FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-4718
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1244795
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
530 McCullough Avenue 78215
San Antonio, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (210) 246-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, $1 Par Value New York Stock Exchange
$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. [X]
The aggregate market value on February 14, 1995, 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
$739 million. As of February 14, 1995, 43,762,346 shares of the
registrant's Common Stock were issued and outstanding. The
registrant also has outstanding 126,500 voting shares of its
Preferred Stock, $8.50 Cumulative Series A, for which there is no
readily ascertainable market value, and 3,450,000 shares of
$3.125 Convertible Preferred Stock, which are nonvoting.
DOCUMENTS INCORPORATED BY REFERENCE
The Company intends to file with the Securities and Exchange
Commission (the "Commission") in March 1995 a definitive Proxy
Statement (the "1995 Proxy Statement") for the Company's Annual
Meeting of Stockholders scheduled for May 9, 1995, at which
directors of the Company will be elected. Portions of the 1995
Proxy Statement are incorporated by reference in Part III of this
Form 10-K and shall be deemed to be a part hereof.
<PAGE>
CROSS REFERENCE SHEET
The following table indicates the headings in the 1995 Proxy
Statement where the information required in Part III of Form 10-K
may be found.
<TABLE>
<CAPTION>
Form 10-K Item No. and Caption Heading in 1995 Proxy Statement
<S> <C>
10. "Directors and Executive Officers of the
Registrant". . . . . . . . . . . . . . . "Item No. 1 - Election of Directors" and
"Information Concerning Directors (Classes I and
II)"
11. "Executive Compensation" . . . . . . . . . "Information Concerning Executive Compensation,"
"Arrangements with Certain Officers and Directors"
and "Compensation of Directors"
12. "Security Ownership of Certain Beneficial
Owners and Management" . . . . . . . . . "Beneficial Ownership of Voting Securities"
13. "Certain Relationships and Related
Transactions". . . . . . . . . . . . . . "Transactions with Management and Others"
</TABLE>
Copies of all documents incorporated by reference, other
than exhibits to such documents, will be provided without charge
to each person who receives a copy of this Form 10-K upon written
request to Rand C. Schmidt, Corporate Secretary, Valero Energy
Corporation, P.O. Box 500, San Antonio, Texas 78292.
<PAGE>
CONTENTS
PAGE
Cross Reference Sheet. . . . . . . . . . . . .
PART I
Item 1. Business. . . . .. . . . . . . . . . . . . . .
Recent Developments. . . . . . . . . . . . . .
Acquisition of VNGP, L.P. . . . . . . . . .
Methanol Plant Joint Venture. . . . . . . .
Uncertainty in Gasoline Markets . . . . . .
Proesa MTBE Plant . . . . . . . . . . . . .
Petroleum Refining and Marketing . . . . . . .
Refining Operations . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . .
Resid Supply . . . . . . . . . . . . .. . .
Factors Affecting Operating Results . . . .
Natural Gas. . . . . . . . . . . . . . . . . .
Transmission System . . . . . . . . . . . .
Gas Sales . . . . . . . . . . . . . . . . .
Gas Transportation and Exchange . . . . . .
Gas Supply and Storage. . . . . . . . . . .
Natural Gas Liquids. . . . . . . . . . . . . .
Governmental Regulations . . . . . . . . . . .
Texas Regulation. . . . . . . . . . . . . .
Federal 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 . . . . . . . . . .
<PAGE>
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, including the Partnership. The term
"Partnership" refers collectively to Valero Natural Gas Partners,
L.P. ("VNGP, L.P.") and its consolidated subsidiaries. See
"Recent Developments - Acquisition of VNGP, L.P."
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, and markets those refined products. See
"Petroleum 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
the United States and Mexico, and provides gas transportation
services to third parties. See "Natural Gas." The Company also
owns 11 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."
RECENT DEVELOPMENTS
Acquisition of VNGP, L.P.
Effective May 31, 1994, VNGP, L.P. merged with a wholly
owned subsidiary of Energy (the "Merger"). The holders of the
common units of limited partner interests of VNGP, L.P. ("Common
Units") approved the Merger at a special meeting held at the
offices of the Company on May 31, 1994. Upon consummation of the
Merger, the publicly traded Common Units were converted into the
right to receive cash in the amount of $12.10 per Common Unit.
As a result of the Merger, all of the Common Units are owned by
the Company. Prior to the Merger, the Company held an
approximate 49% effective equity interest in the Partnership.
Because of the Merger, the Company changed its method of
accounting for its investment in the Partnership from the equity
method to the consolidation method as of May 31, 1994. See
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 1 of Notes to Consolidated
Financial Statements. In March 1994, Energy issued
3,450,000 shares of $3.125 convertible preferred stock and
received net cash proceeds of approximately $168 million. The
Company used approximately $117.5 million of the convertible
preferred stock proceeds to acquire the publicly traded Common
Units. The remaining proceeds were used to reduce outstanding
indebtedness and to pay expenses of the acquisition.
Methanol Plant Joint Venture
On December 1, 1994, Hoechst Celanese Chemical Group,
Inc. ("Celanese") and the Company formed a joint venture to
renovate and operate a 13,000-barrel-per-day methanol plant owned
by Celanese in Clear Lake, Texas. The Company will contribute
$75 million to the venture ($15 million of which was paid in
1994), while Celanese will provide the methanol unit and plant
infrastructure and serve as operator of the facility. Celanese
will refurbish and operate the plant, and each owner will be
entitled to one-half of the plant's methanol production. The
refurbished plant is expected to be placed in service in the
second quarter of 1995. The plant will complement the Company's
refining operations by providing the methanol feedstock necessary
for the production of oxygenates at the Refinery. Recent market
prices for methanol have been substantially in excess of the cost
of production. If these higher market prices for methanol
continue to prevail, the addition of this facility is expected to
improve the Company's overall results of operations. The Company
will also supply to the joint venture at least one-half of the
natural gas feedstock required for the plant's production of
methanol.
Uncertainty in Gasoline Markets
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 reformulated
gasoline ("RFG") program. The oxygenated fuel program began in
1992, and requires the 39 areas designated nonattainment for
carbon monoxide to use gasoline during winter months 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. In addition, the EPA's RFG
program commenced January 1, 1995. The RFG program 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 removing aromatics and benzene from regular
gasoline and adding an oxygenate, primarily MTBE or ethanol.
MTBE (methyl tertiary butyl ether) is an oxygen-rich,
high-octane gasoline blendstock produced by reacting methanol
and isobutylene, and is used to manufacture oxygenated and
reformulated gasolines.
The mandated January 1, 1995 transition from
conventional gasoline to RFG in many areas of the country caused
considerable disarray in gasoline markets beginning in the fourth
quarter of 1994, negatively impacting the Company's refining
margins. The market instability was generally attributable to
uncertainties during the first winter of the RFG program. In
December 1994, as the industry prepared for the start-up of the
RFG program, certain counties in Pennsylvania, New York and
Maine which had formerly "opted-in" to the RFG program
announced that they were "opting-out." Based on fears that other
areas would create an RFG surplus by following these counties'
lead, the market responded with severe declines in RFG and
oxygenate prices. The EPA stated that it would allow the "opt-
outs" by not enforcing RFG regulations in the "opt-out" areas.
The market fears were exacerbated by New Jersey's announcement in
early February 1995 of its intent to shorten the duration of its
winter oxygenated gasoline programs and to reduce the required
oxygen content in its gasoline to 2.0% by weight from 2.7% by
March 1, 1995. These uncertainties, together with high refinery
run rates and the general assumption that enough RFG exists to
satisfy current demand, have kept RFG and oxygenate prices
depressed in the spot market and have caused substantial price
fluctuations. Depressed RFG prices and the build-up of MTBE
inventories during the second half of 1994 also depressed the
price of MTBE. In the fourth quarter of 1994, prices for
methanol and butane (feedstocks for the manufacture of MTBE)
remained strong, resulting in feedstock and manufacturing costs
that exceeded the spot value of MTBE. Accordingly, the Company
temporarily reduced its MTBE production by 37% in December 1994
(using existing MTBE inventories to satisfy customer needs). In
January 1995, the Company's production of MTBE at capacity levels
resumed.
Market stability was further delayed because of a
request by Wisconsin to halt the use of RFG until April 1, 1995
in its six southeastern counties (which include the greater
Milwaukee area, one of the nine U.S. areas designated
nonattainment for ozone). In late February 1995, the EPA denied
Wisconsin's request. Gasoline markets were cautious pending the
EPA's decision, however, because the greater Milwaukee area would
have been the first "mandated" (as opposed to "opt-in") area to
be excused from full compliance with the RFG program if the EPA
had granted the request. The Company believes that as the
industry adapts to the RFG program throughout the first quarter
of 1995, demand levels and pricing relationships among RFG,
methanol and MTBE are likely to become more firmly established.
Until the desired market stability is achieved, however, the
Company remains unable to predict the future profitability of its
RFG operations.
Finally, future demand for MTBE may be adversely
affected by the renewable oxygenate regulations promulgated by
the EPA under the Clean Air Act in June 1994. These regulations
require that at least 15% of the oxygenates used in RFG in 1995
originate from renewable sources, primarily ethanol. The 15%
requirement increases to 30% in 1996 and beyond. The American
Petroleum Institute and the National Petroleum Refiners
Association challenged in federal court the EPA's authority to
promulgate the renewable oxygenate regulation. In September
1994, the United States Court of Appeals for the District of
Columbia Circuit granted a motion to stay implementation of the
regulations until the date of the court's ultimate ruling in the
lawsuit. The court is not expected to rule on the matter until
sometime during the second or third quarter of 1995.
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 has not been 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 $450 million, and to produce
approximately 17,000 barrels of MTBE per stream day (based on an
estimated 346 stream days per year).
Proesa has entered into license agreements with a third
party relating to processes to be utilized in the Plant.
Proesa's obligation under the license agreements is approximately
$45 million, and Proesa's minimum obligation, if such license
agreements were canceled, would be approximately $7 million at
January 31, 1995. 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 equal to 10% of the estimated value of MTBE to be delivered
to Pemex during the Plant's first year of operations. Pemex may
call for payment under the surety bond in the event that
deliveries of MTBE are not made to Pemex as specified in the
agreement. Under current market conditions, however, the Company
believes that Proesa would be able to supply Pemex with the
requisite quantities of MTBE even if the Plant were not
ultimately built. The surety bond has an insurable value of
41.3 million New Pesos which, based on the exchange rate at
February 23, 1995, was approximately $7.4 million. The Company
has agreed to guarantee 45% of Proesa's obligations to the surety
company under this arrangement but this agreement has not been
formally documented. Proesa has no independent source of
funding. Therefore, in the event of any cash requirements to
fund payments under the license agreements, surety bond, or other
operating needs, Proesa necessarily would request additional
funding from its owners.
Beginning in December 1994, the Mexican peso experienced
substantial devaluation as the exchange rate deteriorated from
approximately 3.4 New Pesos per $1 U.S. to approximately 5.6 New
Pesos per $1 U.S. at February 23, 1995. This instability caused
interest rates in Mexico to increase significantly and the
Mexican stock market to experience a substantial decline in
market value. As a result of the current Mexican economic
conditions, as well as other factors, the Company cannot
currently determine if Infomin can fund its pro rata share of
Project costs. Infomin has indicated to the Company that it is
interested in reducing its interest in Proesa. However, the
Company is not willing to increase its interest in Proesa, and
believes that the willingness of Dragados or third parties to
take additional shares in Proesa is limited. In addition,
current operating margins for MTBE are considerably lower than
when the Project was conceived.
Based on the foregoing 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. In particular, the Board has
required the renegotiation of purchase and sales agreements
between Proesa and Pemex, the implementation of certain
additional agreements with Pemex, and a reevaluation of the
economics of the Project. Additionally, the Board has required
that the Project participants reach definitive agreement
regarding their ownership interests in Proesa and their funding
commitments to the Project, including procedures for funding any
possible cost overruns.
The Company has begun negotiations with Pemex and the
Project participants to address the issues identified by the
Board of Directors of Energy. If the foregoing matters can be
satisfactorily resolved, the Company intends to proceed with the
Project. However, there can be no assurance that mutually
satisfactory agreements can be reached between Proesa and Pemex
or among the Project participants. At December 31, 1994, the
Company had invested approximately $13.4 million in the Project.
See Note 6 of Notes to Consolidated Financial Statements. The
Company estimates that if the Project is delayed and further
expenditures are reduced to the minimum practicable level until
resolution of the issues mentioned above, the Company will have a
total investment in the Project of approximately $18 million at
the end of the first quarter of 1995, excluding any funding that
may be required with respect to the surety bond discussed above.
PETROLEUM REFINING AND MARKETING
Refining Operations
The Refinery is designed to process primarily high-
sulfur atmospheric tower bottoms, a type of residual fuel oil
("resid"), into a product slate of higher value products,
principally RFG and middle distillates. The Refinery also
processes crude oil, butanes and other feedstocks. The Refinery
can produce over 150,000 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 the refining and marketing
operating results of the Company for the three years ended
December 31, 1994, 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 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 66,000 barrels per
day. The HOC processes feedstock primarily from the HDS Unit,
and has a capacity of approximately 70,000 barrels per day. The
"MTBE Plant" can produce 15,500 barrels per day of MTBE from
butane and methanol feedstocks. The Company can blend the MTBE
produced at the Refinery into the Company's own gasoline cargos
or sell the MTBE separately. The "HOC MTBE/TAME Unit" converts
streams produced at 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 HOC MTBE/TAME Unit
enable the Company to produce approximately 21,000 barrels per
day of MTBE and other oxygenates. All the butane feedstocks
required to operate the MTBE Plant are available through the
Company's operations. All the methanol feedstocks required for
the production of oxygenates at the Refinery are expected to be
provided by the methanol plant joint venture beginning in the
second quarter of 1995. See "Recent Developments - Methanol
Plant Joint Venture."
The Refinery's other significant units include a
34,000 barrel per day "Hydrocracker" (which produces reformer
feed naphtha from the Refinery's gas oil and distillate streams),
a 34,000 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 25,000 barrel per day reformate splitter (which extracts a
benzene concentrate stream from reformate produced at the
Reformer), a 30,000 barrel per day crude unit, and a
23,000 barrel per day vacuum unit. An application to repermit
the entire Refinery was submitted in 1994 to enable the Refinery
to operate at even higher throughput rates.
In 1994, the Company added 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 constructed an environmentally friendly bio-slurry
reactor process at the Refinery which uses microorganisms to
biodegrade and treat solid waste.
The HOC was down in the fall of 1994 for a scheduled
turnaround completed in October. Improvements made during the
downtime increased the HOC's capacity by approximately
4,000 barrels per day and improved its product yields. The MTBE
Plant was down in November 1994 to correct certain mechanical
problems. The Refinery's other principal refining units operated
during 1994 without significant unscheduled downtime. The
HDS Unit is scheduled to be down beginning in the first quarter
of 1995 for maintenance and a catalyst change. This maintenance
and catalyst change is required about every 15 months. Also, the
Hydrocracker and the Reformer are scheduled for turnarounds
beginning in the first quarter of 1995. Other than the HDS Unit,
most of the principal refining units are required to undergo
maintenance turnarounds every three years.
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. See Note 13 of Notes to Consolidated Financial
Statements. The Company also owns dock facilities that can
unload simultaneously two 150,000 dead weight ton capacity ships
and can dock larger crude carriers after partial unloading.
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 has made capital contributions
and advances to Javelina of approximately $20.2 million
(including capitalized interest and overhead) through
December 31, 1994, for the Company's proportionate share of
capital expenditures and operating expenses. Javelina maintains
a term loan agreement and a working capital and letter of credit
facility that mature on January 31, 1996. The Company's
guarantees of these bank credit agreements were approximately
$16.3 million at December 31, 1994.
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,
1994. 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.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Throughput volumes (Mbbls per day). . . . 146 136 119
Average throughput margin per barrel. . . $5.36 $5.99<F1> $7.00
Sales volumes (Mbbls per day) . . . . . . 140 133 123
<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 Note 1 of Notes to Consolidated Financial Statements.
</FN>
</TABLE>
The Company has historically sold refined products on a
spot and truck rack basis, but has recently begun selling refined
products under term contracts as well. A truck rack sale is a
sale to a customer that provides trucks to take delivery at
loading facilities. In 1994, spot and truck rack sales volumes
accounted for 87% and 13%, respectively, of combined gasoline and
distillate sales. 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 midwestern or southeastern United States.
Sales of refined products under term contracts are made
principally to large oil companies. The Company recently
implemented a new marketing strategy to capitalize on the
emerging RFG and oxygenates markets. Approximately 50% of the
Company's 1995 RFG production is already under contract to supply
major gasoline marketers in the Houston and Dallas/Fort Worth
areas at market-related prices. In 1994, the Company also
appointed an exclusive agent for a three-year term for the
wholesale truck rack marketing of the Company's refined products
in the northeast United States. In addition, the Company has
contracted for two tankers to transport RFG to the Northeast.
The Northeast is currently the largest RFG market in the United
States.
Resid 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. A substantial portion of the Company's
resid supplies are obtained from the Middle East. These supplies
are loaded aboard chartered vessels at ports in the Arabian Gulf
and are subject to the usual maritime hazards. The Company
maintains insurance on its feedstock cargos.
Under a feedstock supply agreement with the Company
renewed in late 1994, Arabian American Oil Company ("Aramco") has
agreed to provide an average of 36,000 barrels per day of resid
to the Company at market-based prices. Resid delivery levels
were approximately 55,000 barrels per day under the prior
arrangement. Deliveries under the new agreement will continue
through 1996 and provide approximately 45% of the Company's resid
requirements. This contract is subject to possible price
renegotiation at the end of the first year, with offtake volumes
being subject to possible reduction if agreement is not reached.
During 1994, the Company also purchased approximately 11,000
barrels per day of South Korean resid at market-based prices
under an agreement that expired in the first quarter of 1995.
The South Korean contract was renewed for an additional year for
11,000 barrels per day of resid to be purchased by the Company at
market-based prices. The Company believes that if either of the
existing feedstock arrangements were interrupted or terminated,
supplies of resid could be obtained from other sources or on the
open market. However, over the past year, demand for the type of
resid feedstock now processed at the Refinery has increased in
relation to the availability of supply. See "Petroleum Refining
and Marketing - Factors Affecting Operating Results."
Accordingly, if either arrangement were to terminate, the Company
could be required to incur higher feedstock costs or substitute
other types of resid, thereby producing less favorable operating
results. The remainder of the Refinery's resid feedstocks are
purchased at market-based prices under short-term contracts.
Factors Affecting Operating Results
The Company's refining and marketing operating results
are determined principally 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
its price risk management activities to hedge various portions of
its refining operations. 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. However, resid usually sells at
a discount to crude oil ("resid discount") sufficient to enable
the Company 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 crude oil demand (which generates more resid when processed)
and worldwide additions to resid conversion capacity (which has
the effect of reducing the available supply of resid).
