (4,018)
Proceeds from unexpended debt proceeds held by trustee . . . . - - 937
Partnership distributions. . . . . . . . . . . . . . . . . . . (10,420) (29,532) (48,036)
Net cash used in financing activities. . . . . . . . . . . . (38,414) (54,378) (68,617)
NET DECREASE IN CASH AND TEMPORARY
CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . (1,075) (9,958) (9,215)
CASH AND TEMPORARY CASH INVESTMENTS AT
BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . . . . 6,598 16,556 25,771
CASH AND TEMPORARY CASH INVESTMENTS AT
END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . $ 5,523 $ 6,598 $ 16,556
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
VALERO NATURAL GAS PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization and Control
Valero Natural Gas Partners, L.P. ("VNGP, L.P."), Valero
Management Partnership, L.P. (the "Management Partnership") and
various subsidiary operating partnerships (the "Subsidiary
Operating Partnerships"), all Delaware limited partnerships, are
the successors to substantially all of the natural gas and
natural gas liquids businesses, assets and liabilities of
substantially all of the subsidiaries of Valero Natural Gas
Company ("VNGC") and the transmission division of Rio Grande
Valley Gas Company ("Rio"). VNGC is, and Rio at the time of such
succession was, a wholly owned subsidiary of Valero Energy
Corporation (unless otherwise required by the context, the term
"Energy" as used herein refers to Valero Energy Corporation and
its consolidated subsidiaries, both individually and
collectively). VNGC is the general partner of VNGP, L.P. and the
Management Partnership (in such capacity, the "General Partner"),
while subsidiaries of VNGC are general partners (the "Subsidiary
General Partners") of the respective Subsidiary Operating
Partnerships.
In March 1987, VNGP, L.P. sold in an underwritten public
offering 9.5 million preference units of limited partner
interests (the "Preference Units"), representing a 52% limited
partner interest in VNGP, L.P. VNGP, L.P. concurrently issued
approximately 8.6 million common units of limited partner
interests (the "Common Units"), representing a 47% limited
partner interest, to subsidiaries of Energy, and issued a 1%
general partner interest in VNGP, L.P. to VNGC. Subsequent to
March 1987, VNGP, L.P. issued .4 million additional Common Units
to a subsidiary of Energy. In addition, approximately .2 million
Common Units held by a subsidiary of Energy were transferred to
employees of Energy and converted into Preference Units in
connection with an employee benefit plan adopted by Energy.
During 1992, all outstanding Preference Units were automatically
converted into Common Units (see "Allocation of Net Income and
Cash Distributions"). The original Common Units and former
Preference Units converted into Common Units are collectively
referred to herein as the "Units." Holders of the Units are
referred to herein as the "Unitholders."
Under the partnership structure, VNGP, L.P. holds a 99%
limited partner interest and VNGC holds a 1% general partner
interest in the Management Partnership. The Management
Partnership in turn holds a 99% limited partner interest and
various wholly owned subsidiaries of VNGC each hold a 1% general
partner interest in the various Subsidiary Operating Partnerships
to which the acquired businesses, assets and liabilities were
transferred. Valero Transmission, L.P. ("Transmission"), one of
the Subsidiary Operating Partnerships, owns and operates the
principal pipeline system of the Partnership. (References to
Transmission prior to March 25, 1987 refer to Valero Transmission
Company, a wholly owned subsidiary of VNGC, and after that date
to its successor in interest, Valero Transmission, L.P.)
Transmission is principally a transporter of natural gas as it
transports gas for affiliates and third parties. Transmission
also sells natural gas to intrastate customers under long-term
contracts; however, most of the Partnership's gas sales are made
through other Subsidiary Operating Partnerships which operate
special marketing programs ("SMPs"). Subsequent to March 1987,
VNGP, L.P. acquired a wholly owned subsidiary that makes certain
intrastate gas sales, and formed certain subsidiary partnerships,
one of which leases certain assets from Energy under capital
leases as described in Note 5. Also, during 1992, an additional
Subsidiary Operating Partnership was formed to make certain
intrastate gas sales. VNGP, L.P., the Management Partnership,
the original Subsidiary Operating Partnerships and the additional
entities acquired or formed subsequent to March 1987 are
collectively referred to herein as the "Partnership." As of
December 31, 1993, Energy's total effective equity interest in
the Partnership was approximately 49%.
In October 1993, Energy publicly announced its proposal
to acquire the 9.7 million issued and outstanding Common Units in
VNGP, L.P. held by persons other than Energy (the "Public
Unitholders") pursuant to a merger of VNGP, L.P. with a wholly
owned subsidiary of Energy. The Board of Directors of VNGC
appointed a special committee of outside directors (the "Special
Committee") to consider the merger and to determine the fairness
of the transaction to the Public Unitholders. The Special
Committee thereafter retained independent financial and legal
advisors to assist the Special Committee. Upon the
recommendation of the Special Committee, the Board of Directors
of VNGC unanimously approved the merger. Effective December 20,
1993, Energy, VNGP, L.P. and VNGC entered into an agreement of
merger (the "Merger Agreement") providing for the merger. In the
merger, the Common Units held by the Public Unitholders will be
converted into the right to receive cash in the amount of $12.10
per Common Unit. As a result of the merger, VNGP, L.P. would
become a wholly owned subsidiary of Energy.
Consummation of the merger is subject to, among other
things, (i) approval of the Merger Agreement by the holders of a
majority of the issued and outstanding Common Units;
(ii) approval by the holders of a majority of the Common Units
held by the Public Unitholders and voted at a special meeting of
holders of Common Units to be called to consider the Merger
Agreement; (iii) receipt of satisfactory waivers, consents or
amendments to certain of Energy's financial agreements; and (iv)
completion of an underwritten public offering of convertible
preferred stock by Energy. Energy currently owns approximately
47.5% of the outstanding Common Units and intends to vote its
Common Units in favor of the merger.
Basis of Presentation
The accompanying consolidated financial statements have
been prepared in accordance with generally accepted accounting
principles and are not the basis for reporting taxable income to
Unitholders. The consolidated financial statements include the
accounts of VNGP, L.P. and its consolidated subsidiaries. All
significant interpartnership transactions have been eliminated in
consolidation.
Statements of Cash Flows
In order to determine net cash provided by operating
activities, net income has been adjusted by, among other things,
changes in current assets and current liabilities, excluding
changes in cash and temporary cash investments, cash held in debt
service escrow for principal (see Note 3), and current maturities
of long-term debt and capital lease obligations. Those changes,
shown as an (increase)/decrease in current assets and an
increase/ (decrease) in current liabilities, are provided in the
following table. Temporary cash investments are highly liquid
low-risk debt instruments which have a maturity of three months
or less when acquired and whose carrying amount approximates fair
value. (Dollars in thousands.)
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Cash held in debt service escrow for interest. $ 553 $ 483 $ 343
Receivables, net . . . . . . . . . . . . . . . 17,157 3,118 19,963
Inventories. . . . . . . . . . . . . . . . . . 9,646 (656) (10,430)
Prepaid expenses and other . . . . . . . . . . 2,952 (3,679) (2,005)
Accounts payable . . . . . . . . . . . . . . . (20,223) 31,504 (13,277)
Accrued interest . . . . . . . . . . . . . . . 1,982 (2,653) 2,011
Other accrued expenses . . . . . . . . . . . . 1,297 (1,441) 2,059
Total. . . . . . . . . . . . . . . . . . . . $ 13,364 $ 26,676 $ (1,336)
</TABLE>
Cash interest paid by the Partnership (net of amounts
capitalized) for the years ended December 31, 1993, 1992 and 1991
was $62.7 million, $66.4 million and $62.5 million, respectively.
No cash payments for federal income taxes were made during these
periods as the Partnership is not subject to federal income taxes
(see "Income Taxes" below). Cash payments for state income taxes
made during these periods were insignificant.
Noncash investing and financing activities for the years
ended December 31, 1992 and 1991 included $26 million and $75
million, respectively, of various natural gas and natural gas
liquids facilities acquired by the Partnership through capital
lease transactions entered into with Energy. See Note 5.
Transactions with Energy
The Partnership enters into various types of
transactions with Energy in the normal course of business on
market-related terms and conditions. The Partnership is charged
a management fee for the direct and indirect costs incurred by
Energy on behalf of the Partnership that are associated with
managing its operations. The Partnership sells natural gas and
natural gas liquids ("NGLs") to, and purchases NGLs from,
Energy's refining subsidiary. The Partnership sold natural gas
to Energy's retail natural gas distribution business operated by
Rio until September 30, 1993, when Rio was sold by Energy. The
Partnership operates for a fee two natural gas processing plants
and related facilities for Energy and sells natural gas to,
purchases natural gas and NGLs from, and processes natural gas
owned by Energy in connection with these NGL operations. The
Partnership also enters into other operating transactions with
Energy, including certain leasing transactions discussed in Note
5. As of December 31, 1993 and 1992, the Partnership had
recorded approximately $31.8 million and $13.5 million,
respectively, of accounts payable and accrued expenses, net of
accounts receivable, due to Energy.
During the fourth quarter of 1992, the Partnership
recognized a charge to earnings through the management fee billed
by Energy of approximately $4.4 million, or $.23 per limited
partner unit, representing the Partnership's allocable portion of
the cost of a voluntary early retirement program implemented by
Energy.
The following table summarizes transactions between the
Partnership and Energy for the years ended December 31, 1993,
1992 and 1991 (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
NGL sales to and services for Energy . . . . . . $ 98,590 $ 96,696 $ 86,936
Natural gas sales to Energy. . . . . . . . . . . 59,735 50,991 38,072
Purchases of NGLs and natural gas,
and transportation and other charges
from Energy. . . . . . . . . . . . . . . . . . 38,868 54,674 19,752
Interest expense from capital lease transactions
with Energy. . . . . . . . . . . . . . . . . . 12,828 10,071 9,584
Management fees for direct and indirect
costs billed by the General Partner
and affiliated companies . . . . . . . . . . . 80,727 82,024 73,324
</TABLE>
The direct and indirect costs incurred by the General
Partner on behalf of the Partnership that are charged to the
Partnership through the management fee include, among other
things, salaries and wages and other employee-related costs.
Effective January 1, 1993, Energy adopted the Financial
Accounting Standards Board's Statement of Financial Accounting
Standards ("SFAS") No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." This statement
requires a change in Energy's accounting for postretirement
benefits other than pensions from a pay-as-you-go basis to an
accrual basis of accounting. Energy is amortizing the transition
obligation over 20 years, which is greater than the average
remaining service period until eligibility of active plan
participants. As a result of Energy's adoption of this
statement, the Partnership's proportionate share of other
postretirement employee benefits included in the management fee
in 1993 increased by approximately $1.5 million and the
Partnership's proportionate share of the total accumulated
postretirement benefit obligation at December 31, 1993 was
approximately $15 million. The adoption of this statement by
Energy did not affect the Partnership's cash flows in 1993, nor
is it expected to affect the Partnership's future cash flows, as
Energy expects to continue to fund its postretirement benefits
other than pensions, and require reimbursement from the
Partnership for the Partnership's proportionate share of such
funding, on a pay-as-you-go basis.
