FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X]
For the fiscal year ended December 31, 1995
OR
[ ]
For the transition period from to
Commission file number 1-4718
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1244795
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
530 McCullough Avenue 78215
San Antonio, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (210) 246-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, $1 Par Value New York Stock Exchange
$3.125 Convertible Preferred Stock New York Stock Exchange
Preference Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE.
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value on February 1, 1996, of the
registrant's Common Stock, $1.00 par value ("Common Stock"), held
by nonaffiliates of the registrant, based on the average of the
high and low prices as quoted in the New York Stock Exchange
Composite Transactions listing for that date, was approximately
$1 billion. As of February 1, 1996, 43,745,961 shares of the
registrant's Common Stock were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
The Company intends to file with the Securities and Exchange
Commission (the "Commission") in March 1996 a definitive Proxy
Statement (the "1996 Proxy Statement") for the Company's Annual
Meeting of Stockholders scheduled for April 30, 1996, at which
directors of the Company will be elected. Portions of the 1996
Proxy Statement are incorporated by reference in Part III of this
Form 10-K and shall be deemed to be a part hereof.
CROSS-REFERENCE SHEET
The following table indicates the headings in the 1996 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 1996 Proxy Statement
10. "Directors and Executive Officers of the
Registrant". . . . . . . . . . . . . . . . . "Item No. 1 - Election of Directors," and
"Information Concerning Nominees and Other
Directors" and "Section 16(a) Compliance"
11. "Executive Compensation" . . . . . . . . . . . "Executive Compensation," "Stock Option Grants and
Related Information," "Retirement Benefits,"
"Arrangements with Certain Officers and Directors"
and "Executive Severance Program"
12. "Security Ownership of Certain Beneficial
Owners and Management" . . . . . . . . . . . "Beneficial Ownership of Valero 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.
CONTENTS
PAGE
Cross Reference Sheet. . . . . . . . . . . . . . ii
PART I
Item 1. Business. . . . .. . . . . . . . . . . . . . . .
Refining and Marketing . . . . . . . . . . . . .
Refining Operations . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . .
Feedstock Supply. . . . . . . . . . . . . . .
Factors Affecting Operating Results . . . . .
Proesa MTBE Plant . . . . . . . . . . . . . .
Natural Gas. . . . . . . . . . . . . . . . . . .
Transmission System . . . . . . . . . . . . .
Gas Sales and Marketing . . . . . . . . . . .
Gas Transportation. . . . . . . . . . . . . .
Gas Supply and Storage. . . . . . . . . . . .
Natural Gas Liquids. . . . . . . . . . . . . . .
Governmental Regulations . . . . . . . . . . . .
Federal Regulation. . . . . . . . . . . . . .
Texas Regulation. . . . . . . . . . . . . . .
Competition. . . . . . . . . . . . . . . . . . .
Refining and Marketing. . . . . . . . . . . .
Natural Gas . . . . . . . . . . . . . . . . .
Natural Gas Liquids . . . . . . . . . . . . .
Environmental Matters. . . . . . . . . . . . . .
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 . . . . . . . . . . . . . .
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 . . . . . . . . . . .
PART I
ITEM 1. BUSINESS
Valero Energy Corporation was incorporated in Delaware in
1955 and became a publicly held corporation in 1979. Its
principal executive offices are located at 530 McCullough Avenue,
San Antonio, Texas 78215. Unless otherwise required by the
context, the term "Energy" as used herein refers to Valero Energy
Corporation, and the term "Company" refers to Energy and its
consolidated subsidiaries. The Company is a diversified energy
company engaged in the production, transportation and marketing
of environmentally clean fuels and products. The Company's three
core businesses are specialized refining, natural gas and natural
gas liquids ("NGL"). The Company owns a specialized petroleum
refinery in Corpus Christi, Texas (the "Refinery"), and refines
high-sulfur atmospheric residual oil into premium products,
primarily reformulated gasoline ("RFG"), and markets those
refined products. See "Refining and Marketing." The Company
also has a network of approximately 8,000 miles of natural gas
transmission and gathering lines throughout Texas. The Company
purchases natural gas for resale to distribution companies,
electric utilities, other pipelines and industrial customers
throughout North America, and provides gas transportation
services to third parties. See "Natural Gas." The Company also
owns eight natural gas processing plants and is a major producer
and marketer of NGLs. See "Natural Gas Liquids."
For financial and statistical information regarding the
Company's operations, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and Note 10 of
Notes to Consolidated Financial Statements. For a discussion of
cash flows provided by and used in the Company's operations, see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources."
REFINING AND MARKETING
Refining Operations
The Refinery processes primarily high-sulfur atmospheric
tower bottoms, a type of residual fuel oil ("resid"), into a
product slate of higher value products, principally RFG and
middle distillates. The Refinery also processes crude oil,
butanes and other feedstocks. The Refinery can produce
approximately 170,000 barrels per day of refined products, with
gasoline and gasoline blendstocks comprising approximately 85% of
the Refinery's throughput, and middle distillates comprising the
remainder. The Refinery can produce all of its gasoline as RFG
and all of its diesel fuel as low-sulfur diesel. The Refinery
has substantial flexibility to vary its mix of gasoline products
to meet changing market conditions. For additional information
regarding refining and marketing operating results for the three
years ended December 31, 1995, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
The Refinery's principal operating units include its
hydrodesulfurization unit ("HDS Unit") and the heavy oil cracking
complex ("HOC"). The HDS Unit removes sulfur and metals from
resid to improve resid's subsequent cracking characteristics.
The HDS Unit has a capacity of approximately 70,000 barrels per
day. The HOC processes feedstock primarily from the HDS Unit,
and has a capacity of approximately 74,000 barrels per day. The
Refinery's other significant units include a 36,000 barrel-per-
day "Hydrocracker" (which produces reformer feed naphtha from the
Refinery's gas oil and distillate streams), a 35,600 barrel-per-
day continuous catalyst regeneration "Reformer" (which produces
reformate, a low vapor pressure high-octane gasoline blendstock,
from the Refinery's naphtha streams), a 31,000 barrel-per-day
reformate splitter (which separates a benzene concentrate stream
from reformate produced at the Reformer), a 30,000 barrel-per-day
crude unit, and a 24,000 barrel-per-day vacuum unit.
Also located at the Refinery is the Company's MTBE Plant
(the "MTBE Plant"). The MTBE Plant can produce 15,500 barrels
per day of methyl tertiary butyl ether ("MTBE") from butane and
methanol feedstocks. MTBE is an oxygen-rich, high-octane
gasoline blendstock produced by reacting methanol and
isobutylene, and is used to manufacture oxygenated and
reformulated gasolines. The Company can blend the MTBE produced
at the Refinery into the Company's own gasoline production or
sell the MTBE separately. The "MTBE/TAME Unit" converts streams
produced by the HOC 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 an oxygen-rich, high-octane gasoline
blendstock. The MTBE Plant and MTBE/TAME Unit enable the Company
to produce approximately 21,000 barrels per day of total
oxygenates.
All of the methanol feedstocks presently required for the
production of oxygenates at the Refinery are provided by a
methanol plant in Clear Lake, Texas owned by a joint venture
between the Company and Hoechst Celanese Chemical Group, Inc.
(the "Methanol Plant"). The Methanol Plant, placed in service in
late August 1995, can produce approximately 13,000 barrels per
day of methanol, and provides the MTBE Plant with methanol
feedstocks at production costs below recent methanol market
prices.
Through a wholly owned subsidiary, the Company is a 20%
general partner in Javelina Company ("Javelina"), which owns a
plant in Corpus Christi (the "Javelina Plant") that processes
waste gases from the Refinery and other refineries in the Corpus
Christi area, and extracts hydrogen, ethylene, propylene and NGLs
from the gas stream. The Company's capital investment in
Javelina was approximately $20.2 million as of December 31, 1995.
Javelina maintains a term loan agreement and a working capital
and letter of credit facility that mature on January 31, 1999.
The Company's guarantees of these bank credit agreements were
approximately $8.9 million at December 31, 1995.
The Company also has a marine vapor recovery unit at the
Refinery. The unit enhances air quality by capturing and
recycling vapors that are displaced when gasoline is loaded onto
ships and barges. The retrieved vapors are condensed and blended
back into gasoline. Approximately two gallons of gasoline are
recovered for every 1,000 gallons loaded onto ship or barge. The
Company also operates an environmentally friendly bio-slurry
reactor process at the Refinery which uses microorganisms to
biodegrade and treat solid waste. In 1995, the Company received
the Texas Governor's Award for environmental excellence as well
as the National Petroleum Refiners Association award for
environmental achievements.
In 1995, the Company completed turnarounds on its HDS Unit,
Hydrocracker and Reformer, and performed scheduled maintenance
repairs on the HOC. Improvements made during these downtimes and
during the HOC turnaround in late 1994 enabled the Company to
increase the capacity of the HDS Unit and the HOC by
approximately 5,000 barrels per day. These expansions and other
debottlenecking and upgrading projects completed in 1995 enhanced
the Company's efficiency in converting high-sulfur resid and gas
oils into higher valued gasoline products. The Refinery's other
principal refining units operated during 1995 without significant
unscheduled downtime. The HDS Unit is scheduled for maintenance
and a catalyst change in the third quarter of 1996. This
maintenance and catalyst change is required about every
15 months.
The Company recently announced plans for two additional
expansion projects at the Refinery. In the first, the Company
will construct a facility to fractionate xylenes from the
Reformer's reformate stream. The fractionated xylene may then be
sold into the petrochemical feedstock market to be used as a
feedstock for paraxylene. This project is expected to be
completed near the end of 1996 at a cost of approximately
$27 million. The second project is the proposed expansion of the
MTBE Plant which will allow the Company to increase MTBE
production by approximately 1,500 barrels per day. This project
is expected to be completed in early 1997 at a cost of
approximately $14 million.
Sales
Set forth below is a summary of refining and marketing
throughput volumes per day, average throughput margin per barrel
and sales volumes per day for the three years ended December 31,
1995. Average throughput margin per barrel is computed by
subtracting total direct product cost of sales from product sales
revenues and dividing the result by throughput volumes.
Year Ended December 31,
1995 1994 1993
Throughput volumes (Mbbls per day) . . . . . 160 146 136
Average throughput margin per barrel . . . . $6.25 $5.36 $5.99 <F1>
Sales volumes (Mbbls per day). . . . . . . . 208 140 133
<FN>
<F1> 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. See
"Management's Discussion and Analysis of Financial Condition
and Results of Operations - Results of Operations - 1994
Compared to 1993."
</FN>
The Company sells refined products under term contracts as
well as on a spot and truck rack basis. A truck rack sale is a
sale to a customer that provides trucks to take delivery at
loading facilities. In 1995, term, spot and truck rack sales
volumes accounted for approximately 41%, 49% and 10%,
respectively, of total gasoline and distillate sales. Sales of
refined products under term contracts are made principally to
large oil companies. Spot sales of the Company's refined
products are made to large oil companies and gasoline
distributors. The principal purchasers of the Company's products
from truck racks have been wholesalers and jobbers in the eastern
and midwestern United States. The Company's products are
transported through common-carrier pipelines, barges and tankers.
Interconnects with common-carrier pipelines give the Company the
flexibility to sell products to the northeastern, midwestern or
southeastern United States.
The Company plans to continue to produce a high percentage
of its refined products as RFG and to focus significant marketing
efforts on the RFG and oxygenates markets. Approximately 50% of
the Company's 1996 expected RFG production is under contract to
supply major gasoline marketers in the Houston and Dallas/Fort
Worth areas at market-related prices; another 15% is under
contract to gasoline marketers in the northeast United States,
which is currently the largest RFG market in the United States.
The Company appointed an exclusive agent for a three-year term
for the wholesale truck rack marketing of the Company's refined
products in the Northeast through 1997. In addition, the
Company has entered into a two-year charter expiring in the fall
of 1997 for a tanker to transport RFG from the Refinery to the
Northeast.
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 end-products. Many overseas refineries, however, are less
sophisticated, process smaller portions of resid internally, and
therefore produce larger volumes of resid for sale. As a result,
the Company acquires and expects to acquire most of its resid in
international markets. These supplies are loaded aboard double-
hulled chartered vessels and are subject to the usual maritime
hazards. The Company maintains insurance on its feedstock
cargos.
Under a two-year feedstock supply agreement with the
Company renewed in late 1995, Arabian American Oil Company
("Aramco") agreed to provide an average of 36,000 barrels per day
of resid to the Company at market-based prices through 1997.
This contract is subject to price renegotiation at the end of the
first year, with offtake volumes being subject to a 50% reduction
if agreement is not reached. In late 1995, the Company also
entered into a separate one-year supply agreement with Aramco for
an additional 18,000 barrels per day of resid at market-based
prices. The Company's agreement for approximately 12,000 barrels
per day of South Korean resid at market-based prices was extended
in the first quarter of 1996 for an additional six months.
Deliveries under these agreements provide approximately 80% of
the Refinery's daily resid requirements. The Company believes
that if any of its existing feedstock arrangements were
interrupted or terminated, supplies of resid could be obtained
from other sources or on the open market; however, the Company
could be required to incur higher feedstock costs or substitute
other types of resid, thereby producing less favorable operating
results. Over the past few years, demand for the type of resid
feedstock now processed at the Refinery has increased in relation
to the availability of supply. See "Refining and Marketing -
Factors Affecting Operating Results." At the end of 1995, the
Company contracted for approximately 5,000 barrels per day of
domestic crude for use as a feedstock in the Refinery's crude
unit in 1996. The remainder of the Refinery's resid and crude
feedstocks are purchased at market-based prices under short-term
contracts.
All of the butane and methanol feedstocks required to
operate the MTBE Plant are available through the Company's
operations. The Company also supplies at least one-half of the
Methanol Plant's natural gas feedstock requirements.
The Company owns 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. The Company has approximately
850,000 barrels of fuel oil storage available under lease in
Malta, and leases refined product storage facilities in various
locations. Approximately 600,000 barrels of gasoline storage in
the Houston area became available to the Company in 1995 pursuant
to a seven-year terminaling agreement. See Note 13 of Notes to
Consolidated Financial Statements. The Company also owns dock
facilities at the Refinery that can unload simultaneously two
150,000 dead-weight ton capacity ships and can dock larger crude
carriers after partial unloading.
Factors Affecting Operating Results
The Company's refining and marketing operating results are
significantly affected by the relationship between refined
product prices and resid prices, which in turn are largely
determined by market forces. The crude oil and refined product
markets typically experience periods of extreme price volatility.
During such periods, disproportionate changes in the prices of
refined products and resid usually occur. The potential impact
of changing crude oil and refined product prices on the Company's
results of operations is further affected by the fact that the
Company generally buys its resid feedstock approximately 45 to
50 days prior to processing it in the Refinery. The Company uses
options and futures to hedge refinery feedstock purchases and
refined product inventories to reduce the impact of potential
adverse price changes on these inventories prior to conversion of
the feedstock into finished products and the ultimate sale of the
finished products. The Company also hedges anticipated
transactions including fuel gas purchases and components of
refining margins. See Note 5 of Notes to Consolidated Financial
Statements.
Because the Refinery is technically more sophisticated and
complex than many conventional refineries, and is designed
principally to process resid rather than crude oil, its operating
costs per barrel are necessarily higher than those of most
conventional refineries. But because resid usually sells at a
large enough discount to crude oil ("resid discount"), the
Company is generally able to recover its higher operating costs
and generate higher margins in its refining operations than
conventional refiners that use crude oil as the principal
feedstock. The price of resid is affected by the relationship
between the growth in the demand for fuel oil and other products
(which increases crude oil demand, thereby increasing the supply
of resid when more crude oil is processed) and worldwide
additions to resid conversion capacity (which has the effect of
reducing the available supply of resid). Recent press reports
indicate that Iraq may soon resume sales of crude oil into world
markets. While the export of heavier Iraqi crudes could lead to
increased resid production, such exports could also depress crude
oil prices which in turn could adversely affect inventory values
and lead to volatile changes in the resid discount and other
price relationships important to the Company's results of
operations.
The resid discount has narrowed considerably over the past
two years due to increased worldwide production of light "sweet"
crudes and the addition of new resid conversion capacity.
Several factors contributed to this narrowing of the resid
discount including a shift in Saudi Arabia's production to
lighter grades of crude instead of heavy "sour" types that yield
more resid, and decreased exports of resid from the former Soviet
Union. Refinery upgrades in recent years also have curtailed the
output of resid in favor of the production of lighter end-products
such as gasoline and diesel fuel. Industry publications
report that Aramco plans to begin operation of certain new resid
conversion units in 1998 at the Ras Tanura refining complex in
Saudi Arabia. As a result, the production of resid at Ras Tanura
for export would be significantly reduced. A majority of the
resid feedstock purchased by the Company from Aramco is produced
at Ras Tanura. Accordingly, a reduction in resid production at
Ras Tanura could adversely affect the price or availability of
resid feedstocks in the future. The Company expects resid to
continue to sell at a discount to crude oil, but is unable to
predict future relationships between the supply of and demand for
resid. Installation of additional refinery crude distillation
and upgrading facilities, price volatility, international
political developments and other factors beyond the control of
the Company are likely to continue to play an important role in
refining industry economics.
Two programs implemented by the Environmental Protection
Agency ("EPA") under the Clean Air Act Amendments of 1990 (the
"Clean Air Act") significantly affect the operations of the
Company and the markets in which the Company sells its refined
products: the oxygenated fuel program and the RFG program. The
oxygenated fuel program began in 1992, and requires for certain
winter months that the 39 areas designated nonattainment for
carbon monoxide use gasoline that contains a prescribed amount of
clean burning "oxygenates." Oxygenates are liquid hydrocarbon
compounds containing oxygen, which, when added to conventional
gasoline, reduce the carbon monoxide emissions of gasoline.
Oxygenated gasoline must have a minimum oxygen content of 2.7%
by weight. The EPA's RFG program, which began on January 1, 1995,
is required in the nine areas designated nonattainment for ozone.
In addition, approximately 43 of the 87 areas that have failed to
attain other ozone air-quality standards have also "opted in" to
the RFG program to decrease their emissions of hydrocarbons and toxic
pollutants. Use of RFG reduces ozone-forming compounds and total
air toxics such as carbon monoxide. The RFG program requires the
use of RFG on a year-round basis. RFG is manufactured by
substantially reducing the amount of aromatics and benzene from
regular gasoline and adding an oxygenate, primarily MTBE or
ethanol. The oxygen content of RFG must equal or exceed 2.0% by
weight. The California Air Resources Board ("CARB") is
scheduled to implement its "CARB 2" gasoline program
beginning March 1, 1996. The CARB 2 program is a state-wide,
year-round program requiring the use of gasoline which
meets more restrictive air quality specifications than the
federally mandated RFG but which may generally have a lesser
oxygen content.
Market uncertainties as a result of certain areas
"opting out" of the RFG program as well as continued debate
regarding the health effects of MTBE kept RFG and oxygenated
gasoline prices depressed in early 1995. However, low product
inventories, lower imports and an increase in gasoline demand
contributed to improving market conditions throughout the
remainder of the year. The market also responded favorably to a
report from the White House Office of Science and Technology
Policy to the EPA stating that no "evidence of hazards" was found
that would cause the office to recommend the cessation of the use
of MTBE. Hot weather during 1995 contributed to many areas in
the country exceeding their permitted ozone emission levels. The
Company expects that some of these areas may choose to "opt in"
to the RFG program to reduce emissions and thereby increase the
demand for RFG. California's CARB 2 program should also increase
the demand for oxygenated gasoline.
MTBE margins are affected by the price of methanol, an MTBE
feedstock, and the demand for RFG and oxygenated gasoline. MTBE
prices were depressed in early 1995 because of the market
uncertainties associated with certain areas "opting out" of the
RFG program. In addition, some areas announced their intent to
shorten the period for required oxygenated gasoline use during
the winter. Growing acceptance of RFG and the increased value of
MTBE as an octane component, however, helped to bolster MTBE
prices during the remainder of the year. The worldwide movement
to reduce lead in gasoline is expected to increase worldwide
demand for oxygenates to replace the octane provided by lead-
based compounds. Growing demand for RFG and CARB 2 gasoline in
the United States is also expected to sustain stronger MTBE
margins on average in 1996.
Proesa MTBE Plant
The Company currently owns a 35% interest in Productos
Ecologicos, S.A. de C.V., a Mexican corporation ("Proesa"), which
is involved in a project (the "Project") to design, construct and
operate a plant (the "Plant") in Mexico to produce MTBE. Proesa
is also owned 10% by Dragados y Construcciones, S.A., a Spanish
construction company ("Dragados"), and 55% by a corporation
formed by a subsidiary of Banamex, Mexico's largest bank
("Banamex"), and Infomin, S.A. de C.V., a privately owned Mexican
corporation ("Infomin"). The Company, Infomin, Banamex and
Dragados have entered into a letter of understanding under which
the interest of Banamex in Proesa would be acquired by the
Company and Infomin at Banamex's investment cost, plus accrued
interest, with the Company and Infomin each then owning a 45%
interest in Proesa. This arrangement was not formally documented
and is subject to successfully obtaining financing for Infomin's
interest in the Project. However, since August 1994, the Company
has funded 45% of the Project's costs. The Plant, to be
constructed at a site near the Bay of Campeche, has been
estimated to cost approximately $400 million (exclusive of working
capital, capitalized interest and financing costs), and to produce
approximately 17,000 barrels of MTBE per stream day.
Under an existing MTBE sales agreement between Proesa and a
subsidiary of Petroleos Mexicanos, S.A., the Mexican state-owned
oil company ("Pemex"), Proesa has furnished a surety bond in
connection with the Plant's first year of operations. The surety
bond has an insurable value of 41.3 million New Pesos which,
based on the exchange rate at January 31, 1996, was approximately
$5.6 million. Proesa currently has no independent source of
funding. Therefore, in the event of any cash requirements to
fund payments under the surety bond or other obligations, Proesa
necessarily would request additional funding from its owners.
Beginning in December 1994, the Mexican peso experienced
substantial devaluation, interest rates in Mexico increased
significantly and Mexican economic conditions deteriorated.
Because of these factors, in January 1995 the Board of Directors
of Energy determined that the Company would suspend further
investment in the Project pending resolution of key issues related
to the Project. During 1995 and continuing in 1996, the Company
engaged in discussions with Pemex and the Project participants in
order to renegotiate the purchase and sales agreements between
Proesa and Pemex and to reach definitive agreement regarding the
participants' ownership interests in Proesa and their funding
commitments to the Project, including procedures for funding any
possible cost overruns. Despite some indications that Mexican
economic conditions are beginning to improve, there can be no
assurance that mutually satisfactory agreements can be reached
between Proesa and Pemex and among the Project participants, or
that financing satisfactory to all participants can be arranged.
If the Project is terminated, there can be no assurance that the
Company's investment in the Project could be recovered. At
December 31, 1995, the Company had invested approximately $16.5
million in the Project, and Proesa had incurred approximately
$10 million of additional obligations that have not yet been
funded by its owners.
NATURAL GAS
The natural gas division of the Company has been evolving
from a Texas intrastate pipeline company to a more diversified,
midstream gas company offering value-added services and products
to producers and end-users, not only in Texas, but throughout
North America as well. The Company owns and operates natural gas
pipeline systems serving Texas intrastate markets, and the
Company markets natural gas throughout North America through
interconnections with interstate pipelines. The Company's
natural gas pipeline and marketing operations<F2> consist
principally of purchasing, gathering, processing, storing,
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. The Company is also engaged in
price-risk management activities to complement and enhance its
merchant business.
[FN]
<F2> The Company's natural gas operations are conducted
primarily through Valero Natural Gas Partners, L.P.