In 1994, the resid discount was reduced by over $2.50
per barrel in the spot market. This change in the resid discount
impacted the Company's market-related term feedstock
arrangements, although by an amount less than the spot market
decline. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Results of Operations -
1994 Compared to 1993 - Segment Results - Refining and
Marketing." Several factors contributed to the recent 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. Moreover,
unusually hot weather in Japan in 1994 boosted that country's
demand for resid for power generation. 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 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.
The Company expects the global demand for gasoline to
continue to increase along with the general growth in economic
activity worldwide. Most of this demand growth is expected to
occur outside the United States. With the increase in upgrading
capacity in 1994, combined with new upgrading capacity planned in
1995, it is expected that the supply of gasoline will be adequate
to meet all of the demand increase. This upgrading capacity is
expected to reduce resid output further. Therefore, the Company
believes that the resid discount will remain tight through 1995.
Although domestic gasoline production will continue to
be supplemented significantly with foreign imports, the Company
believes that the availability of foreign gasoline supplies for
import into the United States may be reduced because of the
implementation of the RFG program in this country. For a further
discussion of the Clean Air Act and its impact on the refining
industry, see "Recent Developments - Uncertainty in Gasoline
Markets" and "Environmental Matters."
NATURAL GAS
The Company owns and operates natural gas pipeline
systems principally serving Texas intrastate markets. The
Company also markets natural gas throughout the United States
through interconnections with interstate pipelines. The
Company's natural gas pipeline and marketing operations consist
principally of purchasing, gathering, transporting and selling
natural gas to gas distribution companies, electric utilities,
other pipeline companies and industrial customers, and
transporting natural gas for producers, other pipelines and end
users. The Company's natural gas operations consist primarily of
the natural gas operations conducted through the Partnership
which were acquired in connection with the Merger described above
(see "Recent Developments - Acquisition of VNGP, L.P."). 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 below
reflect the combination of all such natural gas operations for
all of 1994, 1993 and 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.
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
42 mainline compressor stations with a total of approximately
174,000 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 2.8 TBtu<F1> per day
in 1994, and has been in excess of 2.3 TBtu per day in recent
years. The Company's owned and leased pipeline systems have
69 interconnects with 19 intrastate pipelines, 39 interconnects
with 13 interstate pipelines, and two international interconnects
with Pemex in South Texas.
[FN]
<F1>
The term "Btu" means British Thermal Unit, a standard
measure of heating value. The terms MMBtu, BBtu and TBtu
mean million Btu's, billion Btu's, and trillion Btu's,
respectively. The number of MMBtu's of total natural gas
deliveries is approximately equal to the number of Mcf's
(thousand cubic feet) of such deliveries. An Mcf 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.
Gas Sales
The following table sets forth the Company's gas sales
volumes and average gas sales prices for the three years ended
December 31, 1994.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Intrastate sales (BBtu per day). . . . . . . . 638 699 630
Interstate sales (BBtu per day). . . . . . . . 506 452 357
Total. . . . . . . . . . . . . . . . . . 1,144 1,151 987
Average gas sales price per MMBtu. . . . . . . $2.07 $2.32 $2.08
</TABLE>
Sales of natural gas accounted for approximately 40%,
41% and 41% of the Company's total daily gas volumes for 1994,
1993 and 1992, 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 1994, the
Company sold natural gas under hundreds of separate short- and
long-term gas sales contracts. Through the use of financial
instruments such as swaps, futures and options, the Company
hedges the risk associated with fluctuating natural gas prices.
See Note 5 of Notes to Consolidated Financial Statements. The
Company's gas sales are made primarily to gas distribution
companies, electric utilities, other pipeline companies and
industrial users. The gas sold to distribution companies is
resold to consumers in a number of cities including San Antonio,
Dallas, Austin, Corpus Christi and Chicago. The demand for
natural gas has increased at a rate of approximately 3.5% per
year since 1986. The Company expects that long-term demand will
continue to grow about 2% per year, especially in the industrial
and power generation sectors, although natural gas demand in 1994
was negatively affected by unseasonably mild weather during the
fourth quarter and the operations of alternative fuel facilities
in the Company's core service area. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -
Results of Operations - 1994 Compared to 1993 - Segment Results -
Natural Gas."
The Company's largest gas sales customer is San Antonio
City Public Service ("CPS"). The Company supplies 100% of CPS's
natural gas requirements. The CPS contract is effective until
2002, subject to possible renegotiation of certain contract terms
beginning in 1997. Natural gas sales to CPS in 1994 represented
approximately 12% of the Company's total consolidated daily gas
sales volumes (but less than 10% of the Company's consolidated
operating revenues). Except for the CPS contract, 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."
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 must acquire 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 1994, 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 300 BBtu per day with terms ranging from one to ten
years.
Order 636 has created a new market 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 and Mexico City. The Company
also operates the Waha-Permian Basin Hub in West Texas under a
1994 agreement with a third party to support that party's
electronic trading system to forward buy and sell physical
quantities of gas. In 1995, the Company also agreed to operate
the Waha hub as the designated delivery point for a new futures
contract proposed by the Kansas City Board of Trade. This
futures contract would provide risk management opportunities for
natural gas markets in the Western United States. Finally, in
anticipation of new opportunities expected in connection with the
FERC's deregulation of the electric power generation industry,
the Company secured its power marketing certificate from the FERC
in 1994 in order to participate in the wholesale bulk power
business.
Gas Transportation and Exchange
The following table sets forth the Company's gas
transportation volumes and average transportation fees for the
three years ended December 31, 1994.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Transportation volumes (BBtu per day). . . . . 1,682 1,672 1,406
Average transportation fee per MMBtu . . . . . $.102 $.107 $.106
</TABLE>
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 60%, 59% and 59% of total daily
gas volumes for 1994, 1993 and 1992, 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. In 1994,
transportation rates were notably 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. Despite this increased capacity, the
Company's 1994 transportation revenues were negatively impacted
by reduced demand for natural gas in 1994 and increased
competition for transportation services. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations - Results of Operations - 1994 Compared to 1993 -
Segment Results - Natural Gas."
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 1994, 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. Because of the extensive
coverage within the State of Texas by the Company's pipeline
systems, the Company believes that 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. To meet Order 636 term business, the
Company supplemented its own natural gas storage capacity by
securing during 1994 an additional 5 Bcf of third-party storage
capacity for the 1994-95 winter heating season.
NATURAL GAS LIQUIDS
The Company owns 11 gas processing plants and is a major
producer and marketer of NGLs. The Company's NGL operations
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 at the Refinery. The Company's NGL
operations consist primarily of the NGL operations conducted
through the Partnership which were acquired in connection with
the Merger described above (see "Recent Developments -
Acquisition of VNGP, L.P."). In addition, the Company's NGL
operations include the operations of certain South Texas NGL
assets acquired by the Company in May 1992 and not included
within the operations of the Partnership. For comparability
purposes, the information and statistics below reflect the
combination of all such NGL operations for all of 1994, 1993 and
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.
Recent expansions and improvements at the Company's gas
processing plants increased 1994 NGL production to 29 million
barrels for the year and a record average for the Company of
approximately 80,000 barrels per day. The table below sets forth
NGL production volumes, average NGL market prices, and average
gas costs for the three years ended December 31, 1994.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
NGL plant production (Mbbls per day) . . . . . 79.5 77.4 67.7
Average market price per gallon<F1>. . . . . . $.271 $.287 $.314
Average gas cost per MMBtu . . . . . . . . . . $1.75 $1.96 $1.61
<FN>
<F1>
Represents the average Houston area market prices for individual NGL products weighted
by relative volumes of each product produced.
</FN>
</TABLE>
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 1994,
approximately 77% of the Company's butane production was used as
a feedstock for the Refinery's MTBE Plant.
The Company's 11 gas processing plants are located in
South and West 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
444 miles of NGL pipelines, 460 miles of gathering lines, and
fractionation facilities at five locations. The Company
fractionated an average of 77,600 barrels per day in 1994,
approximately 17% of which represented NGLs fractionated for
third parties. The Company's NGL pipelines transport NGLs from
gas processing plants to fractionation facilities. The NGL
pipelines also connect with end users and major common-carrier
NGL pipelines, which ultimately deliver NGLs to the principal NGL
markets. The Company's NGL pipelines are located principally in
South Texas and West Texas. In South Texas, the Company owns
200 miles of NGL pipelines that directly or indirectly connect
five of the Company's processing plants and four 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 Company's four largest NGL customers accounted for
approximately 62% of the Company's 1994 NGL product sales
revenues to nonaffiliates (although none of these customers
accounted for 10% or more of the Company's total consolidated
revenues). The petrochemical industry represents an expanding
principal market for NGLs due to increasing market demand for
ethylene-derived products. Both NGL demand and prices were
benefitted by the start-up of a new ethylene plant and a new
butane dehydrogenation MTBE plant along the Texas Gulf Coast
region during the second quarter of 1994. These plants increased
the NGL base demand by at least 30,000 barrels per day during
1994. In the first quarter of 1995, another new ethylene plant,
together with expansions to existing ethylene plants along the
Texas Gulf Coast, will have the potential to increase NGL demand
by an additional 50,000 to 60,000 barrels per day.
The Company's ability to process natural gas attracts
significant gas supplies to the Transmission System. In 1994,
the Company secured approximately 800 BBtu per day of natural gas
supplies from natural gas producers under agreements to process,
transport or purchase their natural gas for terms ranging from
two to ten years. Of these supplies, approximately 225 BBtu per
day represent new natural gas supplies dedicated to the Company's
pipeline system.
GOVERNMENTAL REGULATIONS
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 (defined as casinghead gas, gas from wells
primarily producing oil, and certain special allowable gas that
are the last to be shut in during periods of reduced market
demand) having higher priority than gas well gas (defined as gas
from wells primarily producing gas), notwithstanding any
contractual commitments. The 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 - 1994 Compared
to 1993 - 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. The RRC requires the filing of tariffs
and compliance with environmental and 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.
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
8,000-mile pipeline system is an intrastate business not subject
to direct regulation by the FERC. Although the Company's
interstate 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.
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. Prices of
feedstocks and refined products are established principally by
market conditions. 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.
Within the next several years, all United States
refineries must obtain operating permits under the Clean Air Act.
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.
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. Despite the increased competition, the
Company generally believes that it has been able to take
advantage of the increased business opportunities resulting from
the implementation of Order 636. Accordingly, 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." Firm and term contracts have
become more common in the industry in recent years. These
contracts generally require gas suppliers to commit to specified
deliveries of gas without the option of interrupting service and
penalize gas suppliers for failure to perform in accordance with
their contractual commitments. Because of Order 636, the 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.
The acquisition of gas supply is capital intensive, as it
frequently requires installation of new gathering lines to reach
sources of gas. Additionally, the combination of intrastate and
interstate pipelines within one organization may in some
instances enable competitors to lower gas prices and
transportation fees, and thereby increase price competition in
the Company's intrastate and interstate markets.
The U.S.-Canada free trade agreement and changes in
Canadian export regulations have increased Canadian natural gas
imports into the United States. Under the North American Free
Trade Agreement, Canadian natural gas imports into the United
States are expected to continue. Canadian imports have increased
competition in the interstate markets in which the Company
competes for natural gas sales and have affected natural gas
availability and prices in the Texas intrastate market. As a
result, competition in the natural gas industry is expected to
remain intense.
Natural Gas Liquids
The 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. Compliance with regulations promulgated by these
authorities increases the cost of designing, installing and
operating such facilities. The regulatory requirements relate to
water and storm water discharges, waste management and air
pollution control measures. In 1994, capital expenditures for
the Company's refining operations attributable to compliance with
environmental regulations were approximately $6 million and are
currently estimated to be the same for 1995. 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 "Recent
Developments - Uncertainty in Gasoline Markets."
The Company's capital expenditures for environmental
control facilities related to its natural gas and NGL operations
were not material in 1994 and are not expected to be material in
1995. Currently, expenditures are made to comply with air
emission regulations and solid waste management regulations
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, 1995, the Company had 1,658 employees.
<PAGE>
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as
of December 31, 1994 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.
<TABLE>
<CAPTION>
___________________________________________________________________________________________
Energy Year First Elected Age as of
Position and or Appointed as December 31,
Name Office Held Officer or Director 1994
___________________________________________________________________________________________
<S> <C> <C> <C>
William E. Greehey Director, Chairman of 1979 58
the Board and Chief
Executive Officer
Edward C. Benninger Director, Executive 1979 52
Vice President
Stan L. McLelland Executive Vice President 1981 49
and General Counsel
Don M. Heep Senior Vice President and 1990 45
Chief Financial Officer
Steven E. Fry Vice President Administration 1980 49
E. Baines Manning<F1> Senior Vice President, 1992<F1> 54
Valero Refining and
Marketing Company
Martin P. Zanotti<F1> Executive Vice President, 1992<F1> 62
Valero Refining and
Marketing Company
___________________________________________________________________________________________
<FN>
<F1>
Messrs. Manning and Zanotti have been designated by the
Energy Board of Directors as "executive officers" of the
Registrant in accordance with Rule 3b-7 under the
Securities Exchange Act of 1934, as amended (the
"Exchange Act"), and will be eligible for inclusion in
the Summary Compensation Table in the Proxy Statement.
Mr. Zanotti retired from the Company effective
December 31, 1994.
</FN>
</TABLE>
Mr. Greehey has served as Chief Executive Officer and as
a director of Energy since 1979 and as Chairman of the Board
since 1983. Mr. Greehey is also a director of Weatherford
International Incorporated and Santa Fe Energy Resources, Inc.,
neither of which are affiliated with 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 Financial Officer from 1986 to 1992. In 1992, he was
elected Executive Vice President and Chief Operating Officer of
Valero Natural Gas Company.
Mr. McLelland was elected Executive Vice President and
General Counsel in 1989 and had served as Senior Vice President
and General Counsel of Energy since 1981.
Mr. Heep was elected Senior Vice President and Chief
Financial Officer of Energy in 1994, prior to which he served as
Vice President Finance since 1990.
Mr. Fry was elected Vice President Administration of
Energy in 1989 and served as Secretary of Energy from 1980 to
1992.
Mr. Zanotti, until his retirement on December 31, 1994,
served as Executive Vice President of Valero Refining and
Marketing Company since 1988 and as President and Chief Operating
Officer of Valero Refining Company since 1990.
Mr. Manning has served as Senior Vice President of
Valero Refining and Marketing Company since 1986 and of Valero
Refining Company since 1987.
ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery
and related facilities, 11 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:
Cook, et al. v. Shell Oil Company; Texaco, Inc.; Valero
Management Company; et al., 172nd State District Court, Jefferson
County, Texas (filed November 7, 1994). This lawsuit arises 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
Highlands, Crosby, Baytown, and McNair, Texas, and surrounding
areas. The plaintiffs 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 original plaintiffs and additional
intervening plaintiffs make other similar assertions and seek
certification as a class. 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.
Harding, et al. v. Browning-Ferris Industries, Inc.;
Valero Refining Company; et al. 229th State District Court, Duval
County, Texas (filed March 1, 1994). In June 1994, Valero
Refining Company ("VRC") was added as a defendant in a lawsuit
filed by several hundred plaintiffs who are residents of San
Patricio County, Texas. The suit was brought against numerous
defendants whom the plaintiffs allege are either owners or
operators of a landfill site in San Patricio County, or
generators of hazardous wastes accepted into the landfill. VRC
is named as a "generator" of hazardous wastes accepted into the
landfill. The plaintiffs claim that hazardous wastes escaped
from the landfill and were released into the surrounding ground,
water and air, allegedly causing damages including bodily injury,
emotional distress, costs for medical monitoring and devaluation
of property. The plaintiffs seek an unspecified amount of actual
and punitive damages. In January 1995, the parties reached a
tentative settlement of the plaintiffs' claims against VRC on
terms immaterial to VRC and the Company. The settlement of
certain claims held by plaintiffs who are minors is subject to
final approval by the court.
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). Energy and Valero
Hydrocarbons, L.P. were named as original defendants in the
lawsuit filed in January 1993. Through the plaintiff's amended
petitions, the lawsuit now includes several other subsidiaries of
the Company as additional defendants. The lawsuit arises from
construction work performed by the plaintiff at certain of the
Partnership'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's second amended
petition, filed April 30, 1994, asserts claims for breach of
contract and numerous tort claims. The plaintiff alleges actual
damages of approximately $9.7 million and punitive damages of
$45.5 million. The defendants have filed a motion for partial
summary judgment to dismiss the plaintiff's tort claims.
The Long Trusts v. Tejas Gas Corporation, 123rd Judicial
District Court, Panola County, Texas (filed March 1, 1989).
Valero Transmission Company ("VTC"), as buyer, and Tejas Gas
Corporation ("Tejas"), as seller, are parties to various gas
purchase contracts assigned to and assumed by Valero
Transmission, L.P. ("VT, L.P.") upon formation of the Partnership
in 1987 (the "Valero Contracts"). In turn, Tejas has entered
into a series of gas purchase contracts between Tejas, as buyer,
and certain trusts (the "Long Trusts"), as seller (the "Long
Trusts Contracts"). The litigation originated in 1989 as a
lawsuit by the Long Trusts against Tejas. In the Long Trusts'
claims against Tejas, the Long Trusts claim that Tejas breached
various minimum take, take-or-pay and other contractual
provisions in connection with the Long Trusts Contracts, and seek
alleged actual damages, including interest, of approximately $30
million. Neither VTC nor VT, L.P. was originally a party to the
lawsuit. However, because of the relationship between the Valero
Contracts and the Long Trusts Contracts, and in order to resolve
existing and potential disputes, Tejas, VTC and VT, L.P. agreed
in March 1991 to cooperate in the conduct of the litigation, and
agreed that VTC and VT, L.P. will bear a substantial portion of
the costs of any appeal and any nonappealable final judgment
rendered against Tejas. In January 1993, the District Court
ruled on the Long Trusts' motion for summary judgment, finding
that as a matter of law the Long Trusts Contracts were fully
binding and enforceable, that Tejas breached the minimum take
obligations under one of the contracts, that Tejas is not
entitled to claimed offsets for gas purchased by third parties
and that availability of gas for take-or-pay purposes is
established solely by the delivery capacity testing procedures in
the contracts. Damages, if any, were not determined. On
April 15, 1994, the Long Trusts named VTC and VT, L.P. as
additional defendants (the "Valero Defendants") to the lawsuit,
alleging that the Valero Defendants maliciously interfered with
the Long Trusts Contracts. In the Long Trusts' claim against the
Valero Defendants, the Long Trusts seek unspecified actual and
punitive damages. 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.