Gas Sales and Transportation
In the course of making gas sales and providing
transportation services to customers, Transmission experiences
measurement and other volumetric differences related to the
amounts of gas received and delivered. Transmission has in the
past experienced overall net volume gains due to such differences
and its Rate Order allows such volumes to be sold to its
customers. Transmission historically has derived a substantial
benefit from such sales. The amount included in operating income
in 1993 was substantially the same as in 1992. However, the
implementation of more precise gas measurement equipment and
standards and the reduction in Transmission's total sales
volumes, discussed in Note 6 - "Customer Audit of Transmission",
is expected to reduce operating income from such sales in future
periods.
Inventories
Inventories are carried principally at weighted average
cost not in excess of market. Inventories as of December 31,
1993 and 1992 were as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
Natural gas in underground storage . . . . $ 23,184 $ 27,768
Natural gas liquids. . . . . . . . . . . . 2,250 7,312
$ 25,434 $ 35,080
</TABLE>
In addition to the above noted natural gas storage
inventories, which are located at the Wilson Storage Facility in
Wharton County, Texas (see Note 5), the Partnership also had
natural gas in third-party storage facilities, available under
exchange agreements, totalling $10.8 million and $1.2 million at
December 31, 1993 and 1992, respectively. Such amounts are
included in receivables in the accompanying consolidated balance
sheets.
Property, Plant and Equipment
Property, plant and equipment at date of inception of
the Partnership was increased by the excess of the acquisition
cost of the holders of the Preference Units over VNGC's
historical net cost basis. Accordingly, approximately 51% of
property, plant and equipment was recorded at fair value
reflecting the value attributable to the holders of the
Preference Units while the remaining 49% was recorded at
historical net book cost to reflect the value attributable to the
General Partner and the holders of the original Common Units.
Property additions and betterments include capitalized
interest and acquisition and administrative costs allocable to
construction and property purchases. Assets under capital leases
are included in property, plant and equipment and are recorded at
the lesser of the fair value of the leased property at the
inception of the lease or the present value of the related future
minimum lease payments.
The costs of minor property units (or components
thereof), net of salvage, retired or abandoned are charged or
credited to accumulated depreciation. Gains or losses on sales
or other dispositions of major units of property are credited or
charged to income.
Provision for depreciation of property, plant and
equipment is made primarily on a straight-line basis over the
estimated useful lives of the depreciable facilities. Assets
under capital leases are depreciated on a straight-line basis
over the lease term. The rates for depreciation are as follows:
<TABLE>
<S> <C>
Natural gas facilities . . . . . 2 1/4%-20%
Natural gas liquids facilities . 4 1/2%-20%
</TABLE>
During the fourth quarter of 1992, the Partnership
extended the estimated useful lives of the majority of its
natural gas liquids facilities from 14 to 20 years to better
reflect the estimated periods during which such assets are
expected to remain in service. The effect of this change in
accounting estimate, which was made retroactive to January 1,
1992, was to decrease depreciation expense and increase net
income for 1992 by approximately $5.6 million, or $.29 per
limited partner unit.
Other Assets
Payments made or agreed to be made in connection with
the settlement of certain disputed contractual issues with gas
suppliers of Transmission are initially deferred. The balance of
such payments is subsequently reduced as recoveries are made
through Transmission's rates. The balance of deferred gas costs
of $67 million and $72 million at December 31, 1993 and 1992,
respectively, is included in noncurrent other assets and is
expected to be recovered over future periods. See Note 6 -
"Customer Audit of Transmission."
Debt issuance costs are included in deferred charges and
other assets and are amortized by the effective interest method
over the term of each respective issue of the Management
Partnership's First Mortgage Notes ("First Mortgage Notes"). See
Note 3.
Income Taxes
Income and deductions of the Partnership for federal
income tax purposes are includable in the tax returns of the
individual partners. Accordingly, no recognition has been given
to federal income taxes in the accompanying consolidated
financial statements of the Partnership. At December 31, 1993
and 1992, the net difference between the tax bases and the
reported amounts of assets and liabilities in the accompanying
Consolidated Balance Sheets was $314 million and $322 million,
respectively. Under the Revenue Act of 1987, certain publicly
traded limited partnerships will be taxed as corporations after
December 31, 1997 unless specifically exempted. This Act
exempted natural resource partnerships including those dealing
with natural gas transportation and processing of natural gas
liquids, such as the Partnership, from its taxation provision.
Price Risk Management Activities
The Partnership, through its Market Center Services
Program established in 1992, enters into exchange-traded
futures and options contracts, forward contracts, swaps and
other financial instruments with third parties to hedge natural
gas inventories and certain anticipated natural gas purchase
requirements in order to minimize the risk of market
fluctuations. The Partnership also utilizes such price risk
management techniques to provide services to gas producers
and end users. Changes in the market value of these contracts
are deferred until the gain or loss is recognized on the hedged
transaction. As of December 31, 1993 and 1992, the Partnership
had outstanding contracts for natural gas totalling approximately
15.0 billion cubic feet ("Bcf") and 4.8 Bcf, respectively, for
which the Partnership is the fixed price payor and 27.1 Bcf and
10.0 Bcf, respectively, for which the Partnership is the fixed
price receiver. Such contracts run for a period of one to twelve
months. A portion of such contracts represented hedges of
natural gas volumes in underground storage and in third-party
storage facilities which totalled approximately 10.3 Bcf and 7.4
Bcf at December 31, 1993 and 1992, respectively. See
"Inventories" above.
In 1993 and 1992, the Partnership recognized $18.7
million and $12.9 million, respectively, in gas cost reductions
and other benefits from this program. An additional $5.1 million
and $3.6 million in other reductions of cost of gas was generated
by transactions entered into in 1993 and 1992, respectively,
which is recognized in income in the subsequent year as the
related gas is sold.
Allocation of Net Income and Cash Distributions
Net income is allocated to partners based on their
effective ownership interest in the operating results of the
Partnership, except that additional depreciation expense
pertaining to the excess of the Partnership's acquisition cost
over the historical cost basis in net property, plant and
equipment and certain other assets in which the former holders of
Preference Units have an ownership interest is allocated solely
to such holders as a noncash charge to net income. The
allocation of additional depreciation expense to the former
holders of Preference Units does not affect the cash
distributions with respect to the Units. Under the Partnership
structure, the income of the Subsidiary Operating Partnerships is
allocated to the Subsidiary General Partners, which hold a 1%
general partner interest, and to the Management Partnership,
which holds a 99% limited partner interest. As a result, net
income allocable to the Subsidiary General Partners is not
reduced by interest expense associated with the Management
Partnership's First Mortgage Notes.
The Partnership is required to make quarterly cash
distributions with respect to all Units in an amount equal to
"Distributable Cash Flow" as defined in the Second Amended and
Restated Agreement of Limited Partnership of VNGP, L.P. (the
"Partnership Agreement") and as determined by the General
Partner. With the payment on May 30, 1992 of the cash
distribution of $.625 per Unit for the first quarter of 1992, the
Partnership completed the payment of cumulative cash
distributions of $12.50 per Preference Unit resulting in the
termination of the period (the "Preference Period") during which
the holders of Preference Units were entitled to a preferential
distribution amount. As a result of the termination of the
Preference Period, all outstanding Preference Units were
automatically converted into Common Units in accordance with the
terms of the Partnership Agreement. The Partnership subsequently
reduced cash distributions to $.125 per Unit for the remaining
quarters of 1992 and the first three quarters of 1993. On
January 25, 1994, the VNGC Board of Directors declared a cash
distribution of $.125 per Unit for the fourth quarter of 1993
that is payable March 1, 1994 to holders of record as of February
7, 1994. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for a discussion of factors
that have reduced the amount of cash available for distribution
to Unitholders.
If the proposed merger with Energy described above under
"Organization and Control" occurs after March 9, 1994, the
General Partner intends and expects to declare and pay a pro rata
distribution to holders of record of the Common Units on the
effective date of the merger based upon the number of days
elapsed between February 7, 1994 and such effective date.
2. SHORT-TERM BANK LINES
The Partnership, through the Management Partnership,
currently maintains five separate short-term bank lines of credit
totalling $80 million. In accordance with the terms of the
indenture of mortgage and deed of trust pursuant to which the
Management Partnership's First Mortgage Notes were issued (the
"Mortgage Note Indenture"), at least $20 million of revolving
credit agreements must be maintained at all times; however, no
more than $50 million of borrowings are permitted to be
outstanding at any time. See Note 3. The Partnership had
borrowings of as much as $39.9 million under its short-term bank
lines during 1993. No borrowings were outstanding under these
lines at December 31, 1993 or 1992. The lines of credit mature
at various times during 1994, bear interest at each respective
bank's prime, quoted money market or Eurodollar rate and require
commitment fees based on the unused amount of the credit. If
the proposed merger with Energy does not occur, the General
Partner believes that these short-term bank lines could be
renewed or replaced with other short-term lines during 1994 on
terms and conditions similar to those currently existing. If
the proposed merger with Energy is completed, the General
Partner anticipates that new bank credit agreements will be
negotiated and that the Partnership's existing short-term bank
lines will be cancelled.
3. LONG-TERM DEBT
Long-term debt balances were as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1993 1992
<S> <C> <C>
First Mortgage Notes . . . . . . . . . . . . . $534,286 $559,643
Less current maturities. . . . . . . . . . . 27,857 25,357
Long-term debt, less current maturities . . $506,429 $534,286
</TABLE>
The First Mortgage Notes, which are currently comprised
of eight remaining series due serially from 1994 through 2009,
are secured by mortgages on and security interests in
substantially all of the currently existing and after-acquired
property, plant and equipment of the Management Partnership and
each Subsidiary Operating Partnership and by the Management
Partnership's limited partner interest in each Subsidiary
Operating Partnership (the "Mortgaged Property"). As of December
31, 1993, the First Mortgage Notes have a remaining weighted
average life of approximately 7.3 years and a weighted average
interest rate of 10.12% per annum. Interest on the First
Mortgage Notes is payable semiannually, but one-half of each
interest payment and one-fourth of each annual principal payment
are escrowed quarterly in advance. At December 31, 1993 and
1992, $34.2 million and $32.9 million, respectively, had been
deposited with the Mortgage Note Indenture trustee ("Trustee") in
an escrow account. The amount on deposit is classified as a
current asset (cash held in debt service escrow) and the
liability to be paid off when the cash is released by the Trustee
from escrow is classified as a current liability.