("VNGP, L.P.") and its subsidiaries (the "Partnership").
These operations were acquired in connection with the
merger described in Note 2 of Notes to Consolidated
Financial Statements. For a discussion of the Company's
method of accounting for its investment in the Partnership,
see Note 1 of Notes to Consolidated Financial Statements.
In addition, the Company's natural gas operations also
include certain minor natural gas pipeline operations, and
prior to September 30, 1993, certain minor natural gas
distribution operations, not conducted through the
Partnership. For comparability purposes, the information
and statistics presented in this Part I reflect the
combination of all such natural gas operations for all of
1995, 1994 and 1993.
Transmission System
The Company's principal natural gas pipeline system is its
Texas intrastate gas system ("Transmission System"). The
Transmission System generally consists of large diameter
transmission lines that receive gas at central gathering points
and move the gas to delivery points. The Transmission System
also includes numerous small diameter lines connecting individual
wells and common receiving points to the Transmission System's
larger diameter lines. The Company's wholly owned, jointly owned
and leased natural gas pipeline systems include approximately
8,000 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. These integrated systems include
39 mainline compressor stations with a total of approximately
178,000 horsepower, together with gas processing plants,
dehydration and gas treating plants and numerous measuring and
regulating stations. The Company's pipeline systems have
considerable flexibility in providing connections between many
producing and consuming areas, and are able to handle widely
varying loads caused by changing supply and demand patterns.
Annual average throughput was approximately 3.1 Bcf<F3> per day
in 1995, and was in excess of 2.8 Bcf per day in 1994 and 1993.
The Company's owned and leased pipeline systems have
73 interconnects with 21 intrastate pipelines, 40 interconnects
with 13 interstate pipelines, and two international interconnects
with Pemex in South Texas.
[FN]
<F3> Mcf (thousand cubic feet) is a standard unit for measuring
natural gas volumes at a pressure base of 14.65 pounds per
square inch absolute and at 60 degrees Fahrenheit. The term
"MMcf" means million cubic feet, and the term "Bcf" means
billion cubic feet. The term "Btu" means British Thermal
Unit, a standard measure of heating value. The number of
MMBtu's of total natural gas deliveries is approximately
equal to the number of Mcf's of such deliveries. The terms
MMBtu, BBtu and TBtu mean million Btu's, billion Btu's, and
trillion Btu's, respectively.
Gas Sales and Marketing
The following table sets forth the Company's gas sales
volumes and average gas sales prices for the three years ended
December 31, 1995.
Year Ended December 31,
1995 1994 1993
Intrastate sales (MMcf per day). . . . . 661 638 699
Interstate sales (MMcf per day). . . . . 773 506 452
Total. . . . . . . . . . . . . . . 1,434 1,144 1,151
Average gas sales price per Mcf. . . . . $1.74 $2.07 $2.32
Sales of natural gas accounted for approximately 46%, 40%
and 41% of the Company's total daily gas volumes for 1995, 1994
and 1993, respectively. The Company supplies both intrastate and
interstate markets with gas supplies acquired from producers,
marketers and pipelines. Gas sales are made on both a long-term
basis and a short-term interruptible basis. The Company also
engages in off-system sales. During 1995, the Company sold
natural gas under hundreds of separate short- and long-term gas
sales contracts. Total gas sales volumes made by the Company
increased 45% over a three-year period from approximately
987 MMcf per day in 1992 to 1,434 MMcf per day in 1995. The
Company's off-system marketing business, which increased from
70 MMcf per day of sales in 1992 to 340 MMcf per day in 1995, was
a large contributor to this increase.
The Company's gas sales are made primarily to gas
distribution companies, electric utilities, gas marketers
(resellers), other pipeline companies and industrial users. The
Company's gas sales contracts with its intrastate customers
generally require the Company to provide a fixed and determinable
quantity of gas rather than total customer requirements; however,
certain gas sales contracts with intrastate customers provide for
either maximum volumes or total requirements, subject to
priorities and allocations established by the Railroad Commission
of Texas. See "Governmental Regulations - Texas Regulation."
The gas sold to distribution companies is resold to consumers in
a number of cities including San Antonio, Dallas, Austin, Corpus
Christi and Chicago. Nationally, the demand for natural gas has
increased at a rate of approximately 3.3% per year since 1986.
The Company expects that long-term demand will continue to grow
about 2% to 3% per year, especially in the industrial and power
generation sectors.
Federal Energy Regulatory Commission ("FERC") Order No. 636
("Order 636") has effectively transformed the interstate gas
industry into a service-oriented business with natural gas and
transportation trading as separate commodities. Because of
Order 636, local distribution companies ("LDCs") and power
generation companies are responsible for acquiring their own gas
supplies, including managing their needs for swing,
transportation and storage services. See "Governmental
Regulations - Federal Regulation." The Company is continuing to
emphasize diversification of its customer base through interstate
sales. By the end of 1995, the Company had secured contracts to
provide gas supply and swing services to certain LDCs, electric
utilities and industrial customers primarily in the midwest,
northeast and western United States providing for deliveries of
up to approximately 400 MMcf per day with terms ranging from one
to ten years. Order 636 has created new market opportunities for
the Company, requiring that the Company efficiently provide an
array of value-added services to the customer base. In response,
the Company offers a broad range of marketing services. The
Company has marketing offices located throughout Texas as well as
in Los Angeles, Chicago, Louisville, Mexico City and Calgary.
The Company's Market Center Services Program, established
in 1992, provides pricing and price-risk management services to
both gas producers and end users. This program uses financial
instruments, such as futures, swaps and options to manage the
price-risk exposure within the Company, and to offer customized
pricing arrangements with both the Company's suppliers and its
customers. Activities of the Market Center have improved the
Company's ability to capture and optimize gas transportation,
storage and sales margins, as well as managing gas price
volatility for the Company's gas processing and refining
businesses. See Note 5 of Notes to Consolidated Financial
Statements.
The Company capitalized on the strategic west-to-east
position of its pipeline system when its Waha hub, located in
West Texas, was chosen to serve as the delivery point for the
Western Natural Gas Futures and Options Contracts traded on the
Kansas City Board of Trade ("KCBT"). These futures and options
contracts began trading on August 1, 1995. Approximately 13 Bcf
of gas was delivered through the hub during the last four months
of 1995. In addition, the Waha hub serves as the delivery
location for "Streamline," an electronic trading system operated
by Williams Pipeline to trade physical gas at various hubs across
the United States. The Company actively utilizes these new
methods not only to buy and sell gas, but also to better manage
its price-risk exposure in the Western part of the United States.
In November 1995, the Company introduced to a test-group of
customers "Velocity," its intrastate electronic bulletin board
("EBB") designed to improve communications between the Company
and its customers and to enable customers to monitor and control
their natural gas volumes in a more timely manner. Through the
EBB, the Company offers natural gas producers, shippers and end-users
real-time access to measurement and operational data
relating to the Company's network of natural gas pipelines and
gas processing plants. Velocity receives data on a daily basis
from electronic flow measurement ("EFM") points as well as weekly
updates of other measurement data from the Company's Transmission
System. Once connected to Velocity, customers can access a
variety of information including monthly measurement data for the
last 24 months, final measurement delivery statements for the
previous month, current month measurement data from existing EFM
stations, and general notices relating to the Company's
operations.
Valero Field Services Company, a wholly owned subsidiary,
was established in 1995 to build and diversify the Company's gas
supply portfolio and to create synergistic opportunities with the
Company's other gas businesses by providing gas gathering,
compression, dehydration and treating services in and around the
Transmission System and in those regions that are complementary
to the Company's anticipated growth. The field services unit
will also evaluate for potential acquisition third-party
gathering systems that are near active drilling areas
complementary to the Company's pipeline and processing
operations. The unit will also pursue additional long-term
dedications of "rich" gas from producers.
Deregulation of the electric utility and power industry
also offers new opportunities for natural gas companies. In
response, the Company in 1995 formed a wholly owned subsidiary,
Valero Power Services Company, to provide risk management and
marketing services to the electric power industry. The Company
plans to offer to wholesale customers hourly, daily and monthly
energy trading services; transmission services; emissions
allowances; generation capacity transactions including fuel-to-
energy conversions; and fuel-to-energy swaps. In addition,
wholesale customers are offered an array of risk management tools
for managing their costs and reliability associated with power
procurement. The Company's initial power marketing efforts are
concentrated in the central United States. Valero Power Services
Company is a member of the Western Systems Power Pool, the
Southwest Power Pool, the Electric Reliability Council of Texas
and the Mid-Continent Area Power Pool. The Company began trading
power in January 1996 with the initiation of 24-hour operations.
Gas Transportation
The following table sets forth the Company's gas
transportation volumes and average transportation fees for the
three years ended December 31, 1995.
Year Ended December 31,
1995 1994 1993
Transportation volumes (MMcf per day) . . . . . . . . 1,704 1,682 1,672
Average transportation fee per Mcf. . . . . . . . . . $.093 $.102 $.107
Gas transportation and exchange transactions (collectively
referred to as "gas transportation" or "transportation")
constitute the largest portion of the Company's natural gas
volumes, representing 54%, 60% and 59% of total daily gas volumes
for 1995, 1994 and 1993, respectively. The Company's natural gas
operations have been affected by an emerging trend of west-to-east
movement of gas across the United States caused by increased
production in western supply basins, the pipeline expansions from
Canada and the Rocky Mountains and increasing demand for power
generation in the East and Southeast. Transportation rates are
often higher on eastbound transmission than on east-to-west
transmission. To capitalize on the west-to-east trend, the
Company in 1994 completed a capacity expansion project on its
joint venture North Texas pipeline which added incremental
capacity of approximately 90 MMcf of gas per day to the pipeline.
The Company transports gas for third parties under hundreds
of separate short- and long-term transportation contracts. The
Company's transportation contracts generally limit the Company's
maximum transportation obligation (subject to available capacity)
but generally do not provide for any minimum transportation
requirement. The Company's transportation customers include
major oil and natural gas producers and pipeline companies.
Gas Supply and Storage
Gas supplies available to the Company for purchase and
resale or transportation include supplies of gas committed under
both short- and long-term contracts with independent producers as
well as additional gas supplies contracted for purchase from
pipeline companies, gas processors and other suppliers that own
or control reserves. There are no reserves of natural gas
dedicated to the Company and the Company does not own any gas
reserves other than gas in underground storage which comprises an
insignificant portion of the Company's gas supplies. 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 1995, the Company purchased natural gas under
hundreds of separate contracts. Surplus gas supplies, if
available, may be purchased to supplement the Company's delivery
capability during peak use periods. A majority of the Company's
gas supplies are obtained from sources with multiple connections.
In such instances, the Company frequently competes on a monthly
basis for available gas supplies. The Company's ability to
process natural gas attracts significant gas supplies to the
Transmission System. In 1995, the Company secured approximately
750 MMcf per day of natural gas supplies from natural gas
producers under agreements to process, transport or purchase
their natural gas for terms ranging generally from one to ten
years. Of these supplies, approximately 325 MMcf per day
represent new natural gas supplies dedicated to the Company's
pipeline system and 425 MMcf were extensions of existing
agreements that otherwise would have expired. Because of the
extensive coverage within the State of Texas by the Company's
pipeline systems, the Company can access a number of supply
areas. While there can be no assurance that the Company will be
able to acquire new gas supplies in the future as it has in the
past, the Company believes that Texas will remain a major
producing state, and that for the foreseeable future the Company
will be able to compete effectively for sufficient new gas
supplies to meet customer demand.
The Company operates an underground gas storage facility in
Wharton County, Texas. The current storage capacity of this
facility is 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. The Company supplemented its own natural
gas storage capacity by leasing during 1995 an additional 8.0 Bcf
of third-party storage capacity for the 1995-96 winter heating
season.
NATURAL GAS LIQUIDS
The Company owns and operates eight<F4> gas processing
plants and is a major producer and marketer of NGLs. The
Company's NGL operations<F5> provide strong integration among
the Company's three core businesses. The Company's ability to
process natural gas is a value-added service offered to producers
and attracts additional quantities of gas to the Company's
pipeline system. Production from the Company's NGL plants also
provides butane feedstocks for the production of oxygenates
(primarily MTBE) at the Refinery.
[FN]
<F4> The Company also owns a ninth gas processing plant, but this
plant ceased operations in 1995 and the gas streams formerly
processed at this plant were diverted to another of the
Company's gas processing plants.
<F5> The Company's NGL operations are conducted primarily through
the Partnership, and through certain non-Partnership NGL
assets acquired by the Company in May 1992. For a
discussion of the Company's method of accounting for its
investment in the Partnership, see Note 1 of Notes to
Consolidated Financial Statements. For comparability
purposes, the information and statistics presented in this
Part I reflect the combination of all such NGL operations
for all of 1995, 1994 and 1993.
Recent expansions and improvements at the Company's gas
processing plants increased 1995 NGL production to approximately
29.3 million barrels for the year, equal to an average daily
production of 80,300 barrels per day. The 1995 NGL production
represents the Company's sixth consecutive year for record
production volumes. The Company sold two of its gas processing
plants in West Texas effective August 1, 1995. Processing
capacity lost by the sale of these plants was partially offset,
however, by significant expansions and upgrading projects
completed at certain of the Company's other plants during the
second half of the year. The table below sets forth NGL
production volumes, average NGL market prices, and average gas
costs for the three years ended December 31, 1995.
Year Ended December 31,
1995 1994 1993
NGL plant production (Mbbls per day) . . . . . 80.3 79.5 77.4
Average market price per gallon<F1>. . . . . . $.261 $.271 $.287
Average gas cost per Mcf . . . . . . . . . . . $1.40 $1.75 $1.96
<FN>
<F1> Represents the average Houston area market prices for individual NGL products
weighted by relative volumes of each product produced.
</FN>
The Company's NGL operations include the extraction of
NGLs, the separation ("fractionation") of mixed NGLs into
component products (e.g., ethane, propane, butane, natural
gasoline), and the transportation and marketing of NGLs.
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 principal
source of gas for processing is from the Transmission System.
The Company receives revenues from the extraction of NGLs
principally through the sale of NGLs extracted in its gas
processing plants and the collection of processing fees charged
for the extraction of NGLs owned by others. The Company
compensates gas suppliers for shrinkage and fuel usage in various
ways, including sharing NGL profits, returning extracted NGLs to
the supplier or replacing an equivalent amount of gas. Extracted
NGLs are transported to downstream fractionation facilities and
end-use markets through the Company's NGL pipelines, certain
common-carrier NGL pipelines and trucks. The primary markets for
NGLs are petrochemical plants (all NGLs), refineries (butanes and
natural gasoline), and domestic fuel distributors (propane). The
Company's NGL production is sold primarily in the Corpus Christi
and Mont Belvieu (Houston) markets. NGL prices are generally set
by or in competition with prices for refined products in the
petrochemical, fuel and motor gasoline markets. During 1995,
approximately 72% of the Company's butane production was used as
a feedstock for the Refinery's MTBE Plant.
The Company's gas processing plants are located primarily
in South Texas and process approximately 1.3 Bcf of gas per day.
Each of the Company's plants is situated along the Transmission
System. The Company also owns approximately 385 miles of NGL
pipelines, 460 miles of gathering lines, and fractionation
facilities at five locations. The Company fractionated an
average of 81,500 barrels per day in 1995, approximately 5% of
which represented NGLs fractionated for third parties. The
Company's NGL pipelines, located primarily in South Texas,
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. In South Texas, the Company owns
228 miles of NGL pipelines that directly or indirectly connect
five of the Company's processing plants and three processing
plants owned by third parties to the Company's fractionation
facilities near Corpus Christi.
The Company sells NGLs that have been extracted,
transported and fractionated in the Company's facilities and NGLs
purchased in the open market from numerous suppliers (including
major refiners and natural gas processors) under long-term,
short-term and spot contracts. The Company's contracts for the
purchase, sale, transportation and fractionation of NGLs are
generally with longstanding customers and suppliers of the
Company. The petrochemical industry represents an expanding
principal market for NGLs due to increasing market demand for
ethylene-derived products. Petrochemical demand for NGLs is
projected to remain strong through 1996 with the announcement of
several expansions to existing petrochemical facilities. In
addition, the start-up of five new ethylene plants along the
Texas Gulf Coast from 1998 through 1999 has been announced. A
majority of this incremental capacity is projected to be built by
independent petrochemical companies with little affiliated NGL
production, which may improve market liquidity for NGLs and
create market opportunities for major NGL producers. However,
planned facilities additions frequently are delayed or canceled,
and no assurances can be given that the proposed petrochemical
facilities will be completed.
GOVERNMENTAL REGULATIONS
Federal Regulation
The Company's refining operations are primarily subject to
various federal and state environmental statutes and regulations.
See "Environmental Matters." The Company's pipeline system is an
intrastate business not subject to direct regulation by the FERC.
Although the Company's interstate gas sales and transportation
activities are subject to specific FERC regulations, these
regulations do not change the Company's overall regulatory
status. The Company's natural gas operations are more
significantly affected by the implementation of 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 the Company to compete with
interstate pipelines and other companies 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 Company can more
effectively compete for sales of natural gas to LDCs and other
natural gas customers located outside Texas.
Texas Regulation
The Railroad Commission of Texas ("RRC") regulates the
intrastate transportation, sale, delivery and pricing of natural
gas in Texas by intrastate pipeline and distribution systems,
including those of the Company. The RRC's gas proration rule
prohibits the production of gas in excess of market demand, and
permits producers to tender and deliver, and gas purchasers to
take, only volumes of gas equal to their market demand. The gas
proration rule requires purchasers to take gas by priority
categories, ratably among producers without undue discrimination,
with high-priority gas (gas from wells primarily producing oil
and certain special allowable gas) having higher priority than
gas well gas (gas from wells primarily producing gas),
notwithstanding any contractual commitments. The RRC rules are
intended to bring production allowables in line with estimated
market demand.
For pipelines, the RRC approves intrastate sales and
transportation rates and all proposed changes to such rates.
Changes in the price of gas sold to gas distribution companies
are subject to rate determination in a rate case before the RRC.
Under applicable statutes and current RRC 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. Since
December 31, 1979, a portion of the Company's gas sales have been
made at rates established by an order (the "Rate Order") of the
RRC. However, the proportion of these sales to the Company's
total gas sales has been decreasing because of various factors.
See "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Results of Operations - 1995 Compared
to 1994 - Segment Results - Natural Gas." Currently, the price
of natural gas sold under a majority of the Company's gas sales
contracts is not regulated by the RRC, and the Company may
generally enter into any sales contract that it is able to
negotiate with customers.
NGL pipeline transportation is also subject to regulation
by the RRC through the filing of tariffs and compliance with
safety standards. To date, the impact of this regulation on the
Company's operations has not been significant. The RRC also has
regulatory authority over gas processing operations, but has not
exercised such authority.
COMPETITION
Refining and Marketing
The refining industry is highly competitive with respect to
both supply and markets. The Company competes with numerous
other companies for available supplies of resid and other
feedstocks and for outlets for its refined products. The Company
has no crude reserves and is not engaged in production. It
obtains all of its resid feedstock from unaffiliated sources.
Many of the companies with which the Company 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. The Company does not have retail gasoline
operations. 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.
Because the Refinery was completed in 1984, it was built
under more stringent environmental requirements than many
existing refineries. The Refinery currently meets EPA emissions
standards requiring the use of "best available control
technology," and is located in an area currently designated
"attainment" for air quality. Accordingly, the Company expects
to be able to comply with the Clean Air Act and future
environmental legislation more easily than older, conventional
refineries, and will not be required to spend significant
additional capital for environmental compliance. Recently,
however, the Corpus Christi area has experienced increased ozone
levels and there can be no assurance that the area will remain a
designated "attainment" area for air quality.
The Company produces enough oxygenates to blend all of its
gasoline as RFG and to sell additional quantities of oxygenates
to third parties who require oxygenates for blending. RFG
generally sells at a premium over conventional gasoline. Most of
the refining industry traditionally uses the conventional "3-2-1
crack spread" (which assumes the input of three parts of West
Texas Intermediate crude oil and the output of two parts gasoline
and one part diesel); however, the Company produces premium
products such as RFG and low-sulfur diesel and also produces a
higher percentage of its refined products as gasoline. Thus, the
Company's "85-15 clean fuels crack spread" (85% RFG, 15% low-
sulfur diesel) has provided a wider margin than the typical crack
spread experienced by a conventional refiner. However, many of
the Company's competitors are large, integrated oil companies
which, because of their diverse operations, stronger
capitalization and brand-name recognition, may be better able
than the Company to withstand volatile industry conditions such
as shortages of feedstocks or intense price competition.
Natural Gas
The natural gas industry is and is expected to remain
highly competitive with respect to both gas supply and markets.
Changes in the gas markets during the recent period of
deregulation under Order 636 have resulted in significantly
increased competition. However, the Company has not only
maintained but has increased its throughput volumes since
implementation of Order 636. Under Order 636, the Company can
more effectively compete for sales of natural gas to LDCs and
other customers located outside Texas. See "Governmental
Regulations - Federal Regulation." Because of Order 636, the
Company now can guarantee long-term supplies of natural gas to be
delivered to buyers at interstate locations. The Company can
charge a fee for this guarantee, which together with
transportation charges, can exceed the amount that the Company
could receive for merely transporting natural gas. Because of
Order 636 and the location of the Transmission System, the
Company believes that the Company is able to compete for new gas
supplies and new gas sales and transportation customers.
In recent years, certain intrastate pipelines with which
the Company 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 Company and, notwithstanding Order 636's "open access"
regulations, may realize economies of scale and other economic
advantages in acquiring, selling and transporting natural gas.
Additionally, the combination of intrastate and interstate
pipelines within one organization may in some instances enable
competitors to lower gas prices and transportation fees, and
thereby increase price competition in the Company's intrastate
and interstate markets. Consequently, the Company's competitors
in the near future are likely to be a smaller number of larger
energy service firms that can offer "one-stop shopping" for the
customer's energy needs, whether the needs are physical,
managerial, or financial for the respective energy commodity.
Accordingly, the Company has recently undertaken three
initiatives to strengthen the Company's ability to compete as an
energy service firm: (i) the formation of Valero Field Services
Company (see "Natural Gas - Gas Sales and Marketing"), (ii) the
expansion of the Company's NGL marketing activities and
infrastructure, and (iii) the formation of Valero Power Services
Company (see "Natural Gas - Gas Sales and Marketing").
Natural Gas Liquids
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 Company believes that
competitive barriers to entering the business are generally low.
Moreover, improvements in NGL-recovery technology have improved
the economics of NGL processing and have increased the
attractiveness of many processing opportunities. In recent
years, NGL margins have been subject to the extreme volatility of
energy prices in general. The Company 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. The Company's South Texas gas
processing plants, however, have direct access to many of the
large petrochemical markets along the Texas Gulf Coast, which
gives the Company a competitive advantage over many other NGL
producers.
ENVIRONMENTAL MATTERS
The Company's refining, natural gas and NGL operations are
subject to environmental regulation by federal, state and local
authorities, including the EPA, the Texas Natural Resources
Conservation Commission ("TNRCC"), the Texas General Land Office
and the RRC. The regulatory requirements relate to water and
storm water discharges, waste management and air pollution
control measures. In 1995, capital expenditures for the
Company's refining operations attributable to compliance with
environmental regulations were approximately $5 million and are
currently estimated to be $9 million for 1996. These amounts are
exclusive of any amounts related to constructed facilities for
which the portion of expenditures relating to compliance with
environmental regulations is not determinable. For a discussion
of the effects of the Clean Air Act's oxygenated gasoline and RFG
programs on the Company's refining operations, see "Refining and
Marketing - Factors Affecting Operating Results."