Ventura, et al. v. Valero Refining Company, 105th State
District Court, Nueces County, Texas (filed June 17, 1994). This
lawsuit was filed against VRC 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 of allegedly hazardous chemicals
and toxic hydrocarbons produced by Refining. The plaintiffs'
claims include negligence, gross negligence, strict liability,
nuisance and trespass. The plaintiffs seek certification as a
class and an unspecified amount of damages based on an alleged
diminution in the value of their property, loss of use and
enjoyment of property, emotional distress and other costs.
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 seven lawsuits filed
since 1992 in state district courts in Nueces County, and Duval
County, Texas. Five 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. One of the
suits seeks certification of the litigation as a class action.
The plaintiffs seek an unspecified amount of actual and punitive
damages. The other two suits were brought by plaintiffs who
either live or have businesses near the Javelina Company plant.
The suits allege claims similar to those described above. These
plaintiffs do not specify an amount of damages claimed.
The Company is also a party to additional claims and
legal proceedings arising in the ordinary course of business. The
Company believes it is unlikely that the final outcome of any of
the claims or proceedings to which the Company is a party,
including those described above, would have a material adverse
effect on the Company's financial 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 1994.
<PAGE>
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 14, 1995, there were
approximately 7,500 holders of record and an estimated 19,000
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:
<TABLE>
<CAPTION>
Common Stock
Dividends
1994 1993 Per Common Share
Quarter Ended High Low High Low 1994 1993
<S> <C> <C> <C> <C> <C> <C>
March 31. . . . . . . . . . $24 1/8 $19 1/2 $24 1/2 $20 7/8 $.13 $.11
June 30 . . . . . . . . . . $22 1/8 16 3/4 24 7/8 21 5/8 .13 .11
September 30. . . . . . . . 21 1/8 17 1/4 26 1/8 22 .13 .11
December 31 . . . . . . . . 22 16 1/2 26 1/8 19 5/8 .13 .13
</TABLE>
The Energy Board of Directors declared a quarterly
dividend of $.13 per share of Common Stock at its January 19,
1995 meeting. Dividends are considered quarterly by the Energy
Board of Directors and are limited by, among other things, the
Company's financing agreements. See Note 4 of Notes to
Consolidated Financial Statements.
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year
ended December 31, 1994 is derived from the Company's
Consolidated Financial Statements contained elsewhere herein.
The selected financial data for the years ended prior to
December 31, 1994 is derived from the selected financial data
contained in the Company's Annual Report on Form 10-K for the
year ended December 31, 1993.
The following summaries are in thousands of dollars
except for per share amounts:
<TABLE>
<CAPTION>
Year Ended December 31,
1994<F1> 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . $1,837,440 $1,222,239 $1,234,618 $1,011,835 $1,168,867
OPERATING INCOME . . . . . . . . . . . $ 125,925 $ 75,504 $ 134,030 $ 119,266 $ 134,391
EQUITY IN EARNINGS (LOSSES) OF AND
INCOME FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . $ (10,698) $ 23,693 $ 26,360 $ 32,389 $ 29,161
NET INCOME . . . . . . . . . . . . . . $ 26,882 $ 36,424 $ 83,919 $ 98,667 $ 94,693
Less: Preferred and preference
stock dividend
requirements. . . . . . . . 9,490 1,262 1,475 6,044 7,060
NET INCOME APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . $ 17,392 $ 35,162 $ 82,444 $ 92,623 $ 87,633
EARNINGS PER SHARE OF
COMMON STOCK . . . . . . . . . . . . $ .40 $ .82 $ 1.94 $ 2.28 $ 2.31
TOTAL ASSETS . . . . . . . . . . . . . $2,831,358 $1,764,437 $1,759,100 $1,502,430 $1,266,223
LONG-TERM OBLIGATIONS AND
REDEEMABLE PREFERRED STOCK . . . . . $1,034,470 $ 499,421 $ 497,308 $ 395,948 $ 264,656
DIVIDENDS PER SHARE OF COMMON
STOCK. . . . . . . . . . . . . . . . $ .52 $ .46 $ .42 $ .34 $ .26
<FN>
<F1>
Reflects the consolidation of the Partnership for the months of June 1994 through December 1994.
<F2>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
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 a wholly
owned subsidiary of Energy was consummated on May 31, 1994. As a
result of the Merger, VNGP, L.P. has become a wholly owned
subsidiary of Energy. The accompanying consolidated statements
of income of the Company for the years ended December 31, 1994,
1993 and 1992 include the Company's approximate 49% effective
equity interest in the Partnership's operations for all periods
prior to and including May 31, 1994 and include 100% of the
Partnership's operations thereafter. Because 1994 results of
operations for the Company's natural gas and natural gas liquids
segments are not comparable to prior periods due to the Merger,
the discussion of these operations which follows under "Results
of Operations - 1994 Compared to 1993 - Segment Results" includes
100% of the Partnership's operations rather than only the
Company's effective interest in the Partnership's operating
results. Such discussion is based on pro forma operating results
that reflect the consolidation of the Partnership with Energy for
all of 1994 and 1993.
<PAGE>
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, 1994. The 1993 and 1992 amounts of operating
revenues and operating income (loss) by segment have been
restated to conform to the 1994 segment presentation. The
amounts in the following table are in thousands of dollars,
unless otherwise noted:
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
OPERATING REVENUES:
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . $1,090,368 $1,044,749 $1,056,873
Natural gas<F1>:
Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 452,381 42,375 42,163
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . 35,183 3,646 4,603
Natural gas liquids<F1>. . . . . . . . . . . . . . . . . . . . . . 307,016 53,252 49,299
Other<F1>. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42,639 83,886 85,461
Intersegment eliminations<F1>. . . . . . . . . . . . . . . . . . . (90,147) (5,669) (3,781)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,837,440 $1,222,239 $1,234,618
OPERATING INCOME (LOSS):
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . $ 78,660 $ 75,401 $ 137,187
Natural gas<F1>. . . . . . . . . . . . . . . . . . . . . . . . . . 26,731 2,863 2,445
Natural gas liquids<F1>. . . . . . . . . . . . . . . . . . . . . . 35,213 10,057 9,267
Corporate general and administrative expenses and other, net<F1> . (14,679) (12,817) (14,869)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 125,925 $ 75,504 $ 134,030
Equity in earnings (losses) of and income from
Valero Natural Gas Partners, L.P.<F2>. . . . . . . . . . . . . . . $ (10,698) $ 23,693 $ 26,360
Gain on disposition of assets and other income, net. . . . . . . . . $ 4,476 $ 6,209 $ 1,452
Interest and debt expense, net . . . . . . . . . . . . . . . . . . . $ (76,921) $ (37,182) $ (30,423)
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 26,882 $ 36,424 $ 83,919
Net income applicable to common stock. . . . . . . . . . . . . . . . $ 17,392 $ 35,162 $ 82,444
Earnings per share of common stock . . . . . . . . . . . . . . . . . $ .40 $ .82 $ 1.94
PRO FORMA OPERATING INCOME (LOSS)<F3>:
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . $ 78,660 $ 75,401
Natural gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . 30,829 73,379
Natural gas liquids. . . . . . . . . . . . . . . . . . . . . . . . 38,940 40,309
Corporate general and administrative expenses and other, net . . . (22,486) (30,151)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 125,943 $ 158,938
OPERATING STATISTICS:
Refining and marketing:
Throughput volumes (Mbbls per day) . . . . . . . . . . . . . . . 146 136 119
Average throughput margin per barrel<F4> . . . . . . . . . . . . $ 5.36 $ 5.99 $ 7.00
Sales volumes (Mbbls per day). . . . . . . . . . . . . . . . . . 140 133 123
Natural gas (pro forma)<F3>:
Gas volumes (BBtu per day):
Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,144 1,151
Transportation . . . . . . . . . . . . . . . . . . . . . . . . 1,682 1,672
Total gas volumes. . . . . . . . . . . . . . . . . . . . . . 2,826 2,823
Average gas sales price per MMBtu. . . . . . . . . . . . . . . . $ 2.07 $ 2.32
Average gas transportation fee per MMBtu . . . . . . . . . . . . $ .102 $ .107
Natural gas liquids (pro forma)<F3>:
Plant production (Mbbls per day) . . . . . . . . . . . . . . . . 79.5 77.4
Average market price per gallon. . . . . . . . . . . . . . . . . $ .271 $ .287
Average gas cost per MMBtu . . . . . . . . . . . . . . . . . . . $ 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>
Pro forma operating income (loss) and pro forma operating statistics for the natural gas
and natural gas liquids segments reflect the consolidation of VNGP, L.P. with Energy for
all of 1994 and 1993.
<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>
</TABLE>
<PAGE>
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 issuance
in the first quarter of 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 $615.2 million, or 50%,
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 management fees 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%, 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 and income from the
Partnership for the five months of 1994 preceding the Merger was
$(10.7) million compared to equity in earnings and income from
the Partnership of $23.7 million in 1993. Included in the 1994
amount was the Company's equity interest in the $14 million cost
of a settlement among the Company, the Partnership and the City
of Houston regarding a franchise fee dispute. 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
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 the continued weakness in
refined product prices was 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 reformulated gasoline ("RFG") during November and December
of 1994. Weak refined product prices during 1994 resulted from
an increase in gasoline supply due to increased refinery
upgrading capacity, high refinery utilization rates and increased
gasoline imports.
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 resulting from narrower discounts for the
Company's residual oil ("resid") feedstocks (which had an effect
of approximately $30 million), lower margins between conventional
refined product prices and crude oil (which had an effect of
approximately $12 million), and lower margins on sales of MTBE
due to higher costs for the Company's methanol feedstocks (which
had an effect of approximately $7 million), which more than
offset higher margins on sales of RFG and other premium products
(which had an effect of approximately $21 million) and a 7%
increase in average daily throughput volumes (which had an effect
of approximately $19 million). The Company's resid discount,
representing the average discount at which resid sells to crude
oil, decreased from $4.43 per barrel in 1993 to $3.25 per barrel
in 1994 due to a worldwide decrease in resid supplies resulting
from increased refinery upgrading capacity, an increase in the
proportion of light crude oil produced in relation to heavy crude
oil, reduced resid exports from the former Soviet Union and
strong demand for fuel oil in the Far East due to unusually hot
weather. Methanol prices increased significantly during 1994 due
to tight supplies and an anticipated increase in demand for
oxygenates in connection with the start-up of the RFG program in
late 1994. 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.
During the fourth quarter of 1994, the Company
negotiated a new resid feedstock supply agreement with Arabian
American Oil Company ("Aramco") which became effective January 1,
1995 and will run for a period of two years. The new agreement
provides for minimum deliveries of approximately 36,000 barrels
per day at a market-based pricing formula that is subject to
price renegotiation in the fourth quarter of 1995. Deliveries
under this agreement provide approximately 45% of the Refinery's
resid requirements. During the first quarter of 1995, the
Company renewed for an additional year its contract to purchase
11,000 barrels per day of resid from South Korea at market-based
prices. The Company believes that if either of the existing
feedstock arrangements were interrupted, 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 year, the Company
could be required to incur higher feedstock costs or substitute
other types of resid, thereby producing less favorable operating
results. The remainder of the Refinery's resid feedstocks are
purchased at market-based prices under short-term contracts. On
December 1, 1994, the Company formed a joint venture with Hoechst
Celanese Chemical Group, Inc. ("Celanese") to renovate and
operate a 13,000-barrel-per-day methanol plant. The Company's
50% share of methanol production from this plant is expected to
provide substantially all of the methanol feedstock required for
the Refinery's production of oxygenates used in RFG at a cost
substantially lower than prevailing market prices. The
refurbished methanol plant is estimated to be placed in service
in the second quarter of 1995. See "Liquidity and Capital
Resources."
Scheduled maintenance and catalyst changes of the
Refinery's hydrodesulfurization unit (the "HDS Unit") were
completed in October 1992 and December 1993, and a turnaround of
the Refinery's heavy oil cracking complex (the "HOC") was
completed in October 1994. During 1995, the Refinery's
hydrocracker and naphtha reformer units are scheduled for
turnarounds, while the HDS Unit is scheduled for maintenance and
a catalyst change, all beginning in the first quarter.
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 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. Operating and general expenses increased due primarily
to the City of Houston settlement discussed above under
"Consolidated Results."
As noted above, the Company's natural gas operations
were negatively impacted in 1994 by a decrease in demand for
natural gas resulting from unseasonably mild weather during the
1994 fourth quarter and the return to service of the South Texas
Project nuclear plant ("STP") in Bay City, Texas during the 1994
second quarter. During most of 1993, both units of the STP were
shut down due to operational problems. At full operation, the
STP displaces approximately 650 BBtu per day of natural gas
demand. Demand for natural gas in the Company's core service
area is also affected by the operational status of other nuclear
and coal-fired power plants, including the Comanche Peak nuclear
plant near Ft. Worth, Texas and coal-fired electrical generation
facilities owned and operated by San Antonio City Public Service.
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 the flexible use of its strategically
located pipeline system and its aggressive marketing efforts.
Sales and transportation volumes were flat in 1994 compared to
1993 as volume increases resulting from aggressive efforts to
generate business related to the implementation of Federal Energy
Regulatory Commission ("FERC") Order No. 636 ("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. The Company utilizes hedging techniques
to manage the cost of gas consumed in its NGL operations, and
manage price risk associated with its natural gas storage and
marketing activities. 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 hedging
activities. In 1994 and 1993, the Company recognized on a pro
forma basis $2.1 million and $18.7 million, respectively, in gas
cost reductions from price risk management activities. An
additional $6.8 million and $5.1 million was deferred at
December 31, 1994 and 1993, respectively, which is recognized as
a reduction to the cost of gas in the subsequent year. See
"Price Risk Management Activities" under Note 1 of Notes to
Consolidated Financial Statements.
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. WACOG includes purchases of high-cost casinghead
gas and certain special allowable gas that is required to be
purchased contractually and under the Railroad Commission's
priority rules. 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. Sales volumes under these
contracts have been decreasing as such contracts expire and are
not renewed. As a result of these factors, the gas sales price
for these contracts is substantially in excess of market clearing
levels.
WACOG has been periodically audited by certain of the
customers under the above noted contracts, as allowed under the
Rate Order. As a result of an audit by one such customer (the
"Customer"), the Company and the Customer entered into a
settlement agreement which, among other things, excluded certain
gas gathering costs from WACOG, effective with July 1993 sales,
resulting in a reduction of annual operating income by
approximately $6 million. In addition, beginning 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 and 1993 resulted in
increased gas sales revenues of approximately $20 million and $17
million, respectively. However, revenues resulting from such net
volumetric gains are expected to be substantially reduced by the
implementation of changes to measurement standards promulgated by
the American Gas Association and now implemented by the Company,
the expiration of certain gas purchase contracts in February 1995
and the further reduction in WACOG-based gas sales discussed
above.
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 margins, a 3% increase in NGL production
volumes and a decrease in operating and general expenses,
primarily maintenance expense. NGL 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.
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.
Approximately 83% 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 either increased third-party transportation and
fractionation fees or 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 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
Other operating revenues consisted primarily of
management fees received by the Company from the Partnership
equal to the direct and indirect costs incurred by the Company on
behalf of the Partnership that were associated with managing the
Partnership's operations. As discussed above under "Consolidated
Results," such management fee revenues decreased in 1994 compared
to 1993 as a result of the May 31, 1994 Merger.
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.
1993 COMPARED TO 1992
Consolidated Results
The Company reported net income of $36.4 million, or
$.82 per share, for the year ended December 31, 1993 compared to
$83.9 million, or $1.94 per share, for the year ended
December 31, 1992. For the fourth quarter of 1993, the Company
reported a net loss of $15.2 million, or $.36 per share, compared
to net income of $8.2 million, or $.18 per share, for the fourth
quarter of 1992. 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 to reflect existing market
prices. See "Segment Results - Refining and Marketing" below.
The decrease in net income and earnings per share for the year
was due primarily to a decrease in operating income and to a
lesser extent to a decrease in equity in earnings of and income
from the Partnership and an increase in net interest expense.
The decreases resulting from these factors were partially offset
by the recognition in the third quarter of 1993 of an approximate
$5 million after-tax gain, net of other nonoperating charges,
related to the disposition of the Company's natural gas
distribution operations and a decrease in income tax expense.
Operating revenues decreased $12.4 million, or 1%,
during 1993 compared to 1992 due primarily to a $12.1 million
decrease in operating revenues from the Company's refining and
marketing operations and to a lesser extent to a decrease in
operating revenues from the Company's natural gas operations,
partially offset by an increase in operating revenues from the
Company's NGL operations. Operating income decreased
$58.5 million, or 44%, due primarily to a decrease in refining
and marketing operating income, partially offset to a small
extent by increases in operating income from the Company's
natural gas and NGL operations and a decrease in corporate
expenses. See "Segment Results" below.
The Company's equity in earnings of and income from the
Partnership decreased $2.7 million, or 10%, in 1993 compared to
1992 due primarily to a decrease in operating income from the
Partnership's NGL operations, partially offset by an increase in
operating income from the Partnership's natural gas operations
and an increase in interest income earned by the Company on
capital lease transactions with the Partnership resulting from
the inception on December 1, 1992 of the Company's lease to the
Partnership of a new gas processing plant near Thompsonville in
South Texas.
Partnership operating income by segment for 1993 and
1992, based on 100% of the Partnership's operations, was as
follows (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992
<S> <C> <C>
Natural gas . . . . . . . . . . . . . $53,458 $32,484
Natural gas liquids . . . . . . . . . 26,020 57,357
Total operating income . . . . . $79,478 $89,841
</TABLE>
Operating income from the Partnership's NGL operations
decreased in 1993 compared to 1992 due primarily to a decrease in
NGL prices in the last six months of 1993 resulting from
continuing high levels of NGL inventories and a significant
decline in refined product prices, combined with an increase in
fuel and shrinkage costs resulting from a 22% increase in the
cost of natural gas. The decline in NGL prices resulted in an
operating loss from NGL operations for the fourth quarter of 1993
compared to operating income for the fourth quarter of 1992.
Also reducing fourth quarter 1993 operating results was an
increase in depreciation expense resulting from the recognition
in the 1992 period of a change in the estimated useful lives of
the majority of the Partnership's NGL facilities from 14 to 20
years retroactive to January 1, 1992. Operating income from the
Partnership's natural gas operations increased in 1993 compared
to 1992 due to a 10% increase in daily natural gas sales volumes
and a 12% increase in transportation revenues resulting from
continued strong demand for natural gas, the settlement of
certain favorable measurement, fuel usage and customer billing
differences and an increase in gas cost reductions resulting from
price risk management activities. Partially offsetting these
increases in natural gas operating income was a decrease in the
recovery of Transmission's fixed costs resulting from the
settlement of the customer audit of Transmission's weighted
average cost of gas discussed above under "1994 Compared to 1993
- -Segment Results - Natural Gas." For the fourth quarter of 1993,
natural gas operating income increased compared to the fourth
quarter of 1992 due to the factors noted above.