The Mortgage Note Indenture contains covenants
prohibiting the Management Partnership and the Subsidiary
Operating Partnerships (collectively referred to herein as the
"Operating Partnerships") from incurring additional indebtedness,
including any additional First Mortgage Notes, other than (i) up
to $50 million of indebtedness to be incurred for working capital
purposes (provided that for a period of 45 consecutive days
during each 16 consecutive calendar month period no such
indebtedness will be permitted to be outstanding) and (ii) up to
the amount of any future capital improvements financed through
the issuance of debt or equity by VNGP, L.P. and the contribution
of such amounts as additional equity to the Management
Partnership. The Mortgage Note Indenture also prohibits the
Operating Partnerships from (a) creating new indebtedness unless
certain cash flow to debt service requirements are met; (b)
creating certain liens; or (c) making cash distributions in any
quarter in excess of the cash generated in the prior quarter,
less (i) capital expenditures during such prior quarter (other
than capital expenditures financed with certain permitted
indebtedness), (ii) an amount equal to one-half of the interest
to be paid on the First Mortgage Notes on the interest payment
date occurring in or next following such prior quarter and (iii)
an amount equal to one-quarter of the principal required to be
paid on the First Mortgage Notes on the principal payment date
occurring in or next following such prior quarter, plus cash
which could have been distributed in any prior quarter but which
was not distributed. The Operating Partnerships are further
prohibited from purchasing or owning any securities of any person
or making loans or capital contributions to any person other than
investments in the Subsidiary Operating Partnerships, advances
and contributions of up to $20 million per year and $100 million
in the aggregate to entities engaged in substantially similar
business activities as the Operating Partnerships, temporary
investments in certain marketable securities and certain other
exceptions.
The Mortgage Note Indenture also prohibits the Operating
Partnerships from consolidating with or conveying, selling,
leasing or otherwise disposing of all or any material portion of
their property, assets or business as an entirety to any other
person unless the surviving entity meets certain net worth
requirements and certain other conditions are met, or from
selling or otherwise disposing of any part of the Mortgaged
Property, subject to certain exceptions. The Mortgage Note
Indenture also provides that it will be an event of default if
VNGC withdraws as General Partner of the Management Partnership
prior to 1997, if VNGC is removed as General Partner but the
Subsidiary General Partners are not also removed, or if the
General Partner or any Subsidiary General Partner withdraws or is
removed and is not replaced within 30 days.
Maturities of long-term debt for the years ending
December 31, 1995 through 1998 are $30.3 million, $32.9 million,
$35.3 million and $37.9 million, respectively.
Based on the borrowing rates currently available to the
Partnership for long-term debt with similar terms and average
maturities, the fair value of the Partnership's First Mortgage
Notes, including current maturities, at December 31, 1993 was
approximately $562 million. At December 31, 1992, the fair value
of the First Mortgage Notes was essentially equal to their
carrying value.
4. INDUSTRY SEGMENT INFORMATION
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Operating revenues:
Natural gas. . . . . . . . . . . . $ 900,252 $ 743,026 $ 764,226
Natural gas liquids . . . . . . . 441,741 466,017 390,708
Intersegment eliminations. . . . . (15,535) (11,914) (10,933)
Total. . . . . . . . . . . . . . $1,326,458 $1,197,129 $1,144,001
Operating income:
Natural gas. . . . . . . . . . . . $ 53,458 $ 32,484 $ 37,140
Natural gas liquids. . . . . . . . 26,020 57,357 62,694
Total. . . . . . . . . . . . . . 79,478 89,841 99,834
Other income, net. . . . . . . . . . 1,263 624 4,013
Interest expense, net. . . . . . . . (66,294) (65,479) (66,811)
Net income . . . . . . . . . . . $ 14,447 $ 24,986 $ 37,036
Identifiable assets:
Natural gas. . . . . . . . . . . . $ 865,487 $ 889,620 $ 900,588
Natural gas liquids. . . . . . . . 154,767 174,170 126,380
Other. . . . . . . . . . . . . . . 43,008 43,292 52,489
Intersegment eliminations. . . . . (18,180) (22,601) (17,967)
Total. . . . . . . . . . . . . . $1,045,082 $1,084,481 $1,061,490
Depreciation expense:
Natural gas. . . . . . . . . . . . $ 28,549 $ 28,136 $ 27,977
Natural gas liquids. . . . . . . . 7,897 6,268 11,254
Total. . . . . . . . . . . . . . $ 36,446 $ 34,404 $ 39,231
Capital expenditures:
Natural gas. . . . . . . . . . . . $ 20,511 $ 22,537 $ 26,931
Natural gas liquids. . . . . . . . 15,550 13,356 6,143
Total. . . . . . . . . . . . . . $ 36,061 $ 35,893 $ 33,074
</TABLE>
The Partnership operates in the natural gas and natural
gas liquids industry segments. The natural gas operations
consist of purchasing, gathering, transporting and selling
natural gas, principally to gas distribution companies, electric
utilities, pipeline companies and industrial customers. The
Partnership also transports gas for a fee for sales customers,
other pipelines and end users and provides price risk management
services to gas producers and end users through its Market Center
Services Program. The natural gas liquids operations include the
extraction of natural gas liquids, principally from natural gas
throughput of the natural gas operations, and the fractionation
and transportation of natural gas liquids. The primary markets
for sales of natural gas liquids are petrochemical plants,
refineries and domestic fuel distributors. Intersegment revenue
eliminations relate primarily to transportation provided by the
natural gas segment for the natural gas liquids segment. During
1993, natural gas sales and transportation revenues from San
Antonio City Public Service accounted for approximately 11% of
the Partnership's total consolidated operating revenues. No
single unaffiliated customer accounted for more than 10% of the
Partnership's total consolidated operating revenues during 1992
or 1991. Energy and its consolidated subsidiaries accounted for
approximately 12%, 12% and 11% of the Partnership's total
consolidated operating revenues during 1993, 1992 and 1991,
respectively.
The Partnership's natural gas segment has a
concentration of customers in the natural gas transmission and
distribution industries while its natural gas liquids segment has
a concentration of customers in the refining and petrochemical
industries. These concentrations of customers may impact the
Partnership's overall exposure to credit risk, either positively
or negatively, in that the customers may be similarly affected by
changes in economic or other conditions. However, the General
Partner believes that the Partnership's portfolio of accounts
receivable is sufficiently diversified to the extent necessary to
minimize any potential credit risk. Historically, the
Partnership has not had any significant problems in collecting
its accounts receivable. The Partnership's accounts receivable
are generally not collateralized.
5. LEASE AND OTHER COMMITMENTS
Valero Gas Storage Company ("Gas Storage"), a wholly
owned subsidiary of VNGC, is the lessee under an operating lease
for a gas storage facility (the "Wilson Storage Facility"). Gas
Storage and Valero Transmission Company had previously entered
into a gas storage agreement ("Gas Storage Agreement") which
required Valero Transmission Company to pay to Gas Storage
amounts essentially equivalent to the lease payments and
operating costs in connection with Valero Transmission Company's
use of the Wilson Storage Facility. Upon formation of the
Partnership, Valero Transmission Company assigned the Gas Storage
Agreement to Valero Transmission, L.P., and Valero Transmission,
L.P. assumed Valero Transmission Company's obligation to make
such payments to Gas Storage. The remaining primary lease term
for the Wilson Storage Facility is six years with options to
renew at varying terms. The future minimum lease payments
related to this lease are included in the table below. The
Partnership has other noncancelable operating leases with
remaining terms ranging generally from one year to 13 years.
During 1992, the Partnership entered into a capital
lease with Energy to lease a gas processing plant near
Thompsonville in South Texas and 48 miles of NGL product pipeline
(the "Thompsonville Project"). The Thompsonville Project lease
commenced December 1, 1992 and has a term of 15 years. During
1991, the Partnership entered into capital leases with Energy to
lease an interest in an approximate 105-mile pipeline in East
Texas (the "East Texas pipeline") and certain fractionation
facilities in Corpus Christi, Texas. The East Texas pipeline
lease commenced February 1, 1991 and has a term of 25 years while
the lease for the fractionation facilities commenced December 1,
1991 and has a term of 15 years. As a result of the settlement
and dismissal in 1992 of certain claims asserted in litigation
filed against Energy and certain of its affiliates, officers and
directors, Energy agreed to adjust the payments and certain other
terms under these capital leases. Such adjusted payments are
reflected in the table of future minimum lease payments shown
below.
The assets and associated obligations related to the
capital leases with Energy described above are not subject to the
Mortgage Note Indenture. The Partnership has the right to
purchase all or any portion of these assets, subject to certain
restrictions, under purchase option provisions of the respective
lease agreements. The total cost of these leased facilities,
which is included in the accompanying consolidated balance sheets
under property, plant and equipment, was approximately $101
million. Amortization of these capital leases, which is included
in depreciation expense in the accompanying consolidated income
statements, was $5.3 million, $3.5 million and $2.2 million for
1993, 1992 and 1991, respectively.
The related future minimum lease payments under the
Partnership's capital leases and noncancelable operating leases
as of December 31, 1993 are as follows (in thousands):
<TABLE>
<CAPTION>
Operating Leases
Other Partnership
Partnership Commitments
Capital Lease (Wilson Storage
Leases Commitments Facility)
<S> <C> <C> <C>
1994 . . . . . . . . . . . . . . . . $ 12,867 $1,873 $ 10,438
1995 . . . . . . . . . . . . . . . . 12,867 147 10,438
1996 . . . . . . . . . . . . . . . . 13,867 134 10,438
1997 . . . . . . . . . . . . . . . . 15,114 105 9,832
1998 . . . . . . . . . . . . . . . . 15,361 103 10,156
Remainder. . . . . . . . . . . . . . 213,557 449 15,660
Total minimum lease payments . . . . 283,633 $2,811 $66,962
Less amount representing interest. 178,795
Net present value of minimum lease
payments . . . . . . . . . . . . . 104,838
Less current maturities. . . . . . 1,051
Capital lease obligations. . . . . $ 103,787
</TABLE>
The future minimum lease payments listed above under the
caption "Partnership Lease Commitments" exclude certain operating
lease commitments which are cancelable by the Partnership upon
notice of one year or less. Consolidated rent expense was
approximately $698,000, $833,000 and $746,000 for the years ended
December 31, 1993, 1992 and 1991, respectively, and excludes
amounts billed by Energy to the Partnership for its proportionate
use of Energy's corporate headquarters office complex and related
charges which are included in the management fee charged to the
Partnership. See Note 1 - "Transactions with Energy." Rentals
paid of $10,438,000 per year for 1993, 1992 and 1991 in
connection with the Wilson Storage Facility were included in the
computation of Transmission's weighted average cost of gas.