The Company's capital expenditures for environmental
control facilities related to its natural gas and NGL operations
were not material in 1995 and are not expected to be material in
1996. Currently, expenditures are made to comply with
regulations for air emissions, solid waste management and waste
water applicable to various facilities. In 1991, environmental
legislation was passed in Texas that conformed Texas law with the
Clean Air Act to allow Texas to administer the federal programs.
Upon interim approval by the EPA of the Texas Title V operating
permit program, many of the Company's gas processing plants and
gas pipeline facilities will be among the first facilities
required to submit applications to the TNRCC for new operating
permits, and may be subject to increased requirements for
monitoring air emissions. Although new requirements may increase
operating costs, they are not expected to have a material adverse
effect on the Company's operations or financial condition.
The Oil Pollution Act of 1990 ("OPA 90") and regulations
thereunder impose a variety of regulations on "responsible
parties" related to the prevention of oil spills and the
assessment of liability for damages resulting from oil spills in
U.S. territorial waters. Shipments of crude oil and resid within
U.S. territorial waters are subject to the regulations
promulgated under OPA 90. These regulations require tankers to
comply with certain Certificate of Financial Responsibility
("COFR") requirements in order to ship within U.S. territorial
waters. The Company's shippers have complied with the COFR
requirements and the Company has not experienced any difficulty
in obtaining tonnage to move its supplies to the Refinery. The
OPA 90 regulations are not expected to have a material impact on
operating results from the Company's refining and marketing
operations.
EMPLOYEES
As of January 31, 1996, the Company had 1,658 employees.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of
December 31, 1995 regarding the 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. There is no
arrangement or understanding between any executive officer and
any other person pursuant to which he was or is to be selected as
an officer.
_________________________________________________________________________________________
Energy Year First Elected Age as of
Position and or Appointed as December 31,
Name Office Held Officer or Director 1995
_________________________________________________________________________________________
William E. Greehey Director, Chairman of 1979 59
the Board and Chief
Executive Officer
F. Joseph Becraft Director, President and 1995 52
Chief Operating Officer
Edward C. Benninger Director and Executive 1979 53
Vice President
Stan L. McLelland Executive Vice President 1981 50
and General Counsel
Don M. Heep Senior Vice President and 1990 46
Chief Financial Officer
*E. Baines Manning Executive Vice President of 1992* 55
Valero Refining and
Marketing Company
_________________________________________________________________________________________
* Mr. Manning has been designated by the Energy Board of Directors as an "executive
officer" 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.
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 Energy Resources, Inc.,
neither of which are affiliated with the Company. Mr. Greehey
has announced that he will retire as Chief Executive
Officer of Energy effective June 30, 1996.
Mr. Becraft was elected as a director in 1995 and was
elected as President and Chief Operating Officer of Energy
effective January 1, 1996. Effective June 30, 1996, he will
succeed Mr. Greehey as Chief Executive Officer of Energy.
From 1984 to 1989 Mr. Becraft served as Senior Vice President
in the Company's natural gas division. Prior to rejoining the
Company in May 1995, he had served as President and Chief
Executive Officer of Transok, Inc. since 1989. Transok, Inc.
is not an affiliate of the Company.
Mr. Benninger has served as a director of Energy since
1990. He was elected Executive Vice President in 1989 and served
as Chief Operating Officer of Valero Natural Gas Company from
1992 to 1995, and in various other capacities with the Company
since 1975.
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.
Mr. Manning has served as Executive Vice President of
Valero Refining and Marketing Company since 1995 and in various
other capacities within the Company's refining division since
1986.
ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery and
related facilities, eight natural gas processing plants, and
various natural gas and NGL pipelines, gathering lines,
fractionation facilities, compressor stations, treating plants
and related facilities, all located in Texas. Substantially all
of the Company's refining fixed assets are pledged as security
under deeds of trust securing industrial revenue bonds issued on
behalf of Valero Refining and Marketing Company. Substantially
all of the gas systems and processing facilities acquired by the
Company in connection with the Merger are pledged as collateral
for the First Mortgage Notes of Valero Management Partnership,
L.P. See Note 4 of Notes to Consolidated Financial Statements.
Reference is made to "Item 1. Business" which includes detailed
information regarding properties of the Company. The Company
believes that its facilities are generally adequate for their
respective operations, and that the facilities of the Company are
maintained in a good state of repair. The Company is the lessee
under a number of cancelable and noncancelable leases for certain
real properties. See Note 13 of Notes to Consolidated Financial
Statements.
ITEM 3. LEGAL PROCEEDINGS
The Company is party to the following proceedings:
Adams, et al. v. Colonial Pipeline Company; Valero
Transmission, L.P.; et al., 157th State District Court, Harris
County, Texas (filed August 31, 1995).
American Plant Food Corporation, et al., v. Colonial
Pipeline Company; Texaco, Inc.; Valero Energy Corporation;
et al., 80th State District Court, Harris County, Texas (filed
June 1, 1995).
Benavides, et al. v. Colonial Pipeline Company; Valero
Transmission, L.P.; et al., 93rd State District Court, Hidalgo
County, Texas (filed August 31, 1995).
Cook, et al. v. Shell Oil Company; Texaco, Inc.; Valero
Transmission, L.P.; et al., 172nd State District Court, Jefferson
County, Texas (filed November 7, 1994).
Gandy, et al. v. Colonial Pipeline Company; Valero
Management Company; et al., 151st State District Court, Harris
County, Texas (filed August 31, 1995).
Grant v. Colonial Pipeline Company; Valero Transmission,
L.P.; et al., 152nd State District Court, Harris County, Texas
(filed August 31, 1995).
The six lawsuits listed above arise from the rupture of
several pipelines and fire as a result of severe flooding of the
San Jacinto River in Harris County, Texas on October 20, 1994.
The plaintiffs are property owners in surrounding areas who
allege that the defendant pipeline owners were negligent and
grossly negligent in failing to bury the pipelines at a proper
depth to avoid rupture or explosion and in allowing the pipelines
to leak chemicals and hydrocarbons into the flooded area. The
plaintiffs assert claims for property damage, costs for medical
monitoring, personal injury and nuisance. Plaintiffs seek an
unspecified amount of actual and punitive damages.
Alonso, et al. v. Fina Oil and Chemical Company, Forest Oil
Corporation, Valero Energy Corporation, Valero Natural Gas
Company, et al., 370th State District Court, Hidalgo County,
Texas (filed May 17, 1995). This lawsuit was filed by certain
mineral interest owners in South Texas against Forest Oil
Corporation ("Forest") and several other defendants, including
the Company, asserting several claims in connection with an
alleged underpayment of royalties. In 1987, certain subsidiaries
of the Company entered into a settlement agreement with Forest, a
natural gas producer, to resolve a take-or-pay dispute between
the parties. As part of the settlement, the parties terminated
their then-existing gas sales contracts and entered into new gas
sales contracts. Under the settlement agreement, the Company's
subsidiaries agreed to pay one-half of any "excess royalty claim"
brought against Forest relating to any natural gas produced and
sold to the subsidiaries after the date of the settlement
agreement. In their lawsuit, the mineral interest owners allege
that the numerous "operator defendants" (excluding the Company)
breached certain covenants and duties thereby depriving the
plaintiffs of the full value of their royalty interests. The
plaintiffs allege that the Company conspired with Forest to
deprive plaintiffs of royalties that they would have earned but
for the settlement of the gas contract dispute. Plaintiffs seek
unspecified actual and punitive damages.
J.M. Davidson, Inc. v. Valero Energy Corporation; Valero
Hydrocarbons, L.P.; et al., 229th State District Court, Duval
County, Texas (filed January 21, 1993). This lawsuit is based
upon construction work performed by the plaintiff at certain of
the Company's gas processing plants in 1991 and 1992. The
plaintiff alleges that it performed work for the defendants for
which it was not compensated. The plaintiff asserts claims for
breach of contract, quantum meruit, and numerous other contract
and tort claims. The plaintiff alleges actual damages of
approximately $3.7 million and punitive damages of $20.4 million.
The defendants' motion for summary judgment regarding certain of
the plaintiff's tort claims was denied. A trial date of July 22,
1996 has been set.
The Long Trusts v. Tejas Gas Corporation; Valero
Transmission, L.P.; et al., 123rd Judicial District Court, Panola
County, Texas (filed March 1, 1989). On April 15, 1994, certain
trusts (the "Long Trusts") named VTC and VT, L.P. as additional
defendants (the "Valero Defendants") to a lawsuit filed in 1989
against Tejas Gas Corporation ("Tejas"), a supplier with whom
VT, L.P., as successor to VTC, has contractual relationships
under gas purchase contracts. In order to resolve certain
potential disputes with respect to the gas purchase contracts,
VT, L.P. agreed to bear a substantial portion of any settlement
or nonappealable final judgment rendered against Tejas. In
January 1993, the District Court ruled in favor of the Long
Trusts' motion for summary judgment against Tejas. Damages, if
any, were not determined. In the Long Trusts' sixth amended
petition, the trusts seek $50 million in damages from the Company
as a result of the Valero Defendants' alleged interference
between the Long Trusts and Tejas, and seek $36 million in take-
or-pay damages from Tejas. The Long Trusts also seek punitive
damages in an amount equal to treble the amount of actual damages
proven at trial. The Company believes that the claims brought by
the Long Trusts have been significantly overstated, and that
Tejas and the Valero Defendants have a number of meritorious
defenses to the claims. Trial is set to begin on May 13, 1996.
Mizel v. Valero Energy Corporation, Valero Natural Gas
Company, and Valero Natural Gas Partners, L.P., removed to the
United States District Court for the Western District of Texas
(originally filed May 1, 1995 in the United States District Court
for the Southern District of California). This is a federal
securities fraud lawsuit filed by a former owner of approximately
19,500 units of limited partnership interests of VNGP, L.P.
Plaintiff alleges that the proxy statement used in connection
with the solicitation of votes for approval of the merger of
VNGP, L.P. with a wholly owned subsidiary of the Company
contained fraudulent misrepresentations. Plaintiff also alleges
breach of fiduciary duty in connection with the merger
transaction. The subject matter of this lawsuit was the subject
matter of a prior Delaware class action lawsuit which was settled
prior to consummation of the merger. The Company believes that
plaintiff's claims have been settled and released by the prior
class action settlement. The lawsuit is scheduled for trial on
December 2, 1996.
Ventura, et al. v. Valero Refining Company, 105th State
District Court, Nueces County, Texas (filed June 17, 1994). This
lawsuit was filed against a subsidiary of the Company by certain
residents of the Mobile Estate subdivision located near the
Refinery in Corpus Christi, Texas, alleging that air, soil and
water in the subdivision have been contaminated by emissions from
the Refinery of allegedly hazardous chemicals and toxic
hydrocarbons. The plaintiffs' claims include negligence, gross
negligence, strict liability, nuisance and trespass. In May
1995, the plaintiffs filed a motion for nonsuit, seeking a
dismissal of the case against the Company. Various filings and
motions are before the court with respect to the attempted
termination of this lawsuit.
Javelina Company Litigation. Valero Javelina Company, a
wholly owned subsidiary of Energy, owns a 20 percent general
partner interest in Javelina Company, a general partnership. See
Note 6 of Notes to Consolidated Financial Statements. Javelina
Company has been named as a defendant in eight lawsuits filed
since 1993 in state district courts in Nueces County, and Duval
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 alleged exposure to toxic
chemicals, and generally claim that the defendants were
negligent, grossly negligent and committed trespass. The
plaintiffs claim personal injury and property damages resulting
from soil and ground water contamination and air pollution
allegedly caused by the operations of the defendants. The
plaintiffs seek an unspecified amount of actual and punitive
damages. The remaining four suits were brought by plaintiffs who
either live or have businesses near the Javelina plant. The
plaintiffs in these suits allege claims similar to those
described above and seek unspecified actual and punitive damages.
The Company is also a party to additional claims and legal
proceedings arising in the ordinary course of business. The
Company believes it is unlikely that the final outcome of any of
the claims or proceedings to which the Company is a party,
including those described above, would have a material adverse
effect on the Company's financial statements; however, due to the
inherent uncertainty of litigation, the range of possible loss,
if any, cannot be estimated with a reasonable degree of precision
and there can be no assurance that the resolution of any
particular claim or proceeding would not have an adverse effect
on the Company's results of operations for the interim period in
which such resolution occurred.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders
during the fourth quarter of 1995.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
Energy's Common Stock is listed under the symbol "VLO" on
the New York Stock Exchange, which is the principal trading
market for this security. As of February 1, 1996, there were
approximately 6,850 holders of record and an estimated 18,000
additional beneficial owners of Energy's Common Stock.
The range of the high and low sales prices of the Common
Stock as quoted in The Wall Street Journal, New York Stock
Exchange-Composite Transactions listing, and the amount of per-
share dividends for each quarter in the preceding two years, are
set forth in the tables shown below:
Common Stock Dividends
1995 1994 Per Common Share
Quarter Ended High Low High Low 1995 1994
March 31. . . . . . . . $18 5/8 $16 $24 1/8 $19 1/2 $.13 $.13
June 30 . . . . . . . . 22 7/8 17 3/4 22 1/8 16 3/4 .13 .13
September 30. . . . . . 25 5/8 19 5/8 21 1/8 17 1/4 .13 .13
December 31 . . . . . . 25 7/8 22 1/2 22 16 1/2 .13 .13
The Energy Board of Directors declared a quarterly dividend
of $.13 per share of Common Stock at its January 23, 1996
meeting. Dividends are considered quarterly by the Energy Board
of Directors and may be paid only when approved by the Board.
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year
ended December 31, 1995 is derived from the Company's
Consolidated Financial Statements contained elsewhere herein.
The selected financial data for the years ended prior to
December 31, 1995 is derived from the selected financial data
contained in the Company's Annual Report on Form 10-K for the
year ended December 31, 1994.
The following summaries are in thousands of dollars except
for per share amounts:
Year Ended December 31,
1995<F1> 1994<F1> 1993 1992 1991
OPERATING REVENUES . . . . . . . . . . . $3,019,792 $1,837,440 $1,222,239 $1,234,618 $1,011,835
OPERATING INCOME . . . . . . . . . . . . $ 188,791 $ 125,925 $ 75,504 $ 134,030 $ 119,266
EQUITY IN EARNINGS (LOSSES) OF AND
INCOME FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . . $ - $ (10,698) $ 23,693 $ 26,360 $ 32,389
NET INCOME . . . . . . . . . . . . . . . $ 59,838 $ 26,882 $ 36,424 $ 83,919 $ 98,667
Less: Preferred stock dividend
requirements. . . . . . . . . 11,818 9,490 1,262 1,475 6,044
NET INCOME APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . $ 48,020 $ 17,392 $ 35,162 $ 82,444 $ 92,623
EARNINGS PER SHARE OF
COMMON STOCK . . . . . . . . . . . . . $ 1.10 $ .40 $ .82 $ 1.94 $ 2.28
TOTAL ASSETS . . . . . . . . . . . . . . $2,876,680 $2,831,358 $1,764,437 $1,759,100 $1,502,430
LONG-TERM OBLIGATIONS AND
REDEEMABLE PREFERRED STOCK . . . . . . $1,042,541 $1,034,470 $ 499,421 $ 497,308 $ 395,948
DIVIDENDS PER SHARE OF COMMON
STOCK. . . . . . . . . . . . . . . . . $ .52 $ .52 $ .46 $ .42 $ .34
<FN>
<F1>
Reflects the consolidation of the Partnership as of May 31, 1994.
<F2>
See Notes to Consolidated Financial Statements.
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ACQUISITION OF VNGP, L.P.
As described in Note 2 of Notes to Consolidated Financial
Statements, the Merger of VNGP, L.P. with Energy was consummated
on May 31, 1994. As a result of the Merger, VNGP, L.P. became a
subsidiary of Energy. The accompanying consolidated statements
of income of the Company for the years ended December 31, 1995,
1994 and 1993 reflect the Company's 100% interest in the
Partnership's operations after May 31, 1994 and its effective
equity interest of approximately 49% for all periods prior to and
including May 31, 1994. Because 1994 results of operations for
the Company's natural gas and natural gas liquids segments are
not comparable to subsequent and prior periods due to the Merger,
the discussion of these segments which follows under "Results of
Operations - 1995 Compared to 1994 - Segment Results" and
"Results of Operations - 1994 Compared to 1993 - Segment Results"
is based on pro forma operating results for 1994 and 1993 that
reflect the consolidation of the Partnership with Energy for all
of such periods.
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, 1995. Certain 1994 and 1993 amounts have been
reclassified for comparative purposes. The amounts in the
following table are in thousands of dollars, unless otherwise
noted:
Year Ended December 31,
1995 1994 1993
OPERATING REVENUES:
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . $1,772,577 $1,090,368 $1,044,749
Natural gas <F1>:
Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 915,455 452,381 42,375
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . 57,764 35,183 3,646
Natural gas liquids <F1> . . . . . . . . . . . . . . . . . . . . . . . 435,979 307,016 53,252
Other <F1> . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 126 42,639 83,886
Intersegment eliminations <F1> . . . . . . . . . . . . . . . . . . . . (162,109) (90,147) (5,669)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,019,792 $1,837,440 $1,222,239
OPERATING INCOME (LOSS):
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . $ 141,512 $ 78,660 $ 75,401
Natural gas <F1> . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,496 26,731 2,863
Natural gas liquids <F1> . . . . . . . . . . . . . . . . . . . . . . . 43,684 35,213 10,057
Corporate general and administrative expenses and other, net <F1>. . . (35,901) (14,679) (12,817)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 188,791 $ 125,925 $ 75,504
Equity in earnings (losses) of and income from:
Valero Natural Gas Partners, L.P. <F2> . . . . . . . . . . . . . . . . $ - $ (10,698) $ 23,693
Joint ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,827 $ 2,437 $ (1,688)
Gain on disposition of assets and other income, net. . . . . . . . . . . $ 2,742 $ 2,039 $ 7,897
Interest and debt expense, net . . . . . . . . . . . . . . . . . . . . . $ (101,222) $ (76,921) $ (37,182)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 59,838 $ 26,882 $ 36,424
Net income applicable to common stock. . . . . . . . . . . . . . . . . . $ 48,020 $ 17,392 $ 35,162
Earnings per share of common stock . . . . . . . . . . . . . . . . . . . $ 1.10 $ .40 $ .82
PRO FORMA OPERATING INCOME (LOSS) <F3>:
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . $ 141,512 $ 78,660 $ 75,401
Natural gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,496 30,829 73,379
Natural gas liquids. . . . . . . . . . . . . . . . . . . . . . . . . . 43,684 38,940 40,309
Corporate general and administrative expenses and other, net . . . . . (35,901) (22,486) (30,151)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 188,791 $ 125,943 $ 158,938
OPERATING STATISTICS:
Refining and marketing:
Throughput volumes (Mbbls per day) . . . . . . . . . . . . . . . . . 160 146 136
Average throughput margin per barrel <F4>. . . . . . . . . . . . . . $ 6.25 $ 5.36 $ 5.99
Sales volumes (Mbbls per day). . . . . . . . . . . . . . . . . . . . 208 140 133
Natural gas <F3>:
Gas volumes (MMcf per day):
Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,434 1,144 1,151
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . 1,704 1,682 1,672
Total gas volumes. . . . . . . . . . . . . . . . . . . . . . . . 3,138 2,826 2,823
Average gas sales price per Mcf. . . . . . . . . . . . . . . . . . . $ 1.74 $ 2.07 $ 2.32
Average gas transportation fee per Mcf . . . . . . . . . . . . . . . $ .093 $ .102 $ .107
Natural gas liquids <F3>:
Plant production (Mbbls per day) . . . . . . . . . . . . . . . . . . 80.3 79.5 77.4
Average market price per gallon. . . . . . . . . . . . . . . . . . . $ .261 $ .271 $ .287
Average gas cost per Mcf . . . . . . . . . . . . . . . . . . . . . . $ 1.40 $ 1.75 $ 1.96
<FN>
<F1>
Reflects the consolidation of the Partnership commencing
June 1, 1994.
<F2>
Represents the Company's approximate 49% effective equity
interest in the operations of the Partnership and interest
income on certain capital lease transactions with the
Partnership for the periods prior to June 1, 1994.
<F3>
Operating income (loss) presented herein for 1994 and 1993
represents pro forma amounts that reflect the consolidation
of the Partnership with Energy for all of such periods.
Operating statistics for the natural gas and natural gas
liquids segments for 1994 and 1993 represent pro forma
statistics that reflect such consolidation.
<F4>
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.
</FN>
1995 COMPARED TO 1994
Consolidated Results
The Company reported net income of $59.8 million, or $1.10
per share, for the year ended December 31, 1995 compared to $26.9
million, or $.40 per share, for the year ended December 31, 1994.
For the fourth quarter of 1995, net income was $12.9 million, or
$.23 per share, compared to net income of $3.9 million, or $.02
per share, for the fourth quarter of 1994. Net income and
earnings per share increased during 1995 compared to 1994 due
primarily to a significant increase in operating income from the
Company's refining and marketing operations and improved
operating results from the Company's natural gas and natural gas
liquids operations, including the effect of the Merger. The
increases in net income and earnings per share resulting from
these factors were partially offset by increases in corporate
expenses, net interest expense and income tax expense and the
nonrecurring recognition in income in 1994 of deferred management
fees resulting from the Merger. The increase in earnings per
share was also partially offset by an increase in preferred stock
dividend requirements resulting from the issuance in March 1994
of 3.45 million shares of Energy's $3.125 Convertible Preferred
Stock. See Note 8 of Notes to Consolidated Financial Statements.
Operating revenues increased $1.2 billion to $3 billion
during 1995 compared to 1994 due primarily to an increase in
operating revenues from refining and marketing operations which
is explained below under "Segment Results" and the inclusion of
operating revenues attributable to Partnership operations in all
of 1995 versus only the months of June through December in 1994.
Other operating revenues decreased $42.5 million due to the
elimination of management fee revenues received by the Company
from the Partnership as a result of the Merger.
Operating income increased $62.9 million, or 50%, to $188.8
million during 1995 compared to 1994 due primarily to an increase
in operating income from refining and marketing operations and to
the inclusion of Partnership operating income in all of 1995
versus only the months of June through December in 1994.
Partially offsetting these increases in operating income was an
increase in corporate expenses, net, resulting primarily from the
nonrecurring recognition in income in 1994 of deferred management
fees resulting from the Merger (see "1994 Compared to 1993 -
Consolidated Results"), the allocation of corporate expenses to
the Partnership in 1994 for the periods prior to the Merger and
an increase in compensation expense.
As a result of the Merger and the Company's change in the
method of accounting for its investment in the Partnership from
the equity method to the consolidation method, the Company did
not report equity in earnings (losses) of and income from the
Partnership for 1995 and the months of June through December in
1994. See "Segment Results" below for a discussion of the
Company's natural gas and natural gas liquids operations,
including 100% of the operations of the Partnership on a pro
forma basis for 1994. Equity in earnings of joint ventures
increased $2.4 million to $4.8 million for 1995 compared to 1994
due to an increase in the Company's equity in earnings of
Javelina. Javelina's earnings increased due primarily to higher
product prices as a result of strong product demand from the
petrochemical industry, as well as lower feedstock costs.