Net interest and debt expense increased $6.8 million in
1993 compared to 1992 due primarily to the issuance of medium-
term notes during the second and fourth quarters of 1992 and to a
decrease in capitalized interest resulting from the placing in
service of the MTBE Plant during the second quarter of 1993.
Income tax expense decreased in 1993 compared to 1992 due
primarily to a decrease in pre-tax income, partially offset by a
one-time, noncash charge to 1993 third quarter earnings of $8.2
million resulting from the effect of a one percent increase in
the corporate income tax rate, from 34% to 35%, on the Company's
balance of deferred income taxes as of December 31, 1992.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and
marketing operations decreased $12.1 million, or 1%, during 1993
compared to 1992 as an 8% decrease in the average sales price per
barrel was basically offset by an 8% increase in sales volumes.
The decrease in the average sales price per barrel was due
primarily to the precipitous drop in crude oil and refined
product prices beginning in November 1993 resulting from, among
other things, the decision by the Organization of Petroleum
Exporting Countries ("OPEC") at its November 1993 meeting to
forego any cuts in production. Increased production capacity
resulting from operation of the MTBE Plant contributed to the
increase in sales and throughput volumes. Operating income
decreased $61.8 million, or 45%, during 1993 compared to 1992 due
primarily to the $27.6 million inventory write-down recognized in
the fourth quarter of 1993, a decrease in throughput margins
resulting from the significant drop in refined product prices
noted above, and an increase in Refinery operating costs and
depreciation expense due to costs associated with operation of
the MTBE Plant and other new Refinery units, partially offset by
a 14% increase in average daily throughput volumes. The
Refinery's average throughput margin per barrel, before operating
costs and depreciation expense, decreased from $7.00 in 1992 to
$5.99 in 1993 ($5.44, including the effect of the inventory
write-down).
Natural Gas
Operating revenues from the Company's natural gas
operations decreased $.7 million, or 2%, during 1993 compared to
1992 due primarily to the sale on September 30, 1993 of Rio
Grande Valley Gas Company ("RGV"), the Company's natural gas
distribution subsidiary. Operating income increased $.4 million,
or 17%, during 1993 compared to 1992 due primarily to a decrease
in operating and general expenses, partially offset by a decrease
in transportation revenues.
Natural Gas Liquids
Operating revenues and operating income from the
Company's NGL operations increased $4 million, or 8%, and $.8
million, or 9%, respectively, during 1993 compared to 1992 due
primarily to the full-year effect in 1993 of the NGL assets
acquired from Oryx Energy in May 1992.
Other
Other operating revenues, consisting primarily of
management fees received by the Company from the Partnership,
decreased in 1993 compared to 1992 due primarily to reduced
management fees resulting from the nonrecurrence of one-time
charges related to the Company's 1992 early retirement program,
partially offset by the inclusion in management fees of other
postemployment benefit costs commencing in 1993 and an increase
in the percentage of costs allocated to the Partnership resulting
from the sale of RGV. Corporate general and administrative
expenses and other, net, decreased in 1993 compared to 1992 due
primarily to the effects of the early retirement program and
increased allocation of costs to the Partnership discussed above,
partially offset by the above noted incurrence of other
postemployment benefit costs commencing in 1993.
OUTLOOK
Refining and Marketing
The worldwide decrease in resid supplies which caused a
narrowing of the Company's resid discount in 1994 is expected to
continue to affect the market in 1995. However, refining and
marketing operations are expected to benefit in 1995 from the
completion of the 50% owned methanol plant with Celanese which
should reduce the cost of the Company's methanol feedstocks used
in MTBE production. As a result of the completion of several
major units at the Refinery during the last few years, the
Company is currently able to produce all of its gasoline as RFG.
Various uncertainties in the January 1, 1995 mandated transition
from conventional gasoline to RFG under regulations promulgated
under the Clean Air Act resulted in severe declines in prices for
RFG and oxygenates, including MTBE, beginning in December 1994.
Combined with continued high costs for the Company's methanol
feedstocks used in MTBE production, such decline in RFG and MTBE
prices negatively impacted the Refinery's throughput margins and
resulted in the Company temporarily reducing its MTBE production
by 37% in December 1994. During January 1995, the Company
resumed production of MTBE at capacity levels due to an
improvement in market conditions. As the industry adapts to the
RFG program in the first quarter of 1995, demand levels and
pricing relationships among RFG, methanol and MTBE are likely to
become more firmly established.
Natural Gas
Subject to seasonal variations in weather, demand for
natural gas has remained strong and is expected to increase in
the long term due to its desirability as a clean-burning fuel,
which should benefit the Company's natural gas throughput
volumes. Currently, the Company's natural gas operations
continue to adjust to the changes in the natural gas industry
resulting from the implementation of FERC Order No. 636 in 1993
and the trend of west-to-east movement of gas across the United
States. The required unbundling of individual natural gas
services by pipelines subject to FERC jurisdiction under Order
636 has created new interstate supply, marketing and
transportation opportunities for the Company, although in an
extremely competitive environment. In response to Order 636, the
Company is continuing to emphasize diversification of its
customer base through interstate sales, and to develop and expand
its slate of value-added services, such as gas gathering, volume
and capacity management, and gas processing, which it offers to
both upstream and downstream customers. To capitalize on the
trend of west-to-east movement of gas across the United States
caused by increased production in western supply basins, recent
pipeline expansions from such basins and Canada to the United
States West Coast, and growing natural gas demand in the eastern
United States, the Company in 1994 added additional compression
to its North Texas pipeline, increasing its capacity to move gas
across Texas. In addition, to develop new opportunities
anticipated in connection with the FERC's deregulation of the
electric power generation industry, the Company secured a power
marketing certificate from the FERC in 1994 in order to
participate in the wholesale bulk power business. During 1995,
the Company intends to further develop these and other
opportunities in the natural gas industry and believes that as a
result, it should be able to increase its natural gas volumes in
1995.
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 is a
value-added service offered to producers and attracts 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 increase as a
result of continued economic growth, petrochemical plant
expansions and increased production of oxygenated and
reformulated gasolines. The Company continues 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. The Company
continuously makes operational improvements at its NGL plants,
which during 1994 resulted in an increase in its NGL production
volumes, and anticipates further plant expansions and
improvements which will further increase production volumes.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by the Company's operating activities
totalled $68.1 million during 1994 compared to $141.3 million
during 1993. The decrease in 1994 from 1993 was due primarily to
an increase in working capital requirements attributable to the
inclusion of Partnership operations commencing June 1, 1994, and
an increase in refining and marketing working capital
requirements resulting primarily from $37 million of costs
incurred in 1993 but not paid until 1994 related to capital
projects placed in service in the latter part of 1993. During
1994, the Company utilized the cash provided by its operating
activities, bank borrowings and proceeds from the issuance of
medium-term notes ("Medium-Term Notes") and Convertible Preferred
Stock to fund capital expenditures, deferred turnaround and
catalyst costs and investments in joint ventures, to pay common
and preferred stock dividends, to make principal escrow payments
under Valero Management Partnership, L.P.'s (the "Management
Partnership") First Mortgage Notes (the "First Mortgage Notes"),
to repay principal on certain outstanding nonbank debt and to
acquire the publicly traded Common Units of VNGP, L.P.
As described in Note 2 of Notes to Consolidated
Financial Statements, the Company used a portion of the
approximate $168 million net proceeds from its March 1994
Convertible Preferred Stock issuance to fund the acquisition of
the publicly traded Common Units of VNGP, L.P. and to pay
expenses of the acquisition. The remaining proceeds were used to
reduce bank borrowings.
In 1992, Energy filed with the Securities and Exchange
Commission (the "Commission") a shelf registration statement for
$150 million principal amount of Medium-Term Notes, $116 million
of which had been issued as of December 31, 1993. During
December 1994, Energy issued the remaining $34 million of Medium-
Term Notes. Energy recently filed another shelf registration
statement with the Commission to offer up to $250 million
principal amount of additional debt securities, including Medium-
Term Notes. The net proceeds from this offering 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. 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 1.74 and 1.30 on a historical
and pro forma basis, respectively, for the year ended
December 31, 1994.
Energy currently maintains an unsecured $250 million
revolving bank credit and letter of credit facility which
originally became effective upon the consummation of the Merger
on May 31, 1994 and replaced all of the Company's and the
Partnership's then existing bank credit facilities. Effective
September 30, 1994, this facility was amended to provide for,
among other things, a reduced interest rate on LIBOR advances,
reduced commitment and utilization fees, elimination of sublimits
for direct advances and letters of credit, and elimination of
scheduled commitment reductions. As of December 31, 1994, Energy
had approximately $85.7 million available under this committed
bank credit facility for additional borrowings and letters of
credit. Energy also has $130 million of unsecured short-term
bank credit lines which are unrestricted as to use. Under the
terms of Energy's $250 million credit facility, as amended, total
borrowings under these short-term credit lines are limited to
$100 million and any amounts outstanding under such short-term
lines automatically reduce the availability under the
$250 million credit facility. As of December 31, 1994, no
amounts were outstanding under these short-term lines. Energy's
revolving bank credit and letter of credit facility (which is the
most restrictive of the Company's various financing agreements)
contains various restrictive covenants, including restrictions on
the ability of its subsidiaries to issue debt and on its ability
to pay dividends and make certain other "restricted payments."
Under the most restrictive of such covenants, the Company had the
ability to pay approximately $36 million in common and preferred
stock dividends and other restricted payments at December 31,
1994. In February 1995, Energy's bank credit facility was
further amended to modify certain restrictive covenants resulting
in increased financial flexibility for the Company. The
Company's long-term debt includes the Management Partnership's
First Mortgage Notes which were assumed by the Company in
connection with the Merger, $506.4 million of which was
outstanding at December 31, 1994. The indenture of mortgage and
deed of trust pursuant to which the First Mortgage Notes were
issued (the "Mortgage Indenture") also contains various
restrictive covenants. The Company was in compliance with all
bank credit and letter of credit facility and First Mortgage Note
covenants as of December 31, 1994. 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 $153.2 million, $154.6 million, $150.8 million,
$144.1 million and $138.6 million for the years 1995 through
1999, respectively. See Notes 3 and 4 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, 1994, Energy had repurchased 505,000
shares at an average price of $23.11 per share.
During 1994, the Company expended approximately $116
million for capital investments, including capital expenditures,
deferred turnaround and catalyst costs and investments in and
advances to joint ventures. Of this amount, $82 million related
to refining and marketing operations including the turnaround of
the HOC completed in October 1994, while $21 million related to
the natural gas and NGL operations acquired in connection with
the Merger. Included in the refining and marketing amount was a
$15 million payment to the joint venture formed with Celanese in
December 1994, to be used in renovating a 13,000-barrel-per-day
methanol plant located in Clear Lake, Texas. The remaining $60
million of the Company's total $75 million commitment for the
plant renovation will be paid in 1995. For 1995, the Company
currently expects to incur approximately $160 million for capital
expenditures, deferred turnaround and catalyst costs, and
investments and related expenditures. Such amount includes the
$60 million payment related to the methanol plant renovation
discussed above, but 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 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 $450 million and to produce approximately 17,000
barrels of MTBE per stream day (based on an estimated 346 stream
days per year). The Company has entered into a letter of
understanding with Proesa's other shareholders 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. At December 31, 1994, the
Company had invested approximately $13.4 million in the project.
The Company has also agreed to guarantee 45% of Proesa's
obligation to a surety company related to an existing MTBE sales
agreement between Proesa and Petroleos Mexicanos, S.A. ("Pemex"),
the Mexican state-owned oil company. Based on the exchange rate
at February 23, 1995, the Company's portion of such guarantee was
approximately $3.3 million. Beginning in December 1994, the
Mexican peso experienced substantial devaluation causing interest
rates in Mexico to increase significantly and the Mexican stock
market to experience a substantial decline in market value. In
addition, current operating margins for MTBE are considerably
lower than when the project was first conceived. Based on these
and other factors, in January 1995, Energy's Board of Directors
determined that the Company would suspend further investment in
the project pending the resolution of certain key issues
including, among other things, the renegotiation of purchase and
sales agreements between Proesa and Pemex, the implementation of
certain additional agreements with Pemex, a reevaluation of the
economics of the project and the execution by Proesa's
shareholders of a definitive agreement regarding their ownership
interests in Proesa and their funding commitments to the project,
including procedures for funding any possible cost overruns. If
the foregoing matters can be satisfactorily resolved, the Company
intends to proceed with the project. However, there can be no
assurance that mutually satisfactory agreements can be reached
between Proesa and Pemex or among Proesa's shareholders. The
Company estimates that if the project is delayed and further
expenditures are reduced to the minimum practicable level until
resolution of the issues mentioned above, the Company will have a
total investment in the project of approximately $18 million at
the end of the first quarter of 1995, excluding any funding that
may be required with respect to the guarantee of Proesa's
obligation to a surety company discussed above. See Item 1.
"Business -Recent Developments - 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 at its September 1993 meeting, effective in the fourth
quarter of 1993. Such dividend rate remained unchanged
throughout 1994. 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 current and
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 the $250 million debt securities 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 $6
million in 1994 and are expected to be approximately the same in
1995. 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
significant to date and are not expected to be significant in
1995. 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.
<PAGE>
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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
San Antonio, Texas
February 14, 1995
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
<CAPTION>
December 31,
1994 1993
A S S E T S
<S> <C> <C>
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . . $ 26,210 $ 7,252
Cash held in debt service escrow . . . . . . . . . . . . . . . . . . . . . 35,441 -
Receivables, less allowance for doubtful accounts of $2,770 (1994) and
$359 (1993). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232,273 64,521
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182,089 123,905
Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . 31,842 12,304
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . 25,017 27,504
532,872 235,486
PROPERTY, PLANT AND EQUIPMENT - including construction in
progress of $115,785 (1994) and $10,158 (1993), at cost. . . . . . . . . . 2,672,715 1,640,136
Less: Accumulated depreciation. . . . . . . . . . . . . . . . . . . . . 531,501 346,570
2,141,214 1,293,566
INVESTMENT IN AND LEASES RECEIVABLE FROM VALERO NATURAL
GAS PARTNERS, L.P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 130,557
INVESTMENT IN AND ADVANCES TO JOINT VENTURES . . . . . . . . . . . . . . . . 41,162 28,343
DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . . 116,110 76,485
$2,831,358 $1,764,437
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 . . . . . . . . . . . . . . . . . . . $ 62,230 $ 28,737
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 341,694 90,994
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,693 5,063
Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . 37,150 28,233
460,767 153,027
LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . . 1,021,820 485,621
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . 264,236 232,564
DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . 59,405 37,128
REDEEMABLE PREFERRED STOCK, SERIES A, issued 1,150,000 shares,
outstanding 126,500 (1994) and 138,000 (1993) shares . . . . . . . . . . . 12,650 13,800
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 (1994) and -0- (1993) shares ($172,500 aggregate
involuntary liquidation value) . . . . . . . . . . . . . . . . . . . 3,450 -
Common stock, $1 par value - 75,000,000 shares authorized; issued
43,463,869 (1994) and 43,391,685 (1993) shares . . . . . . . . . . . . . 43,464 43,392
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . 536,613 371,303
Unearned Valero Employees' Stock Ownership Plan Compensation . . . . . . . (13,706) (15,958)
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 442,659 446,931
Treasury stock, -0- (1994) and 145,119 (1993) common shares, at cost . . . - (3,371)
1,012,480 842,297
$2,831,358 $1,764,437
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . $1,837,440 $1,222,239 $1,234,618
COSTS AND EXPENSES:
Cost of sales . . . . . . . . . . . . . . . . . . . . 1,502,118 970,435 926,189
Operating expenses. . . . . . . . . . . . . . . . . . 125,365 119,567 126,185
Depreciation expense. . . . . . . . . . . . . . . . . 84,032 56,733 48,214
Total . . . . . . . . . . . . . . . . . . . . . . . 1,711,515 1,146,735 1,100,588
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . 125,925 75,504 134,030
EQUITY IN EARNINGS (LOSSES) OF AND INCOME FROM
VALERO NATURAL GAS PARTNERS, L.P. . . . . . . . . . . (10,698) 23,693 26,360
GAIN ON DISPOSITION OF ASSETS AND OTHER INCOME, NET. . . 4,476 6,209 1,452
INTEREST AND DEBT EXPENSE:
Incurred. . . . . . . . . . . . . . . . . . . . . . . (79,286) (49,517) (46,276)
Capitalized . . . . . . . . . . . . . . . . . . . . . 2,365 12,335 15,853
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . 42,782 68,224 131,419
INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . . 15,900 31,800 47,500
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 26,882 36,424 83,919
Less: Preferred stock dividend requirements. . . . . 9,490 1,262 1,475
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . . $ 17,392 $ 35,162 $ 82,444
EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . . $ .40 $ .82 $ 1.94
DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . . $ .52 $ .46 $ .42
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Dollars)
<CAPTION>
Convertible
Preferred Number of Common Additional Unearned
Stock Common Stock Paid-in VESOP Retained Treasury
$1 Par Shares $1 Par Capital Compensation Earnings Stock
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE, December 31, 1991 . . . $ - 40,710,935 $40,711 $300,711 $(20,100) $366,916 $(1,703)
Net income . . . . . . . . . . - - - - - 83,919 -
Dividends on Series A
Preferred Stock. . . . . . . - - - - - (1,368) -
Dividends on Common Stock. . . - - - - - (17,867) -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . . - - - - 2,015 - -
Sale of Common Stock, net. . . - 2,610,000 2,610 72,197 - - -
Shares repurchased and shares
issued pursuant to employee
stock plans and other. . . . - - - (1,149) - - (6,134)
BALANCE, December 31, 1992 . . . - 43,320,935 43,321 371,759 (18,085) 431,600 (7,837)
Net income . . . . . . . . . . - - - - - 36,424 -
Dividends on Series A
Preferred Stock. . . . . . . - - - - - (1,271) -
Dividends on Common Stock. . . - - - - - (19,822) -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . . - - - - 2,127 - -
Shares repurchased and shares
issued pursuant to employee
stock plans and other. . . . - 70,750 71 (456) - - 4,466
BALANCE, December 31, 1993 . . . - 43,391,685 43,392 371,303 (15,958) 446,931 (3,371)
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 $ -
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . .$ 26,882 $ 36,424 $ 83,919
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation expense . . . . . . . . . . . . . . . . . . . 84,032 56,733 48,214
Amortization of deferred charges and other, net. . . . . . 18,407 22,766 20,117
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. . . . . (95,597) 9,805 (22,722)
Deferred income tax expense . . . . . . . . . . . . . . . 12,200 15,300 26,200
Equity in (earnings) losses of Valero Natural Gas
Partners, L.P. in excess of distributions. . . . . . . . 16,179 (4,970) (1,067)
Changes in deferred items and other, net . . . . . . . . . 6,008 (15,487) (2,150)
Net cash provided by operating activities. . . . . . . . 68,111 141,281 152,511
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . . . . (80,738) (136,594) (282,755)
Deferred turnaround and catalyst costs . . . . . . . . . . . . (21,999) (23,054) (12,209)
Investment in and advances to joint ventures, net. . . . . . . (9,229) (6,167) (8,649)
Investment in Valero Natural Gas Partners, L.P.. . . . . . . . (124,264) - -
Assets leased to Valero Natural Gas Partners, L.P. . . . . . . (1,886) - (25,849)
Distributions from Valero Natural Gas Partners, L.P. . . . . . 2,789 - -
Dispositions of property, plant and equipment. . . . . . . . . 4,504 30,720 1,197
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . 898 991 (467)
Net cash used in investing activities. . . . . . . . . . . . (229,925) (134,104) (328,732)
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term debt reduction, net. . . . . . . . . . . . . . . . . (27,285) (15,000) (756)
Long-term borrowings, net. . . . . . . . . . . . . . . . . . . 92,000 32,000 119,000
Increase (decrease) in short-term bank lines . . . . . . . . . - (6,700) 6,700
Increase in cash held in debt service escrow for principal . . (22,768) - -
Preferred stock dividends. . . . . . . . . . . . . . . . . . . (8,600) (1,271) (1,368)
Common stock dividends . . . . . . . . . . . . . . . . . . . . (22,554) (19,822) (17,867)
Issuance of Convertible Preferred Stock, net . . . . . . . . . 167,878 - -
Issuance of common stock, net. . . . . . . . . . . . . . . . . 3,251 3,844 65,984
Repurchase of Series A Preferred Stock . . . . . . . . . . . . (1,150) (1,150) (1,150)
Net cash provided by (used in) financing activities. . . . . 180,772 (8,099) 170,543
NET INCREASE (DECREASE) IN CASH AND TEMPORARY
CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . 18,958 (922) (5,678)
CASH AND TEMPORARY CASH INVESTMENTS AT
BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . . . . 7,252 8,174 13,852
CASH AND TEMPORARY CASH INVESTMENTS AT
END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . .$ 26,210 $ 7,252 $ 8,174
<FN>
See Notes to Consolidated Financial Statements.