The obligations of Gas Storage under the gas storage
facility lease include its obligation to make scheduled lease
payments and, in the event of a declaration of default and
acceleration of the lease obligation, to make certain lump sum
payments based on a stipulated loss value for the gas storage
facility less the fair market sales price or fair market rental
value of the gas storage facility. Under certain circumstances,
a default by Energy or a subsidiary of Energy, including VNGC,
with respect to its own indebtedness could result in a cross
default under the gas storage facility lease. The General Partner
believes that it is unlikely that a default by Energy or a
subsidiary of Energy would result in acceleration of the gas
storage facility lease, and further believes that such event, if
it occurred, would not have a material adverse effect on the
Partnership.
6. LITIGATION AND CONTINGENCIES
Take-or-Pay and Related Claims
As a result of past market conditions and contracting
practices in the natural gas industry, numerous producers and
other suppliers brought claims against Transmission asserting
that it was in breach of contractual provisions requiring that
it take, or pay for if not taken, certain specified volumes of
natural gas. The Partnership has settled substantially all of
the significant take-or-pay claims, pricing differences and
contractual disputes heretofore brought against it. Although
additional claims may arise under older contracts until their
expiration or renegotiation, the General Partner believes that
the Partnership has resolved substantially all of the significant
take-or-pay claims that are likely to be made. As described
below, Energy and/or the Partnership have agreed to bear a
portion of certain potential liabilities that may be incurred by
certain Partnership suppliers. Although the General Partner is
currently unable to predict the total amount Transmission or the
Partnership ultimately may pay or be required to pay in
connection with the resolution of existing and potential take-or-
pay claims, the General Partner believes that any remaining
claims can be resolved on terms satisfactory to the Partnership
and that the resolution of such claims and any potential claims
has not had and will not have a material adverse effect on the
Partnership's financial position or results of operations.
In 1987, Transmission and a producer from whom
Transmission has purchased natural gas entered into an agreement
resolving certain take-or-pay issues between the parties in which
Transmission agreed to pay one-half of certain excess royalty
claims arising after the date of the agreement. The royalty
owners of the producer recently completed an audit of the
producer and have presented to the producer a claim for
additional royalty payments in the amount of approximately $17.3
million, and accrued interest thereon of approximately $19.8
million. Approximately $8 million of the royalty owners' claim
accrued after the effective date of the agreement between the
producer and Transmission. The producer and Transmission are
reviewing the royalty owners' claims. No lawsuit has been filed
by the royalty owners. The General Partner believes that various
defenses under the agreement may reduce any liability of
Transmission to the producer in this matter.
Valero Transmission Company and one of its gas suppliers
are parties to various gas purchase contracts assigned to and
assumed by Valero Transmission, L.P. upon formation of the
Partnership in 1987. The supplier is also a party to a series of
gas purchase contracts between the supplier, as buyer, and
certain trusts, as seller, which are in litigation. Neither the
Partnership nor Valero Transmission Company is a party to this
litigation or the contracts between Transmission's supplier and
the trusts. However, because of the relationship between
Transmission's contracts with the supplier and the supplier's
contracts with the trusts, and in order to resolve existing and
potential disputes, the supplier, Valero Transmission Company and
Valero Transmission, L.P. have agreed that they will cooperate in
the conduct of this litigation, and that Valero Transmission
Company and Valero Transmission, L.P. will bear a substantial
portion of the costs of any appeal and any nonappealable final
judgment rendered against the supplier. In the litigation, the
trusts allege that Transmission's supplier has breached various
minimum take, take-or-pay and other contractual provisions, and
assert a statutory nonratability claim. The trusts seek alleged
actual damages, including interest, of approximately $30 million
and an unspecified amount of punitive damages. The District
Court ruled on the plaintiff's motion for summary judgment,
finding, among other things, that as a matter of law the three
gas purchase contracts at issue were fully binding and
enforceable, the supplier breached the minimum take obligations
under one of the contracts, the supplier is not entitled to
claimed offsets for gas purchased by third parties and the
"availability" of gas for take-or-pay purposes is established
solely by the delivery capacity testing procedures in the
contracts. Damages, if any, have not been determined. Because
of existing contractual obligations of Valero Transmission, L.P.
to its supplier, the lawsuit may ultimately involve a contingent
liability for Valero Transmission, L.P. The General Partner
believes that the claims brought against the supplier have been
significantly overstated, and that the supplier has a number of
meritorious defenses to the claims including various regulatory,
statutory, contractual and common law defenses. The Court
recently granted the supplier's Motion for Continuance of the
former January 10, 1994 trial date. This litigation is not
currently set for trial.
Payments that Transmission has made or agreed to make in
connection with settlements to date are included in its deferred
gas costs. The General Partner believes that the rate order
under which Transmission currently operates (the "Rate Order"),
issued in 1979 by the Railroad Commission of Texas (the "Railroad
Commission," which regulates the sale and transportation of
natural gas by intrastate pipeline systems in Texas), allows for
the recovery of such costs. See Note 1 - "Other Assets" and
"Customer Audit of Transmission" below. Certain take-or-pay and
other claims have been resolved through the Partnership agreeing
to provide discounted transportation services. These agreements
do not involve a cash outlay by the Partnership but in certain
cases have the effect of reducing transportation margins over an
extended period of time.
Any liability of Energy with respect to take-or-pay
claims involving Transmission's intrastate pipeline operations
has been assumed by the Partnership. Based upon the General
Partner's beliefs and rate considerations discussed above, no
liabilities have been recorded for any unresolved take-or-pay
claims.
Other Litigation
Seven lawsuits were filed in Chancery Court in Delaware
against VNGP, L.P., VNGC and Energy and certain officers and
directors of VNGC and/or Energy in response to the
announcement by Energy on October 14, 1993 of its proposal to
acquire the publicly traded Common Units of VNGP, L.P. pursuant
to a proposed merger of VNGP, L.P. with a wholly owned subsidiary
of Energy. See Note 1 - "Organization and Control." The suits
were consolidated into a single proceeding by the Chancery Court
on November 23, 1993. The plaintiffs sought to enjoin or
rescind the proposed merger, alleging that the corporate
defendants and the individual defendants, as officers or
directors of the corporate defendants, engaged in actions in
breach of the defendants' fiduciary duties to the Public
Unitholders by proposing the merger. The plaintiffs
alternatively sought an increase in the proposed merger
consideration, unspecified compensatory damages and attorneys'
fees. In December 1993, the parties reached a tentative
settlement of the consolidated lawsuit. The terms of the
settlement will not require a material payment by Energy or
the Partnership. However, there can be no assurance that the
settlement will be completed, or that it will be approved by the
Chancery Court.
In March 1993, two indirect wholly owned subsidiaries of
Energy serving as general partners of two of VNGP, L.P.'s
principal Subsidiary Operating Partnerships were served as third-
party defendants in a lawsuit originally filed in 1991 by a
subsidiary of The Coastal Corporation ("Coastal") against
TransAmerican Natural Gas Corporation ("TANG"). In August 1993,
Energy, VNGP, L.P. and certain of their respective subsidiaries
were named as additional third-party defendants (collectively,
including the original defendant subsidiaries, the "Valero
Defendants") in this lawsuit. In its counterclaims against
Coastal and third-party claims against the Valero Defendants,
TANG alleges that it contracted to sell natural gas to Coastal at
the posted field price of one of the Valero Defendants and that
the Valero Defendants and Coastal conspired to set the posted
field price at an artificially low level. TANG also alleges that
the Valero Defendants and Coastal conspired to cause TANG to
deliver unprocessed or "wet" gas, thus precluding TANG from
extracting NGLs from its gas prior to delivery. TANG seeks
actual damages of approximately $50 million, trebling of damages
under antitrust claims, punitive damages of $300 million, and
attorneys' fees. The General Partner believes that the
plaintiff's claims have been exaggerated, and that Energy and the
Partnership have meritorious defenses to such claims. In the
event of an adverse determination involving Energy, Energy likely
would seek indemnification from the Partnership under terms of
the partnership agreements and other applicable agreements
between VNGP, L.P., its subsidiary partnerships and their
respective general partners. The Valero Defendants' motion for
summary judgment on TANG's antitrust claims was argued on January
24, 1994. The court has not ruled on such motion. The current
trial setting for this case is March 14, 1994.
In September 1991, a lawsuit was filed by Valero
Transmission, L.P. alleging breach of contract against a
producer. On January 11, 1993, the defendant filed a cross-
action against Valero Transmission, L.P., Valero Industrial Gas,
L.P. and Reata Industrial Gas, L.P. The defendant asserted
claims for actual damages for failure to pay for goods and
services delivered. Additionally, the defendant asserted various
other cross-claims, including conversion, breach of contract,
breach of an alleged duty to market gas in good faith, tortious
breach of a duty imposed by law and tortious negligence. The
defendant sought actual damages aggregating not less than
$1 million, injunctive relief, attorneys fees and costs, and
exemplary damages in the amount of not less than $20 million. In
January 1994, the parties reached a tentative settlement of the
lawsuit on terms immaterial to the Partnership.
The Partnership was a party to a lawsuit originally
filed in 1988 in which Energy, Valero Transmission Company, VNGP,
L.P., the Management Partnership and Valero Transmission, L.P.
(the "Valero Defendants") and a subsidiary of Coastal were
alleged to be liable for failure to take minimum quantities of
gas, failure to make take-or-pay payments and other breach of
contract and breach of fiduciary duty claims. The plaintiffs
sought declaratory relief, actual damages in excess of $37
million and unspecified punitive damages. During the third
quarter of 1992, the plaintiffs, Coastal and the Valero
Defendants settled this lawsuit on terms which were not material
to the Valero Defendants and on July 19, 1993, this lawsuit was
dismissed. On November 16, 1992, prior to entry of the order of
dismissal, NationsBank of Texas, N.A., as trustee for certain
trusts (the "Intervenors"), filed a plea in intervention to
intervene in the lawsuit. The Intervenors asserted that they
held a non-participating mineral interest in the lands subject to
the litigation and that their rights were not protected by the
plaintiffs in the settlement. On February 4, 1993, the Court
struck the Intervenors' plea in intervention. However, on
February 2, 1993, the Intervenors had filed a separate suit in
the 160th State District Court, Dallas County, Texas, against all
prior defendants and an additional defendant, substantially
adopting in form and substance the allegations and claims in the
original litigation. In February 1994, the parties reached a
tentative settlement of the lawsuit on terms immaterial to the
Partnership.