Net interest and debt expense increased $24.3 million to
$101.2 million during 1995 compared to 1994 due primarily to the
inclusion of Partnership interest expense in all of 1995 versus
only the months of June through December in 1994, and to a lesser
extent to the issuance of medium-term notes ("Medium-Term Notes")
in December 1994 and the first half of 1995. See "Liquidity and
Capital Resources." Income tax expense increased $19.4 million
to $35.3 million in 1995 compared to 1994 due primarily to higher
pre-tax income.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and
marketing operations increased $682.2 million, or 63%, to $1.8
billion during 1995 compared to 1994 due to a 49% increase in
sales volumes and a 10% increase in the average sales price per
barrel. The increase in sales volumes was due primarily to
higher purchases for resale of conventional gasoline to supply
rack customers as a result of the Company's conversion of its
Refinery operations to produce primarily reformulated gasoline
("RFG") beginning in the fourth quarter of 1994, and to a 10%
increase in throughput volumes resulting from various unit
improvements completed during the latter part of 1994 and first
half of 1995. The average sales price per barrel increased due
to higher refined product prices, including higher prices
received on sales of RFG and other higher-value products.
Operating income from the Company's refining and marketing
operations increased $62.8 million, or 80%, to $141.5 million
during 1995 compared to 1994 due primarily to an increase in
total throughput margins partially offset by an increase in
operating and other expenses. Throughput margins increased due
to higher margins on sales of RFG and oxygenates of approximately
$46 million, higher margins on sales of petrochemical feedstocks
of approximately $15 million, and an approximate $22 million
increase due to unit improvements noted above and the
nonrecurrence of a turnaround of the Refinery's heavy oil
cracking complex completed during the latter part of 1994, net of
the effect of unit turnarounds which occurred in 1995 as
described below. These increases in throughput margins were
partially offset by an approximate $13 million decrease in
conventional refined product margins ("crack spread") resulting
primarily from depressed gasoline markets in early 1995
attributable to uncertainties pertaining to the general
acceptance of RFG and oxygenates. Costs for the Company's
residual oil ("resid") feedstocks increased in 1995 compared to
1994 as the Company's "resid discount", representing the average
discount at which resid sold to crude oil, decreased from
approximately $3.25 per barrel in 1994 to approximately $2.28 per
barrel in 1995 due to a continuing worldwide decrease in resid
supplies resulting from the addition of new refinery upgrading
capacity and increased production of light sweet crude oil in
relation to heavy crude oil. However, the effect of such
increased resid costs on throughput margins was more than offset
by a decrease in other feedstock costs, including a $7.5 million
benefit from price risk management activities, approximately $7
million of which was attributable to fourth quarter operations.
As a result of the above factors, the Refinery's average
throughput margin per barrel, before operating expenses and
depreciation expense, increased 17%, from $5.36 in 1994 to $6.25
in 1995. Although operating expenses increased approximately $5
million due primarily to higher costs resulting from increased
throughput, operating expenses per barrel decreased by
approximately 5%. Selling and administrative expenses also
increased approximately $5 million due to higher compensation and
other expenses, while depreciation expense increased
approximately $2 million due to capital expenditures incurred
during the latter part of 1994 and in 1995.
During the fourth quarter of 1995, the Company's existing
resid feedstock supply agreement with Arabian American Oil
Company ("Aramco") for approximately 36,000 barrels per day at
market-based prices was extended through the end of 1997. Such
agreement is subject to price renegotiation in the fourth quarter
of 1996 and provides for a reduction in volumes in 1997 to 18,000
barrels per day if a new price cannot be agreed upon. The
Company also entered into a separate one-year resid contract with
Aramco which is effective through the end of 1996 and provides
for deliveries of approximately 18,000 barrels per day at a
market-based pricing formula. The Company also has a contract to
purchase 12,000 barrels per day of resid from South Korea at
market-based prices which was extended during the first quarter
of 1996 for an additional six months. Deliveries under these
agreements provide approximately 80% of the Refinery's daily
resid feedstock requirements. The Company believes that if any
of its existing feedstock arrangements were interrupted or
terminated, adequate supplies of feedstock could be obtained from
other sources or on the open market. However, because the demand
for the type of resid feedstock now processed at the Refinery has
increased in relation to the availability of supply over the past
two years, if any such interruptions did occur, the Company could
be required to incur higher feedstock costs or substitute other
types of resid, thereby producing less favorable operating
results. At the end of 1995, the Company also contracted for
approximately 5,000 barrels per day of domestic crude for use as
a feedstock in the Refinery's crude unit in 1996. The remainder
of the Refinery's resid and crude feedstocks are purchased at
market-based prices under short-term contracts. During the third
quarter of 1995, the renovation of a 13,000-barrel-per-day
methanol plant located in Clear Lake, Texas, jointly owned by the
Company and Hoechst Celanese Chemical Group, Inc. ("Celanese"),
was completed and the plant was placed in service. See
"Liquidity and Capital Resources." In October 1995, the Company
began receiving its full 50% share of the methanol production
capacity from this plant. Such production provides all of the
methanol feedstock presently required for the Refinery's
production of oxygenates used in RFG at a cost which has been
lower than prevailing market prices.
Scheduled maintenance and catalyst changes of the
Refinery's hydrodesulfurization unit (the "HDS Unit") were
completed in December 1993 and April 1995. A turnaround of the
Refinery's heavy oil cracking complex (the "HOC") was completed
in October 1994 and turnarounds of the Refinery's hydrocracker
and naphtha reformer units were completed in April 1995. During
1996, the HDS Unit is scheduled for maintenance and a catalyst
change in the third quarter.
The Company enters into various exchange-traded and
financial instrument contracts with third parties to manage price
risk associated with its refinery feedstock purchases, refined
product inventories and refining operating margins. Although
such activities are intended to limit the Company's exposure to
loss during periods of declining margins, such activities could
tend to reduce the Company's participation in rising margins. In
1995, the Company's refining and marketing segment recognized a
$12.8 million benefit to throughput margins from price risk
management activities compared to a $5.3 million benefit in 1994.
See Note 1 under "Price Risk Management Activities" and Note 5 of
Notes to Consolidated Financial Statements.
Natural Gas
Operating income from the Company's natural gas operations
was $39.5 million for 1995 compared to pro forma operating income
of $30.8 million for 1994. The $8.7 million, or 28%, increase
was due primarily to an approximate $9 million increase in total
gas sales margins and other operating revenues and an approximate
$4 million decrease in operating, selling and administrative
expenses, partially offset by an approximate $5 million decrease
in transportation revenues. Total gas sales margins increased
due to a 25% increase in gas sales volumes, reductions in gas
costs resulting from price risk management activities, and the
nonrecurrence of certain settlements relating to measurement and
customer billing differences which adversely affected 1994. The
increase in total margins resulting from these factors was
partially offset by reduced volumetric gains, discussed below,
and lower unit margins due primarily to an increase in lower-
margin spot and off-system sales. The decrease in operating,
selling and administrative expenses was due primarily to the
nonrecurrence of certain adverse settlements in 1994, including
$6.8 million related to a settlement with the City of Houston
regarding a franchise fee dispute, and lower transportation
expense, partially offset by higher ad valorem tax, maintenance
and compensation expenses. The decrease in transportation
revenues was due primarily to a 9% decrease in average
transportation fees. Both transportation fees and unit sales
margins were adversely affected by surplus industry capacity,
resulting in continued intense competition for market share.
Demand for natural gas continues to be affected by the
operation of various nuclear and coal power plants in the
Company's core service area. At full operation, the South Texas
Project nuclear plant ("STP") in Bay City, Texas and the Comanche
Peak nuclear plant near Ft. Worth, Texas displace approximately
650 MMcf per day and 600 MMcf per day of natural gas demand,
respectively. In addition, coal-fired electrical generation
facilities owned and operated by San Antonio City Public Service
displace a portion of natural gas demand.
The Company's gas sales and transportation businesses are
based primarily on competitive market conditions and contracts
negotiated with individual customers. The Company has been able
to mitigate, to some extent, the effect of competitive industry
conditions by aggressive marketing efforts to increase gas
throughput volumes, particularly in its off-system marketing
business with local distribution and industrial companies
throughout the United States, and by the flexible use of its
strategically located pipeline system. However, gas sales and
transportation margins remain under intense pressure as the
natural gas industry continues to evolve to a customer-oriented,
mature commodity market.
Gas sales are also made, to a significantly lesser extent,
to intrastate customers under contracts which originated in the
1960s and 1970s with 20- to 30-year terms. These contracts were
full requirements, no-notice service contracts governed by a rate
order (the "Rate Order") issued in 1979 by the Railroad
Commission of Texas (the "Railroad Commission"). The Rate Order
provides for the sale of gas under such contracts at its weighted
average cost, as defined ("WACOG"), plus a margin of $.15 per
Mcf. In addition to the cost of gas purchases, WACOG has
included storage, gathering and other fixed costs, including the
amortization of deferred gas costs related to the settlement of
take-or-pay and related claims. The gas sales price for these
contracts is substantially in excess of market clearing levels
and sales volumes under these contracts have been decreasing as
such contracts expire and are not renewed. As a result of
expiring contracts in 1998, the majority of storage costs
previously included in WACOG, including the cost of the Company's
natural gas storage facility (see Note 13 of Notes to
Consolidated Financial Statements), will no longer be recovered
through gas sales rates governed under the Rate Order.
In the course of making gas sales and providing
transportation services to customers, the Company has in the past
experienced overall net volumetric gains due to measurement and
other volumetric differences related to the amounts of gas
received and delivered, which during 1994 resulted in increased
gas sales revenues of approximately $20 million. However, as a
result of the implementation by the Company of changes to
measurement standards promulgated by the American Gas
Association, the expiration of certain gas purchase contracts in
February 1995 and the continuing reduction in WACOG-based gas
sales discussed above, revenues resulting from such net
volumetric gains decreased to approximately $10 million in 1995
and are expected to decline further in 1996.
The Company enters into various exchange-traded and
financial instrument contracts with third parties to manage price
risk associated with its natural gas storage and marketing
operations. Such activities are intended to manage price risk
but may result in gas costs either higher or lower than those
that would have been incurred absent such activities. In 1995,
the Company's natural gas segment recognized $12 million in gas
cost reductions from price risk management activities, $5.6
million of which was recognized in the fourth quarter, compared
to $2.1 million in 1994 on a pro forma basis. An additional $.8
million and $6.8 million was deferred at December 31, 1995 and
1994, respectively, which is recognized as a reduction to the
cost of gas in the subsequent year. See Note 1 under "Price Risk
Management Activities" and Note 5 of Notes to Consolidated
Financial Statements.
Natural Gas Liquids
Operating income from the Company's NGL operations was
$43.7 million for 1995 compared to pro forma operating income of
$38.9 million for 1994. The $4.8 million, or 12%, increase was
due primarily to an increase in NGL margins and a decrease in
transportation and fractionation costs, partially offset by an
approximate $2 million decrease in revenues from transportation
and fractionation of third party plant production. NGL margins
increased due to a decrease in fuel and shrinkage costs resulting
from a 20% decrease in the average cost of natural gas, which
more than offset a 4% decrease in the average NGL market price.
Average natural gas costs decreased due to surplus industry
capacity and benefits from price risk management activities,
while average NGL prices decreased due to weak ethane prices
resulting from above-normal inventory levels. NGL production
volumes increased slightly in 1995 compared to 1994 as volume
increases in 1995 resulting from the addition of new natural gas
supplies under processing agreements with natural gas producers
and operational improvements and production enhancements at
certain of the Company's NGL plants were mostly offset by volume
decreases resulting primarily from the sale of the Company's two
West Texas processing plants in August 1995.
The Company also enters into various exchange-traded and
financial instrument contracts with third parties to manage the
cost of gas consumed in its NGL operations. Such activities are
intended to manage price risk but may result in fuel and
shrinkage costs either higher or lower than those that would have
been incurred absent such activities. In 1995, the Company's NGL
segment recognized $4.1 million in fuel and shrinkage cost
reductions from price risk management activities. In 1994, the
effect of such activities on fuel and shrinkage costs was not
significant. An additional $3 million was deferred at
December 31, 1995 which will be recognized as a reduction to fuel
and shrinkage costs in 1996. See Note 1 under "Price Risk
Management Activities" and Note 5 of Notes to Consolidated
Financial Statements.
The Company's NGL operations benefit from the strategic
location of its facilities in relation to natural gas supplies
and markets, particularly in South Texas which is a core supply
area for the Company's natural gas and NGL operations.
Currently, approximately 92% of the Company's NGL production
comes from plants in South Texas and the Texas Gulf Coast. As
the Company's existing South Texas NGL pipeline and fractionation
facilities are operating at or near capacity, the Company
anticipates incurring additional capital expenditures in the
future in order to develop incremental South Texas NGL production
opportunities. The Company's NGL operations should benefit in
the longer term from the expected continued growth in demand for
NGLs as petrochemical feedstocks and in the production of methyl
tertiary butyl ether ("MTBE"). A substantial portion of the
Company's butane production is processed internally as feedstock
for the Refinery's MTBE Plant. The demand for NGLs, particularly
natural gasoline, will continue to be affected seasonally,
however, by Environmental Protection Agency ("EPA") regulations
limiting gasoline volatility during the summer months.
Other
Pro forma corporate general and administrative expenses and
other, net, increased $13.4 million during 1995 compared to 1994
due primarily to the nonrecurring recognition in income in 1994
of deferred management fees resulting from the Merger, as noted
above, and an increase in compensation expense.
1994 COMPARED TO 1993
Consolidated Results
The Company reported net income of $26.9 million, or $.40
per share, for the year ended December 31, 1994 compared to $36.4
million, or $.82 per share, for the year ended December 31, 1993.
For the fourth quarter of 1994, net income was $3.9 million, or
$.02 per share, compared to a net loss of $15.2 million, or $.36
per share, for the fourth quarter of 1993. The 1993 fourth
quarter and total year results were adversely 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. See "Segment Results - Refining and Marketing"
below. Although operating income increased during 1994 compared
to 1993, a decrease in equity in earnings of and income from the
Partnership, an increase in net interest and debt expense and the
nonrecurring gain on disposition of the Company's natural gas
distribution operations during the third quarter of 1993,
partially offset by a decrease in income tax expense, resulted in
a decrease in net income and earnings per share for the year.
Earnings per share was also reduced by an increase in preferred
stock dividend requirements resulting from the above-noted
issuance in March 1994 of 3.45 million shares of Energy's $3.125
Convertible Preferred Stock.
Operating revenues increased $615.2 million, or 50%, to
$1.8 billion during 1994 compared to 1993 due primarily to the
inclusion in 1994 of operating revenues attributable to the
Partnership beginning June 1, 1994, and to a lesser extent to an
increase in operating revenues from refining and marketing
operations which is explained below under "Segment Results." The
increases attributable to these factors were partially offset by
a decrease in Other operating revenues due to the elimination of
management fee revenues received from the Partnership resulting
from the May 31, 1994 Merger, and a decrease in natural gas sales
and transportation revenues resulting from the 1993 disposition
of the Company's natural gas distribution operations noted above.
Operating income increased $50.4 million, or 67%, to $125.9
million during 1994 compared to 1993 due primarily to the
inclusion of Partnership operating income for the seven months
commencing June 1, 1994. Operating income also benefitted from
the nonrecurring recognition in income at the time of the Merger
of the $6.7 million remaining balance of deferred management
fees. Such deferred management fees arose in connection with the
formation of the Partnership in 1987 at which time the Company
entered into a management agreement with the Partnership whereby
the Company would provide, over a ten-year period, certain
management services to the Partnership. The Company deferred a
portion of the gain generated upon the Partnership formation
which represented the profit element in providing such future
services. At the time of the Merger, the remaining $6.7 million
unamortized portion of such deferred gain was recognized.
The Company's equity in losses of and income from the
Partnership for the five months of 1994 preceding the Merger was
$(10.7) million compared to equity in earnings of and income from
the Partnership of $23.7 million in 1993. Included in the 1994
amount was the Company's $6.8 million equity interest in the cost
of a settlement among the Company, the Partnership and the City
of Houston regarding a franchise fee dispute noted above under
"1995 Compared to 1994 - Segment Results - Natural Gas." For a
discussion of the Company's natural gas and natural gas liquids
operations, including 100% of the operations of the Partnership
on a pro forma basis, see "Segment Results" below.
Net interest and debt expense increased $39.7 million in
1994 compared to 1993 due primarily to the inclusion of the
Partnership's interest expense subsequent to the Merger and to a
decrease in capitalized interest resulting from the placing in
service at the Refinery of the MTBE plant during the second
quarter of 1993 and the MTBE/TAME complex and reformate splitter
unit during the fourth quarter of 1993. Income tax expense
decreased in 1994 compared to 1993 due to lower pre-tax income
and the nonrecurrence of the 1993 third quarter charge to
earnings of $8.2 million resulting from the effect of a one-
percent increase in the corporate income tax rate on the
Company's December 31, 1992 balance of deferred income taxes.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and
marketing operations increased $45.6 million, or 4%, during 1994
compared to 1993 due primarily to a 5% increase in average daily
sales volumes. Sales and throughput volumes increased as a
result of placing in service various new Refinery units in 1993,
as discussed above. The average sales price per barrel in 1994
was basically unchanged from 1993 as weak refined product prices
during 1994, resulting from an increase in gasoline supply due to
increased refinery upgrading capacity, high refinery utilization
rates and increased gasoline imports, were offset by a change in
product mix resulting from increased sales of MTBE during 1994,
due to a full year's operation of the MTBE plant, and initial
sales of higher-valued RFG during November and December of 1994.
Operating income from the Company's refining and marketing
operations increased $3.3 million, or 4%, during 1994 compared to
1993 due primarily to the nonrecurrence of a write-down in the
carrying value of refinery inventories during the fourth quarter
of 1993 which reduced 1993 operating income by $27.6 million.
Excluding the effect of the 1993 inventory write-down, refining
and marketing operating income decreased $24.3 million, or 24%,
in 1994 compared to 1993 due to a decrease in throughput margins
and an increase in operating costs and depreciation expense.
Throughput margins decreased due to narrower discounts for the
Company's resid feedstocks of approximately $30 million, lower
conventional refined product margins of approximately $12
million, and lower margins on sales of MTBE of approximately $7
million due to higher costs for the Company's methanol
feedstocks, which more than offset higher margins on sales of RFG
and other premium products of approximately $21 million and an
approximate $19 million improvement due to a 7% increase in
average daily throughput volumes. As a result of the above
factors, the Refinery's average throughput margin per barrel,
before operating costs and depreciation expense, decreased from
$5.99 in 1993 (excluding the effect of the inventory write-down)
to $5.36 in 1994. Operating costs and depreciation expense
increased approximately $9 million and $6 million, respectively,
in 1994 compared to 1993 due to placing in service various new
Refinery units in 1993, as discussed above, although operating
costs per barrel were basically unchanged due to increased
throughput volumes.
Natural Gas
Pro forma operating income from the Company's natural gas
operations decreased $42.6 million, or 58%, during 1994 compared
to 1993 due to settlements of certain measurement, fuel usage and
customer billing differences which benefitted 1993 by $11 million
but negatively impacted 1994 by $3.1 million, lower gas sales
margins, a decrease in transportation revenues, and an increase
in operating and general expenses. Gas sales margins were lower
due primarily to a $16.6 million decrease in gas cost reductions
resulting from price risk management activities, reduced demand
for natural gas resulting from unseasonably mild weather during
the 1994 fourth quarter and the return to service of the STP
during the 1994 second quarter, and reduced recoveries of fixed
costs, principally gas gathering costs, as a result of a customer
audit settlement effective July 1, 1993. The decrease in
transportation revenues was due primarily to a 5% decrease in
average transportation fees also resulting from reduced gas
demand. Sales and transportation volumes were flat in 1994
compared to 1993 as volume increases resulting from business
generated in connection with the implementation of FERC Order 636
and the west-to-east shift in natural gas supply patterns were
offset by volume decreases resulting from the above-noted return
to service of the STP in 1994 and unseasonably mild weather
during the 1994 fourth quarter. Operating and general expenses
increased due primarily to the above-noted 1994 franchise fee
settlement with the City of Houston.
Natural Gas Liquids
Pro forma operating income from the Company's NGL
operations decreased $1.4 million, or 3%, during 1994 compared to
1993 due to a decrease in revenues from transporting and
fractionating volumes for third parties and an increase in
transportation and fractionation expense, partially offset by a
slight increase in NGL unit margins, a 3% increase in NGL
production volumes and a decrease in operating and general
expenses, primarily maintenance expense. NGL unit margins
increased due to a decrease in fuel and shrinkage costs resulting
from an 11% decrease in the average cost of natural gas, which
more than offset a 6% decrease in the average NGL market price.
Average natural gas costs decreased as a result of milder weather
experienced during the fourth quarter of 1994, higher industry-
wide natural gas storage inventories and the return to service of
the STP during the 1994 second quarter, while average NGL prices
decreased due to continued weak refined product prices during the
first part of 1994.
Other
Pro forma corporate general and administrative expenses and
other, net, decreased in 1994 compared to 1993 due to the
recognition in income in 1994 of deferred management fees, as
noted above, and a decrease in employee benefit expenses
resulting from various cost containment measures implemented by
the Company in 1994.
OUTLOOK
The following discussion of the outlook for the Company's
three principal business areas contains certain forward-looking
statements reflecting the Company's current expectations of the
manner in which the various factors discussed therein may affect
its business in the near future. The energy business has a history
of volatility and there is no assurance that the Company's
expectations will be realized or that unexpected events will not
have an adverse impact on the Company's business.
Refining and Marketing
Although refining margins are expected to remain volatile,
several key factors look promising for the Company's refining and
marketing operations. With regard to feedstocks, the Company's
resid discount, which narrowed considerably over the last two
years due primarily to a worldwide decrease in resid supplies
resulting from increased production of light sweet crudes and the
addition of new refinery upgrading capacity, is expected to show
gradual improvement as crude quality is now stabilizing and much
of the new upgrading capacity has already come on line. Refinery
upgrading capacity is not expected to keep pace with new crude
distillation capacity over the next several years, which should
further increase resid supplies. However, recent press reports
indicate that Iraq may soon resume sales of crude oil into world
markets. While the export of heavier Iraqi crudes could lead to
increased resid production, such exports could also depress crude
oil prices which in turn could adversely affect inventory values
and lead to volatile changes in the resid discount and other
price relationships important to the Company's results of
operations. Moreover, industry publications report that Aramco
plans to begin operation of certain new resid conversion units in
1998 at the Ras Tanura refining complex in Saudi Arabia. As a
result, the production of resid at Ras Tanura for export would be
significantly reduced. A majority of the resid feedstock
purchased by the Company from Aramco is produced at Ras Tanura.
Accordingly, a reduction in resid production at Ras Tanura could
adversely affect the price or availability of resid feedstocks in
the future. The cost of methanol feedstocks used in the
production of MTBE should benefit from a full year's operation of
the Company's joint venture methanol plant.
On the product side, domestic gasoline demand, which
increased by 1.5% and 1.7% in 1995 and 1994, respectively, is
expected to continue to grow over the next several years due to
slowing gains in fuel efficiency for passenger cars, higher sales
of light trucks and sport-utility vehicles which average fewer
miles per gallon than passenger cars, higher speed limits in
several states and an increasing number of miles driven. The
demand for oxygenates, including MTBE, is expected to increase
due to the implementation of the California Air Resources Board's
"CARB 2" gasoline program in March 1996 and to an expected increase in
worldwide demand for oxygenates to replace the octane displaced
by the worldwide movement to reduce the use of lead in gasoline.
The demand for RFG, which currently represents about 25% of the
total demand for gasoline in the U.S., also may increase if areas
of the country whose ozone emissions exceeded permitted levels in
1995 choose to "opt in" to the RFG program to reduce their
emission levels. With regard to operations, refinery throughput
volumes are expected to increase due to the full year effect of
various unit improvements and enhancements made during 1995 and
no significant unit turnarounds being scheduled in 1996.