</FN>
</TABLE>
<PAGE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements
include the accounts of Valero Energy Corporation ("Energy") and
subsidiaries (collectively referred to herein as the "Company").
All significant intercompany transactions have been eliminated in
consolidation. 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 principal operating
subsidiary, Valero Refining Company ("VRC") (collectively
referred to herein as "Refining"). Prior to 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" or "SOPs") (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).
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.
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,
current maturities of long-term debt and short-term bank lines.
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 and whose carrying amounts
approximate fair value. (Dollars in thousands.)
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Cash held in debt service escrow for interest. $(12,673) $ - $ -
Receivables, net . . . . . . . . . . . . . . . (64,150) 31,854 (43,486)
Inventories. . . . . . . . . . . . . . . . . . (21,785) 3,870 35,955
Prepaid expenses and other . . . . . . . . . . 142 (392) (756)
Accounts payable . . . . . . . . . . . . . . . (4,295) (21,778) (19,437)
Accrued interest . . . . . . . . . . . . . . . 3,901 (81) 2,603
Other accrued expenses . . . . . . . . . . . . 3,263 (3,668) 2,399
Total. . . . . . . . . . . . . . . . . . . . $(95,597) $ 9,805 $(22,722)
</TABLE>
The following provides information related to cash
interest and income taxes paid by the Company for the periods
indicated (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Interest - net of amount capitalized of $2,365 (1994),
$12,335 (1993) and $15,853 (1992). . . . . . . . . . $72,023 $36,001 $25,850
Income taxes . . . . . . . . . . . . . . . . . . . . . 3,931 18,324 17,821
</TABLE>
Noncash financing activities for the years ended
December 31, 1994, 1993 and 1992 include reductions of
$1.5 million, $1.3 million and $1.2 million, respectively, of the
recorded guarantee by Energy of a $15 million long-term borrowing
by the Valero Employees' Stock Ownership Plan ("VESOP") to
purchase Common Stock. Such reductions were a result of debt
service by the VESOP. See Notes 4 and 12. Noncash investing
activities for 1994 include the remaining $60 million payment to
be made in 1995 for the Company's interest in a methanol plant
renovation project. Noncash investing activities for 1994 and
1993 also include the reclassification to property, plant and
equipment and investment in and advances to joint ventures of
$5.9 million and $5 million, respectively, previously included
in deferred charges and other assets on the Consolidated Balance
Sheets.
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 $26 million at December 31, 1994. 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, 1994 and
December 31, 1993 are as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Refinery feedstocks. . . . . . . . . . . . . . . . . . $ 82,099 $ 81,117
Refined products and blendstocks . . . . . . . . . . . 50,499 32,175
Natural gas in underground storage . . . . . . . . . . 29,678 -
Natural gas liquids. . . . . . . . . . . . . . . . . . 4,664 92
Materials and supplies . . . . . . . . . . . . . . . . 15,149 10,521
$182,089 $123,905
</TABLE>
Refinery feedstock and refined product and blendstock
inventory volumes totalled 8.9 million barrels ("MMbbls") and
8.1 MMbbls at December 31, 1994 and December 31, 1993,
respectively. Natural gas inventory volumes totalled
approximately 9.8 trillion British thermal units ("TBtus") at
December 31, 1994.
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:
<TABLE>
<S> <C>
Refining and marketing . . . 3 3/5%
Natural gas. . . . . . . . . 2 1/4% - 20%
Natural gas liquids. . . . . 4 1/2% - 20%
Other. . . . . . . . . . . . 9% - 20%
</TABLE>
Income Taxes
Effective January 1, 1992, the Company adopted Statement
of Financial Accounting Standards ("SFAS") No. 109, "Accounting
for Income Taxes," which established financial accounting and
reporting standards for deferred income tax liabilities that
arise as a result of differences between the reported amounts of
assets and liabilities for financial reporting and income tax
purposes.
Deferred Charges
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 $42 million at December 31, 1994 is
included in noncurrent other assets and is expected to be
recovered over the next seven 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, debt issuance costs, and certain other
costs. Technological royalties and licenses are amortized over
the estimated useful life of each particular related asset. Debt
issuance costs are amortized by the effective interest method
over the estimated life of each instrument or facility.
Price Risk Management Activities
The Company enters into various exchange-traded and
other 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 either a hedge when 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, or as a speculative contract where there is no such
relationship. Gains and losses on hedges of inventories are
included in the carrying amounts of inventories and are
ultimately recognized in income as those assets are sold. Gains
and losses related to anticipatory transactions and purchase and
sales commitments are also deferred and are recognized in income
or as adjustments of carrying amounts when the hedged transaction
occurs. 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. For those contracts that are not
designated as hedges, changes in the fair value of those
contracts are recognized as gains or losses in income currently
and are recorded in the statement of financial position 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.
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 year ended December 31, 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, 1994, 1993 and 1992 was 43,369,836, 43,098,808 and
42,577,368, respectively.
Accounting Change
Effective January 1, 1993, the Company adopted SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions." See Note 12.
Other Accrued Expenses
Other accrued expenses for the periods indicated are as
follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . $15,201 $10,133
Other accrued employee benefit costs (see Note 12) . . . 7,337 7,043
Accrued pension cost (see Note 12) . . . . . . . . . . . 4,287 5,872
Accrued lease expense. . . . . . . . . . . . . . . . . . 3,955 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 6,370 5,185
$37,150 $28,233
</TABLE>
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. The
consolidated statements of income of the Company for the year
ended December 31, 1994 and 1993, 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.
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993
(Thousands of dollars, except
per share amounts)
<S> <C> <C>
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
</TABLE>
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. As of December 31, 1993, the
Company had recorded approximately $31.8 million of accounts
receivables, net of accounts payables, and had also recorded
$105.5 million of leases receivable, due from the Partnership.
The following table summarizes transactions between the
Company and the Partnership for the five months ended May 31,
1994 and for the two years in the period ended December 31, 1993
(in thousands):
<TABLE>
<CAPTION>
Five Months Year
Ended May 31, Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
NGL purchases and services from the Partnership . . . $36,536 $98,590 $96,696
Natural gas purchases from the Partnership. . . . . . 9,672 59,735 50,991
Sales of NGLs and natural gas, and transportation
and other charges to the Partnership . . . . . . . 11,385 38,868 54,674
Management fees billed to the Partnership for
direct and indirect costs. . . . . . . . . . . . . 34,299 80,727 82,024
Interest income from capital lease transactions . . . 5,481 13,178 10,386
</TABLE>
3. SHORT-TERM BANK LINES
At December 31, 1994, Energy maintained nine separate
short-term bank lines of credit totalling $130 million, under
which no amounts were outstanding. Three of these lines are
cancellable on demand, and the others expire at various times in
1995. These short-term lines bear interest at each respective
bank's quoted money market rate, have no commitment or other fees
or compensating balance requirements and are unsecured and
unrestricted as to use. Total borrowings under these short-term
lines are limited to $100 million and any amounts outstanding
reduce the availability under the $250 million credit facility
described in Note 4.
4. LONG-TERM DEBT AND BANK CREDIT FACILITIES
<TABLE>
Long-term debt balances were as follows (in thousands):
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
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
Revolving credit and letter of credit facility, 6% at December 31, 1993 . - 75,000
Valero Energy Corporation:
Revolving bank credit and letter of credit facility, 7.11% at
December 31, 1994 (interest fluctuates with LIBOR or prime rate), due
September 30, 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . 133,000 -
10.58% Senior Notes, due December 30, 2000. . . . . . . . . . . . . . . . 187,714 200,000
12 1/4% Senior subordinated notes, Series B, redeemed
September 30, 1994. . . . . . . . . . . . . . . . . . . . . . . . . . . - 15,000
9.14% VESOP Notes, due February 15, 1999. . . . . . . . . . . . . . . . . 8,407 9,858
Medium-Term Notes . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150,000 116,000
Valero Management Partnership, L.P. First Mortgage Notes . . . . . . . . . . 506,429 -
Total long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,084,050 514,358
Less current maturities . . . . . . . . . . . . . . . . . . . . . . . . . 62,230 28,737
$1,021,820 $485,621
</TABLE>
Effective September 30, 1994, Energy amended its
unsecured $250 million revolving bank credit and letter of credit
facility which is available for working capital and general
corporate purposes. The bank credit facility originally became
effective upon the consummation of the Merger on May 31, 1994 and
replaced VRC's $160 million secured revolving credit facility,
Energy's $30 million unsecured revolving credit facility, and all
of the Partnership's committed unsecured revolving credit
facilities. Among other things, the amendment to the bank credit
facility extended the term one year, reduced the interest rate on
LIBOR advances, reduced commitment and utilization fees,
eliminated sublimits for direct advances and letters of credit
and eliminated scheduled commitment reductions. Borrowings under
the amended facility bear interest, at the Company's option, at
LIBOR plus .75% or at the agent bank's prime rate. The Company
is charged various fees, including commitment fees on the
unutilized portion, and various letter of credit and facility
fees. As of December 31, 1994, Energy had approximately
$85.7 million available under this committed bank credit facility
for additional borrowings and letters of credit.
The bank credit facility contains covenants limiting
Energy's ability to make certain "restricted payments," including
dividend payments on and purchases, redemptions or exchanges of
its capital stock, to make certain "restricted disbursements,"
including the restricted payments described above plus capital
expenditures and certain capital investments, and to make
advances and capital contributions to the Partnership. In
February 1995, the bank credit facility was amended to increase
by $50 million through December 31, 1995, the amount of
"restricted disbursements" payable by Energy. The facility also
contains covenants that require Energy to maintain a minimum
consolidated working capital and net worth and also contains
various financial tests including debt-to-capitalization, fixed
charge and earnings coverage ratios. Under the most restrictive
of such covenants, Energy had the ability to pay approximately
$36 million in common and preferred stock dividends and other
"restricted payments" at December 31, 1994.
In 1992, Energy filed with the Commission a shelf
registration statement which was used to offer $150 million
principal amount of Medium-Term Notes. These Medium-Term Notes
have a weighted average life of approximately 7.97 years and a
weighted average interest rate of approximately 8.77%. Energy
recently filed another shelf registration statement with the
Commission to offer up to $250 million principal amount of
additional debt securities, including Medium-Term Notes. 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.
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 eight remaining series due serially from 1995
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, 1994, the First Mortgage Notes have a remaining
weighted average life of approximately 6.7 years and a weighted
average interest rate of 10.16% 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, 1994,
$35.4 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. Under
provisions of Energy's $250 million bank agreement, such
indebtedness for working capital purposes must be provided by
Energy and not by a third party. 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 bank credit and
letter of credit facility and First Mortgage Note covenants as of
December 31, 1994.
Based on long-term debt outstanding at December 31,
1994, maturities of long-term debt, including sinking fund
requirements and excluding borrowings under bank credit
facilities, for the years ending December 31, 1996 through 1999
are approximately $69.7 million, $72.4 million, $75.1 million and
$73.2 million, respectively. Maturities of long-term debt under
bank credit facilities for the year ended December 31, 1997 are
$133 million; however, it is expected that at such time these
bank credit facilities will be replaced with new bank credit
facilities on similar terms and conditions.
Based on the borrowing rates currently available to the
Company for long-term debt with similar terms and average
maturities, the fair value of the Company's long-term debt,
including current maturities, was $1,126 million and $584 million
at December 31, 1994 and 1993, respectively. As a result of the
Merger, the 1994 amount includes the fair value of the
Partnership's long-term debt.
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 1994 had
remaining terms of up to three months. As of December 31, 1994,
1.1 MMbbls or 12% of the Company's refining inventory position of
8.9 MMbbls were hedged. The amount of deferred hedge losses
included as an increase to refinery inventory was $.4 million at
December 31, 1994. The following table is a summary of the
Company's contracts held or issued to hedge inventories as of
December 31, 1994:
<TABLE>
<CAPTION>
Contract or Notional Amounts
Mbbls Range of Prices Per Bbl
<S> <C> <C>
Options:
Receiver . . . . . . . . . . 695 $16.00-$23.10
Futures:
Receiver . . . . . . . . . . 365 $17.20-$17.36
Total Hedged Positions . . (1,060)
</TABLE>
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.
As of December 31, 1994, the Company had established open price
swap positions for one or more of such components with respect to
an average of 1.3 million barrels of feedstock and refined
products per month through December 31, 1995. Through these open
price swap positions on components of refining's operating
margin, approximately 10% of the Company's anticipated 1995
refining margin was hedged as of December 31, 1994. The amount
of explicit deferrals of hedging gains related to these
anticipated transactions was $.1 million as of December 31, 1994.
The Company also enters into commitments to buy and sell refinery
feedstocks and refined products at fixed prices. These
commitments usually extend for a period of less than 30 days and
are at current market prices. The following table is a summary
of the Company's futures contracts held or issued to hedge
refining margins and commitments to purchase and sell refinery
feedstocks and refined products as of December 31, 1994:
<TABLE>
<CAPTION>
Contract or Notional Amounts
Mbbls Range of Prices Per Bbl
<S> <C> <C>
Futures:
Payor. . . . . . . . . . . . 280 $20.24-$20.84
Receiver . . . . . . . . . . 295 $16.76-$17.82
Total Hedged Positions . . (15)
Commitments:
Purchases. . . . . . . . . . 1,063 $15.55-$45.57
Sales. . . . . . . . . . . . 504 $13.50-$60.90
Net. . . . . . . . . . . . 559
</TABLE>
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 to hedge gas storage. As of December 31,
1994, 2.2 TBtus or 22% of the Company's natural gas inventory
position of 9.8 TBtus were hedged. These futures run for periods
of up to 13 months. The amount of deferred hedge gains included
as a reduction of natural gas inventories was $5.7 million at
December 31, 1994. The following table is a summary of the
Company's contracts held or issued to hedge inventory:
<TABLE>
<CAPTION>
Contract or Notional Amounts
BBtus Range of Prices per MMBtu
<S> <C> <C>
Futures:
Receiver . . . . . . . . . . 2,190 $1.58-$2.15
Total Hedged Positions . . (2,190)
</TABLE>
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 extending for periods of up to 15 months. Volumes
hedged as of December 31, 1994, represent 23% of the expected
annual plant shrinkage and 36% of the expected natural gas
requirements of the refining operations. Explicitly deferred
gains from anticipated hedges of $1.1 million as of December 31,
1994 will be recognized in the month being hedged. The Company
also enters into basis swaps for location differentials at fixed
prices which generally extend for periods up to 15 months. The
following table is a summary of the Company's contracts held or
issued to hedge plant shrinkage, refinery operations and natural
gas purchase and sales commitments as of December 31, 1994:
<TABLE>
<CAPTION>
Contract or Notional Amounts
BBtus Range of Prices per MMBtu
<S> <C> <C>
Swaps:
Payor. . . . . . . . . . . . 9,525 $1.58-$1.73
Receiver . . . . . . . . . . 1,345 $3.58-$3.74
Net. . . . . . . . . . . . 8,180
Futures:
Payor. . . . . . . . . . . . 17,900 $1.57-$2.26
Receiver . . . . . . . . . . 6,566 $1.54-$3.69
Net. . . . . . . . . . . . 11,334
Total Hedged Positions . . . 19,514
Basis Swaps:
Payor. . . . . . . . . . . . 27,520 $.03-$.25
Receiver . . . . . . . . . . 16,090 $.02-$.25
Net. . . . . . . . . . . . 11,430
Commitments:
Purchases. . . . . . . . . . 6,788 $1.40-$2.08
Sales. . . . . . . . . . . . 8,947 $1.50-$2.25
Net. . . . . . . . . . . . (2,159)
</TABLE>
Trading Activities
The Company enters into limited speculative transactions
using its fundamental and technical analysis of market conditions
to earn additional revenues. The types of instruments used
include futures, price swaps, and over-the-counter and exchange-
traded options. These contracts run for periods of up to 13
months. The following table is a summary of the Company's
contracts held or issued for trading purposes as of December 31,
1994:
<TABLE>
<CAPTION>
Contract or Notional Amounts
BBtus Range of Prices per MMBtu Mbbls Price per bbl
<S> <C> <C> <C> <C>
Options:
Payor . . . . . . . . . . . . 1,100 $1.70-$2.10 250 $24.36
Receiver. . . . . . . . . . . 500 $1.70-$1.85 -
Net . . . . . . . . . . . . 600 250
Futures:
Payor . . . . . . . . . . . . 380 $1.98-$1.99 -
Receiver. . . . . . . . . . . 380 $1.98-$2.02 -
Net . . . . . . . . . . . . - -
Total Trading Positions . . 600 250
</TABLE>
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 period ended
December 31, 1994 (dollars in thousands):
<TABLE>
<CAPTION>
Fair Value
of Assets Net
(Liabilities) Gains
Average Ending (Losses)
<S> <C> <C> <C>
Options. . . . . . . . . . $(101) $33 $430
Swaps. . . . . . . . . . . 23 - 285
Futures. . . . . . . . . . - - (232)
Total. . . . . . . . . . $ (78) $33 $483
</TABLE>
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. The Company also monitors
credit risk, the risk of nonperformance by counterparties to its
swaps and purchase and sales commitments. 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 $450 million 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, 1994, the Company had invested
approximately $13.4 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%.