City of Houston Franchise Fee Audit
In a letter dated September 1, 1993 from the City of
Houston (the "City") to Valero Transmission Company ("VTC"), the
City stated its intent to bring suit against VTC for certain
claims asserted by the City under the franchise agreement between
the City and VTC. VTC is the general partner of Valero
Transmission, L.P. The franchise agreement was assigned to and
assumed by Valero Transmission, L.P. upon formation of the
Partnership in 1987. In the letter, the City declared a
conditional forfeiture of the franchise rights based on the
City's claims. In a letter dated October 27, 1993, the City
claimed that VTC owes to the City franchise fees and accrued
interest thereon aggregating approximately $13.5 million. In a
letter dated November 9, 1993, the City claimed an additional
$18 million in damages related to the City's allegations that VTC
engaged in unauthorized activities under the franchise agreement
by transmitting gas for resale and by transporting gas for third
parties on the franchised premises. The City has not filed a
lawsuit. The General Partner believes that the City's claims are
significantly overstated and that VTC has a number of meritorious
defenses to the claims. Any liability of VTC with respect to the
City's claims has been assumed by the Partnership.
Customer Audit of Transmission
Transmission's Rate Order provides for Transmission to
sell gas at its weighted average cost of gas, as defined
("WACOG"), plus a margin of $.15 per Mcf. In addition to the
cost of gas purchases, Transmission's WACOG has included storage,
gathering and other fixed costs totalling approximately $19
million per year, and amortization of deferred gas costs related
to the settlement of take-or-pay and related claims (see Note 1 -
"Other Assets" and "Take-or-Pay and Related Claims" above).
Transmission's gas purchases include high-cost casinghead gas and
certain special allowable gas that Transmission is required to
purchase contractually and under the Railroad Commission's
priority rules. Transmission's sales volumes have been
decreasing with the expiration of its sales contracts including
the July 1992 expiration of a contract representing approximately
37% of Transmission's sales volumes for the first six months of
1992. As a result of each of these factors, Transmission's WACOG
and gas sales price are substantially in excess of market
clearing levels.
Transmission's WACOG has been periodically audited by
certain of its customers, as allowed under the Rate Order. One
such customer (the "Customer") questioned the application of
certain of Transmission's current rate policies to future periods
in light of the decreases that have occurred in Transmission's
throughput, and the Customer has recently completed its audit of
Transmission's WACOG with respect thereto. For 1993, the
Customer represented approximately 70% of Transmission's sales
volumes and such percentage is expected to increase as other
sales contracts expire and are not renewed. As a result of the
Customer's audit, Transmission and the Customer entered into a
settlement agreement which excludes certain of the fixed costs
described above from Transmission's WACOG, effective with July
1993 sales, resulting in a reduction of the Partnership's annual
net income by approximately $6 million. Upon the termination of
Transmission's gas sales contract with the Customer in 1998,
Transmission's fixed costs, including storage (see Note 5), would
be charged to income instead of recovered through its gas sales
rates. Transmission expects to recover its deferred gas costs
over a period of approximately eight years. The recovery of any
additional payments made in connection with any future
settlements would be limited.
The Partnership is also a party to additional claims and
legal proceedings arising in the ordinary course of business.
The General Partner believes it is unlikely that the final
outcome of any of the claims or proceedings to which the
Partnership is a party, including those described above, would
have a material adverse effect on the Partnership's financial
position or results of operations; however, due to the inherent
uncertainties of litigation, the range of possible loss, if any,
cannot be estimated with a reasonable degree of precision and
there can be no assurance that the resolution of any particular
claim or proceeding would not have an adverse effect on the
Partnership's results of operations for the fiscal period in
which such resolution occurred.
7. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended
December 31, 1993 and 1992 were as follows (in thousands of
dollars, except per Unit amounts):
<TABLE>
<CAPTION>
Net Income
Net (Loss) Per
Operating Operating Income Limited
Revenues Income (Loss) Partner Unit
<S> <C> <C> <C> <C>
1993-Quarter Ended:
March 31 . . . . . . $ 331,484 $ 21,747 $ 5,133 $ .26
June 30. . . . . . . 326,259 23,496 7,699 .39
September 30 . . . . 336,893 19,812 3,621 .18
December 31. . . . . 331,822 14,423 (2,006) (.11)
Total. . . . . . . $1,326,458 $ 79,478 $ 14,447 $ .72
1992-Quarter Ended:
March 31 . . . . . . $ 265,745 $ 18,785 $ 2,617 $ .13
June 30. . . . . . . 276,609 22,035 6,155 .31
September 30 . . . . 314,245 30,032 13,901 .72
December 31. . . . . 340,530 18,989 2,313 .11
Total. . . . . . . $1,197,129 $ 89,841 $ 24,986 $ 1.27
</TABLE>
<PAGE>
<TABLE>
SCHEDULE V
VALERO NATURAL GAS PARTNERS, L.P.
PROPERTY, PLANT AND EQUIPMENT
(Thousands of Dollars)
<CAPTION>
Balance at Balance
Beginning Additions Other at End
Description of Period at Cost Retirements Changes of Period
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1993
Natural gas. . . . . . . . $745,223 $ 20,511 $ 9,300 $ (164) (2) $756,270
Natural gas liquids. . . . 171,511 15,550 3,638 (128) (2) 183,295
$916,734 $ 36,061 $ 12,938 $ (292) $939,565
Year Ended December 31, 1992
Natural gas. . . . . . . . $732,014 $ 22,537 $ 9,483 $ 155 (2) $745,223
Natural gas liquids. . . . 135,231 13,356 1,535 26,589 (1)
(2,130) (2) 171,511
$867,245 $ 35,893 $ 11,018 $ 24,614 $916,734
Year Ended December 31, 1991
Natural gas. . . . . . . . $653,098 $ 26,931 $ 7,018 $ 58,627 (1) $732,014
376 (2)
Natural gas liquids. . . . 126,862 6,143 14,125 16,611 (1) 135,231
(260) (2)
$779,960 $ 33,074 $ 21,143 $ 75,354 $867,245
<FN>
Note: See Note 1 - "Property, Plant and Equipment" of Notes to
Consolidated Financial Statements for disclosure of depreciation
methods and rates.
(1) Assets acquired under capital leases with Energy.
(2) Reclassifications, intersegment transfers and other
miscellaneous adjustments.
</TABLE>
<TABLE>
SCHEDULE VI
VALERO NATURAL GAS PARTNERS, L.P.
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
(Thousands of Dollars)
<CAPTION>
Additions
Balance at Charged to Balance
Beginning Costs and Other at End
Description of Period Expenses Retirements Changes (1) of Period
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1993
Natural gas. . . . . . . . $118,994 $ 28,549 $ 8,066 $ 117 $139,594
Natural gas liquids. . . . 54,524 7,897 2,287 35 60,169
$173,518 $ 36,446 $ 10,353 $ 152 $199,763
Year Ended December 31, 1992
Natural gas. . . . . . . . $ 98,870 $ 28,136 $ 8,652 $ 640 $118,994
Natural gas liquids. . . . 50,070 6,268 1,432 (382) 54,524
$148,940 $ 34,404 $ 10,084 $ 258 $173,518
Year Ended December 31, 1991
Natural gas. . . . . . . . $ 76,816 $ 27,977 $ 6,367 $ 444 $ 98,870
Natural gas liquids. . . . 46,323 11,254 7,448 (59) 50,070
$123,139 $ 39,231 $ 13,815 $ 385 $148,940
<FN>
NOTE: See Note 1 - "Property, Plant and Equipment" of Notes to
Consolidated Financial Statements for disclosure of depreciation
methods and rates.
(1) Reclassifications, intersegment transfers and other
miscellaneous adjustments.
</TABLE>
<TABLE>
SCHEDULE IX
VALERO NATURAL GAS PARTNERS, L.P.
SHORT-TERM BORROWINGS(1)
(Thousands of Dollars)
<CAPTION>
Maximum Average Weighted-
Category Weighted- Amount Amount Average
of Aggregate Balance at Average Outstanding Outstanding Interest Rate
Short-Term End of Interest During the During the During the
Borrowings Period Rate Period(2) Period(3) Period(4)
<S> <C> <C> <C> <C> <C>
Year Ended:
December 31, 1993 . . . . . $ - - % $39,900 $10,925 4.04%
December 31, 1992 . . . . . - - 23,500 359 4.16
December 31, 1991 . . . . . - - 14,200 458 7.55
<FN>
(1) See Note 2 of Notes to Consolidated Financial Statements
for a discussion of the terms and provisions of the
Partnership's short-term bank lines.
(2) The maximum amount outstanding occurred during September
of 1993, December of 1992 and January of 1991,
respectively.
(3) The average amount outstanding during the period was
determined on a daily average basis.
(4) Percentages were computed by dividing total interest
expense on all short-term borrowings by the average amount
outstanding during the period.
</TABLE>
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
VALERO ENERGY CORPORATION
(Registrant)
By /s/ William E. Greehey
(William E. Greehey)
Chairman of the Board and
Chief Executive Officer
Date: March 1, 1994
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose
signature appears below hereby constitutes and appoints
William E. Greehey, Stan L. McLelland and Rand C. Schmidt, or any
of them, each with power to act without the other, his true and
lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him and in his name, place
and stead, in any and all capacities, to sign any or all
subsequent amendments and supplements to this Annual Report on
Form 10-K, and to file the same, or cause to be filed the same,
with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting
unto each said attorney-in-fact and agent full power to do and
perform each and every act and thing requisite and necessary to
be done in and about the premises, as fully to all intents and
purposes as he might or could do in person, hereby qualifying and
confirming all that said attorney-in-fact and agent or his
substitute or substitutes may lawfully do or cause to be done by
virtue hereof.
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
Signature Title Date
Director, Chairman of the
Board and Chief Executive
Officer (Principal
/s/ William E. Greehey Executive Officer) March 1, 1994
(William E. Greehey)
Senior Vice President
and Chief Financial Officer
(Principal Financial
/s/ Don M. Heep and Accounting Officer) March 1, 1994
(Don M. Heep)
/s/ Edward C. Benninger Director March 1, 1994
(Edward C. Benninger)
/s/ Robert G. Dettmer Director March 1, 1994
(Robert G. Dettmer)
/s/ A. Ray Dudley Director March 1, 1994
(A. Ray Dudley)
/s/ James L. Johnson Director March 1, 1994
(James L. Johnson)
/s/ Lowell H. Lebermann Director March 1, 1994
(Lowell H. Lebermann)
/s/ Sally A. Shelton Director March 1, 1994
(Sally A. Shelton)
Director
(Philip K. Verleger, Jr.)
Refining
SECOND AMENDMENT
TO
AMENDED AND RESTATED CREDIT AGREEMENT
This Second Amendment to Amendment and Restated Credit
Agreement (this "Amendment") dated as of December 31, 1993 is
among Valero Refining Company, a Delaware corporation
("Refining"), Valero Energy Coropration, a Delaware corporation
("VEC"), Valero Refining and Marketing Company, a Delaware
corporation ("VRMC"), Bankers Trust Company ("BTCo"),
individually and as Agent, Bank of Montreal ("BMO"), individually
and as Co Agent, and the other banks signatory hereto. All
capitalized terms used herein and not otherwise defined herein
shall have the same meanings herein as in the "Existing Credit
Agreement" (as defined below), as amended hereby.