Natural Gas
Due to its desirability as a clean-burning fuel, demand for
natural gas has remained strong and is expected to continue to
grow due primarily to increasing demand in utility and non-
utility electric generation applications and in industrial,
particularly cogeneration, applications. Natural gas supplies
should be sufficient to meet the growth in natural gas demand due
to anticipated increases in domestic productive and storage
capacity and in Canadian imports. As a result of the
implementation of FERC Order No. 636 in 1993, the Company's
natural gas operations are continuing to adjust to the
transformation of the U.S. natural gas industry into a more
deregulated, market-oriented environment where increasing
competition and market efficiencies are pressuring margins for
all categories of business. In response to such conditions, the
Company is continuing to emphasize growth of off-system sales by
diversification of its customer base through marketing offices
located throughout the nation and in Canada, and to further
develop and expand its slate of value-added services, such as gas
gathering and related activities, gas processing, volume and
capacity management, price risk management and power marketing.
In addition, to capitalize on the trend of west-to-east movement
of gas across the United States caused by increased production in
western supply basins, pipeline expansions from such basins and
Canada to the West Coast, and growing natural gas demand in the
East and Southeast, the Company intends to further increase its
capacity to move gas across Texas through pipeline
debottlenecking and other projects. As a result of the
development of these and other natural gas business
opportunities, the Company believes that it should be able to
increase its natural gas volumes in 1996.
Natural Gas Liquids
The Company's NGL operations benefit from its strong
integration with the Company's natural gas and refining and
marketing operations. The ability to process natural gas, and
fractionate and market NGLs, are value-added services offered to
producers which attract additional quantities of gas to the
Company's pipeline system, while production from the Company's
NGL plants provides butane feedstock for the production of
oxygenates at the Company's refinery. The demand for NGLs is
expected to remain strong as a result of continued economic
growth, petrochemical plant expansions and the addition of new
independent petrochemical facilities, and increased production of
oxygenated and reformulated gasolines. NGL margins softened
somewhat during the latter half of 1995 due to above-normal
inventory levels and lower product prices and are expected to
continue at such levels in 1996. The Company is continuing to
emphasize the addition of new natural gas supplies under
processing agreements with natural gas producers and the
development and expansion of market alternatives for its NGL
production. In order to accommodate an increase in natural gas
supplies, the Company increased the processing capacity at
certain of its NGL plants in 1995 through various expansion
projects and the addition of compression facilities which
resulted in an increase in NGL production volumes at such plants.
The full year effect of such plant expansions and improvements
should further increase production volumes in 1996.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by the Company's operating activities
increased $87.7 million during 1995 compared to 1994 due
primarily to the increase in income described above under
"Results of Operations" and to the changes in current assets and
current liabilities detailed in Note 1 of Notes to Consolidated
Financial Statements under "Statements of Cash Flows." Included
in such changes was a decrease in inventories, primarily refining
inventories, resulting from a decrease in volumes available under
crude feedstock contracts, above-normal low-sulphur HOC feedstock
inventories at the end of 1994 in anticipation of a turnaround of
the HDS Unit in the first quarter of 1995, and above-normal
refined product inventories at the end of 1994 attributable to
uncertainties related to the implementation of the new RFG
regulations. In addition, the increase in accounts payable in
1995 compared to the decrease in 1994 was due primarily to
payments in 1994 related to capital additions accrued at the end
of 1993. During 1995, the Company utilized the cash provided by
its operating activities, proceeds from the issuance of Medium-
Term Notes, and proceeds from the sale of two NGL processing
plants as noted above under "Results of Operations - 1995
Compared to 1994 - Segment Results - Natural Gas Liquids" to fund
capital expenditures and deferred turnaround and catalyst costs,
to reduce borrowings under its revolving bank credit and letter
of credit facility, to repay principal on various outstanding
nonbank debt, to pay common and preferred stock dividends, and to
redeem a portion of its outstanding Cumulative Preferred Stock,
$8.50 Series A ("Series A Preferred Stock").
In the first quarter of 1995, the Securities and Exchange
Commission declared effective Energy's shelf registration
statement to offer up to $250 million principal amount of
additional debt securities, including Medium-Term Notes, $96.5
million of which had been issued through January 31, 1996. The
net proceeds received from this offering have been used, and will
be used in the future, for general corporate purposes, including
the repayment of existing indebtedness, financing of capital
projects and additions to working capital. See Note 4 of Notes
to Consolidated Financial Statements. The Company's ratio of
earnings to fixed charges, as computed based on rules promulgated
by the Commission, was 1.78 for the year ended December 31,
1995.
Effective November 1, 1995, Energy replaced its $250
million revolving bank credit and letter of credit facility with
a new five-year, unsecured $300 million revolving bank credit and
letter of credit facility that is available for general corporate
purposes including working capital needs and letters of credit.
The new facility has reduced financing rates, commitment fees and
letter of credit pricing, and both fewer and less restrictive
covenants. The new facility has three primary financial
covenants, including a minimum fixed charge coverage ratio of 1.6
to 1.0 for each period of four consecutive nonturnaround
quarters, a maximum debt to capitalization ratio of 57.5% and a
minimum net worth test. In addition, certain events involving an
actual or potential change of control of Energy may result in an
event of default under the new facility and could thereupon
result in a cross-default to other financial obligations of the
Company. As of December 31, 1995, Energy had approximately $178
million available under this committed bank credit facility for
additional borrowings and letters of credit. As defined under
the new bank credit facility, Energy's fixed charge coverage
ratio for the four quarters ended December 31, 1995 was 2.0 to
1.0, while its debt to capitalization ratio at December 31, 1995
was 52.0%. Energy also has three separate uncommitted bank
letter of credit facilities which are being used to support the
Company's Refinery feedstock trading activity. As of December
31, 1995, letters of credit aggregating approximately $34 million
were issued and outstanding under these separate uncommitted
letter of credit facilities. In addition, Energy has
$125 million of unsecured short-term bank credit lines which are
uncommitted and unrestricted as to use. As of December 31, 1995,
no amounts were outstanding under these short-term lines. The
Company's long-term debt includes Valero Management Partnership,
L.P.'s First Mortgage Notes (the "First Mortgage Notes"), $476.1
million of which was outstanding at December 31, 1995. The
indenture of mortgage and deed of trust pursuant to which the
First Mortgage Notes were issued also contains various
restrictive covenants. The Company was in compliance with all
covenants contained in its various debt facilities as of
December 31, 1995. Debt service on the Company's non-bank debt
for both principal and interest, including payments into escrow
for both principal and interest on the First Mortgage Notes, will
be $187.7 million, $160.9 million, $153.5 million, $147.4 million
and $149.1 million for the years 1996 through 2000, respectively.
See Notes 3 and 4 of Notes to Consolidated Financial Statements.
In December 1995, Energy redeemed 57,500 shares of its
Series A Preferred Stock at $100 per share, reducing the amount
of such stock outstanding to 69,000 shares at December 31, 1995.
An additional 57,500 shares will be redeemed in December 1996 at
$100 per share. See Note 7 of Notes to Consolidated Financial
Statements. 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, 1995, Energy had repurchased 505,000
shares at an average price of $23.11 per share, with no shares
being repurchased in 1995. The Company intends to repurchase
additional shares under this authorization if the price of the
Common Stock reaches levels which the management of the Company
considers to be undervalued.
During 1995, the Company expended approximately $165
million for capital investments, including capital expenditures,
deferred turnaround and catalyst costs and investments in and
advances to joint ventures. Of this amount, $125 million related
to refining and marketing operations while $34 million related to
natural gas and NGL operations. Included in the refining and
marketing amount was $36 million for turnarounds of the
Refinery's hydrodesulfurization, hydrocracker and reformer units
and $60 million for renovation of a methanol plant located in
Clear Lake, Texas. For 1996, the Company currently expects to
incur approximately $150 million for capital expenditures,
deferred turnaround and catalyst costs, and investments and
related expenditures. Such amount excludes any expenditures
related to the Company's investment in Proesa which is discussed
separately below.
The Company currently owns a 35% interest in Productos
Ecologicos, S.A. de C.V. ("Proesa"), a Mexican corporation which
is involved in a project (the "Project") to design, construct and
operate a plant in Mexico to produce MTBE. The plant, to be
constructed at a site near the Bay of Campeche, has been
estimated to cost approximately $400 million (exclusive of working
capital, capitalized interest and financing costs), and to produce
approximately 17,000 barrels of MTBE per stream day. The Company
and Proesa's other shareholders have entered into a letter of
understanding under which the Company's ownership interest in
Proesa would increase to 45%. Although this arrangement has not
been formally documented and is subject to certain conditions,
the Company has funded 45% of the Project's costs since August
1994. Because of the substantial devaluation of the Mexican peso
beginning in December 1994 and the resulting increase in Mexican
interest rates and deterioration of Mexican economic conditions,
in January 1995, the Company suspended further investment in the
Project pending the resolution of certain key issues related to
the Project. During 1995 and continuing in 1996, the Company
engaged in discussions with Petroleos Mexicanos, S.A. ("Pemex"),
the Mexican state-owned oil company, and the Project participants
in order to renegotiate the purchase and sales agreements between
Proesa and Pemex and to reach definitive agreement regarding the
participants' ownership interests in Proesa and their funding
commitments to the Project, including procedures for funding any
possible cost overruns. Despite some indications that Mexican
economic conditions are beginning to improve, there can be no
assurance that mutually satisfactory agreements can be reached
between Proesa and Pemex and among the Project participants, or
that financing satisfactory to all participants can be arranged.
If the Project is terminated, there can be no assurance that the
Company's investment in the Project could be recovered.
At December 31, 1995, the Company had a total investment
in the Project of approximately $16.5 million, and Proesa had
incurred additional obligations totalling approximately $10
million which have not been funded by its owners. Proesa has
also furnished a surety bond in connection with the plant's first
year of operations under an existing MTBE sales agreement between
Proesa and Pemex. Based on the exchange rate at January 31,
1996, the insurable value of such surety bond was approximately
$5.6 million. Proesa currently has no independent source of
funding. Therefore, in the event of any cash requirements
resulting from the above, Proesa would necessarily request
additional funding from its owners. See Item 1. "Business -
Refining and Marketing - Proesa MTBE Plant" and Note 6 of Notes
to Consolidated Financial Statements.
The Energy Board of Directors increased the quarterly
dividend on its Common Stock from $.11 per share to $.13 per
share effective in the fourth quarter of 1993. Such dividend
rate has remained unchanged throughout 1994 and 1995. Dividends
are considered quarterly by the Energy Board of Directors, and
may be paid only when approved by the Board. Because appropriate
levels of dividends are determined by the Board on the basis of
earnings and cash flows, the Company cannot assure the
continuation of Common Stock dividends at any particular level.
The Company believes it has sufficient funds from
operations, and to the extent necessary, from the public and
private capital markets and bank market, to fund its ongoing
operating requirements. The Company expects that it will raise
additional funds from time to time through equity or debt
financings, including borrowings under bank credit agreements;
however, except for Medium-Term Notes or other debt securities
that may be issued from time to time under the $250 million shelf
registration statement discussed above, the Company has no
specific financing plans as of the date hereof.
The Company's refining and marketing operations have a
concentration of customers in the oil refining industry and spot
and retail gasoline markets. The Company's natural gas
operations have a concentration of customers in the natural gas
transmission and distribution industries while its NGL operations
have a concentration of customers in the refining and
petrochemical industries. These concentrations of customers may
impact the Company's overall exposure to credit risk, either
positively or negatively, in that the customers in each specific
industry segment may be similarly affected by changes in economic
or other conditions. However, the Company believes that its
portfolio of accounts receivable is sufficiently diversified to
the extent necessary to minimize potential credit risk.
Historically, the Company has not had any significant problems
collecting its accounts receivable. The Company's accounts
receivable are generally not collateralized.
The Company is subject to environmental regulation at the
federal, state and local levels. The Company's capital
expenditures for environmental control and protection for its
refining and marketing operations totalled approximately $5
million in 1995 and are expected to be approximately $9 million
in 1996. These amounts are exclusive of any amounts related to
constructed facilities for which the portion of expenditures
relating to environmental requirements is not determinable.
Capital expenditures for environmental control and protection for
the Company's natural gas and NGL operations have not been
material to date and are not expected to be material in 1996.
The Refinery was completed in 1984 under more stringent
environmental requirements than many existing United States
refineries, which are older and were built before such
environmental regulations were enacted. As a result, the Company
believes that it may be able to more easily comply with present
and future environmental legislation. Within the next several
years, all U.S. refineries must obtain operating permits under
provisions of the Clean Air Act Amendments of 1990 (the "Clean
Air Act"). In addition, Clean Air Act provisions will require
many of the Company's gas processing plants and gas pipeline
facilities to obtain new operating permits. However, the Clean
Air Act is not expected to have any significant adverse impact on
the Company's operations and the Company does not anticipate that
it will be necessary to expend any material amounts in addition
to those mentioned above to comply with such legislation. The
Company is not aware of any material environmental remediation
costs related to its operations. Accordingly, no amount has been
accrued for any contingent environmental liability.
In October 1995, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation."
This statement encourages entities to adopt the fair value method
of accounting for employee stock compensation plans for fiscal
years beginning after December 15, 1995, but allows an entity to
continue to measure compensation cost for those plans using the
intrinsic value based method of accounting prescribed by
Accounting Principles Board ("APB") Opinion No. 25, "Accounting
for Stock Issued to Employees." The Company intends to continue
to measure compensation cost for its employee stock compensation
plans in accordance with APB Opinion No. 25.
In March 1995, the FASB issued SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of." This statement establishes accounting
standards for the impairment of long-lived assets, certain
identifiable intangibles, and goodwill related to assets to be
held and used, and for long-lived assets and certain identifiable
intangibles to be disposed of, and is effective for fiscal years
beginning after December 15, 1995, although earlier
implementation is permitted. This statement is required to be
applied prospectively for assets to be held and used, while its
initial application to assets held for disposal is required to be
reported as the cumulative effect of a change in accounting
principle. The Company plans to adopt this statement as of
January 1, 1996. Based on information currently known by the
Company, such adoption would not have a significant impact on the
Company's consolidated financial statements.
ITEM 8. FINANCIAL STATEMENTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders
of Valero Energy Corporation:
We have audited the accompanying consolidated balance
sheets of Valero Energy Corporation (a Delaware corporation) and
subsidiaries as of December 31, 1995 and 1994, 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, 1995. These financial
statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
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,
1995 and 1994, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1995, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
San Antonio, Texas
February 14, 1996
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31,
A S S E T S 1995 1994
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . . . . . . . . $ 28,054 $ 26,210
Cash held in debt service escrow . . . . . . . . . . . . . . . . . . . . . . . . . . . 36,627 35,441
Receivables, less allowance for doubtful accounts of $1,193 (1995) and
$2,770 (1994). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 339,189 232,273
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140,822 182,089
Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . . . . . . . 29,530 31,842
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,321 25,017
621,543 532,872
PROPERTY, PLANT AND EQUIPMENT - including construction in
progress of $37,472 (1995) and $115,785 (1994), at cost. . . . . . . . . . . . . . . . 2,697,494 2,672,715
Less: Accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . . . . . . 622,123 531,501
2,075,371 2,141,214
INVESTMENT IN AND ADVANCES TO JOINT VENTURES . . . . . . . . . . . . . . . . . . . . . . 41,890 41,162
DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . . . . . . . . 137,876 116,110
$2,876,680 $2,831,358
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 . . . . . . . . . . . . . . . . . . . . . . . . . $ 81,964 $ 62,230
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312,672 341,694
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31,104 19,693
Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,542 37,150
468,282 460,767
LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . . . . . . . . 1,035,641 1,021,820
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276,013 264,236
DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . . . . . . . 56,031 59,405
REDEEMABLE PREFERRED STOCK, SERIES A, issued 1,150,000 shares,
outstanding 69,000 (1995) and 126,500 (1994) shares. . . . . . . . . . . . . . . . . . 6,900 12,650
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY:
Preferred stock, $1 par value - 20,000,000 shares authorized including
redeemable preferred shares:
$3.125 Convertible Preferred Stock, issued and outstanding
3,450,000 (1995 and 1994) shares ($172,500 aggregate
involuntary liquidation value) . . . . . . . . . . . . . . . . . . . . . . . . . 3,450 3,450
Common stock, $1 par value - 75,000,000 shares authorized; issued
43,739,380 (1995) and 43,463,869 (1994) shares . . . . . . . . . . . . . . . . . . . 43,739 43,464
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 530,177 536,613
Unearned Valero Employees' Stock Ownership Plan Compensation . . . . . . . . . . . . . (11,318) (13,706)
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 467,943 442,659
Treasury stock, 6,904 (1995) and -0- (1994) common shares, at cost . . . . . . . . . . (178) -
1,033,813 1,012,480
$2,876,680 $2,831,358
<FN>
See Notes to Consolidated Financial Statements.
</FN>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Per Share Amounts)
Year Ended December 31,
1995 1994 1993
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . $3,019,792 $1,837,440 $1,222,239
COSTS AND EXPENSES:
Cost of sales and operating expenses. . . . . . . . . . . . 2,652,556 1,561,225 1,021,403
Selling and administrative expenses . . . . . . . . . . . . 78,120 66,258 68,599
Depreciation expense. . . . . . . . . . . . . . . . . . . . 100,325 84,032 56,733
Total . . . . . . . . . . . . . . . . . . . . . . . . . . 2,831,001 1,711,515 1,146,735
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . 188,791 125,925 75,504
EQUITY IN EARNINGS (LOSSES) OF AND INCOME FROM:
Valero Natural Gas Partners, L.P. . . . . . . . . . . . . . - (10,698) 23,693
Joint ventures. . . . . . . . . . . . . . . . . . . . . . . 4,827 2,437 (1,688)
GAIN ON DISPOSITION OF ASSETS AND OTHER INCOME, NET. . . . . . 2,742 2,039 7,897
INTEREST AND DEBT EXPENSE:
Incurred. . . . . . . . . . . . . . . . . . . . . . . . . . (105,921) (79,286) (49,517)
Capitalized . . . . . . . . . . . . . . . . . . . . . . . . 4,699 2,365 12,335
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . . . 95,138 42,782 68,224
INCOE TAX EXPENSE. . . . . . . . . . . . . . . . . . . . . . . 35,300 15,900 31,800
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 59,838 26,882 36,424
Less: Preferred stock dividend requirements. . . . . . . . 11,818 9,490 1,262
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . $ 48,020 $ 17,392 $ 35,162
EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . . . . . $ 1.10 $ .40 $ .82
DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . . . . . $ .52 $ .52 $ .46
<FN>
See Notes to Consolidated Financial Statements.
</FN>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Dollars)
Convertible
Preferred Number of Common Additional Unearned
Stock Common Stock Paid-in VESOP Retained Treasury
$1 Par Shares $1 Par Capital Compensation Earnings Stock
BALANCE, December 31, 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)
Net income . . . . . . . . . . . - - - - - 26,882 -
Dividends on Series A
Preferred Stock. . . . . . . . - - - - - (1,173) -
Dividends on Convertible
Preferred Stock. . . . . . . . - - - - - (7,427) -
Dividends on Common Stock. . . . - - - - - (22,554) -
Issuance of Convertible
Preferred Stock, net . . . . . 3,450 - - 164,428 - - -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . . . - - - - 2,252 - -
Shares repurchased and
shares issued pursuant
to employee stock plans
and other. . . . . . . . . . . - 72,184 72 882 - - 3,371
BALANCE, December 31, 1994 . . . . 3,450 43,463,869 43,464 536,613 (13,706) 442,659 -
Net income . . . . . . . . . . . - - - - - 59,838 -
Dividends on Series A
Preferred Stock. . . . . . . . - - - - - (1,075) -
Dividends on Convertible
Preferred Stock. . . . . . . . - - - - - (10,781) -
Dividends on Common Stock. . . . - - - - - (22,698) -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . . . - - - - 2,388 - -
Deficiency payment tax
effect . . . . . . . . . . . . - - - (9,106) - - -
Shares repurchased and
shares issued pursuant to
employee stock plans and
other. . . . . . . . . . . . . - 275,511 275 2,670 - - (178)
BALANCE, December 31, 1995 . . . . $3,450 43,739,380 $43,739 $530,177 $(11,318) $467,943 $ (178)
<FN>
See Notes to Consolidated Financial Statements.
</FN>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year Ended December 31,
1995 1994 1993
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 59,838 $ 26,882 $ 36,424
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation expense . . . . . . . . . . . . . . . . . . . . . . . . 100,325 84,032 56,733
Amortization of deferred charges and other, net. . . . . . . . . . . 34,955 20,844 21,078
Inventory write-down to market . . . . . . . . . . . . . . . . . . . - - 27,588
Gain on disposition of assets, net of other
nonoperating charges. . . . . . . . . . . . . . . . . . . . . . . . - - (6,878)
Changes in current assets and current liabilities. . . . . . . . . . (31,636) (95,597) 9,805
Deferred income tax expense . . . . . . . . . . . . . . . . . . . . 4,700 12,200 15,300
Equity in (earnings) losses in excess of distributions:
Valero Natural Gas Partners, L.P.. . . . . . . . . . . . . . . . . - 16,179 (4,970)
Joint ventures. . . . . . . . . . . . . . . . . . . . . . . . . . (4,304) (2,437) 1,688
Changes in deferred items and other, net . . . . . . . . . . . . . . (8,056) 6,008 (15,487)
Net cash provided by operating activities. . . . . . . . . . . . . 155,822 68,111 141,281
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . (124,619) (80,738) (136,594)
Deferred turnaround and catalyst costs . . . . . . . . . . . . . . . . . (35,590) (21,999) (23,054)
Investment in and advances to joint ventures, net. . . . . . . . . . . . (2,018) (9,229) (6,167)
Investment in Valero Natural Gas Partners, L.P.. . . . . . . . . . . . . - (124,264) -
Assets leased to Valero Natural Gas Partners, L.P. . . . . . . . . . . . - (1,886) -
Distributions from Valero Natural Gas Partners, L.P. . . . . . . . . . . - 2,789 -
Dispositions of property, plant and equipment. . . . . . . . . . . . . . 13,531 4,504 30,720
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70 898 991
Net cash used in investing activities. . . . . . . . . . . . . . . . . (148,626) (229,925) (134,104)
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease in short-term debt. . . . . . . . . . . . . . . . . . . . . . . - - (6,700)
Long-term debt reduction, net. . . . . . . . . . . . . . . . . . . . . . (61,357) (27,285) (15,000)
Long-term borrowings, net. . . . . . . . . . . . . . . . . . . . . . . . 96,500 92,000 32,000
Increase in cash held in debt service escrow for principal . . . . . . . (1,875) (22,768) -
Common stock dividends . . . . . . . . . . . . . . . . . . . . . . . . . (22,698) (22,554) (19,822)
Preferred stock dividends. . . . . . . . . . . . . . . . . . . . . . . . (11,856) (8,600) (1,271)
Issuance of Convertible Preferred Stock, net . . . . . . . . . . . . . . - 167,878 -
Issuance of common stock, net. . . . . . . . . . . . . . . . . . . . . . 1,684 3,251 3,844
Repurchase of Series A Preferred Stock . . . . . . . . . . . . . . . . . (5,750) (1,150) (1,150)
Net cash provided by (used in) financing activities. . . . . . . . . . (5,352) 180,772 (8,099)
NET INCREASE (DECREASE) IN CASH AND TEMPORARY
CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,844 18,958 (922)
CASH AND TEMPORARY CASH INVESTMENTS AT
BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . . . 26,210 7,252 8,174
CASH AND TEMPORARY CASH INVESTMENTS AT
END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 28,054 $ 26,210 $ 7,252
<FN>
See Notes to Consolidated Financial Statements.
</FN>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements include
the accounts of Valero Energy Corporation ("Energy") and
subsidiaries (collectively referred to herein as the "Company").