The Company has agreed to guarantee 45% of Proesa's obligation to
a surety company 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
February 23, 1995, the Company's portion of the guarantee was
approximately $3.3 million.
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. In particular, the Board has required the renegotiation
of purchase and sales agreements between Proesa and Pemex, the
implementation of certain additional agreements with Pemex, and a
reevaluation of the economics of the Project. Additionally, the
Board has required that the Project participants reach definitive
agreement regarding their ownership interests in Proesa and their
funding commitments to the Project, including procedures for
funding any possible cost overruns. The Company estimates that
if the Project is delayed and further expenditures are reduced to
the minimum practicable level until resolution of the issues
mentioned above, the Company will have a total investment in the
Project of approximately $18 million at the end of the first
quarter of 1995, excluding any funding that may be required with
respect to the guarantee of Proesa's obligation to a surety
company discussed above.
Javelina Partnership
Valero Javelina Company, a wholly owned subsidiary of
Energy, owns a 20% interest in Javelina Company ("Javelina"), a
general partnership. Javelina maintains a term loan agreement
and a working capital and letter of credit facility which mature
on January 31, 1996. Because the Company accounts for its
interest in Javelina on the equity method of accounting, its
share of the borrowings outstanding under such bank credit
agreements is not recorded on its Consolidated Balance Sheets.
The Company's guarantees of these bank credit agreements were
approximately $16.3 million at December 31, 1994.
At December 31, 1994, 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
Energy is required to redeem and, commencing in 1986,
has redeemed in December of each year its Cumulative Preferred
Stock, $8.50 Series A ("Series A Preferred Stock"), at $100 per
share at the rate of 11,500 shares annually ($1,150,000 per
year). The redemption requirement for the Series A Preferred
Stock for each of the five years following December 31, 1994 is
also $1,150,000 per year. Energy also has the option to redeem
shares of the Series A Preferred Stock at any time at $105 per
share until November 30, 1995, with such amount being reduced by
$.50 per share each year thereafter to $100 per share.
In the event of an involuntary liquidation, the holders
of the outstanding Series A Preferred Stock would be entitled,
after the payment of all debts, to $100 per share, plus any
accrued and unpaid dividends. In the event of a voluntary
liquidation, the holders of the outstanding Series A Preferred
Stock would be entitled to $100 per share, any applicable premium
Energy would have had to pay if it had elected to redeem the
Series A Preferred Stock at that time and any accrued and unpaid
dividends. In the event dividends on the Series A Preferred
Stock are six or more quarters in arrears, holders 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 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 15, 1985, Energy's Board of Directors
declared a dividend distribution of one Preference Share Purchase
Right ("Right") for each outstanding share of Energy's Common
Stock. Until exercisable, the Rights are not transferable apart
from Energy's Common Stock. Each Right will entitle shareholders
to buy one-hundredth (1/100) of a share of a newly issued series
of Junior Participating Serial Preference Stock, Series II, at an
exercise price of $35 per Right.
<PAGE>
10. INDUSTRY SEGMENT INFORMATION
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Operating revenues:
Refining and marketing. . . . . . . . . . . . . . . $1,090,368 $1,044,749 $1,056,873
Natural gas . . . . . . . . . . . . . . . . . . . . 487,564 46,021 46,766
Natural gas liquids . . . . . . . . . . . . . . . . 307,016 53,252 49,299
Other . . . . . . . . . . . . . . . . . . . . . . . 42,639 83,886 85,461
Intersegment eliminations . . . . . . . . . . . . . (90,147) (5,669) (3,781)
Total . . . . . . . . . . . . . . . . . . . . . . $1,837,440 $1,222,239 $1,234,618
Operating income (loss):
Refining and marketing. . . . . . . . . . . . . . . $ 78,660 $ 75,401 $ 137,187
Natural gas . . . . . . . . . . . . . . . . . . . . 26,731 2,863 2,445
Natural gas liquids . . . . . . . . . . . . . . . . 35,213 10,057 9,267
Corporate general and administrative
expenses and other, net . . . . . . . . . . . . . (14,679) (12,817) (14,869)
Total . . . . . . . . . . . . . . . . . . . . . 125,925 75,504 134,030
Equity in earnings (losses) of and income from
Valero Natural Gas Partners, L.P. . . . . . . . . . (10,698) 23,693 26,360
Gain on disposition of assets and other income, net . 4,476 6,209 1,452
Interest and debt expense, net. . . . . . . . . . . . (76,921) (37,182) (30,423)
Income before income taxes. . . . . . . . . . . . . . $ 42,782 $ 68,224 $ 131,419
Identifiable assets:
Refining and marketing. . . . . . . . . . . . . . . $1,528,621 $1,407,221 $1,377,074
Natural gas . . . . . . . . . . . . . . . . . . . . 894,678 18,854 47,947
Natural gas liquids . . . . . . . . . . . . . . . . 248,430 83,262 86,403
Other . . . . . . . . . . . . . . . . . . . . . . . 149,688 105,456 106,291
Investment in and leases receivable from
Valero Natural Gas Partners, L.P.. . . . . . . . . - 130,557 125,285
Investment in and advances to joint ventures. . . . 41,162 28,343 24,809
Intersegment eliminations and reclassifications . . (31,221) (9,256) (8,709)
Total . . . . . . . . . . . . . . . . . . . . . . $2,831,358 $1,764,437 $1,759,100
Depreciation expense:
Refining and marketing. . . . . . . . . . . . . . . $ 52,956 $ 47,381 $ 40,241
Natural gas . . . . . . . . . . . . . . . . . . . . 17,633 1,522 1,887
Natural gas liquids . . . . . . . . . . . . . . . . 9,003 3,648 2,530
Other . . . . . . . . . . . . . . . . . . . . . . . 4,440 4,182 3,556
Total . . . . . . . . . . . . . . . . . . . . . . $ 84,032 $ 56,733 $ 48,214
Capital additions:
Refining and marketing. . . . . . . . . . . . . . . $ 119,748 $ 123,031 $ 194,207
Natural gas . . . . . . . . . . . . . . . . . . . . 12,010 2,232 3,358
Natural gas liquids . . . . . . . . . . . . . . . . 6,850 1,458 82,309
Other . . . . . . . . . . . . . . . . . . . . . . . 2,130 9,873 2,881
Total. . . . . . . . . . . . . . . . . . . . . . . $ 140,738 $ 136,594 $ 282,755
</TABLE>
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 unleaded gasoline, at its refinery,
and sells those products principally on a spot and truck rack
basis and also through the use of term contracts. Spot and term
sales of Refining's products are made principally to larger oil
companies and gasoline distributors. The principal purchasers of
Refining's products from truck racks have been wholesalers and
jobbers in the eastern and midwestern United States. Natural gas
operations consist of purchasing, gathering, 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. The natural gas liquids operations include the
extraction of natural gas liquids, principally from natural gas
throughput of the natural gas operations, and the fractionation
and transportation of natural gas liquids. The primary markets
for sales of natural gas liquids are petrochemical plants,
refineries and domestic fuel distributors. Intersegment revenue
eliminations for 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
foreign operations other than petroleum storage facilities and no
single customer accounts for more than 10% of its operating
revenues. 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 include the remaining
$60 million payment to be 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):
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Current:
Federal. . . . . . . . . . . . . . $ 3,535 $16,377 $20,392
State. . . . . . . . . . . . . . . 165 123 908
Total current . . . . . . . . . 3,700 16,500 21,300
Deferred:
Federal. . . . . . . . . . . . . . 12,200 17,892 23,608
State. . . . . . . . . . . . . . . - (2,592) 2,592
Total deferred. . . . . . . . . 12,200 15,300 26,200
Total income tax expense . . . . . . $15,900 $31,800 $47,500
</TABLE>
The Company has credited the tax benefit associated with
expenses for certain employee benefits recognized differently for
financial reporting and income tax purposes directly to
stockholders' equity. Such amounts (in thousands) were $30, $903
and $1,758 for 1994, 1993 and 1992, respectively.
Total income tax expense differs from the amount
computed by applying the statutory federal income tax rate to
income before income taxes. The reasons for these differences
are as follows (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Federal income tax expense at the statutory rate . . . . $ 15,000 $ 23,900 $ 44,700
Additional deferred income taxes due to increase in
federal income tax rate. . . . . . . . . . . . . . . . - 8,200 -
State income taxes, net of federal income tax benefit. . 100 (1,600) 2,300
Other - net. . . . . . . . . . . . . . . . . . . . . . . 800 1,300 500
Total income tax expense . . . . . . . . . . . . . . . . $ 15,900 $ 31,800 $ 47,500
</TABLE>
The tax effects of significant temporary differences
representing deferred income tax assets and liabilities are as
follows (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Deferred income tax assets:
Tax credit carryforwards . . . . . . . . . $ 78,368 $ 67,693
Other. . . . . . . . . . . . . . . . . . . 24,482 29,479
Total deferred income tax assets . . . . $ 102,850 $ 97,172
Deferred income tax liabilities:
Depreciation . . . . . . . . . . . . . . . $(302,762) $(286,207)
Deferred gas costs . . . . . . . . . . . . (11,180) (10,400)
Other. . . . . . . . . . . . . . . . . . . (21,302) (20,825)
Total deferred income tax liabilities. . $(335,244) $(317,432)
</TABLE>
At December 31, 1994, the Company had federal net
operating loss carryforwards of approximately $7 million, which
are available to reduce future federal taxable income and will
expire in 1997 if not utilized.
In addition, the Company had investment tax credit
("ITC"), Employee Stock Ownership Plan ("ESOP") tax credit and
alternative minimum tax ("AMT") credit carryforwards of
approximately $82 million which are available to reduce future
federal income tax liabilities. The ITC and ESOP tax credits of
approximately $54 million expire in the years 1995 ($6 million),
1996 ($23 million), 1997 ($12 million), 1998 ($7 million) and
1999 through 2001 ($6 million) if not utilized and the AMT credit
of approximately $28 million has no expiration date. The Company
did not record any valuation allowances against deferred income
tax assets at December 31, 1994.
The Company's federal income tax returns have been
examined by the IRS for all taxable years through 1990. All
issues were resolved with the exception of one in which the
Company has petitioned the U.S. Court of Appeals. 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, 1994
and 1993 (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $49,197 (1994) and $55,836 (1993). . . . . . . $49,642 $56,692
Projected benefit obligation for services rendered to date . . $63,793 $70,382
Plan assets at fair value. . . . . . . . . . . . . . . . . . . 52,289 51,296
Projected benefit obligation in excess of plan assets. . . . . 11,504 19,086
Unrecognized net gain from past experience different
from that assumed. . . . . . . . . . . . . . . . . . . . . . 10,206 3,439
Prior service cost not yet recognized in net periodic
pension cost . . . . . . . . . . . . . . . . . . . . . . . . (5,434) (6,062)
Unrecognized net asset at beginning of year. . . . . . . . . . 1,625 1,768
Additional minimum liability accrual . . . . . . . . . . . . . 1,217 1,000
Accrued pension cost . . . . . . . . . . . . . . . . . . . . $19,118 $19,231
</TABLE>
Net periodic pension cost for the years ended
December 31, 1994, 1993 and 1992 included the following
components (in thousands):
<TABLE>
<CAPTION>
Year Ended December 31,
1994 1993 1992
<S> <C> <C> <C>
Service cost - benefits earned during the period . . $ 3,981 $ 4,374 $ 4,770
Interest cost on projected benefit obligation. . . . 4,990 5,258 4,925
Actual (return) loss on plan assets. . . . . . . . . 1,820 (3,450) (756)
Net amortization and deferral. . . . . . . . . . . . (6,135) 22 (2,434)
Net periodic pension cost. . . . . . . . . . . . . 4,656 6,204 6,505
Additional expense resulting from early retirement
program. . . . . . . . . . . . . . . . . . . . . . - - 4,605
Curtailment gain resulting from RGV disposition. . . - (1,650) -
Total pension expense. . . . . . . . . . . . . . $ 4,656 $ 4,554 $ 11,110
</TABLE>
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
8.7% and 7.2%, respectively, as of December 31, 1994 and 1993.
The rate of increase in future compensation levels used in
determining the projected benefit obligation as of December 31,
1994 and 1993 was 4% for nonexempt personnel and was 3% and 2%,
respectively for exempt personnel. The expected long-term rate
of return on plan assets was 9.25% and 9% as of December 31, 1994
and 1993, respectively. Contributions, when permitted, are
actuarially determined in an amount sufficient to fund the
currently accruing benefits and amortize any prior service cost
over the expected life of the then current work force. The
Company also maintains a nonqualified Supplemental Executive
Retirement Plan ("SERP") which provides additional pension
benefits to the executive officers and certain other employees of
the Company. The Company's contributions to the pension plan and
SERP in 1994, 1993 and 1992 were approximately $5 million,
$7.5 million and $7.5 million, respectively, and are currently
estimated to be $4.3 million in 1995. 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. Company contributions to the Thrift Plan during
1994, 1993 and 1992 were approximately $42,000, $660,000 and
$348,000, respectively.
In 1989, the Company established the 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 1994, 1993 and 1992, the Company
contributed $3,160,000, $3,596,000 and $3,596,000, respectively,
to the VESOP, comprised of $819,000, $947,000 and $1,065,000,
respectively, of interest on the VESOP Notes and
$2,777,000, $2,649,000 and $2,531,000, 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 and
1992. However, the Company's contributions to the VESOP during
1994 were reduced by $436,000 of dividends paid on unallocated
shares. VESOP shares of Common Stock are considered outstanding
for earnings per share computations. As of December 31, 1994 and
1993, the number of allocated shares were 817,877 and 669,660,
respectively, the number of committed-to-be-released shares were
62,922 and 62,922, respectively, and the number of suspense
shares were 897,893 and 1,086,659, 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, 1994 and 1993 (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Accumulated benefit obligation:
Retirees. . . . . . . . . . . . . . . . . . . . . . $11,319 $10,314
Fully eligible active plan participants . . . . . . 244 3,196
Other active plan participants. . . . . . . . . . . 11,254 11,706
Total accumulated benefit obligation. . . . . . . 22,817 25,216
Unrecognized loss . . . . . . . . . . . . . . . . . . (800) (3,755)
Unrecognized prior service cost . . . . . . . . . . . 1,267 -
Unrecognized transition obligation. . . . . . . . . . (17,066) (18,014)
Accrued postretirement benefit cost . . . . . . . . $ 6,218 $ 3,447
</TABLE>
Net periodic postretirement benefit cost for the years
ended December 31, 1994 and 1993 included the following
components (in thousands):
<TABLE>
<CAPTION>
December 31,
1994 1993
<S> <C> <C>
Service cost - benefits attributed to service during the period . . . $ 1,196 $ 1,011
Interest cost on accumulated benefit obligation . . . . . . . . . . . 1,686 1,692
Amortization of unrecognized transition obligation. . . . . . . . . . 948 1,029
Amortization of prior service cost. . . . . . . . . . . . . . . . . . (84) -
Amortization of unrecognized net loss . . . . . . . . . . . . . . . . 75 -
Net periodic postretirement benefit cost. . . . . . . . . . . . . . 3,821 3,732
Curtailment loss resulting from RGV disposition . . . . . . . . . . . - 616
Total postretirement benefit cost . . . . . . . . . . . . . . . . . $ 3,821 $ 4,348
</TABLE>
For measurement purposes, the assumed health care cost
trend rate was 9% in 1994, 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, 1994 by $3.7 million and the aggregate of the
service and interest cost components of net periodic
postretirement benefit cost for the year then ended by $.5
million. The weighted-average discount rate used in determining
the accumulated postretirement benefit obligation as of
December 31, 1994 and 1993 was 8.7% and 7.2%, respectively.
Prior to 1993, the cost of providing health care and
life insurance benefits to retired employees was recognized as
expense as health care claims and life insurance premiums were
paid. These costs totaled approximately $675,000 for 1992.
Stock Option and Bonus Plans
Energy has three non-qualified stock option plans, Stock
Option Plan No. 5, Stock Option Plan No. 4, and Stock Option Plan
No. 3, collectively referred to herein as the "Stock Option
Plans." The Stock Option Plans provide for the granting of
options to purchase shares of Energy's Common Stock. Such
options are granted to key officers, employees and prospective
employees of the Company. Under the terms of the Stock Option
Plans, the exercise price of the options granted will generally
not be less than 75% of the fair market value of Common Stock at
the date of grant. All stock options granted since 1990 contain
exercise prices equal to the market value at the date of grant.
Stock options become exercisable pursuant to the individual
written agreements between Energy and the participants in the
Stock Option Plans, which provide for options becoming
exercisable in three equal annual installments beginning one year
after the date of grant, with unexercised options expiring ten
years from the date of grant. The aggregate difference between
the market value of Common Stock at date of grant and the option
price is recorded as compensation expense during the exercise
period. At December 31, 1994, 2,575,902 options were
outstanding, at a weighted-average exercise price of $21.51 per
share, of which 708,055 options were exercisable at a weighted-
average exercise price of $23.13 per share. During 1994,
1,343,919 options were granted at a weighted-average exercise
price of $19.43 per share, 7,555 options were exercised at a
weighted-average exercise price of $14.53 per share and 22,086
options were terminated and/or forfeited. At December 31, 1994,
there were 27,561 shares available for grant under these Stock
Option Plans, including shares transferred from previously
terminated stock option plans of the Company.
For each share of stock that can be purchased thereunder
pursuant to a stock option, Stock Option Plans No. 3 and 4
provide that a stock appreciation right ("SAR") may also be
granted. A SAR is a right to receive a cash payment equal to the
difference between the fair market value of Energy's Common Stock
on the exercise date and the option price of the stock to which
the SAR is related. SARs are exercisable only upon the exercise
of the related stock options. At the end of each reporting
period within the exercise period, Energy records an adjustment
to deferred compensation expense based on the difference between
the fair market value of Energy's Common Stock at the end of each
reporting period and the option price of the stock to which the
SAR is related. At December 31, 1994, 133,969 SARs were
outstanding and exercisable, at a weighted-average exercise price
of $14.52 per share. During 1994, 5,346 SARs were exercised at a
weighted-average exercise price of $14.54 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, 1994, there
were 15,927 shares available for award and 3,000 shares were
awarded under this plan during 1994. 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 operating lease commitments in
connection with a gas storage facility, its corporate
headquarters office complex and various facilities used to store
refinery feedstocks and refined products. The gas storage
facility lease has a remaining primary lease term of five 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 the corporate headquarters
lease under which the lease payments were reduced beginning in
1995. The future minimum lease payments for the office complex
noted in the table below reflect the terms of the renegotiated
agreement. The Company has operating leases for various
facilities used to store refinery feedstocks and refined
products. These leases have primary terms ranging from three to
seven 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 12 years.