Preliminary Statements
(1) Pursuant to the Amended and Restated Credit
Agreement dated as of December 4, 1992 among Refining, VEC, VRMC,
BTCo, individually and as Agent and BMO, individually and as Co
Agent, and the other banks signatory thereto (the "December 4,
1992 Credit Agreement"), the Banks have agreed to make loans to,
and BTCo has agreed to issue letters of credit for the account
of, Refining.
(2) The December 4, 1992 Credit Agreement was amended
by that certain First Amendment to Amended and Restated Credit
Agreement dated as of August 25, 1993 among the parties hereto
(the December 4, 1992 Credit Agreement as so amended, the
Existing Credit Agreement ).
(3) At the request of Refining, VEC and VRMC, the
parties hereto have agreed to amend the Existing Credit
Agreement, in the manner and upon the terms and conditions set
forth herein, in order to evidence, inter alia, the Banks'
agreement to amend certain definitions in the Existing Credit
Agreement and Section 8.01(a) thereof.
SECTION 1. Amendment to the Existing Credit Agreement.
(a) The definitions of "Consolidated Capital Funds"
and "Fixed Charge Ratio" set forth in Annex A of the Existing
Credit Agreement are hereby amended and restated to read as
follows:
"Consolidated Capital Funds" at any time shall mean the
sum of (i) Consolidated Net Worth of VEC, plus (ii) Consolidated
Total Indebtedness, plus (iii) to the extent not included in
Consolidated Total Indebtedness, the liquidation value of (a)
outstanding shares of any redeemable preferred stock, as shown on
the consolidated balance sheet of VEC and (b) outstanding shares
of any other preferred stock or preference stock issued or sold
after March 28, 1991, except to the extent included in
Consolidated Net Worth, plus (iv) that amount which is equal to
the noncash charge to the income of VEC and its consolidated
Subsidiaries, net of income taxes, for the fourth calendar
quarter of 1993 resulting from the write down of the value of
refining inventories determined on the "last-in, first-out"
("LIFO") method of inventory valuation, as said charge is
reflected in the income statement for VEC and its consolidated
Subsidiaries for the fiscal year ending December 31, 1993, not to
exceed, however, in any event, 50,000,000.
"Fixed Charge Ratio" shall mean, with respect to any
period, the ratio of: (a) the sum of (i) consolidated net income
(excluding extraordinary items and the excess of VEC s and its
Subsidiaries equity in the earnings of the Master Limited
Partnership over distributions but including distributions in
excess of VEC s and its Subsidiaries equity in the earnings of
the Master Limited Partnership) of VEC and its Subsidiaries for
such period, plus (ii) interest expense for VEC and its
Subsidiaries on a consolidated basis for such period, plus (iii)
deferred federal and state income taxes deducted in determining
such consolidated net income for such period, plus (iv)
Depreciation and Amortization Expense for such period, plus (v)
other noncash charges deducted in determining such consolidated
net income for such period (including, without limitation, that
amount which is equal to the noncash charge to the income of VEC
and its consolidated Subsidiaries for the fourth calendar quarter
of 1993 resulting from the write down of the value of refining
inventories determined on the last in, first out ( LIFO )
method of inventory valuation as reflected in the income
statement for VEC and its consolidated Subsidiaries for the
fiscal year ending December 31, 1993, it being expressly agreed
and understood that for purposes of this definition, the noncash
charge described in this parenthetical clause shall be determined
prior to income taxes; provided, however, that in any event,
such noncash charge described in this parenthetical clause shall
not exceed 50,000,000), minus (vi) other noncash credits added
in determining such consolidated net income for such period to
(b) the sum of (i) interest incurred for VEC and its Subsidiaries
on a consolidated basis for such period, plus (ii) cash dividends
paid by VEC on its preferred and preference stock during such
period (other than dividends paid on preferred and preference
stock held by VEC or a Subsidiary of VEC) plus (iii) cash
dividends paid by VEC on its common stock during such period
(other than dividends reinvested in newly issued or treasury
shares of common stock of VEC pursuant to any dividend
reinvestment plan maintained by VEC for holders of its common
stock), plus (iv) the amount of mandatory redemptions of
preferred stock made by VEC during such period (excluding
redemptions of shares of such preferred stock held by
Subsidiaries of VEC).
(b) Subsection (a) of Section 8.01, Restricted
Disbursements, of the Existing Credit Agreement is hereby amended
and restated to read as follows:
"SECTION 8.01 Restricted Disbursements. (a) VEC will
not, and will not permit any of its Subsidiaries to, directly or
indirectly, make any Restricted Disbursement if, after giving
effect thereto, as of the last day of any fiscal quarter of VEC
(each such day being a determination date ) the aggregate amount
of all Restricted Disbursements made by VEC and its Subsidiaries
subsequent to March 31, 1991, and on or prior to such
determination date, exceeds the sum of (i) the lesser of (A) the
aggregate amount of cash and Permitted Cash Investments reflected
on the consolidated balance sheet of VEC and its Subsidiaries as
of March 31, 1991 minus 5,000,000 or (B) 150,000,000, plus (ii)
the sum, determined without duplication, of (A) EBT, plus (B)
Depreciation and Amortization Expense for the cumulative period
commencing on April 1, 1991 and ending on such determination date
(which sum may be positive or negative, and may from time to time
increase or decrease, all as a function of the cumulative
operating income or loss of VEC and its Subsidiaries included in
the computation of EBT for such cumulative period), plus (C) that
amount which is equal to the noncash charge to the income of VEC
and its consolidated Subsidiaries for the fourth calendar quarter
of 1993 resulting from the write down of the value of refining
inventories determined on the "last in, first out" ("IFO") method
of inventory valuation, as said charge is reflected in the income
statement for VEC and its consolidated Subsidiaries for the
fiscal year ending December 31, 1993, not to exceed, however, in
any event, 50,000,000, plus (iii) an amount equal to net cash
proceeds received from the sale by VEC of its capital stock after
March 31, 1991, but on or prior to such determination date, plus
(iv) an amount equal to net cash proceeds received from the sale
or conversion of rights, options and warrants to purchase capital
stock of VEC after March 31, 1991, but on or prior to such
determination date, plus (v) an amount equal to net cash proceeds
received after March 31, 1991, but on or prior to such
determination date, from any issuance of Funded Indebtedness of
VEC pursuant to a commitment (other than under this Agreement or
the VEC Bank Agreement) entered into after March 31, 1991, but on
or prior to such determination date, minus (vi) all payments of
principal of Funded Indebtedness (other than payments that
constitute Restricted Disbursements and payments under this
Agreement or the VEC Bank Agreement) of VEC or its Subsidiaries
made after March 31, 1991, but on or prior to such determination
date, plus (vii) 50,000,000, plus (viii) the aggregate amount of
net cash proceeds received by VEC or any of its Subsidiaries
subsequent to September 1, 1993 but on or prior to such
determination date from Transfers of assets permitted by Section
8.09(b) or by Section 8.09(d).
SECTION 2. Affirmation of Liens and Guaranties. (a)
VRMC hereby acknowledges and agrees that all Liens arising under
the Credit Documents against the properties and assets of VRMC
shall remain in full force and effect following the execution and
delivery of this Amendment, and such Liens are hereby affirmed,
ratified and confirmed by VRMC.
(b) Each of VEC and VRMC hereby acknowledges and
agrees that all of its obligations under the Existing Credit
Agreement, as amended hereby (including, without limitation, its
obligation as a guarantor of the Guaranteed Obligations under
Article XII of the Existing Credit Agreement), and the other
Credit Documents shall remain in full force and effect following
the execution and delivery of this Amendment, and such
obligations are hereby affirmed, ratified and confirmed by each
of VEC and VRMC.
SECTION 3. Representations and Warranties. Each of
Refining, VEC, and VRMC represents and warrants that, after
giving effect to the execution and delivery of this Amendment, as
of the date hereof:
(a) the representations and warranties set forth in
the Existing Credit Agreement, as amended hereby, are true and
correct as though made on and as of the date hereof.
(b) no Default or Event of Default has occurred and is
continuing;
(c) the execution, delivery, and performance of this
Amendment by each of VEC, VRMC, and Refining (i) are within the
corporate powers of each such Person, (ii) have been duly
authorized by all necessary corporate action on the part of each
such Person, (iii) do not violate or create a default under any
provision of applicable law, or the certificate of incorporation
or bylaws of any of VEC, VRMC, or Refining, or any contractual
provision binding on or affecting any such Person or the property
of any such Person and (iv) do not contravene any judgment,
injunction, order or decree or other instrument binding upon any
such Person or result in the creation or imposition of any Lien
on any asset of any such Person or any of its Subsidiaries; and
(d) no authorization or approval or other action by,
and no notice to or filing or registration with, any governmental
authority or regulatory body or any other Person is required in
connection with the execution, delivery, and performance of this
Amendment by any of VEC, VRMC, and Refining.
SECTION 4. Conditions of Effectiveness. The
provisions of Section 1 of this Amendment shall become effective
when, and only when, the Agent shall have received the following,
with sufficient copies of the documents referred to in (a)
through (c) for the Co Agent and the Banks:
(a) Counterparts of this Amendment executed by the
Banks, the Agent, the Co Agent, VEC, VRMC, and Refining.
(b) A certificate dated as of the date of the
effective date of this Amendment, in form and substance
satisfactory to the Agent and the Co Agent, of the secretary or
an assistant secretary of each of VEC, VRMC, and Refining
certifying, inter alia, (i) true and correct copies of
resolutions adopted by the Board of Directors of such Person (or
a duly authorized committee thereof) (A) authorizing the
execution, delivery and performance by such Person of this
Amendment, (B) approving the form of this Amendment and (C)
authorizing officers of such Person to execute and deliver this
Amendment, all in form and substance satisfactory to the Agent
and the Co Agent, and (ii) the incumbency, and specimen
signatures, of the officers of such Person executing this
Amendment or any other documents on its behalf.
(c) A favorable, signed opinion addressed to the
Agent, the Co Agent and the Banks from the General Counsel of
VEC, in form and substance satisfactory to the Agent, the Co
Agent and the Banks.
(d) A favorable, signed opinion addressed to the
Agent, the Co-Agent and the Banks from Andrews & Kurth L.L.P. in
form and substance satisfactory to the Agent, the Co-Agent and
the Banks in respect of, inter alia, the enforceability of this
Amendment under New York law.
SECTION 5. References to the Credit Agreement, Etc.