All significant intercompany transactions have been eliminated in
consolidation. Certain prior period amounts have been
reclassified for comparative purposes.
Energy conducts its refining and marketing operations
through its wholly owned subsidiary, Valero Refining and
Marketing Company ("VRMC"), and VRMC's operating subsidiaries
(collectively referred to herein as "Refining"). Prior to and
including May 31, 1994, the Company accounted for its effective
equity interest of approximately 49% in Valero Natural Gas
Partners, L.P. ("VNGP, L.P.") and VNGP, L.P.'s consolidated
subsidiaries, including Valero Management Partnership, L.P. (the
"Management Partnership") and various subsidiary operating
partnerships ("Subsidiary Operating Partnerships") (collectively
referred to herein as the "Partnership") using the equity method
of accounting. Effective May 31, 1994, the Company acquired
through a merger (the "Merger") the remaining effective equity
interest of approximately 51% in the Partnership and changed the
method of accounting for its investment in the Partnership to the
consolidation method (see Note 2).
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Revenue Recognition
Revenues generally are recorded when services have been
provided or products have been delivered. Changes in the fair
value of financial instruments related to trading activities are
recognized in income currently. See "Price Risk Management
Activities" below.
Price Risk Management Activities
The Company enters into various exchange-traded as well as
financial instrument contracts with third parties to hedge the
purchase costs and sales prices of inventories, operating margins
and certain anticipated purchases of natural gas to be consumed
in operations. Such contracts are designated at inception as a
hedge where there is a direct relationship to the price risk
associated with the Company's inventories or future purchases and
sales of commodities used in the Company's operations. Hedges of
inventories are accounted for under the deferral method with
gains and losses included in the carrying amounts of inventories
and ultimately recognized in cost of sales as those inventories
are sold. Hedges of anticipatory transactions and purchase and
sales commitments are also accounted for under the deferral
method with gains and losses on these transactions recognized in
cost of sales when the hedged transaction occurs. Gains and
losses on early terminations of financial instrument contracts
designated as hedges are carried forward and included in cost of
sales in the measurement of the hedged transaction. Certain of
the Company's hedging activities could tend to reduce the
Company's participation in rising margins but are intended to
limit the Company's exposure to loss during periods of declining
margins.
The Company also enters into various exchange-traded as well
as financial instrument contracts with third parties for trading
purposes. Contracts entered into for trading purposes are
accounted for under the fair value method. Changes in the fair
value of those contracts are recognized as gains or losses in
cost of sales currently and are recorded in the statement of
financial position in prepaid expenses and other at fair value at
the reporting date. The Company determines the fair value of its
exchange-traded contracts based on the settlement prices for open
contracts, which are established by the exchange on which the
instruments are traded. The fair value of the Company's over-the-
counter contracts is determined based on market-related
indexes or by obtaining quotes from brokers. (See Note 5.)
Inventories
The Company owns a specialized petroleum refinery (the
"Refinery") in Corpus Christi, Texas. Refinery feedstocks and
refined products and blendstocks are carried at the lower of cost
or market with cost determined primarily under the last-in,
first-out ("LIFO") method of inventory pricing. The excess of
the replacement cost of such inventories over their LIFO values
was approximately $33 million at December 31, 1995. 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 then existing market prices. Natural gas in
underground storage, natural gas liquids ("NGLs") and materials
and supplies are carried principally at weighted average cost not
in excess of market. Inventories as of December 31, 1995 and
December 31, 1994 are as follows (in thousands):
December 31,
1995 1994
Refinery feedstocks . . . . . . . . . . . . . . . . . . . $ 48,295 $ 82,099
Refined products and blendstocks. . . . . . . . . . . . . 41,967 50,499
Natural gas in underground storage. . . . . . . . . . . . 31,156 29,678
Natural gas liquids . . . . . . . . . . . . . . . . . . . 3,280 4,664
Materials and supplies. . . . . . . . . . . . . . . . . . 16,124 15,149
$140,822 $182,089
Refinery feedstock and refined product and blendstock
inventory volumes totalled 6.2 million barrels ("MMbbls") and
8.9 MMbbls at December 31, 1995 and December 31, 1994,
respectively. Natural gas inventory volumes totalled
approximately 11.7 billion cubic feet ("Bcf") and 9.8 Bcf at
December 31, 1995 and December 31, 1994, respectively.
Prepaid Expenses and Other
Prepaid expenses and other for the periods indicated are
as follows (in thousands):
December 31,
1995 1994
Commodity deposits and deferrals (see Note 5) . . . . . . $34,553 $ 5,639
Prepaid insurance . . . . . . . . . . . . . . . . . . . . 8,663 11,527
Prepaid benefits expense. . . . . . . . . . . . . . . . . 2,187 5,291
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 1,918 2,560
$47,321 $25,017
Property, Plant and Equipment
Property additions and betterments include capitalized
interest, and acquisition and administrative costs allocable to
construction and property purchases.
The costs of minor property units (or components of
property units), net of salvage, retired or abandoned are charged
or credited to accumulated depreciation. 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:
Refining and marketing. . . . . . . . . . . 3 3/5%
Natural gas . . . . . . . . . . . . . . . . 2 1/4% - 20%
Natural gas liquids . . . . . . . . . . . . 4 1/2% - 20%
Other . . . . . . . . . . . . . . . . . . . 9% - 20%
Deferred Charges
Deferred Gas Costs
Payments made or agreed to be made in connection with the
settlement of certain disputed contractual issues with natural
gas suppliers are initially deferred. The balance of deferred
gas costs of $33 million at December 31, 1995 is included in
noncurrent other assets and is expected to be recovered over the
next 6 years through natural gas sales rates charged to certain
customers.
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, contract costs, debt issuance costs, and certain
other costs. Technological royalties and licenses are amortized
over the estimated useful life of each particular related asset.
Contract costs are amortized over the term of the related
contract. Debt issuance costs are amortized by the effective
interest method over the estimated life of each instrument or
facility.
Other Accrued Expenses
Other accrued expenses for the periods indicated are as
follows (in thousands):
December 31,
1995 1994
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . $16,433 $15,201
Other accrued employee benefit costs (see Note 12) . . . . . 11,047 7,337
Accrued pension cost (see Note 12) . . . . . . . . . . . . . 4,695 4,287
Accrued lease expense. . . . . . . . . . . . . . . . . . . . 4,566 3,955
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,801 6,370
$42,542 $37,150
Fair Value of Financial Instruments
The carrying amounts of the Company's financial instruments
approximate fair value, except for long-term debt and certain
financial instruments used in price risk management activities.
See Notes 4 and 5.
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. For the years ended December 31, 1995 and
1994, the conversion of the Convertible Preferred Stock (see Note
8) is not assumed since its effect would be antidilutive.
Potentially dilutive common stock equivalents were not material
and therefore were also not included in the computation. The
weighted average number of common shares outstanding for the
years ended December 31, 1995, 1994 and 1993 was 43,651,914,
43,369,836 and 43,098,808, respectively.
Statements of Cash Flows
In order to determine net cash provided by operating
activities, net income has been adjusted by, among other things,
changes in current assets and current liabilities, excluding
changes in cash and temporary cash investments, cash held in debt
service escrow for principal, current deferred income tax assets,
short-term debt and current maturities of long-term debt. Also
excluded are the Partnership's current assets and liabilities as
of the acquisition date (see Note 2). The changes in current
assets and current liabilities, excluding the items noted above,
are shown in the following table as an (increase) decrease in
current assets and an increase (decrease) in current liabilities.
The Company's temporary cash investments are highly liquid low-
risk debt instruments which have a maturity of three months or
less when acquired. (Dollars in thousands.)
Year Ended December 31,
1995 1994 1993
Cash held in debt service escrow for interest. . . . . . . $ 689 $(12,673) $ -
Receivables, net . . . . . . . . . . . . . . . . . . . . . (106,916) (64,150) 31,854
Inventories. . . . . . . . . . . . . . . . . . . . . . . . 41,267 (21,785) 3,870
Prepaid expenses and other . . . . . . . . . . . . . . . . (22,304) 142 (392)
Accounts payable . . . . . . . . . . . . . . . . . . . . . 38,825 (4,295) (21,778)
Accrued interest . . . . . . . . . . . . . . . . . . . . . 11,411 3,901 (81)
Other accrued expenses . . . . . . . . . . . . . . . . . . 5,392 3,263 (3,668)
Total . . . . . . . . . . . . . . . . . . . . . . . . . $ (31,636) $(95,597) $ 9,805
The following provides information related to cash interest
and income taxes paid by the Company for the periods indicated
(in thousands):
Year Ended December 31,
1995 1994 1993
Interest - net of amount capitalized of $4,699 (1995),
$2,365 (1994) and $12,335 (1993). . . . . . . . . . . . . . . . . . $86,553 $72,023 $36,001
Income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,935 3,931 18,324
Noncash investing activities for 1995 include the
reclassification to deferred charges and other assets of
$12.1 million of contract costs, previously included in property,
plant and equipment on the Consolidated Balance Sheets. Noncash
investing activities for 1994 include the remaining $60 million
payment made in 1995 for the Company's interest in a methanol
plant renovation project.
Accounting Changes
In October 1995, the Financial Accounting Standards Board
("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 123, "Accounting for Stock-Based Compensation."
This statement encourages entities to adopt the fair value method
of accounting for employee stock compensation plans for fiscal
years beginning after December 15, 1995, but allows an entity to
continue to measure compensation cost for those plans using the
intrinsic value based method of accounting prescribed by
Accounting Principles Board ("APB") Opinion No. 25, "Accounting
for Stock Issued to Employees." The Company intends to continue
to measure compensation cost for its employee stock compensation
plans in accordance with APB Opinion No. 25.
In March 1995, the FASB issued SFAS No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of." This statement establishes accounting
standards for the impairment of long-lived assets, certain
identifiable intangibles, and goodwill related to assets to be
held and used, and for long-lived assets and certain identifiable
intangibles to be disposed of, and is effective for fiscal years
beginning after December 15, 1995, although earlier
implementation is permitted. This statement is required to be
applied prospectively for assets to be held and used, while its
initial application to assets held for disposal is required to be
reported as the cumulative effect of a change in accounting
principle. The Company plans to adopt this statement as of
January 1, 1996. Based on information currently known by the
Company, such adoption would not have a significant impact on the
Company's consolidated financial statements.
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions." See Note 12.
2. ACQUISITION OF VALERO NATURAL GAS PARTNERS, L.P.
In March 1994, Energy issued Convertible Preferred Stock
(see Note 8) to fund the Merger of VNGP, L.P. with a wholly owned
subsidiary of Energy. On May 31, 1994, the holders of common
units of limited partner interests ("Common Units") of VNGP, L.P.
approved the Merger. Upon consummation of the Merger, VNGP, L.P.
became a wholly owned subsidiary of Energy and the publicly
traded Common Units (the "Public Units") were converted into the
right to receive cash in the amount of $12.10 per Common Unit.
The Company utilized $117.5 million of the net proceeds from the
Convertible Preferred Stock issuance to fund the acquisition of
the Public Units. The remaining net proceeds of $50.4 million
were used to reduce outstanding indebtedness under bank credit
lines and to pay expenses of the acquisition. As a result of the
Merger, all of the outstanding Common Units are held by the
Company.
The Merger has been accounted for as a purchase and the
purchase price has been allocated to assets acquired and
liabilities assumed based on estimated fair values resulting in
part from an independent appraisal of the property, plant and
equipment of the Partnership. The consolidated statements of
income of the Company for the years ended December 31, 1995 and
1994, reflect the Company's effective equity interest of
approximately 49% in the Partnership's operations for periods
prior to and including May 31, 1994, and reflect 100% of the
Partnership's operations thereafter.
The following unaudited pro forma financial information of
Valero Energy Corporation and subsidiaries assumes that the above
described transactions occurred for all periods presented. Such
pro forma information is not necessarily indicative of the
results of future operations.
Year Ended December 31,
1994 1993
(Thousands of dollars, except
per share amounts)
Operating revenues. . . . . . . . . . . . . $2,333,982 $2,265,157
Operating income. . . . . . . . . . . . . . 125,943 158,938
Net income. . . . . . . . . . . . . . . . . 19,389 41,898
Net income applicable to common stock . . . 7,442 29,855
Earnings per share of common stock. . . . . .17 .69
Prior to the Merger, the Company entered into transactions
with the Partnership commensurate with its status as the General
Partner. The Company charged the Partnership a management fee
equal to the direct and indirect costs incurred by it on behalf
of the Partnership. In addition, the Company purchased natural
gas and NGLs from the Partnership and sold NGLs to the
Partnership. The Company paid the Partnership a fee for
operating certain of the Company's assets. Also, the Company and
the Partnership entered into other transactions, including
certain leasing transactions.
The following table summarizes transactions between the
Company and the Partnership for the five months ended May 31,
1994 and for the year ended December 31, 1993 (in thousands):
Five Months Year Ended
Ended May 31, December 31,
1994 1993
NGL purchases and services from the Partnership . . . . . . $36,536 $98,590
Natural gas purchases from the Partnership. . . . . . . . . 9,672 59,735
Sales of NGLs and natural gas, and transportation
and other charges to the Partnership. . . . . . . . . . . . 11,385 38,868
Management fees billed to the Partnership for
direct and indirect costs. . . . . . . . . . . . . . . . 34,299 80,727
Interest income from capital lease transactions . . . . . . 5,481 13,178
3. SHORT-TERM DEBT
At December 31, 1995, Energy maintained eight separate
short-term bank lines of credit totalling $125 million, under
which no amounts were outstanding. Five of these lines are
cancellable on demand, and the others expire at various times in
1996. 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.
4. LONG-TERM DEBT AND BANK CREDIT FACILITIES
Long-term debt balances were as follows (in thousands):
December 31,
1995 1994
Valero Refining and Marketing Company:
Industrial revenue bonds:
Marine terminal and pollution control revenue bonds, Series 1987A
bonds, 10 1/4%, due June 1, 2017. . . . . . . . . . . . . . . . . . . . . . . $ 90,000 $ 90,000
Marine terminal revenue bonds, Series 1987B bonds, 10 5/8%,
due June 1, 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,500 8,500
Valero Energy Corporation:
$300 million revolving bank credit and letter of credit facility, 7.55% at
December 31, 1995, due November 1, 2000 . . . . . . . . . . . . . . . . . . . . 120,000 -
$250 million revolving bank credit and letter of credit facility, 7.11% at
December 31, 1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 133,000
10.58% Senior Notes, due December 30, 2000 . . . . . . . . . . . . . . . . . . . . 187,714 187,714
9.14% VESOP Notes, due February 15, 1999 (see Note 12) . . . . . . . . . . . . . . 6,819 8,407
Medium-Term Notes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 228,500 150,000
Valero Management Partnership, L.P. First Mortgage Notes . . . . . . . . . . . . . . 476,072 506,429
Total long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,117,605 1,084,050
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 81,964 62,230
$1,035,641 $1,021,820
Effective November 1, 1995, Energy replaced its $250
million revolving bank credit and letter of credit facility with
a new, unsecured $300 million revolving bank credit and letter of
credit facility that is available for general corporate purposes
including working capital needs and letters of credit.
Borrowings under the new facility bear interest at either LIBOR
plus .50%, prime or a competitive money market rate. The Company
is charged various fees, including commitment fees on the
unutilized portion, and various letter of credit and facility
fees. The new facility has three primary financial covenants,
including a minimum fixed charge coverage ratio of 1.6 to 1.0 for
each period of four consecutive nonturnaround quarters, a maximum
debt to capitalization ratio of 57.5% and a minimum net worth
test. In addition, certain events involving an actual or
potential change of control of Energy may result in an Event of
Default under the new facility and could thereupon result in a
cross-default to other financial obligations of the Company. As
of December 31, 1995, Energy had approximately $178 million
available under this committed bank credit facility for
additional borrowings and letters of credit.
In 1992, Energy filed with the Securities and Exchange
Commission (the "Commission") a shelf registration statement
which was used to offer $150 million principal amount of Medium-
Term Notes. In 1994, Energy filed another shelf registration
statement with the Commission to offer up to $250 million
principal amount of additional debt securities, including Medium-
Term Notes, $96.5 million of which had been issued through
December 31, 1995. Net proceeds from any debt securities issued
pursuant to this shelf registration statement will 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. Energy's
outstanding Medium-Term Notes have a weighted average life of
approximately 8.5 years and a weighted average interest rate of
approximately 8.35%.
The Company's long-term debt also includes the Management
Partnership's First Mortgage Notes (the "First Mortgage Notes").
The First Mortgage Notes, which are currently comprised of six
remaining series due serially from 1996 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, 1995, the First
Mortgage Notes have a remaining weighted average life of
approximately 6 years and a weighted average interest rate of
10.19% 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, 1995, $36.6 million had
been deposited with the Mortgage Note Indenture trustee
("Trustee") in an escrow account. The amount on deposit is
classified as a current asset (cash held in debt service escrow)
and the liability to be paid off when the cash is released by the
Trustee from escrow is classified as a current liability.
The indenture of mortgage and deed of trust pursuant to
which the First Mortgage Notes were issued (the "Mortgage Note
Indenture") contains covenants prohibiting the Management
Partnership and the Subsidiary Operating Partnerships
(collectively referred to herein as the "Operating Partnerships")
from incurring additional indebtedness, including any additional
First Mortgage Notes, other than (i) up to $50 million of
indebtedness to be incurred for working capital purposes
(provided that for a period of 45 consecutive days during each 16
consecutive calendar month period no such indebtedness will be
permitted to be outstanding) and (ii) up to the amount of any
future capital improvements financed through the issuance of debt
or equity by VNGP, L.P. and the contribution of such amounts as
additional equity to the Management Partnership. The Mortgage
Note Indenture also prohibits the Operating Partnerships from (a)
creating new indebtedness unless certain cash flow to debt
service requirements are met; (b) creating certain liens; or (c)
making cash distributions in any quarter in excess of the cash
generated in the prior quarter, less (i) capital expenditures
during such prior quarter (other than capital expenditures
financed with certain permitted indebtedness), (ii) an amount
equal to one-half of the interest to be paid on the First
Mortgage Notes on the interest payment date occurring in or next
following such prior quarter and (iii) an amount equal to one-
quarter of the principal required to be paid on the First
Mortgage Notes on the principal payment date occurring in or next
following such prior quarter, plus cash which could have been
distributed in any prior quarter but which was not distributed.
The Operating Partnerships are further prohibited from purchasing
or owning any securities of any person or making loans or capital
contributions to any person other than investments in the
Subsidiary Operating Partnerships, advances and contributions of
up to $20 million per year and $100 million in the aggregate to
entities engaged in substantially similar business activities as
the Operating Partnerships, temporary investments in certain
marketable securities and certain other exceptions. The Mortgage
Note Indenture also prohibits the Operating Partnerships from
consolidating with or conveying, selling, leasing or otherwise
disposing of all or any material portion of their property,
assets or business as an entirety to any other person unless the
surviving entity meets certain net worth requirements and certain
other conditions are met, or from selling or otherwise disposing
of any part of the Mortgaged Property, subject to certain
exceptions.
The Company was in compliance with all covenants contained
in its various debt facilities as of December 31, 1995.
Based on long-term debt outstanding at December 31, 1995,
maturities of long-term debt, including sinking fund requirements
and excluding borrowings under bank credit facilities, for the
years ending December 31, 1997 through 2000 are approximately
$72.4 million, $75.1 million, $73.2 million and $85.6 million,
respectively. Maturities of long-term debt under bank credit
facilities for the year ended December 31, 2000 are $120 million;
however, it is expected that prior to 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 $1,275 million and $1,126
million at December 31, 1995 and 1994, respectively.
5. PRICE RISK MANAGEMENT ACTIVITIES
Refinery Feedstock and Refined Products Hedging
The Company uses its price risk management activities to
hedge various portions of the Company's refining operations. The
Company uses options and futures to hedge refinery feedstock
purchases and refined product inventories in order to reduce the
impact of adverse price changes on these inventories before the
conversion of the feedstock to finished products and ultimate
sale. Options and futures contracts at the end of 1995 and 1994
had remaining terms of less than one year. As of December 31,
1995 and 1994, 19% and 8%, respectively, of the Company's
refining inventory position was hedged. The amount of deferred
hedge losses included as an increase to refinery inventory was $1
million and $.4 million at December 31, 1995 and 1994,
respectively. The following is a summary of the contract amounts
and range of prices of the Company's contracts held or issued to
hedge inventory at December 31, 1995 and 1994:
1995 1994
Payor Receiver Receiver
Options:
Volumes (Mbbls). . . . . . - 150 695
Price (per bbl). . . . . . - $24.36-$24.78 $16.00-$23.10
Futures:
Volumes (Mbbls). . . . . . 250 1,327 365
Price (per bbl). . . . . . $22.71-$23.83 $17.57-$24.55 $17.20-$17.36
The Company also hedges anticipated transactions. Over-the-
counter price swaps and futures are used to hedge refining
operating margins for periods up to 12 months in order to lock in
components of the margins, including the resid discount, the
conventional crack spread and the premium product differentials.
Through these open price swap positions on components of
refining's operating margin, less than 2% of the Company's
anticipated 1996 refining margin and approximately 10% of the
Company's anticipated 1995 refining margin was hedged as of
December 31, 1995 and 1994, respectively. There were no explicit
deferrals of hedging gains or losses related to these anticipated
transactions as of December 31, 1995 and the amount of deferred
hedging gains was $.1 million as of December 31, 1994. The
following table is a summary of the contract or notional amounts
and range of prices of the Company's futures contracts and price
swaps held or issued to hedge refining margins at December 31,
1995 and 1994. Volumes shown for swaps represent notional
volumes which are used to calculate amounts due under the
agreements and do not represent volumes exchanged.
1995 1994
Receiver Payor Receiver
Futures:
Volumes (Mbbls). . . . . 14 280 295
Price (per bbl). . . . . $18.95-$19.50 $20.24-$20.84 $16.76-$17.82
Swaps:
Volumes (Mbbls). . . . . 525 - -
Price (per bbl). . . . . $34.23-$35.81 - -
Natural Gas Hedging
The Company uses its price risk management activities to
hedge various portions of the Company's natural gas and natural
gas liquids operations. In its natural gas operations, the
Company uses futures, price swaps and over-the-counter and
exchange-traded options to hedge gas storage. As of December 31,
1995 and 1994, 26% and 22%, respectively, of the Company's
natural gas inventory position was hedged. These financial
instrument contracts run for periods of up to 12 months. The
amount of deferred hedge gains included as a reduction of natural
gas inventories was $.9 million and $5.7 million at December 31,
1995 and 1994, respectively. The Company also enters into basis
swaps for location differentials at fixed prices which generally
extend for periods up to 2 months. The following is a summary of
the contract or notional amounts and range of prices of the
Company's contracts held or issued to hedge inventory at
December 31, 1995 and 1994. Volumes shown for swaps and basis
swaps represent notional volumes which are used to calculate
amounts due under the agreements and do not represent volumes
exchanged.
1995 1994
Payor Receiver Receiver
Swaps:
Volumes (MMcf) . . . . . . . . . 1,000 1,000 -
Price (per Mcf). . . . . . . . . $1.91 $2.87-$3.45 -
Options:
Volumes (MMcf) . . . . . . . . . 12,000 23,000 -
Price (per Mcf). . . . . . . . . $1.90-$2.50 $1.90-$2.50 -
Futures:
Volumes (MMcf) . . . . . . . . . 17,480 15,430 2,190
Price (per Mcf). . . . . . . . . $1.77-$3.45 $1.75-$3.45 $1.58-$2.15
Basis Swaps:
Volumes (MMcf) . . . . . . . . . 500 2,120 -
Price (per Mcf). . . . . . . . . $.63 $.13-$.85 -
The Company also hedges anticipated natural gas purchase
requirements, including plant shrinkage and natural gas used in
refining operations, natural gas liquids sales and commitments to
buy and sell natural gas at fixed prices, using futures and price
swaps and over-the-counter and exchange-traded options extending
through the year 2000. Volumes hedged as of December 31, 1995
and 1994, represent 29% and 23%, respectively, of the expected
annual plant shrinkage and 29% and 36%, respectively, of the
expected natural gas requirements of the refining operations.