The related future minimum lease payments as of December 31, 1994
are as follows (in thousands):
<TABLE>
<CAPTION>
Gas Refining
Storage Office Storage
Facility Complex Facilities Other
<S> <C> <C> <C> <C>
1995 . . . . . . . . . $10,438 $ 4,450 $ 4,472 $1,648
1996 . . . . . . . . . 10,438 4,570 5,830 1,277
1997 . . . . . . . . . 9,832 4,570 4,953 1,239
1998 . . . . . . . . . 10,156 4,570 4,075 1,253
1999 . . . . . . . . . 10,438 4,570 4,075 733
Remainder. . . . . . . 5,222 49,911 9,509 450
Total minimum
lease payments . . $56,524 $72,641 $32,914 $6,600
</TABLE>
The future minimum lease payments listed above under the
caption "Other" exclude certain operating lease commitments which
are cancelable by the Company upon notice of one year or less.
Consolidated rent expense amounted to $14,040,000, $12,948,000,
and $12,643,000 for 1994 (including Partnership rents commencing
June 1, 1994), 1993 and 1992, 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 1994, 1993 and
1992, 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
A lawsuit was filed in November 1994 against a wholly
owned subsidiary of Energy 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 Highlands, Crosby, Baytown, and
McNair, Texas, and surrounding areas. The plaintiffs 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 original
plaintiffs and additional intervening plaintiffs make other
similar assertions and seek certification as a class. 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.
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 of
the Partnership'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's second amended
petition, filed April 30, 1994, asserts claims for breach of
contract and numerous other contract and tort claims. The
plaintiff alleges actual damages of approximately $9.7 million
and punitive damages of $45.5 million. The defendants have filed
a motion for partial summary judgement in order to dismiss the
plaintiff's tort claims.
In 1987, Valero Transmission, L.P. ("VT, L.P.") and a
producer from whom VT, L.P. has purchased natural gas entered
into an agreement resolving certain take-or-pay issues between
the parties in which VT, L.P. agreed to pay one-half of certain
excess royalty claims arising after the date of the agreement.
The royalty owners of the producer completed an audit of the
producer and have presented to the producer a claim for
additional royalty payments in the amount of approximately $17.3
million, and accrued interest thereon of approximately
$19.8 million. Approximately $8 million of the royalty owners'
claim, excluding interest, accrued after the effective date of
the agreement between the producer and VT, L.P. The producer and
VT, L.P. are reviewing the royalty owners' claims. VT, L.P. has
received no indication that any lawsuit has been filed by the
royalty owners. The Company believes that various defenses may
reduce or eliminate any liability of VT, L.P. to the producer in
this matter.
Valero Transmission Company ("VTC") and one of its gas
suppliers are parties to various gas purchase contracts assigned
to and assumed by VT, L.P. upon formation of the Partnership in
1987. The supplier is also a party to a series of gas purchase
contracts between the supplier, as buyer, and certain trusts, as
seller. In 1989, the trusts brought suit against the supplier,
alleging breach of various minimum take, take-or-pay and other
contractual provisions, and asserting a statutory nonratability
claim. In the trusts' claims against the supplier, the trusts
seek alleged actual damages, including interest, of approximately
$30 million. Neither VTC nor VT, L.P. was originally a party to
the lawsuit. However, because of the relationship between VTC
and VT, L.P's contracts with the supplier and the supplier's
contracts with the trusts, and in order to resolve existing and
potential disputes, the supplier, VTC and VT, L.P. agreed in
March 1991 to cooperate in the conduct of the litigation, and
agreed that VTC and VT, L.P. will bear a substantial portion of
the costs of any appeal and any nonappealable final judgment
rendered against the supplier. In January 1993, the District
Court ruled on the trusts' motion for summary judgment, finding
that as a matter of law the three gas purchase contracts at issue
were fully binding and enforceable, the supplier breached the
minimum take obligations under one of the contracts, the supplier
is not entitled to claimed offsets for gas purchased by third
parties and the availability of gas for take-or-pay purposes is
established solely by the delivery capacity testing procedures in
the contracts. Damages, if any, were not determined. On April
15, 1994, the trusts named VTC and VT, L.P. as additional
defendants (the "Valero Defendants") to the lawsuit, alleging
that the Valero Defendants maliciously interfered with the
trusts' contracts with the supplier. In the trusts' claim
against the Valero Defendants, the trusts seek unspecified actual
and punitive damages. 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.
A lawsuit was filed against VRC 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 of allegedly hazardous
chemicals and toxic hydrocarbons produced by VRC. The
plaintiffs' claims include negligence, gross negligence, strict
liability, nuisance and trespass. The plaintiffs seek
certification as a class and an unspecified amount of damages,
based on an alleged diminution in the value of their property,
loss of use and enjoyment of property, emotional distress and
other costs.
Valero Javelina Company, a wholly owned subsidiary of
Energy, owns a 20% general partner interest in Javelina Company,
a general partnership. Javelina Company has been named as a
defendant in seven lawsuits filed since 1992 in state district
courts in Nueces County and Duval County, Texas. Five of the
suits include as defendants other companies that own refineries
or other industrial facilities in Nueces County. These suits
were brought by a number of plaintiffs who reside in
neighborhoods near the facilities. The plaintiffs claim injuries
relating to an alleged exposure to toxic chemicals, and generally
claim that the defendants were negligent, grossly negligent and
committed trespass. The plaintiffs claim personal injury and
property damages resulting from soil and ground water
contamination and air pollution allegedly caused by the
operations of the defendants. One of the suits seeks
certification of the litigation as a class action. The
plaintiffs seek unspecified actual and punitive damages. The
other two suits were brought by plaintiffs who either live or
have businesses near the Javelina Plant. The suits allege claims
similar to those described above. These plaintiffs do not
specify an amount of damages claimed.
The Company is also a party to additional claims and
legal proceedings arising in the ordinary course of business.
The Company believes it is unlikely that the final outcome of any
of the claims or proceedings to which the Company is a party,
including those described above, would have a material adverse
effect on the Company's financial 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, 1994 and 1993 were as follows (in thousands of
dollars, except per share amounts):
<TABLE>
<CAPTION>
Operating Net Earnings (Loss)
Operating Income Income Per Share
Revenues (Loss) (Loss) Of Common Stock
<S> <C> <C> <C> <C>
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
1993-Quarter Ended:
March 31. . . . . . . $ 295,762 $ 24,653 $15,611 $.36
June 30 . . . . . . . 321,072 38,118 24,683 .56
September 30 . . . . 323,389 30,463 11,288 .26
December 31 . . . . . 282,016 (17,730) (15,158) (.36)
Total . . . . . . . $1,222,239 $ 75,504 $36,424 $.82
</TABLE>
The Company's results of operations by quarter for 1994
were affected by decreased equity in earnings of the Partnership
prior to the May 31, 1994 Merger and by the consolidation of the
Partnership's results of operations thereafter. See Note 2. For
the fourth quarter of 1993, results of operations were affected
by a $27.6 million or $17.9 million after-tax ($.42 per share)
write-down in the carrying value of the Company's refinery
inventories to reflect then existing market prices. This was due
to a significant decline in feedstock and refined product prices.
<PAGE>
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 1995 PROXY STATEMENT IN
CONNECTION WITH ITS ANNUAL MEETING OF STOCKHOLDERS SCHEDULED TO
BE HELD MAY 9, 1995. 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,
1994 and 1993. . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of income for the years
ended December 31, 1994, 1993 and 1992 . . . . . . . . .
Consolidated statements of common stock and other
stockholders' equity for the years ended
December 31, 1994, 1993 and 1992 . . . . . . . . . . . .
Consolidated statements of cash flows for the
years ended December 31, 1994, 1993 and 1992 . . . . . .
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 -- Amended and Restated Rights Agreement, dated
as of October 17, 1991, between Valero Energy
Corporation and Ameritrust Texas, N.A.,
successor to Mbank Alamo, N.A., as Rights
Agent --incorporated by reference from Exhibit
1 to the Valero Energy Corporation Current
Report on Form 8-K (Commission File No. 1-
4718, filed October 18, 1991).
4.2 -- $250,000,000 Credit Agreement, dated as of
March 31, 1994, among Valero Energy
Corporation, Bankers Trust Company and Bank of
Montreal as Managing Agents, 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
May 12, 1994).
4.3 -- First Amendment to Credit Agreement, dated as
of September 30, 1994--incorporated by
reference from Exhibit 10.2 to the Valero
Energy Corporation Quarterly Report on Form
10-Q (Commission File No. 1-4718, filed
November 14, 1994).
*4.4 -- Form of Second Amendment to Credit Agreement,
dated as of February 27, 1995.
4.5 -- 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).
4.6 -- 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).
4.7 -- 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).
4.8 -- 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).
4.9 -- 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).
4.10 -- 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).
4.11 -- 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, 1988)--incorporated by
reference from Exhibit 10.19 to the Valero
Energy Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed
February 26, 1988).
+10.4 -- Valero Energy Corporation Stock Option Plan
No. 3, as amended and restated November 28,
1993--incorporated by reference from
Exhibit 10.5 to the Valero Natural Gas
Partners, L.P. Annual Report on Form 10-K
(Commission File No. 1-9433, filed March 1,
1994).
+10.5 -- Valero Energy Corporation Stock Option Plan
No. 4, as amended and restated effective
November 28, 1993--incorporated by reference
from Exhibit 10.6 to the Valero Natural Gas
Partners, L.P. Annual Report on Form 10-K
(Commission File No. 1-9433, filed March 1,
1994).
+10.6 -- Valero Energy Corporation 1990 Restricted
Stock Plan for Non-Employee Directors, dated
effective as of November 14,
1990--incorporated by reference from Exhibit
10.23 to the Valero Energy Corporation Annual
Report on Form 10-K (Commission File No. 1-
4718, filed February 26, 1991).
+10.7 -- Valero Energy Corporation Supplemental
Executive Retirement Plan as amended and
restated effective January 1,
1990--incorporated by reference from Exhibit
10.24 to the Valero Energy Corporation Annual
Report on Form 10-K (Commission File No. 1-
4718, filed February 26, 1991).
+10.8 -- Valero Energy Corporation Executive Incentive
Bonus Plan--incorporated by reference from
Exhibit 10.9 to the Valero Natural Gas
Partners, L.P. Annual Report on Form 10-K
(Commission File No. 1-4718, filed
February 20, 1992).
+10.9 -- Executive Severance Agreement between Valero
Energy Corporation and William E. Greehey,
dated December 15, 1982--incorporated by
reference from Exhibit 10.11 to the Valero
Natural Gas Partners, L.P. Annual Report on
Form 10-K (Commission File No. 1-9433, filed
February 25, 1993)
*+10.10 -- Schedule of Executive Severance Agreements.
+10.11 -- 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).
*+10.12 -- Modification of Employment Agreement between
Valero Energy Corporation and William E.
Greehey, dated November 29, 1994.
+10.13 -- 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).
*+10.14 -- 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 28, 1995.
*24.1 -- Power of Attorney, dated February 28,
1995--set forth at the signatures page of this
Form 10-K.
**27.1 -- Financial Data Schedule.
______________
[FN]
* 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) No reports on Form 8-K were filed during the three-
month period ended December 31, 1994.
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), and No. 33-52533 (filed
March 7, 1994).
Insofar as indemnification for liabilities arising under
the Securities Act of 1933 may be permitted to directors,
officers and controlling persons of the registrant pursuant to
the foregoing provisions, or otherwise, the registrant has been
advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore,
unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the
registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of
any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities
being registered, the registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question of
whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final
adjudication of such issue.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
VALERO ENERGY CORPORATION
(Registrant)
By /s/ William E. Greehey
(William E. Greehey)
Chairman of the Board and
Chief Executive Officer
Date: March 1, 1995
<PAGE>
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose
signature appears below hereby constitutes and appoints
William E. Greehey, Stan L. McLelland and Rand C. Schmidt, or any
of them, each with power to act without the other, his true and
lawful attorney-in-fact and agent, with full power of
substitution and resubstitution, for him and in his name, place
and stead, in any and all capacities, to sign any or all
subsequent amendments and supplements to this Annual Report on
Form 10-K, and to file the same, or cause to be filed the same,
with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting
unto each said attorney-in-fact and agent full power to do and
perform each and every act and thing requisite and necessary to
be done in and about the premises, as fully to all intents and
purposes as he might or could do in person, hereby qualifying and
confirming all that said attorney-in-fact and agent or his
substitute or substitutes may lawfully do or cause to be done by
virtue hereof.
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
Signature Title Date
Director, Chairman of the
Board and Chief Executive
Officer (Principal
/s/ William E. Greehey Executive Officer) March 1, 1995
(William E. Greehey)
Senior Vice President
and Chief Financial Officer
(Principal Financial
/s/ Don M. Heep and Accounting Officer) March 1, 1995
(Don M. Heep)
/s/ Edward C. Benninger Director March 1, 1995
(Edward C. Benninger)
/s/ Robert G. Dettmer Director March 1, 1995
(Robert G. Dettmer)
/s/ A. Ray Dudley Director March 1, 1995
(A. Ray Dudley)
/s/ Ruben M. Escobedo Director March 1, 1995
(Ruben M. Escobedo)
/s/ James L. Johnson Director March 1, 1995
(James L. Johnson)
/s/ Lowell H. Lebermann Director March 1, 1995
(Lowell H. Lebermann)
/s/ Susan Kaufman Purcell Director March 1, 1995
(Susan Kaufman Purcell)
SECOND AMENDMENT
TO
CREDIT AGREEMENT
THIS SECOND AMENDMENT TO CREDIT AGREEMENT (this
"Amendment") dated as of February 27, 1995 is among VALERO ENERGY
CORPORATION, a Delaware corporation ("Borrower"), the banks and
co-agents listed on the signature pages hereto, BANKERS TRUST
COMPANY and BANK OF MONTREAL, as Managing Agents, and BANKERS
TRUST COMPANY, as Administrative Agent.
PRELIMINARY STATEMENTS
(1) Pursuant to the Credit Agreement dated as of March
31, 1994 among the Borrower, the banks and co agents referred to
therein, the Managing Agents and the Administrative Agent, as
amended by the First Amendment to Credit Agreement dated as of
September 30, 1994 (said Credit Agreement, as amended, the
"Existing Credit Agreement") the Banks have agreed to make loans
to, and the Administrative Agent has agreed to issue letters of
credit for the account of, the Borrower.
(2) At the request of the Borrower, the parties hereto
have agreed to amend the Existing Credit Agreement in the manner
and upon the terms and conditions set forth herein.
Accordingly, in consideration of the foregoing and the
mutual covenants set forth herein, the parties hereto agree as
follows:
ARTICLE I
DEFINITIONS
Section 1.01. Defined Terms. All capitalized terms
defined in the Existing Credit Agreement, and not otherwise
defined herein shall have the same meanings herein as in the
Existing Credit Agreement. Upon the effectiveness of this
Amendment, each reference (a) in the Existing Credit Agreement to
"this Agreement," "hereunder," "herein" or words of like import
shall mean and be a reference to the Existing Credit Agreement,
as amended hereby and (b)in the Credit Documents to any term
defined by reference to the Existing Credit Agreement shall mean
and be a reference to such term as defined in the Existing Credit
Agreement, as amended hereby.
Section 1.02. References, Etc. The words "hereof,"
"herein" and "hereunder" and words of similar import when used in
this Amendment shall refer to this Amendment as a whole and not
to any particular provision of this Amendment. In this
Amendment, unless a clear contrary intention appears the word
"including" (and with correlative meaning "include") means
including, without limiting the generality of any description
preceding such term. No provision of this Amendment shall be
interpreted or construed against any Person solely because that
Person or its legal representative drafted such provision.
ARTICLE II
AMENDMENTS TO EXISTING CREDIT AGREEMENT
Section 2.01. Amendment to Section 8.11. (a) Section
8.11(a) of the Existing Credit Agreement is hereby amended and
restated to read as follows:
"(a) Consolidated Working Capital Ratio. The
Borrower will not permit the ratio of: (i) the Consolidated
Current Assets of the Borrower plus the Total Unutilized
Commitment, to (ii) the Consolidated Current Liabilities of the
Borrower (excluding any portion attributable to this Agreement),
to be less than 1.1 to 1.0 at any time."
(b) Section 8.11(c) of the Existing Credit Agreement
is hereby amended and restated to read as follows:
"(c) Fixed Charge Coverage. The Borrower will not
permit the ratio of:
(i) the sum (without duplication) of (A)
Consolidated Net Income (excluding extraordinary items) of the
Borrower for the applicable period, plus (B) interest expense for
the Borrower and its Subsidiaries on a consolidated basis for
such period, plus (C) deferred federal and state income taxes
deducted in determining such Consolidated Net Income for such
period, plus (D) Depreciation and Amortization Expense for such
period, plus (E) other noncash charges deducted in determining
such Consolidated Net Income for such period (including, without
limitation, the LIFO Adjustment to the extent such period
includes the fourth quarter of 1993), minus (F) other noncash
credits added in determining such Consolidated Net Income for
such period, to
(ii) the sum (without duplication) of (A) interest
incurred for the Borrower and its Subsidiaries on a consolidated
basis for such period, plus (B) cash dividends paid by the
Borrower on its preferred and preference stock during such period
(other than dividends paid on preferred and preference stock held
by the Borrower or a Subsidiary of the Borrower) plus (C) cash
dividends paid by the Borrower on its common stock during such
period (other than dividends reinvested in newly issued or
treasury shares of common stock of the Borrower pursuant to any
dividend reinvestment plan maintained by the Borrower for holders
of its common stock), plus (D) the amount of mandatory
redemptions of preferred stock made by the Borrower during such
period (excluding redemptions of shares of such preferred stock
held by Subsidiaries of the Borrower),
to be less than (1) 1.6 to 1.0 for any period of four
consecutive non-Turnaround Quarter fiscal quarters (taken as one
accounting period) ending on or prior to September 30, 1996, (2)
1.1 to 1.0 for any single non-Turnaround Quarter fiscal quarter
ending on or prior to September 30, 1996, (3) 2.0 to 1.0 for any
period of four consecutive non-Turnaround Quarter fiscal quarters
(taken as one accounting period) ending after September 30, 1996,
or (4) 1.5 to 1.0 for any single non-Turnaround Quarter fiscal
quarter ending after September 30, 1996."