Upon the execution and delivery of this Amendment by each of the
parties hereto, each reference (a) in the Existing Credit
Agreement to "this Agreement," "hereunder," "herein" or words of
like import shall mean and be a reference to the Existing Credit
Agreement, as amended hereby, (b) in the Notes and the other
Credit Documents to the Existing Credit Agreement shall mean and
be a reference to the Existing Credit Agreement, as amended
hereby, and (c) in the Credit Documents to any term defined by
reference to the Existing Credit Agreement shall mean and be a
reference to such term as defined in the Existing Credit
Agreement, as amended hereby.
SECTION 6. Successors and Assigns. This Amendment
shall be binding upon, and inure to the benefit of, the parties
hereto and their respective successors and assigns.
SECTION 7. Execution in Counterparts. This
Amendment may be executed in any number of counterparts and by
different parties hereto in separate counterparts, each of which
when so executed and delivered shall be deemed to be an original
and all of which taken together shall constitute but one and the
same instrument.
SECTION 8. Headings. Section headings in this
Amendment are included herein for convenience of reference only
and shall not constitute a part of this Amendment for any other
purpose.
SECTION 9. GOVERNING LAW. THIS AMENDMENT AND THE
RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE
CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAWS OF THE
STATE OF NEW YORK WITHOUT GIVING EFFECT TO THE CONFLICT OF LAW
PRINCIPLES THEREOF.
SECTION 10. FINAL AGREEMENT OF THE PARTIES. THE
EXISTING CREDIT AGREEMENT (INCLUDING THE EXHIBITS THERETO), AS
AMENDED BY THIS AMENDMENT, THE NOTES AND THE OTHER CREDIT
DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND
MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL
AGREEMENTS BETWEEN THE PARTIES.
SECTION 11. Indemnification. Each Credit Party agrees
to jointly and severally indemnify, defend and hold harmless the
Agent, the Collateral Agent, the Co-Agent and the Banks, and each
Affiliate thereof and their respective directors, officers,
shareholders, employees, agents and successors from and against,
any and all losses, costs, liabilities, expenses, judgments,
claims or damages arising out of the assertion against any of
them as a result of their being a party to the Agreement or any
transaction contemplated thereby or the exercise of any rights or
remedies under the Credit Documents, including, without
limitation, the amounts of any fines, penalties, attorneys fees,
response costs and natural resource damages arising out of, or in
connection with, or resulting from any (i) actual or proposed use
by any Credit Party of the proceeds of any extension of credit
(including the Loans and Letters of Credit of any Bank), (ii)
breach by any Credit Party of the Agreement or any other Credit
Document, (iii) violation by any Credit Party or any of its
Subsidiaries or Affiliates of any law, rule, regulation or order
including, but not limited to, Environmental Laws, (iv)
transportation, treatment, recycling, storage, disposal, Release
or threatened Release of any Hazardous Material by, at, or onto
any facility owned or operated by another party, which Hazardous
Material has been used or generated by any Credit Party or any of
its Subsidiaries or which is present at or on any of their
properties, (v) Release or threatened Release of any Hazardous
Material by a Credit Party or any of its Subsidiaries, or the
presence on or under, or Release or threatened Release from, any
of their properties, into or upon the land, atmosphere,
watercourse, body of surface or subsurface water or wetland,
arising from the installation, use, generation, manufacture,
treatment, handling, production, processing, storage, removal,
remediation, cleanup, or disposal of any Hazardous Material,
including, without limitation, any liability arising under or in
connection with CERCLA and similar Environmental Laws, (vi) claim
by any third party based upon the exposure of any person or
property to any Hazardous Material generated, used, or Released
by any Credit Party or any of its Subsidiaries, (vii) Liens or
security interests granted on any real or personal property
pursuant to or under Security Documents, to the extent resulting
from any Hazardous Materials located in, or under any property
owned, leased or operated by any Credit Party or any Subsidiary
or Affiliate of any Credit Party, (viii) ownership by the Banks
of any real or personal property following foreclosure under the
Security Documents, to the extent losses, costs, liabilities,
claims or damages arise out of or result from any Hazardous
Materials located in, on or under such property owned, leased or
operated by any Credit Party or any Subsidiary or Affiliate of
any Credit Party, including, without limitation, losses, costs,
liabilities, claims or damages which are imposed under
Environmental Laws upon Persons by virtue of their ownership,
(ix) circumstance in which the Agent, the Co-Agent or a Bank is
deemed an owner or operator of any such real or personal property
in circumstances in which neither the Agent, the Co-Agent, the
Collateral Agent nor any of the Banks is generally operating or
generally exercising control over the property of the Credit
Party or its Subsidiaries, to the extent such losses,
liabilities, claims or damages arise out of or result from any
Hazardous Materials located in, on or under such property or (x)
investigation, litigation or other proceeding (including any
threatened investigation or proceeding) relating to any of the
foregoing, and each Credit Party shall reimburse the Agent, the
Co-Agent, the Collateral Agent, and each Bank, and each Affiliate
thereof and their respective directors, officers, employees and
agents upon demand for any losses, costs or expenses (including
legal fees) incurred in connection with any investigation or
proceeding; but excluding any such losses, costs, liabilities,
claims, damages or expenses incurred by a Person or any Affiliate
thereof or their respective directors, officers, employees or
agents by reason of the gross negligence or willful misconduct of
such Person, Affiliate, director, officer, employee or agent.
WITHOUT LIMITING ANY PROVISION OF THIS AGREEMENT OR THE OTHER
CREDIT DOCUMENTS, IT IS THE EXPRESS INTENTION OF THE PARTIES THAT
THE AGENT, THE CO-AGENT, THE COLLATERAL AGENT, EACH BANK AND
THEIR RESPECTIVE AFFILIATES, DIRECTORS, OFFICERS, EMPLOYEES AND
AGENTS SHALL BE INDEMNIFIED AND HELD HARMLESS AGAINST ALL SUCH
LOSSES, LIABILITIES, CLAIMS AND DAMAGES ARISING OUT OF OR
RESULTING FROM THE ORDINARY NEGLIGENCE (WHETHER SOLE OR
CONTRIBUTORY) OF SUCH PERSON.
In Witness Whereof, the parties hereto have caused this
Amendment to be executed as of the date first stated herein by
their respective officers thereunto duly authorized.
VALERO REFINING COMPANY
By: /s/ JOHN D. GIBBONS
Name: John D. Gibbons
Title: Treasurer
VALERO REFINING AND
MARKETING COMPANY
By: /s/ JOHN D. GIBBONS
Name: John D. Gibbons
Title: Treasurer
VALERO ENERGY CORPORATION
By: /s/ JOHN D. GIBBONS
Name: John D. Gibbons
Title: Treasurer
BANKERS TRUST COMPANY,
Individually and as Agent
By: /s/ MARY ZADROGA
Name: Mary Zadroga
Title: Vice President
BANK OF MONTREAL,
Individually and as Co Agent
By: /s/ JULIA BUTHMAN
Name: Julia Buthman
Title: Director
ABN AMRO BANK N. V., HOUSTON
AGENCY
By: /s/ MICHAEL N. OAKES
Name: Michael N. Oakes
Title: Vice President
By: /s/ C. W. RANDALL
Name: C. W. Randall
Title: Group Vice President
BANQUE NATIONALE de PARIS
HOUSTON AGENCY
By: /s/ MICHAEL W. MCKEE
Name: Michael W. McKee
Title: Vice President
BERLINER HANDELS UND
FRANKFURTER BANK
By: /s/ PAUL TRAVERS
Name: Paul Travers
Title: Vice President
By: /s/ ELLEN DOOLEY
Name: Ellen Dooley
Title: Vice President
CANADIAN IMPERIAL BANK
OF COMMERCE
By: /s/ J. D. WESTLAND
Name: J. D. Westland
Title: Authorized Signatory
CHRISTIANIA BANK
By: /s/ DEBRA DICKEHUTH
Name: Debra Dickehuth
Title: Vice President
By: /s/ PETER M. DODGE
Name: Peter M. Dodge
Title: Vice President
CORPUS CHRISTI NATIONAL BANK
By: /s/ TOM W. SHIRLEY
Name: Tom W. Shirley
Title: Senior Vice President
CREDIT LYONNAIS
NEW YORK BRANCH
By: /s/ XAVIER RATOUIS
Name: Xavier Ratouis
Title: Senior Vice President
CREDIT LYONNAIS
CAYMAN ISLAND BRANCH
By: /s/ XAVIER RATOUIS
Name: Xavier Ratouis
Title: Senior Vice President
THE FIRST NATIONAL BANK OF
BOSTON
By: /s/ RICHARD A. LOW
Name: Richard A. Low
Title: Division Executive
THE FROST NATIONAL BANK OF
SAN ANTONIO
By: /s/ PHIL DUDLEY
Name: Phil Dudley
Title: Vice President
THE TORONTO DOMINION BANK
By: /s/ F. B. HAWLEY
Name: F. B. Hawley
Title: Mgr. Cr. Admin.
<TABLE>
EXHIBIT 11
VALERO ENERGY CORPORATION AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER SHARE
(Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
Year Ending December 31,
1993 1992 1991
<S> <C> <C> <C>
COMPUTATION OF EARNINGS PER SHARE
ASSUMING NO DILUTION:
Net income. . . . . . . . . . . . . . . . . . . . . $ 36,424 $ 83,919 $ 98,667
Less: Preferred stock dividend requirements. . . . (1,262) (1,475) (6,044)
Net income applicable to common stock . . . . . . . $ 35,162 $ 82,444 $ 92,623
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . . . . 43,098,808 42,577,368 40,570,798
Earnings per share assuming no dilution . . . . . . $ .82 $ 1.94 $ 2.28
COMPUTATION OF EARNINGS PER SHARE
ASSUMING FULL DILUTION:
Net income. . . . . . . . . . . . . . . . . . . . $ 36,424 $ 83,919 $ 98,667
Less: Preferred stock dividend requirements. . . (1,262) (1,475) (6,044)
Net income applicable to common stock
assuming full dilution. . . . . . . . . . . . . $ 35,162 $ 82,444 $ 92,623
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . . . 43,098,808 42,577,368 40,570,798
Weighted average common stock equivalents
applicable to stock options . . . . . . . . . . 67,017 144,469 205,561
Weighted average shares used for computation. . . 43,165,825 42,721,837 40,776,359
Earnings per share assuming full dilution (a) . . $ .81 $ 1.93 $ 2.27
<FN>
(a) This calculation is submitted in accordance with paragraph
601(b)(11) of Regulation S-K although it is not required by
APB Opinion No. 15 because it results in dilution of less
than 3%.