Explicitly deferred gains from anticipated hedges of $3.9 million
and $1.1 million, as of December 31, 1995 and 1994,
respectively, will be recognized in the month being hedged. The
Company also enters into basis swaps for location differentials
at fixed prices which extend through the year 2001. The
following table is a summary of the contract or notional amounts
and range of prices of the Company's contracts held or issued to
hedge plant shrinkage, refinery operations and natural gas
purchase and sales commitments at December 31, 1995 and 1994.
Volumes shown for swaps and basis swaps represent notional
volumes which are used to calculate amounts due under the
agreements and do not represent volumes exchanged.
Total Total
Expected Maturity Date 1995 1994
1996 1997-2001 Balance Balance
Payor Receiver Payor Receiver Payor Receiver Payor Receiver
Swaps:
Volumes (MMcf) . . 36,092 26,111 19,185 - 55,277 26,111 9,525 1,345
Price (per Mcf). . $1.31-$3.45 $1.71-$4.34 $1.91-$2.35 - $1.31-$3.45 $1.71-$4.34 $1.58-$1.73 $3.58-$3.74
Options:
Volumes (MMcf) . . 10,090 8,823 250 250 10,340 9,073 - -
Price (per Mcf). . $1.66-$3.25 $1.50-$2.45 $1.66 $1.60-$1.72 $1.66-$3.25 $1.50-$2.45 - -
Futures:
Volumes (MMcf) . . 104,740 52,620 280 60 105,020 52,680 17,900 6,566
Price (per Mcf). . $1.50-$3.45 $1.50-$3.61 $1.74-$1.95 $1.81-$1.92 $1.50-$3.45 $1.50-$3.61 $1.57-$2.26 $1.54-$3.69
Basis Swaps:
Volumes (MMcf) . . 15,442 58,258 1,345 40,283 16,787 98,541 27,520 16,090
Price (per Mcf). . $.06-$1.06 $.16-$.85 $.21 $.03-$.15 $.06-$1.06 $.03-$.85 $.03-$.25 $.02-$.25
The following table discloses the carrying amount and fair
value of the Company's refining, natural gas and natural gas
liquids' contracts held or issued for non-trading purposes as of
December 31, 1995 and 1994 (dollars in thousands):
1995 1994
Assets (Liabilities) Assets (Liabilities)
Carrying Fair Carrying Fair
Amount Value Amount Value
Swaps. . . . . . . . . . . . . . . $ 98 $1,557 $ 86 $8,011
Options. . . . . . . . . . . . . . (91) 429 (613) (613)
Futures. . . . . . . . . . . . . . 217 217 209 209
Basis Swaps. . . . . . . . . . . . - 5,823 - 145
Total. . . . . . . . . . . . . . $224 $8,026 $(318) $7,752
Trading Activities
The Company enters into transactions for trading purposes
using its fundamental and technical analysis of market conditions
to earn additional revenues. The types of instruments used
include futures, price swaps, basis swaps and over-the-counter
and exchange-traded options. Except in limited circumstances,
these contracts run for periods of up to 13 months, with the
exception of basis swaps which extend through the year 2000. The
following table is a summary of the contract amounts and range
of prices of the Company's contracts held or issued for trading
purposes at December 31, 1995 and 1994:
Total Total
Expected Maturity Date 1995 1994
1996 1997-2000 Balance Balance
Payor Receiver Payor Receiver Payor Receiver Payor Receiver
Swaps:
Volumes (MMcf). . 22,230 23,750 1,200 1,200 23,430 24,950 - -
Price (per Mcf) . $1.79-$3.44 $1.71-$3.44 $1.85 $1.84 $1.79-$3.44 $1.71-$3.44 - -
Volumes (Mbbls) . 2,925 2,250 - - 2,925 2,250 - -
Price (per bbl) . $1.80-$4.14 $2.40-$4.18 - - $1.80-$4.14 $2.40-$4.18 - -
Options:
Volumes (MMcf). . 36,100 18,000 - - 36,100 18,000 1,100 500
Price (per Mcf) . $1.60-$3.25 $1.60-$2.40 - - $1.60-$3.25 $1.60-$2.40 $1.70-$2.10 $1.70-$1.85
Volumes (Mbbls) . - 150 - - - 150 250 -
Price (per bbl) . - $17.50-$19.00 - - - $17.50-$19.00 $24.36 -
Futures:
Volumes (MMcf). . 62,650 58,280 1,000 1,000 63,650 59,280 380 380
Price (per Mcf) . $1.64-$3.44 $1.67-$3.67 $1.94 $1.96 $1.64-$3.44 $1.67-$3.67 $1.98-$1.99 $1.98-$2.02
Volumes (Mbbls) . 100 450 - - 100 450 - -
Price (per bbl) . $23.42-$23.44 $18.24-$19.00 - - $23.42-$23.44 $18.24-$19.00 - -
Basis Swaps:
Volumes (MMcf). . 11,620 19,180 - 22,820 11,620 42,000 - -
Price (per Mcf) . $.07-$.47 $.13-$.22 - $.03 $.07-$.47 $.03-$.22 - -
The following table discloses the fair values of contracts
held or issued for trading purposes and net gains (losses) from
trading activities as of or for the periods ended December 31,
1995 and 1994 (dollars in thousands):
Fair Value of Assets (Liabilities)
Average Ending Net Gains(Losses)
1995 1994 1995 1994 1995 1994
Swaps. . . . . . . . . . . . . . . . $ (329) $ 1 $ 245 $ - $(2,143) $ 285
Options. . . . . . . . . . . . . . . 1,026 (101) 297 33 (3,273) 430
Futures. . . . . . . . . . . . . . . 2,030 486 6,739 806 8,822 (232)
Basis Swaps. . . . . . . . . . . . . 487 - 1,266 - 2,706 -
Total. . . . . . . . . . . . . . . $3,214 $ 386 $8,547 $839 $ 6,112 $ 483
Market and Credit Risk
The Company's price risk management activities involve the
receipt or payment of fixed price commitments into the future.
These transactions give rise to market risk, the risk that future
changes in market conditions may make an instrument less
valuable. The Company closely monitors and manages its exposure
to market risk on a daily basis in accordance with policies
limiting net open positions. Concentrations of customers in the
refining and natural gas industries may impact the Company's
overall exposure to credit risk, in that the customers in each
specific industry may be similarly affected by changes in
economic or other conditions. The Company believes that its
counterparties will be able to satisfy their obligations under
contracts.
6. INVESTMENTS
Proesa
Productos Ecologicos, S.A. de C.V. ("Proesa"), a Mexican
corporation, is involved in a project (the "Project") to design,
construct and operate a plant (the "Plant") in Mexico to produce
methyl tertiary butyl ether ("MTBE"). The Plant, to be
constructed at a site near the Bay of Campeche, has been
estimated to cost approximately $400 million (exclusive of working
capital, capitalized interest and financing costs) and to produce
approximately 17,000 barrels of MTBE per stream day. Proesa is
currently owned 35% by the Company, 10% by Dragados y
Construcciones, S.A., a Spanish construction company and 55% by a
corporation formed by a subsidiary of Banamex, Mexico's largest
bank, and Infomin, S.A. de C.V., a privately owned Mexican
corporation. At December 31, 1995, the Company had invested
approximately $16.5 million in the Project. The Company has
entered into a letter of understanding with Proesa's other
shareholders under which, subject to certain conditions, the
Company's ownership interest in Proesa would increase to 45%.
Proesa has furnished a surety bond related to an MTBE sales
agreement between Proesa and Petroleos Mexicanos, S.A. ("Pemex"),
the Mexican state-owned oil company. Based on the exchange rate
at January 31, 1996, the insurable value of Proesa's obligation
was approximately $5.6 million. The Company estimates the
outstanding obligations of Proesa to be $10 million.
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, 1999. 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 $8.9 million at December 31, 1995.
At December 31, 1995, the Company's investment in Javelina
included its equity contributions and advances to Javelina of
approximately $20.2 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.
7. REDEEMABLE PREFERRED STOCK
In December of 1995, Energy redeemed 57,500 shares
($5,750,000) of its Cumulative Preferred Stock, $8.50 Series A
("Series A Preferred Stock"), at $100 per share. The redemption
requirements for 1996 are the same with the redemption of the
remaining balance (11,500 shares or $1,150,000) to occur in 1997.
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 voting as a
class with holders of any other series of preferred stock also in
arrears may vote to elect two directors. No arrearages currently
exist.
8. CONVERTIBLE PREFERRED STOCK
In March 1994, Energy issued 3,450,000 shares of its $3.125
convertible preferred stock ("Convertible Preferred Stock") with
a stated value of $50 per share and received cash proceeds, net
of underwriting discounts, of approximately $168 million. Each
share of Convertible Preferred Stock is convertible at the option
of the holder into shares of Energy common stock ("Common Stock")
at an initial conversion price of $27.03. The Convertible
Preferred Stock may not be redeemed prior to June 1, 1997.
Thereafter, the Convertible Preferred Stock may be redeemed, in
whole or in part at the option of Energy, at a redemption price
of $52.188 per share through May 31, 1998, and at ratably
declining prices thereafter, plus dividends accrued to the
redemption date.
9. PREFERENCE SHARE PURCHASE RIGHTS
On November 25, 1995, Energy made a dividend distribution of
one Preference Share Purchase Right ("Right") for each
outstanding share of Common Stock, replacing similar expiring
rights distributed on November 25, 1985. Until exercisable, the
Rights are not transferable apart from Common Stock. Each Right
will entitle shareholders to buy one-hundredth (1/100) of a share
of a newly issued series of Junior Participating Serial
Preference Stock, Series III, at an exercise price of $75 per
Right.
10. INDUSTRY SEGMENT INFORMATION
Year Ended December 31,
1995 1994 1993
(Thousands of Dollars)
Operating revenues:
Refining and marketing. . . . . . . . . . . . . . . . . . . $1,772,577 $1,090,368 $1,044,749
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . 973,219 487,564 46,021
Natural gas liquids . . . . . . . . . . . . . . . . . . . . 435,979 307,016 53,252
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 126 42,639 83,886
Intersegment eliminations . . . . . . . . . . . . . . . . . (162,109) (90,147) (5,669)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $3,019,792 $1,837,440 $1,222,239
Operating income (loss):
Refining and marketing. . . . . . . . . . . . . . . . . . . $ 141,512 $ 78,660 $ 75,401
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . 39,496 26,731 2,863
Natural gas liquids . . . . . . . . . . . . . . . . . . . . 43,684 35,213 10,057
Corporate general and administrative
expenses and other, net . . . . . . . . . . . . . . . . . (35,901) (14,679) (12,817)
Total . . . . . . . . . . . . . . . . . . . . . . . . . 188,791 125,925 75,504
Equity in earnings (losses) of and income from:
Valero Natural Gas Partners, L.P. . . . . . . . . . . . . . - (10,698) 23,693
Joint ventures. . . . . . . . . . . . . . . . . . . . . . . 4,827 2,437 (1,688)
Gain on disposition of assets and other income, net . . . . . 2,742 2,039 7,897
Interest and debt expense, net. . . . . . . . . . . . . . . . (101,222) (76,921) (37,182)
Income before income taxes. . . . . . . . . . . . . . . . . . $ 95,138 $ 42,782 $ 68,224
Identifiable assets:
Refining and marketing. . . . . . . . . . . . . . . . . . . $1,524,065 $1,528,621 $1,407,221
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . 944,616 894,678 18,854
Natural gas liquids . . . . . . . . . . . . . . . . . . . . 243,415 248,430 83,262
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 150,141 149,688 105,456
Investment in and leases receivable from
Valero Natural Gas Partners, L.P.. . . . . . . . . . . . . - - 130,557
Investment in and advances to joint ventures. . . . . . . . 41,890 41,162 28,343
Intersegment eliminations and reclassifications . . . . . . (27,447) (31,221) (9,256)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $2,876,680 $2,831,358 $1,764,437
Depreciation expense:
Refining and marketing. . . . . . . . . . . . . . . . . . . $ 55,032 $ 52,956 $ 47,381
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . 28,910 17,633 1,522
Natural gas liquids . . . . . . . . . . . . . . . . . . . . 11,971 9,003 3,648
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,412 4,440 4,182
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $ 100,325 $ 84,032 $ 56,733
Capital additions:
Refining and marketing. . . . . . . . . . . . . . . . . . . $ 29,039 $ 119,748 $ 123,031
Natural gas . . . . . . . . . . . . . . . . . . . . . . . . 16,285 12,010 2,232
Natural gas liquids . . . . . . . . . . . . . . . . . . . . 17,204 6,850 1,458
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,091 2,130 9,873
Total . . . . . . . . . . . . . . . . . . . . . . . . . . $ 64,619 $ 140,738 $ 136,594
The Company's three core businesses are specialized
refining, natural gas and natural gas liquids. Refining converts
high-sulfur atmospheric residual oil into premium products,
including reformulated and conventional unleaded gasoline, at its
refinery, and sells those products principally on a spot, truck
rack and term contract basis. Spot and term sales of Refining's
products are made principally to larger oil companies and
gasoline distributors in the northeastern, midwestern and
southeastern United States. The principal purchasers of
Refining's products from truck racks have been wholesalers and
jobbers in the eastern and midwestern United States. Natural gas
operations consist of purchasing, gathering, processing, storage,
transporting and selling natural gas, principally to gas
distribution companies, electric utilities, pipeline companies
and industrial customers and transporting natural gas for
producers, other pipelines and end users in North America. 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 in the Corpus Christi and Mont Belvieu
(Houston) areas. Intersegment revenue eliminations for 1995 and
1994 relate primarily to the refining and marketing segment's
purchases of feedstocks and fuel gas from the natural gas liquids
and natural gas segments. The Company has no significant foreign
operations other than petroleum storage facilities.
Approximately $300 million or 10% of the Company's operating
revenues were derived from a single customer, substantially all
of which is attributable to the refining and marketing segment.
The foregoing segment information reflects the Company's
effective equity interest of approximately 49% in the
Partnership's operations for periods prior to and including May
31, 1994, and reflects 100% of the Partnership's operations
thereafter (see Note 2). Capital additions in 1994 include the
remaining $60 million payment made in 1995 for the Company's
interest in a methanol plant renovation project.
11. INCOME TAXES
Components of income tax expense attributable to continuing
operations are as follows (in thousands):
Year Ended December 31,
1995 1994 1993
Current:
Federal. . . . . . . . . . . . . . . . $29,674 $ 3,535 $16,377
State. . . . . . . . . . . . . . . . . 926 165 123
Total current . . . . . . . . . . . 30,600 3,700 16,500
Deferred:
Federal. . . . . . . . . . . . . . . . 4,700 12,200 17,892
State. . . . . . . . . . . . . . . . . - - (2,592)
Total deferred. . . . . . . . . . . 4,700 12,200 15,300
Total income tax expense . . . . . . . . $35,300 $15,900 $31,800
Total income tax expense differs from the amount computed
by applying the statutory federal income tax rate to income
before income taxes. The reasons for these differences are as
follows (in thousands):
Year Ended December 31,
1995 1994 1993
Federal income tax expense at the statutory rate . . . . . . $33,300 $15,000 $23,900
Additional deferred income taxes due to increase in
federal income tax rate. . . . . . . . . . . . . . . . . . - - 8,200
State income taxes, net of federal income tax benefit. . . . 600 100 (1,600)
Other - net. . . . . . . . . . . . . . . . . . . . . . . . . 1,400 800 1,300
Total income tax expense . . . . . . . . . . . . . . . . . . $35,300 $15,900 $31,800
The tax effects of significant temporary differences
representing deferred income tax assets and liabilities are as
follows (in thousands):
December 31,
1995 1994
Deferred income tax assets:
Tax credit carryforwards . . . . . . . . . . . $ 33,001 $ 78,368
Other. . . . . . . . . . . . . . . . . . . . . 25,570 24,482
Total deferred income tax assets . . . . . . $ 58,571 $ 102,850
Deferred income tax liabilities:
Depreciation . . . . . . . . . . . . . . . . . $(267,900) $(302,762)
Other. . . . . . . . . . . . . . . . . . . . . (37,154) (32,482)
Total deferred income tax liabilities. . . . $(305,054) $(335,244)
At December 31, 1995, the Company had federal net operating
loss carryforwards of approximately $5 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 ("AMT") credit carryforwards of approximately $36
million which are available to reduce future federal income tax
liabilities. The ITC of approximately $9 million expire in the
years 1996 ($3 million), 1997 ($1 million) and 1999 through 2001
($5 million) if not utilized. The ESOP tax credits of
approximately $6 million expire in the years 1996 ($4 million)
and 1997 ($2 million). The AMT credit of approximately $21
million has no expiration date. The Company has not recorded any
valuation allowances against deferred income tax assets as of
December 31, 1995.
The Company's taxable years through 1991 are closed to
adjustment by the Internal Revenue Service. The Company believes
that adequate provisions for income taxes have been reflected in
its consolidated financial statements.
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, 1995
and 1994 (in thousands):
December 31,
1995 1994
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $65,420 (1995) and $49,197 (1994). . . . . . . . . . . $66,085 $49,642
Projected benefit obligation for services rendered to date . . . . . . $87,609 $63,793
Plan assets at fair value. . . . . . . . . . . . . . . . . . . . . . . 68,619 52,289
Projected benefit obligation in excess of plan assets. . . . . . . . . 18,990 11,504
Unrecognized net gain from past experience different
from that assumed. . . . . . . . . . . . . . . . . . . . . . . . . . 2,335 10,206
Prior service cost not yet recognized in net periodic
pension cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,033) (5,434)
Unrecognized net asset at beginning of year. . . . . . . . . . . . . . 1,483 1,625
Additional minimum liability accrual . . . . . . . . . . . . . . . . . 1,948 1,217
Accrued pension cost . . . . . . . . . . . . . . . . . . . . . . . . $19,723 $19,118
Net periodic pension cost for the years ended December
31, 1995, 1994 and 1993 included the following components (in
thousands):
Year Ended December 31,
1995 1994 1993
Service cost - benefits earned during the period . . . . . . . . . $ 3,465 $ 3,981 $ 4,374
Interest cost on projected benefit obligation. . . . . . . . . . . 5,455 4,990 5,258
Actual (return) loss on plan assets. . . . . . . . . . . . . . . . (14,376) 1,820 (3,450)
Net amortization and deferral. . . . . . . . . . . . . . . . . . . 9,637 (6,135) 22
Net periodic pension cost. . . . . . . . . . . . . . . . . . . . 4,181 4,656 6,204
Curtailment gain resulting from RGV disposition. . . . . . . . . . - - (1,650)
Total pension expense. . . . . . . . . . . . . . . . . . . . . $ 4,181 $ 4,656 $ 4,554
Participation in the pension plan for employees of the
Company commences upon attaining age 21 and the completion of one
year of continuous service. A participant vests in plan benefits
after 5 years of vesting service or upon reaching normal
retirement date. The pension plan provides a monthly pension
payable upon normal retirement of an amount equal to a set
formula which is based on the participant's 60 consecutive
highest months of compensation during credited service under the
plan. The weighted-average discount rate used in determining the
actuarial present value of the projected benefit obligation was
7.25% and 8.7%, respectively, as of December 31, 1995 and 1994.
The rate of increase in future compensation levels used in
determining the projected benefit obligation as of December 31,
1995 and 1994 was 4% for nonexempt personnel and was 3% for
exempt personnel. The expected long-term rate of return on plan
assets was 9.25% as of December 31, 1995 and 1994.
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 1995,
1994 and 1993 were approximately $4.3 million, $5 million and
$7.5 million, respectively, and are currently estimated to be
$4.7 million in 1996. The tables at the beginning of this note
include amounts related to the SERP.
The Company is the sponsor of the Valero Energy Corporation
Thrift Plan ("Thrift Plan") which is an employee profit sharing
plan. Participation in the Thrift Plan is voluntary and is open
to employees of the Company who become eligible to participate
following the completion of three months of continuous
employment. Participating employees may make a base contribution
from 2% up to 8% of their annual base salary, depending upon
months of contributions by a participant. Thrift Plan
participants are automatically enrolled in the VESOP (see below).
The Company makes contributions to the Thrift Plan to the extent
employees' base contributions exceed the amount of the Company's
contribution to the VESOP for debt service. Prior to 1994, the
Company matched 100% of the employee contributions. In 1994, the
Thrift Plan was amended to provide for a total Company match in
both the Thrift Plan and the VESOP aggregating 75% of employee
base contributions, with an additional contribution of up to 25%
subject to certain conditions. Participants may also make a
supplemental contribution to the Thrift Plan of up to an
additional 10% of their annual base salary which is not matched
by the Company. There were no Company contributions to the
Thrift Plan in 1995; however, approximately $42,000 and $660,000
was contributed during 1994 and 1993, respectively.
In 1989, the Company established the Valero Employees'
Stock Ownership Plan ("VESOP") which is a leveraged employee
stock ownership plan. Pursuant to a private placement in 1989,
the VESOP issued notes in the principal amount of $15 million,
maturing February 15, 1999 (the "VESOP Notes"). The net proceeds
from this private placement were used by the VESOP trustee to
fund the purchase of Common Stock. During 1991, the Company made
an additional loan of $8 million to the VESOP which was also used
by the Trustee to purchase Common Stock. This second VESOP loan
matures on August 15, 2001. The number of shares of Common Stock
released at any semi-annual payment date is based on the
proportion of debt service paid during the year to remaining debt
service for that and all subsequent periods times the number of
unreleased shares then outstanding. As explained above, the
Company's annual contribution to the Thrift Plan is reduced by
the Company's contribution to the VESOP for debt service. During
1995, 1994 and 1993, the Company contributed $3,170,000,
$3,160,000 and $3,596,000, respectively, to the VESOP, comprised
of $678,000, $819,000 and $947,000, respectively, of interest on
the VESOP Notes and $2,918,000, $2,777,000 and $2,649,000,
respectively, of compensation expense. Compensation expense is
based on the VESOP debt principal payments for the portion of the
VESOP established in 1989 and is based on the cost of the shares
allocated to participants for the portion of the VESOP
established in 1991. Dividends on VESOP shares of Common Stock
are recorded as a reduction of retained earnings. Dividends on
allocated shares of Common Stock are paid to participants and
dividends on unallocated shares were paid to participants during
1993. However, the Company's contributions to the VESOP during
1995 and 1994 were reduced by $426,000 and $436,000,
respectively, of dividends paid on unallocated shares. VESOP
shares of Common Stock are considered outstanding for earnings
per share computations. As of December 31, 1995 and 1994, the
number of allocated shares were 940,470 and 817,877,
respectively, the number of committed-to-be-released shares were
62,918 and 62,922, respectively, and the number of suspense
shares were 772,055 and 897,893, 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 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, 1995 and 1994 (in thousands):
December 31,
1995 1994
Accumulated benefit obligation:
Retirees. . . . . . . . . . . . . . . . . . . . . . . . . . . $10,295 $11,319
Fully eligible active plan participants . . . . . . . . . . . 331 244
Other active plan participants . . . . . . . . . . . . . . . 13,504 11,254
Total accumulated benefit obligation. . . . . . . . . . . . 24,130 22,817
Unrecognized loss . . . . . . . . . . . . . . . . . . . . . . . (4,586) (800)
Unrecognized prior service cost . . . . . . . . . . . . . . . . - 1,267
Unrecognized transition obligation. . . . . . . . . . . . . . . (10,987) (17,066)
Accrued postretirement benefit cost . . . . . . . . . . . . . $ 8,557 $ 6,218
Net periodic postretirement benefit cost for the years
ended December 31, 1995, 1994 and 1993 included the following
components (in thousands):
December 31,
1995 1994 1993
Service cost - benefits attributed to service during the period . . . . . . . $ 860 $1,196 $1,011
Interest cost on accumulated benefit obligation . . . . . . . . . . . . . . . 1,769 1,686 1,692
Amortization of unrecognized transition obligation. . . . . . . . . . . . . . 766 948 1,029
Amortization of prior service cost. . . . . . . . . . . . . . . . . . . . . . - (84) -
Amortization of unrecognized net loss . . . . . . . . . . . . . . . . . . . . - 75 -
Net periodic postretirement benefit cost. . . . . . . . . . . . . . . . . . 3,395 3,821 3,732
Curtailment loss resulting from RGV disposition . . . . . . . . . . . . . . . - - 616
Total postretirement benefit cost . . . . . . . . . . . . . . . . . . . . . $3,395 $3,821 $4,348
For measurement purposes, the assumed health care cost
trend rate was 8% in 1995, 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, 1995 by $4.2 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, 1995 and 1994 was 7.25% and 8.7%, respectively.