Section 2.02. Amendment to Section 8.12. Section
8.12(a) of the Existing Credit Agreement is hereby amended to add
a new clause (ix) which shall read as follows:
", plus (ix) for each determination date ending on
or prior to December 31, 1995, 50,000,000."
Section 2.03. Amendment to Annex A. The definition of
Capital Investment set forth in Annex A to the Existing Credit
Agreement is hereby amended and restated to read as follows:
" 'Capital Investments' shall mean, without
duplication, the sum of all capital expenditures (determined in
accordance with generally accepted accounting principles, but
recognized on a cash basis as such capital expenditures are paid,
rather than an accrual basis), Investments and Deferred
Turnaround Costs of the Borrower and its Subsidiaries."
ARTICLE III
CONDITIONS TO EFFECTIVENESS
Section 3.01. Conditions to Effectiveness. This
Amendment shall become effective upon receipt by the
Administrative Agent of the following, each in form and substance
reasonably satisfactory to the Managing Agents and in such number
of counterparts as may be reasonably requested by the Managing
Agents:
(a) This Amendment duly executed by the Borrower and
the Required Banks.
(b) A certificate dated as of the date of the
effective date of this Amendment of the secretary or an assistant
secretary of the Borrower certifying (i) true and correct copies
of resolutions adopted by the Board of Directors of the Borrower
(A) authorizing the execution, delivery and performance by the
Borrower of this Amendment, and (B) authorizing officers of the
Borrower to execute and deliver this Amendment, and (ii) the
incumbency and specimen signatures of the officers of the
Borrower executing this Amendment or any other document on behalf
of the Borrower.
(c) A certificate dated as of the effective date of
this Amendment of a Financial Officer of the Borrower certifying
that, after giving effect to this Amendment, the representations
and warranties contained in Article IV are true and correct on
and as of such date, as though made on and as of such date.
(d) A favorable, signed opinion addressed to the
Managing Agents and the Banks from the General Counsel of the
Borrower, addressing such matters as the Managing Agents may
reasonably require.
(e) Certificates of appropriate public officials as to
the existence and good standing of the Borrower in the States of
Delaware and Texas.
ARTICLE IV
REPRESENTATIONS AND WARRANTIES
In order to induce the other parties to enter into this
Amendment, the Borrower hereby represents and warrants to such
other parties as follows:
Section 4.01. Existing Credit Agreement. After giving
effect to the execution and delivery of this Amendment and the
consummation of the transactions contemplated hereby and with
this Amendment constituting one of the Credit Documents, the
representations and warranties set forth in the Existing Credit
Agreement are true and correct on the date hereof as though made
on and as of such date.
Section 4.02. No Default. After giving effect to the
execution and delivery of this Amendment and the consummation of
the transactions contemplated hereby, no Default or Event of
Default has occurred and is continuing as of the date hereof.
ARTICLE V
MISCELLANEOUS
Section 5.01. Affirmation of Credit Documents. The
Borrower hereby acknowledges and agrees that all of its
obligations under the Existing Credit Agreement, as amended
hereby, and the other Credit Documents shall remain in full force
and effect following the execution and delivery of this
Amendment, and such obligations are hereby affirmed, ratified and
confirmed by the Borrower.
Section 5.02. Successors and Assigns. This Amendment
shall be binding upon, and inure to the benefit of, the parties
hereto and their respective successors and assigns.
Section 5.03. Captions. Section and Article headings
in this Amendment have been inserted for convenience of reference
only and shall be given no substantive meaning or significance
whatsoever in construing the terms and provisions of this
Amendment.
Section 5.04. Execution in Counterparts. This
Amendment may be executed in any number of counterparts and by
different parties hereto in separate counterparts, each of which
when so executed and delivered shall be deemed to be an original
and all of which taken together shall constitute but one and the
same instrument.
SECTION 5.05. GOVERNING LAW. THIS AMENDMENT AND THE
RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE
CONSTRUED IN ACCORDANCE WITH AND BE GOVERNED BY THE LAWS OF THE
STATE OF NEW YORK WITHOUT GIVING EFFECT TO THE CONFLICT OF LAW
PRINCIPLES THEREOF (OTHER THAN SECTION 5-1401 OF THE GENERAL
OBLIGATIONS LAW OF THE STATE OF NEW YORK).
SECTION 5.06. FINAL AGREEMENT OF THE PARTIES. THE
EXISTING CREDIT AGREEMENT (INCLUDING THE EXHIBITS THERETO), AS
AMENDED BY THIS AMENDMENT, THE NOTES AND THE OTHER CREDIT
DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND
MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR
SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO ORAL
AGREEMENTS BETWEEN THE PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this
Amendment to be executed as of the date first stated herein by
their respective officers thereunto duly authorized.
VALERO ENERGY CORPORATION
By:
Name: John D. Gibbons
Title: Treasurer
BANKERS TRUST COMPANY,
Individually, as Administrative
Agent and as Managing Agent
By:
Name:
Title:
BANK OF MONTREAL,
Individually and as Managing Agent
By:
Name:
Title:
BANK ONE, TEXAS, N.A.,
Individually and as Co-Agent
By:
Name:
Title:
BANQUE NATIONALE de PARIS,
HOUSTON AGENCY, Individually and as
Co-Agent
By:
Name:
Title:
CIBC INC., Individually and as
Co-Agent
By:
Name:
Title:
THE FIRST NATIONAL BANK OF
BOSTON, Individually and as
Co-Agent
By:
Name:
Title:
THE FUJI BANK, LIMITED
HOUSTON AGENCY, Individually and as
Co-Agent
By:
Name:
Title:
TORONTO DOMINION (TEXAS),
INC., Individually and as Co-Agent
By:
Name:
Title:
THE BANK OF TOKYO, LTD.
By:
Name:
Title:
BERLINER HANDELS UND
FRANKFURTER BANK
By:
Name:
Title:
By:
Name:
Title:
CHRISTIANIA BANK
By:
Name:
Title:
CREDIT LYONNAIS NEW YORK
BRANCH
By:
Name:
Title:
CREDIT LYONNAIS CAYMAN
ISLAND BRANCH
By:
Name:
Title:
THE DAIWA BANK, LTD.
By:
Name:
Title:
By:
Name:
Title:
THE FROST NATIONAL BANK
By:
Name:
Title:
SOCIETE GENERALE, SOUTHWEST
AGENCY
By:
Name:
Title:
EXHIBIT 10.10
SCHEDULE OF EXECUTIVE SEVERANCE AGREEMENTS*
Employer Employee Date of Agreement
- -------- -------- -----------------
Valero Energy Stan L. McLelland December 15, 1982
Corporation
Valero Energy Edward C. Benninger December 15, 1982
Corporation
Valero Energy Steven E. Fry December 15, 1982
Corporation
Valero Energy Eugene Baines Manning July 16, 1988
Corporation
*Each of the aforecited contracts is in substantially the same
form as Exhibit 10.9 to the Valero Energy Corporation Annual
Report on For 10-K for the year ended December 31, 1994.
EXHIBIT 10.12
Excerpt from the November 28-29, 1994 Meeting
of the Board of Directors of Valero Energy Corporation
APPROVED
Board of Directors
Valero Energy Corporation
November 28-29, 1994
Modification of
Employment Agreement
with William E. Greehey
WHEREAS, Valero Energy Corporation (the "Company") and William
E. Greehey have entered into that certain Employment Agreement,
dated May 16, 1990, and amended and restated November 1, 1993
(the "Agreement") providing for the employment of Mr. Greehey by
Company as Chairman of the Board and Chief Executive Officer of
Company for a term beginning May 16, 1990 and ending June 9, 1995
(the "Original Termination Date"); and
WHEREAS, the Agreement provides that, upon his retirement from
the Company following the giving of at least six months prior
notice of his intent to retire, Mr. Greehey shall enjoy certain
specified benefits upon retirement; and
WHEREAS, such benefits would not be realized by Mr. Greehey if
he were to retire following the termination of the Agreement or
upon less than six months' notice; and
WHEREAS, the Compensation Committee has recommended, and this
Board of Directors has determined, that it is in the best
interests of the Company that Mr. Greehey defer any decision to
retire;
NOW THEREFORE, BE IT RESOLVED, that, in consideration of his
forbearance in giving notice of his retirement, Mr. Greehey
shall, upon such retirement prior to the Original Termination
Date, whether or not occurring upon six months prior notice, have
and receive the following rights and benefits, to wit:
(a) the right to be furnished with office, secretarial
help and other facilities and services until he reaches age 69,
all in accordance with the provisions of Section 4(e) of the
Agreement;
(b) the right to the benefits specified in Section
4(c) of the Agreement such benefits to be provided until June 9,
1995;
(c) the right to receive the payments specified in,
and subject to the terms and conditions of, Section 7(c) of the
Agreement until June 9, 1995;
(d) the right, upon retirement, to receive certain
club memberships as specified in the second sentence of Section
7(d) of the Agreement;
(e) the rights with respect to stock options, stock
appreciation rights, restricted stock grants and other similar
employee benefits as specified in Section 7(e) of the Agreement;
(f) the right to receive the comprehensive medical
insurance benefits and paid up life insurance specified in
Sections 7(f)(i) and (ii) of the Agreement; and
(g) the right to eight supplemental "points" under the
Company's pension plan, and the right to receive supplemental
monthly retirement payments based thereon, as specified in and
subject to the provisions of Section 7(f)(iii) of the Agreement;
and
RESOLVED FURTHER, that except to the extent modified by these
resolutions, the terms and conditions of the Agreement shall be
and remain in full force and effect for the term thereof, and
that, following the Original Termination Date thereof, Mr.
Greehey shall continue to be entitled to receive the rights and
benefits enumerated in clauses (a), (d), (e), (f) and (g) of the
preceding resolution; and
RESOLVED FURTHER, that these resolutions shall be deemed for all
purposes to be contractual in nature, shall continue in force and
effect indefinitely and may not be amended, modified, revoked or
rescinded without the prior written consent of Mr. Greehey; and
RESOLVED FURTHER, that the proper officers of this Company be,
and they hereby are, authorized and directed to execute and
deliver all such instruments and documents, take such actions and
make such proper payments as they, or any of them, may deem to be
necessary or appropriate to carry out the intent and purpose of
the foregoing resolutions.
EXHIBIT 10.14
SCHEDULE OF INDEMNITY AGREEMENTS
Employer Employee Date of Agreement
- -------- -------- -----------------
Valero Energy Edward C. Benninger February 24, 1987
Corporation
Valero Energy Robert G. Dettmer October 17, 1991
Corporation
Valero Energy A. Ray Dudley July 21, 1988
Corporation
Valero Energy James L. Johnson April 25, 1991
Corporation
Valero Energy Lowell H. Lebermann February 24, 1987
Corporation
Valero Energy Ruben M. Escobedo October 1, 1994
Corporation
Valero Energy Susan Kaufman Purcell October 1, 1994
Corporation
Valero Energy Steven E. Fry February 24, 1987
Corporation
Valero Energy Stan L. McLelland February 24, 1987
Corporation
Valero Energy Don M. Heep February 22, 1990
Corporation
Valero Energy E. Baines Manning July 16, 1986
Corporation
<TABLE>
EXHIBIT 11.1
VALERO ENERGY CORPORATION AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER SHARE
(Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
Year Ending December 31,
1994 1993 1992
<S> <C> <C> <C>
COMPUTATION OF EARNINGS PER SHARE
ASSUMING NO DILUTION:
Net income. . . . . . . . . . . . . . . . . . . $ 26,882 $ 36,424 $ 83,919
Less: Preferred stock dividend requirements. . (9,490) (1,262) (1,475)
Net income applicable to common stock . . . . . $ 17,392 $ 35,162 $ 82,444
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . . 43,369,836 43,098,808 42,577,368
Earnings per share assuming no dilution . . . . $ .40 $ .82 $ 1.94
COMPUTATION OF EARNINGS PER SHARE
ASSUMING FULL DILUTION:
Net income. . . . . . . . . . . . . . . . . . $ 26,882 $ 36,424 $ 83,919
Less: Preferred stock dividend requirements. (9,490) (1,262) (1,475)
Add: Reduction of preferred stock dividends
applicable to the assumed conversion of
Convertible Preferred Stock . . . . . . . . 8,325 - -
Net income applicable to common stock
assuming full dilution. . . . . . . . . . . $ 25,717 $ 35,162 $ 82,444
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . 43,369,836 43,098,808 42,577,368
Weighted average common stock equivalents
applicable to stock options . . . . . . . . 56,926 67,017 144,469
Weighted average shares issuable upon
conversion of Convertible Preferred Stock . 4,948,079 - -
Weighted average shares used for computation. 48,374,841 43,165,825 42,721,837
Earnings per share assuming full dilution . . $ .53 <F1> $ .81 <F2> $ 1.93 <F2>
<FN>
<F1> This calculation is submitted in accordance with paragraph
601(b)(11) of Regulation S-K although it is contrary to APB
Opinion No. 15 because it produces an antidilutive result.
<F2> This calculation is submitted in accordance with paragraph
601(b)(11) of Regulation S-K although it is not required by
APB Opinion No. 15 because it results in dilution of less
than 3%.
</FN>
</TABLE>
<TABLE> EXHIBIT 12.1
VALERO ENERGY CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
Year Ended Year Ended
December 31, 1994 December 31, 1993 Year Ended December 31,
Pro Forma<F1> Historical Pro Forma<F1> Historical 1992 1991 1990
<S> <C> <C> <C> <C> <C> <C> <C>
Pretax income from continuing
operations . . . . . . . . . . . . . $ 31,289 $ 42,782 $ 76,698 $ 68,224 $131,419 $146,367 $145,593
Add (Deduct):
Net interest expense<F4>. . . . . . 98,695 76,921 89,413 37,182 30,423 12,540 18,067
Amortization of previously
capitalized interest. . . . . . . 6,847 6,282 6,300 4,998 4,544 3,457 3,416
Interest portion of rental
expense<F2> . . . . . . . . . . . 8,259 6,695 8,003 4,316 4,214 3,913 4,256
Distributions (less than)/in
excess of equity in earnings
of VNGP, L.P.<F3>. . . . . . . . - 18,968 - (4,970) (1,067) 1,030 (5,603)
Distributions (less than) equity
in earnings of joint
ventures<F4> . . . . . . . . . . (2,437) (2,437) - - - - -
Earnings as defined. . . . . . . $142,653 $149,211 $180,414 $109,750 $169,533 $167,307 $165,729
Net interest expense<F4> . . . . . . . $ 98,695 $ 76,921 $ 89,413 $ 37,182 $ 30,423 $ 12,540 $ 18,067
Capitalized interest . . . . . . . . . 2,558 2,365 14,048 12,335 15,853 25,408 6,499
Interest portion of rental
expense<F2>. . . . . . . . . . . . . 8,259 6,695 8,003 4,316 4,214 3,913 4,256
Fixed charges as defined . . . . $109,512 $ 85,981 $111,464 $ 53,833 $ 50,490 $ 41,861 $ 28,822
Ratio of earnings to fixed charges . . 1.30x 1.74x 1.62x 2.04x 3.36x 4.00x 5.75x
<FN>
<F1>
The pro forma computations reflect the consolidation of the Partnership with the Company for all of 1994 and 1993.
<F2>
The interest portion of rental expense represents one-third of rents, which is deemed representative of the interest
portion of rental expense.
<F3>
Represents the Company's undistributed equity in earnings or distributions in excess of equity in earnings of the
Partnership for the periods prior to and including May 31, 1994. On May 31, 1994, the Merger of the Partnership with
the Company was consummated and the Partnership became a wholly owned subsidiary of the Company.
<F4>
The Company has guaranteed its pro rata share of the debt of Javelina Company, an equity method investee in which the
Company holds a 20% interest. The interest expense related to the guaranteed debt is not included in the computation
of the ratio as the Company has not been required to satisfy the guarantee nor does the Company believe that it is
probable that it would be required to do so.
</FN>
</TABLE>
EXHIBIT 21.1
VALERO ENERGY CORPORATION
SCHEDULE OF SUBSIDIARIES
-------------------------
Valero Coal Company Delaware
Valero Javelina Company Delaware
Valero Management Company Delaware
VMGA Company Texas
VNGC Holding Company Delaware
Valero Natural Gas Company Delaware
Valero Eastex Pipeline Company Delaware
Valero Gas Marketing Company Delaware
Valero Gas Storage Company Delaware
Valero Hydrocarbons Company Delaware
Valero NGL Investments Company Delaware
Valero South Texas Gathering Company Delaware
Valero South Texas Marketing Company Delaware
Valero South Texas Processing Company Delaware
Valero Power Services Company Delaware
Valero Storage Company Delaware
Valero Transmission Company Delaware
VT Company Delaware
Valero Producing Company Delaware
Valero Refining and Marketing Company Delaware
Valero Refining Company Delaware
Valero MTBE Investments Company Delaware
Valero MTBE Operating Company Delaware
Valero Mediterranean Company Delaware
Valero Mexico Company Delaware
Valero Technical Services Company Delaware
Valero Natural Gas Partners, L.P. Delaware
Valero Management Partnership, L.P. Delaware
Valero Transmission, L.P. Delaware
Valero Hydrocarbons, L.P. Delaware
Valero Marketing, L.P. Delaware
Valero Industrial Gas, L.P. Delaware
Valero Gas Marketing, L.P. Delaware
VLDC, L.P. Delaware
Reata Industrial Gas, L.P. Delaware
Rivercity Gas, L.P. Delaware
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation of our report included in this Form 10-K into the
Company's previously filed Registration Statements on Form S-8
(File Nos. 2-66297, 2-82001, 2-97043, 33-23103, 33-14455,
33-38405, 33-53796, 33-52533) and on Form S-3 (File
No. 33-56441).
/s/ ARTHUR ANDERSEN LLP
San Antonio, Texas
February 28, 1995
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1994 AND THE CONSOLIDATED
STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1994 AND IS QUALIFIED IN ITS
ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<CASH> 61,651
<SECURITIES> 0
<RECEIVABLES> 235,043
<ALLOWANCES> 2,770
<INVENTORY> 182,089
<CURRENT-ASSETS> 532,872
<PP&E> 2,672,715
<DEPRECIATION> 531,501
<TOTAL-ASSETS> 2,831,358
<CURRENT-LIABILITIES> 460,767
<BONDS> 1,021,820
<COMMON> 43,464
12,650
3,450
<OTHER-SE> 965,566
<TOTAL-LIABILITY-AND-EQUITY> 2,831,358
<SALES> 1,837,440
<TOTAL-REVENUES> 1,837,440
<CGS> 1,711,515
<TOTAL-COSTS> 1,711,515
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 76,921
<INCOME-PRETAX> 42,782
<INCOME-TAX> 15,900
<INCOME-CONTINUING> 26,882
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 26,882
<EPS-PRIMARY> .40
<EPS-DILUTED> 0
</TABLE>