</TABLE>
EXHIBIT 21.1
SCHEDULE OF SUBSIDIARIES OF
VALERO ENERGY CORPORATION
As of December 31, 1993
Jurisdiction of
Name Incorporation
Valero Coal Company Delaware
Valero Javelina Company Delaware
Valero Management Company Delaware
VMGA Company Texas
Valero Eastex Pipeline Company Delaware
Valero Interstate Transmission Company Delaware
Valero Merger Partnership, L.P. Delaware
Valero Northern Texas Company Delaware
Valero Natural Gas Company Delaware
Mesquite Services Company Delaware
Reata Industrial Gas Company Delaware
Rio Pipeline Company Delaware
Val Gas Company Delaware
V.H.C. Pipeline Company Delaware
VLDC Company Delaware
Valero Gas Marketing Company Delaware
Valero Gas Storage Company Delaware
Valero Gathering Company Delaware
Valero Hydrocarbons Company Delaware
VH Company Delaware
Valero Industrial Gas Company Delaware
Valero Marketing Company Delaware
VM Company Delaware
Valero Storage Company Delaware
Valero Transmission Company Delaware
VT Company Delaware
Valero NGL Investments Company Delaware
Valero South Texas Gathering Company Delaware
Valero South Texas Marketing Company Delaware
Valero South Texas Processing Company Delaware
Valero Producing Company Delaware
Valero Realty Company Delaware
Valero Refining and Marketing Company Delaware
Valero Refining Company Delaware
Valero MTBE Investments Company Delaware
Valero MTBE Operating Company Delaware
Valero Mediterranean Company Delaware
Valero Mexico Company Delaware
Valero Technical Services Company Delaware
*Valero Natural Gas Partners, L.P. Delaware
*Valero Management Partnership, L.P. Delaware
*Reata Industrial Gas, L.P. Delaware
*Rio Pipeline, L.P. Delaware
*Rivercity Gas, L.P. Delaware
*Val Gas, L.P. Delaware
*Valero Gas Marketing, L.P. Delaware
*V.H.C. Pipeline, L.P. Delaware
*VLDC, L.P. Delaware
*Valero Gathering, L.P. Delaware
*Valero Hydrocarbons, L.P. Delaware
*Valero Industrial Gas, L.P. Delaware
*Valero Marketing, L.P. Delaware
*Valero Texas Pipeline, L.P. Delaware
*West Texas Transmission, L.P. Delaware
*Valero Transmission, L.P. Delaware
*Bay Pipeline, Inc. Texas
__________________
* Valero Natural Gas Company ("VNGC") owns a 1% general partner
interest, and various subsidiaries of Valero Energy
Corporation ("VEC") hold an approximate 47% limited partner
interest, in Valero Natural Gas Partners, L.P. ("VNGP, LP").
VNGC owns a 1% general partner interest and VNGP, LP owns a
99% limited partner interest in Valero Management Partnership,
L.P. ("Management Partnership"). Management Partnership owns a
99% limited partner interest, and various subsidiaries of VNGC
own a 1% general partner interest, in Reata Industrial Gas,
L.P.; Rio Pipeline, L.P.; Rivercity Gas, L.P.; Val Gas, L.P.;
Valero Gas Marketing, L.P.; V.H.C. Pipeline, L.P.; VLDC, L.P.;
Valero Gathering, L.P.; Valero Hydrocarbons, L.P.; Valero
Industrial Gas, L.P.; Valero Marketing, L.P. and Valero
Transmission, L.P. VNGP, LP owns a 99% limited partner
interest, and a subsidiary of VEC owns a 1% general partner
interest, in West Texas Transmission, L.P. and Valero Texas
Pipeline, L.P. VNGP, LP owns all of the outstanding capital
stock of Bay Pipeline, Inc.
(EXHIBIT 23.1)
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our reports included in this Form 10-K into the
Company's previously filed Registration Statements on Form S-8
(File No. 2-66297, 2-82001, 2-97043, 33-23103, 33-14455, 33-38405
and 33-53796) and on Form S-3 (File No. 33-45457).
ARTHUR ANDERSEN & CO.
San Antonio, Texas
March 1, 1994
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 first quarter of
1993.
NATURAL GAS OPERATIONS
General
The Partnership owns and operates natural gas pipeline
systems principally serving Texas intrastate markets. Through
interconnections with interstate pipelines, the Partnership also
markets natural gas throughout the United States. The
Partnership's natural gas pipeline and marketing operations
consist principally of purchasing, gathering, transporting and
selling natural gas to gas distribution companies, electric
utilities, other pipeline companies and industrial customers, and
transporting natural gas for producers, other pipelines and end
users.
Pipeline Facilities
The Partnership's principal natural gas pipeline system
is the intrastate gas system ("Transmission System") operated by
Valero Transmission, L.P. ("Transmission") in the State of Texas.
(References to Transmission prior to March 25, 1987 refer to
Valero Transmission Company, a wholly owned subsidiary of VNGC,
as the previous owner of the Transmission System. References to
Transmission on or after March 25, 1987 refer to Valero
Transmission, L.P., a Subsidiary Operating Partnership, as
successor owner of the Transmission System.) The Transmission
System generally consists of large diameter transmission lines
which receive gas at central gathering points and move the gas to
delivery points. The Transmission System also includes numerous
small diameter lines connecting individual wells and common
receiving points to the Transmission System's larger diameter
lines.
The Partnership's wholly owned, jointly owned and leased
natural gas pipeline systems include approximately 7,200 miles of
mainlines, lateral lines and gathering lines. These pipeline
systems are located along the Texas Gulf Coast and throughout
South Texas and extend westerly to near Pecos, Texas; northerly
to near the Dallas-Fort Worth area, easterly to Carthage, Texas,
near the Louisiana border and southerly into Mexico near Reynosa.
The Partnership operates and jointly owns in equal portions with
Texas Utilities Fuel Company ("TUFCO") a 395-mile pipeline
extending from Waha, near Fort Stockton, Texas, to near Ennis,
Texas, south of the Dallas-Fort Worth area. An addition to this
line also extends 58 miles into East Texas from Ennis to Bethel,
Texas, and is jointly owned 39% by TUFCO (which operates the
line), 39% by Lone Star Gas Company and 22% by the Partnership.
The Partnership also operates and jointly owns in equal portions
with TECO Pipeline Company a 340-mile pipeline system and related
facilities extending from Waha to New Braunfels, near
San Antonio, Texas. The Partnership owns a 3.5-mile, 24-inch
pipeline that connects the Partnership's pipeline near Penitas in
South Texas to Petroleos Mexicanos's ("PEMEX") 42-inch pipeline
outside Reynosa, Mexico. The Partnership leases and operates
several pipelines, including approximately 240 miles of 24-inch
pipeline leased from TUFCO that extends from near Dallas to near
Houston, and approximately 105 miles of pipeline leased from
Energy that extends the Partnership's North Texas pipeline
further into East Texas from Bethel to Carthage (the "East Texas
pipeline"). These integrated systems include 39 mainline
compressor stations with a total of approximately
162,000 horsepower, together with gas processing plants,
dehydration and gas treating plants and numerous measuring and
regulating stations. The Partnership's pipeline systems have
considerable flexibility in providing connections between many
producing and consuming areas. The Partnership's owned and
leased pipeline systems have 70 interconnects with 22 intrastate
pipelines and 38 interconnects with 12 interstate pipelines.
The Partnership's pipeline systems are able to handle
widely varying loads caused by changing supply and demand
patterns. Annual average throughput was approximately 2.5 Bcf
(1) per day in 1993, and has been in excess of 2 Bcf per day in
recent years. The system has served peak demands at hourly rates
of flow significantly in excess of these daily averages.
Although capacity in the Partnership's pipeline systems is
generally expected to be adequate for the foreseeable future,
seasonal factors can significantly influence gas sales and
transportation volumes.
[FN]
(1) All volumes of natural gas referred to herein are stated at a
pressure base of 14.65 pounds per square inch absolute and at 60
degrees Fahrenheit and in most instances are rounded to the
nearest major multiple. The term "Mcf" means thousand cubic
feet, the term "MMcf" means million cubic feet and the term "Bcf"
means billion cubic feet. The term "Btu" means British Thermal
Unit, a standard measure of heating value. The term "MMBtu's"
means million Btu's. The number of MMBtu's of total natural gas
deliveries is approximately equal to the number of Mcf's of such
deliveries.
Gas Sales
The Partnership's gas sales are made principally through
the Subsidiary Operating Partnerships which operate special
marketing programs ("SMPs"). The Subsidiary Operating
Partnerships operating the SMPs are Reata Industrial Gas, L.P.
("Reata"), Valero Industrial Gas, L.P. ("Vigas") and VLDC, L.P.
("VLDC"). Reata buys its gas supply from producers, marketers
and certain intrastate pipelines and resells the gas in the
intrastate market on both a long-term basis and a short-term
interruptible basis. Vigas acquires gas supply directly from gas
producers and sells the gas on a short-term interruptible basis
and a term basis to intrastate and interstate markets. VLDC
serves short-term intrastate sales markets with supplies of both
intrastate and interstate gas. In addition, some of the
Partnership's gas sales are made by Valero Gas Marketing, L.P.
("Valero Gas Marketing"), Val Gas, L.P. ("Val Gas") and Rivercity
Gas, L.P. ("Rivercity"). Valero Gas Marketing engages primarily
in off-system sales. Val Gas primarily purchases and resells
natural gas in interstate commerce. Rivercity sells gas on a
short-term, interruptible basis. Most of the gas sold by Reata,
Vigas, VLDC, Val Gas and Rivercity is transported through the
Transmission System by Transmission. Transmission sells natural
gas under long-term contracts to a few remaining intrastate
customers. However, because of various factors described below,
most of the industrial and other gas sales customers previously
served by Transmission, including local distribution companies
("LDCs") and electric utilities, now purchase gas in the spot
market, including purchases from the Subsidiary Operating
Partnerships operating the SMPs, or have entered into gas
transportation contracts with Transmission to transport gas
acquired by the customers directly from producers or other
suppliers. Accordingly, Transmission is primarily a transporter
rather than a seller of natural gas. See "Natural Gas
Operations - Gas Transportation and Exchange" below.
During 1993, the Partnership sold natural gas under
hundreds of separate short-term and long-term gas sales contracts
to numerous customers in both the intrastate and interstate
markets. The Partnership's gas sales are made primarily to gas
distribution companies, electric utilities, other pipeline
companies and industrial users. The gas sold to distribution
companies is resold to consumers in a number of cities including
San Antonio, Dallas, Austin, Corpus Christi and Chicago.
Although the expiration dates of the Partnership's gas sales
contracts range from 1994 to 2001, many of the Partnership's
short-term sales contracts have expired or will expire by their
terms in 1994 or are terminable on a day-to-day, month-to-month
or similar basis by either the Partnership or the party to whom
gas is sold. The General Partner anticipates that most of these
contracts will be renewed for an additional term or converted to
transportation arrangements, or that the gas sold under these
contracts will be marketed to other customers.
The Partnership's gas sales and transportation volumes
(in MMcf per day) for the three years ended December 31, 1993,
are as follows:
<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.