Stock Option and Bonus Plans
The Company's Executive Stock Incentive Plan (the "ESIP")
authorizes the grant of various stock and stock-related awards to
executive officers and other key employees. Awards available
under the ESIP include options to purchase shares of Common
Stock, stock appreciation rights (SARs), restricted stock,
performance awards and other stock-based awards. A total of
2,100,000 shares may be issued under the ESIP, of which no more
than 750,000 shares may be issued as restricted stock. As of
December 31, 1995, 695,600 options and 127,700 shares of
restricted stock had been granted and 1,277,300 awards were
available for grant under the ESIP. In addition to options
available under the ESIP, the Company also has three non-qualified
stock option plans, Stock Option Plan No. 5, Stock
Option Plan No. 4, and Stock Option Plan No. 3, collectively
referred to herein as the "Stock Option Plans." Awards under the
Stock Option Plans are granted to key officers, employees and
prospective employees of the Company. At December 31, 1995,
there were 52,371 shares available for grant under these Stock
Option Plans.
Under the terms of the ESIP and the Stock Option Plans, the
exercise price of the options granted will not be less than 100%
or less than 75%, respectively, of the fair market value of
Common Stock at the date of grant. As of December 31, 1995, all
outstanding options contain exercise prices not less than fair
market value at date of grant. Stock options become exercisable
pursuant to the individual written agreements between the Company
and the participants either at the end of a three-year period
beginning on the date of grant or in three equal annual
installments beginning one year after the date of grant, with
unexercised options expiring ten years from the date of grant.
At December 31, 1995, 3,928,267 options were outstanding, at a
weighted-average exercise price of $20.69 per share, of which
1,531,718 options were exercisable at a weighted-average exercise
price of $22.30 per share. During 1995, 1,599,463 options were
granted at a weighted-average exercise price of $18.99 per share,
171,604 options were exercised at a weighted-average exercise
price of $17.08 per share and 75,494 options were terminated
and/or forfeited. These amounts include options granted under
the ESIP.
For each share of stock that can be purchased thereunder
pursuant to a stock option, Stock Option Plans No. 3 and 4
provide that a SAR may also be granted. A SAR is a right to
receive a cash payment equal to the difference between the fair
market value of Common Stock on the exercise date and the option
price of the stock to which the SAR is related. SARs under Stock
Option Plans No. 3 and 4 are exercisable only upon the exercise
of the related stock options. At the end of each reporting
period within the exercise period, the Company records an
adjustment to deferred compensation expense based on the
difference between the fair market value of Common Stock at the
end of each reporting period and the option price of the stock to
which the SAR is related. At December 31, 1995, 111,003 SARs
were outstanding and exercisable, at a weighted-average exercise
price of $14.52 per share. During 1995, 22,966 SARs were
exercised at a weighted-average exercise price of $14.52 per
share.
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, 1995, there
were 6,927 shares available for award and 9,000 shares were
awarded under this plan during 1995. 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.
13. LEASE AND OTHER COMMITMENTS
The Company has major long-term operating lease
commitments in connection with a gas storage facility, its
corporate headquarters office complex and various facilities and
equipment used to store and transport refinery feedstocks and
refined products. The gas storage facility lease has a remaining
primary term of four years with one eight-year optional renewal
period during which the lease payments decrease by one-half, and,
subject to certain conditions, one or more additional optional
renewal periods of five years each at fair market rentals. In
February 1995, the Company renegotiated the terms of its
corporate headquarters lease under which the lease payments were
reduced beginning in 1995. The corporate headquarters lease has a
remaining primary term of 16 years with five optional renewal
periods of five years each. The Company's long-term refinery
feedstock and refined product storage and transportation leases
have remaining primary terms ranging from 1.5 to 6.3 years with
optional renewal periods ranging from three to ten years and
provide for various contingent payments based on throughput
volumes in excess of a base amount, among other things. The
Company also has other noncancelable operating leases with
remaining terms ranging generally from one year to 11 years. The
related future minimum lease payments as of December 31, 1995 are
as follows (in thousands):
Gas Refining
Storage Office Storage and
Facility Complex Transportation Other
1996 . . . . . . . . . . . . . . . . $10,438 $ 4,570 $14,248 $ 1,433
1997 . . . . . . . . . . . . . . . . 9,832 4,570 11,830 1,421
1998 . . . . . . . . . . . . . . . . 10,156 4,570 4,075 1,379
1999 . . . . . . . . . . . . . . . . 10,438 4,570 4,075 842
2000 . . . . . . . . . . . . . . . . 5,221 4,570 4,075 195
Remainder. . . . . . . . . . . . . . - 45,341 5,434 329
Total minimum lease payments . . . . $46,085 $68,191 $43,737 $5,599
The future minimum lease payments listed above exclude
certain operating lease commitments which are cancelable by the
Company upon notice of one year or less. Consolidated rental
expense under operating leases, excluding amounts paid in
connection with the gas storage facility noted above, amounted to
approximately $29,313,000, $14,040,000, and $12,948,000 for 1995,
1994 (including Partnership rents commencing June 1, 1994) and
1993, respectively, and includes various month-to-month and other
short-term rentals in addition to rents paid and accrued under
long-term lease commitments. For the period prior to the Merger,
a portion of these amounts was charged to and reimbursed by the
Partnership for its proportionate use of the Company's corporate
headquarters office complex and for the use of certain other
properties managed by the Company for the period prior to the
Merger. Gas storage facility rentals paid by the Partnership for
the period prior to the Merger, and paid by the Company for the
period subsequent to the Merger, totalling $10,438,000 per year
for 1995, 1994 and 1993, were included in the cost of gas.
The obligations of the Company under the gas storage
facility lease include its obligation to make scheduled lease
payments and, in the event of a declaration of default and
acceleration of the lease obligation, to make certain lump sum
payments based on a stipulated loss value for the gas storage
facility less the fair market sales price or fair market rental
value of the gas storage facility. Under certain circumstances,
a default by Energy or a subsidiary of Energy under its credit
facilities could result in a cross default under the gas storage
facility lease. The Company believes that it is unlikely that
such a default would result in actual acceleration of the gas
storage facility lease, and further believes that the occurrence
of such event would not have a material adverse effect on the
Company.
14. LITIGATION AND CONTINGENCIES
Several lawsuits have been filed against various pipeline
owners and other parties, including the Company, arising from the
rupture of several pipelines and fire as a result of severe
flooding of the San Jacinto River in Harris County, Texas on
October 20, 1994. The plaintiffs are property owners in
surrounding areas who allege that the defendant pipeline owners
were negligent and grossly negligent in failing to bury the
pipelines at a proper depth to avoid rupture or explosion and in
allowing the pipelines to leak chemicals and hydrocarbons into
the flooded area. The plaintiffs assert claims for property
damage, costs for medical monitoring, personal injury and
nuisance, and seek an unspecified amount of actual and punitive
damages.
Energy and certain of its subsidiaries are defendants in a
lawsuit originally filed in January 1993. The lawsuit is based
upon construction work performed by the plaintiff at certain gas
processing plants in 1991 and 1992. The plaintiff alleges that
it performed work for the defendants for which it was not
compensated. The plaintiff asserts claims for breach of
contract, quantum meruit, and numerous other contract and tort
claims. The plaintiff alleges actual damages of approximately
$3.7 million and punitive damages of $20.4 million. The
defendants' motion for summary judgment regarding certain of the
plaintiff's tort claims was denied. A trial date of July 22,
1996 has been set.
In 1987, certain subsidiaries of the Company entered into a
settlement agreement with a producer from whom they had purchased
natural gas to resolve a take-or-pay dispute between the parties.
As part of the settlement, the parties terminated their then-
existing gas sales contracts and entered into new gas sales
contracts. Under the settlement agreement, the Company's
subsidiaries agreed to pay one-half of any "excess royalty claim"
brought against the producer relating to any natural gas produced
and sold to the subsidiaries after the date of the settlement
agreement. In May 1995, certain mineral interest owners in South
Texas brought a lawsuit against the producer and several other
defendants, including the Company, asserting several claims in
connection with an alleged underpayment of royalties. In their
lawsuit, the mineral interest owners allege that the numerous
"operator defendants" (excluding the Company) breached certain
covenants and duties thereby depriving the plaintiffs of the full
value of their royalty interests. The plaintiffs allege that the
Company conspired with the producer to deprive plaintiffs of
royalties that they would have earned but for the settlement of
the gas contract dispute. Plaintiffs seek unspecified actual and
punitive damages.
On April 15, 1994, certain trusts named certain
subsidiaries of the Company as additional defendants (the "Valero
Defendants") to a lawsuit filed in 1989 against a supplier with
whom the Valero defendants have contractual relationships under
gas purchase contracts. In order to resolve certain potential
disputes with respect to the gas purchase contracts, the Valero
defendants agreed to bear a substantial portion of any settlement
or any nonappealable final judgment rendered against the
supplier. In January 1993, the District Court ruled in favor of
the trusts' motion for summary judgment against the supplier.
Damages, if any, were not determined. In the trusts' sixth
amended petition, the trusts seek $50 million in damages from the
Company as a result of the Valero Defendants' alleged
interference between the trusts and the supplier, and seek $36
million in take-or-pay damages from the supplier. The trusts
also seek punitive damages in an amount equal to treble the
amount of actual damages proven at trial. The Company believes
that the claims brought by the trusts have been significantly
overstated, and that the supplier and the Valero Defendants have
a number of meritorious defenses to the claims. Trial is set to
begin on May 13, 1996.
A federal securities fraud class action lawsuit was filed
against Energy and certain of its subsidiaries by a former owner
of approximately 19,500 units of limited partnership interests of
VNGP, L.P. The plaintiff alleges that the proxy statement used
in connection with the solicitation of votes for approval of the
Merger contained fraudulent misrepresentations. The plaintiff
also alleges breach of fiduciary duty in connection with the
merger transaction. The subject matter of this lawsuit was the
subject matter of a prior Delaware class action lawsuit which was
settled prior to consummation of the Merger. The Company
believes that the plaintiff's claims have been settled and
released by the prior class action settlement. The lawsuit is
scheduled for trial on December 2, 1996.
A lawsuit was filed against a subsidiary of Energy in June
1994 by certain residents of the Mobile Estate subdivision
located near the Refinery, alleging that air, soil and water in
the subdivision have been contaminated by emissions from the
Refinery of allegedly hazardous chemicals and toxic hydrocarbons.
The plaintiffs' claims include negligence, gross negligence,
strict liability, nuisance and trespass. In May 1995, the
plaintiffs filed a motion for nonsuit, seeking a dismissal of the
case against the Company. Various filings and motions by both
parties are before the court with respect to the attempted
termination of this lawsuit.
The Company owns a 20% general partner interest in
Javelina, a general partnership that owns a refinery off-gas
processing plant in Corpus Christi. Javelina has been named as a
defendant in eight lawsuits filed since 1992 in state district
courts in Nueces County and Duval 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 alleged exposure to toxic chemicals, and generally
claim that the defendants were negligent, grossly negligent and
committed trespass. The plaintiffs claim personal injury and
property damages resulting from soil and ground water
contamination and air pollution allegedly caused by the
operations of the defendants. The plaintiffs seek an unspecified
amount of actual and punitive damages. The remaining four suits
were brought by plaintiffs who either live or have businesses
near the Javelina plant. The plaintiffs in these suits allege
claims similar to those described above and seek unspecified
actual and punitive damages.
The Company is also a party to additional claims and legal
proceedings arising in the ordinary course of business. The
Company believes it is unlikely that the final outcome of any of
the claims or proceedings to which the Company is a party,
including those described above, would have a material adverse
effect on the Company's financial statements; however, due to the
inherent uncertainty of litigation, the range of possible loss,
if any, cannot be estimated with a reasonable degree of precision
and there can be no assurance that the resolution of any
particular claim or proceeding would not have an adverse effect
on the Company's results of operations for the interim period in
which such resolution occurred.
15. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended
December 31, 1995 and 1994 were as follows (in thousands of
dollars, except per share amounts):
Operating Operating Net Earnings Per Share
Revenues Income Income Of Common Stock
1995-Quarter Ended:
March 31. . . . . . . . . $ 690,535 $ 28,667 $ 3,759 $ .02
June 30 . . . . . . . . . 744,607 54,953 20,522 .40
September 30. . . . . . . 740,327 57,781 22,630 .45
December 31 . . . . . . . 844,323 47,390 12,927 .23
Total . . . . . . . . . $3,019,792 $188,791 $59,838 $1.10
1994-Quarter Ended:
March 31. . . . . . . . . $ 281,277 $ 25,578 $ 6,283 $ .13
June 30 . . . . . . . . . 416,143 30,076 4,222 .03
September 30 . . . . . . 577,429 43,155 12,534 .22
December 31 . . . . . . . 562,591 27,116 3,843 .02
Total . . . . . . . . . $1,837,440 $125,925 $26,882 $ .40
The Company's results of operations by quarter for 1994
reflect the Company's effective 49% equity interest in the
Partnership for periods prior to and including the May 31, 1994
Merger and by the consolidation of the Partnership's results of
operations thereafter. See Note 2.
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 1996 PROXY STATEMENT IN
CONNECTION WITH ITS ANNUAL MEETING OF STOCKHOLDERS SCHEDULED TO
BE HELD APRIL 30, 1996. 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, 1995
and 1994 . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of income for the years ended
December 31, 1995, 1994 and 1993 . . . . . . . . . . . .
Consolidated statements of common stock and other
stockholders' equity for the years ended
December 31, 1995, 1994 and 1993 . . . . . . . . . . . .
Consolidated statements of cash flows for the years
ended December 31, 1995, 1994 and 1993 . . . . . . . . .
Notes to consolidated financial statements . . . . . . . .
2. Financial Statement Schedules and Other Financial
Information-
No financial statement schedules are submitted because
either they are inapplicable or because the required information
is included in the Consolidated Financial Statements or notes
thereto.
3. Exhibits
Filed as part of this Form 10-K 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 -- Rights Agreement, dated as of October 26,
1995, between Valero Energy Corporation and
Harris Trust and Savings Bank, as Rights
Agent--incorporated by reference from
Exhibit 1 to the Valero Energy Corporation
Current Report on Form 8-K (Commission File
No. 1-4718, filed October 27, 1995).
4.2 -- $300,000,000 Credit Agreement, dated as of
November 1, 1995, among Valero Energy
Corporation, Morgan Guaranty and Trust Company
of New York as Administrative Agent, and Bank
of Montreal as Syndication Agent and Issuing
Bank, and the banks and co-agents party
thereto--incorporated by reference from
Exhibit 10.1 to the Valero Energy Corporation
Quarterly Report on Form 10-Q (Commission File
No. 1-4718, filed November 9, 1995).
4.3 -- Form of Indenture of Mortgage and Deed of
Trust and Security Agreement, dated as of
March 25, 1987 (the "Indenture"), from Valero
Management Partnership, L.P. to State Street
Bank and Trust Company (successor to Bank of
New England) and Brian J. Curtis, as Trustees -
incorporated by reference from
Exhibit 4.1 to the Valero Natural Gas
Partners, L.P. Quarterly Report on Form 10-Q
(Commission File No. 1-9433, filed May 15,
1987).
4.4 -- First Supplemental Indenture, dated as of
March 25, 1987, to the Indenture -
incorporated by reference from Exhibit 4.2 to
the Valero Natural Gas Partners, L.P.
Quarterly Report on Form 10-Q (Commission File
No. 1-9433, filed May 15, 1987).
4.5 -- Second Supplemental Indenture, dated as of
March 25, 1987, to the Indenture -
incorporated by reference from Exhibit 4.1 to
the Valero Natural Gas Partners, L.P.
Quarterly Report on Form 10-Q (Commission File
No. 1-9433, filed July 31, 1987).
4.6 -- Fourth Supplemental Indenture, dated as of
June 15, 1988, to the Indenture - incorporated
by reference from Exhibit 4.6 to the Valero
Natural Gas Partners, L.P. Registration
Statement on Form S-8 (Registration No. 33-26554,
filed January 13, 1989).
4.7 -- Fifth Supplemental Indenture, dated as of
December 1, 1988, to the Indenture -
incorporated by reference from Exhibit 4.7 to
the Valero Natural Gas Partners, L.P.
Registration Statement on Form S-8
(Registration No. 33-26554, filed January 13,
1989).
4.8 -- Seventh Supplemental Indenture, dated as of
August 15, 1989, to the Indenture -
incorporated by reference from Exhibit 4.6 to
the Valero Natural Gas Partners, L.P. Annual
Report on Form 10-K (Commission File No. 1-9433,
filed March 1, 1990).
4.9 -- Ninth Supplemental Indenture, dated as of
October 19, 1990, to the Indenture -
incorporated by reference from Exhibit 4.7 to
the Valero Natural Gas Partners, L.P. Annual
Report on Form 10-K (Commission File No. 1-9433,
filed February 25, 1991).
+10.1 -- Valero Energy Corporation Executive Deferred
Compensation Plan, amended and restated as of
October 21, 1986--incorporated by reference
from Exhibit 10.16 to the Valero Energy
Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed
February 26, 1988).
+10.2 -- Valero Energy Corporation Key Employee
Deferred Compensation Plan, amended and
restated as of October 21, 1986--incorporated
by reference from Exhibit 10.17 to the Valero
Energy Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed February
26, 1988).
*+10.3 -- Valero Energy Corporation Amended and Restated
Restricted Stock Bonus and Incentive Stock
Plan dated as of January 24, 1984 (as amended
through January 1, 1996).
*+10.4 -- Valero Energy Corporation Stock Option Plan
No. 3, as amended and restated January 1,
1996.
*+10.5 -- Valero Energy Corporation Stock Option Plan
No. 4, as amended and restated January 1,
1996.
+10.6 -- Valero Energy Corporation Amended and Restated
1990 Restricted Stock Plan for Non-Employee
Directors--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 Amended and Restated
Supplemental Executive Retirement Plan (as
amended through January 1, 1996).
+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 -- Valero Energy Corporation Amended and Restated
Executive Stock Incentive Plan (as amended
through January 1, 1996).
+10.10 -- 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).
*+10.11 -- Schedule of Executive Severance Agreements.
+10.12 -- Amended and Restated Employment Agreement
between Valero Energy Corporation and
William E. Greehey, dated November 1, 1993--
incorporated by reference from Exhibit 10.1 to
the Valero Energy Corporation Quarterly Report
on Form 10-Q (Commission File No. 1-4718,
filed November 14, 1994).
+10.13 -- Modification of Employment Agreement between
Valero Energy Corporation and William E.
Greehey, dated November 29, 1994--incorporated by
reference from Exhibit 10.12 to the Valero Energy
Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed March 1, 1995).
+10.14 -- Employment Agreement between Valero Energy
Corporation and F. Joseph Becraft, dated
May 1, 1995--incorporated by reference from
Exhibit 10.2 to the Valero Energy Corporation
Quarterly Report on Form 10-Q (Commission File
No. 1-4718, filed May 12, 1995).
+10.15 -- Indemnity Agreement, dated as of February 24,
1987, between Valero Energy Corporation and
William E. Greehey--incorporated by reference
from Exhibit 10.16 to the Valero Energy
Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed
February 26, 1993).
*+10.16 -- Schedule of Indemnity Agreements.
*11.1 -- Computation of Earnings Per Share.
*12.1 -- Computation of Ratio of Earnings to Fixed
Charges.
*21.1 -- Valero Energy Corporation subsidiaries,
including state or other jurisdiction of
incorporation or organization.
*23.1 -- Consent of Arthur Andersen LLP, dated February
14, 1996.
*24.1 -- Power of Attorney, dated February 16,
1996--set forth at the signatures page of this
Form 10-K.
**27.1 -- Financial Data Schedule.
______________
* 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.
** The Financial Data Schedule shall not be deemed "filed" for
purposes of Section 11 of the Securities Act of 1933 or
Section 18 of the Securities Exchange Act of 1934, and is
included as an exhibit only to the electronic filing of
this Form 10-K in accordance with Item 601(c) of Regulation
S-K and Section 401 of Regulation S-T.
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) Reports on Form 8-K.
A report on Form 8-K dated October 26, 1995 was filed
electronically on October 27, 1995, reporting Item 5. Other
Events and Item 7. Financial Statements and Exhibits, in
connection with the adoption by the Board of Directors of Energy
of the Rights Agreement dated October 26, 1995 between Energy and
Harris Trust and Savings Bank, as Rights Agent, and the
declaration by the Board of Directors of a dividend distribution
of one preference share purchase right for each outstanding share
of Common Stock of Energy. The distribution was payable on
November 25, 1995 to shareholders of record on that date. The
dividend distribution of rights coincided with the expiration
pursuant their terms of a prior series of preference share
purchase rights distributed by the Company on November 25, 1985.
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),
No. 33-53796 (filed October 27, 1992), No. 33-52533 (filed
March 7, 1994), and No. 33-63703 (filed October 26, 1995).
Insofar as indemnification for liabilities arising under
the Securities Act of 1933 may be permitted to directors,
officers and controlling persons of the registrant pursuant to
the foregoing provisions, or otherwise, the registrant has been
advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of
any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question of
whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final
adjudication of such issue.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
VALERO ENERGY CORPORATION
(Registrant)
By /s/ William E. Greehey
(William E. Greehey)
Chairman of the Board and
Chief Executive Officer
Date: February 16, 1996
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) February 16, 1996
(William E. Greehey)
Senior Vice President
and Chief Financial Officer
(Principal Financial
/s/ Don M. Heep and Accounting Officer) February 16, 1996
(Don M. Heep)
/s/ F. Joseph Becraft Director February 16, 1996
(F. Joseph Becraft)
/s/ Edward C. Benninger Director February 16, 1996
(Edward C. Benninger)
Director February , 1996
(Ronald K. Calgaard)
/s/ Robert G. Dettmer Director February 16, 1996
(Robert G. Dettmer)
/s/ A. Ray Dudley Director February 16, 1996
(A. Ray Dudley)
/s/ Ruben M. Escobedo Director February 16, 1996
(Ruben M. Escobedo)
/s/ James L. Johnson Director February 16, 1996
(James L. Johnson)
/s/ Lowell H. Lebermann Director February 16, 1996
(Lowell H. Lebermann)
/s/ Susan Kaufman Purcell Director February 16, 1996
(Susan Kaufman Purcell)