FORM 10-K/A
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X]
For the fiscal year ended December 31, 1996
OR
[ ]
For the transition period from __________ to __________
Commission file number 1-4718
VALERO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 74-1244795
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
530 McCullough Avenue 78215
San Antonio, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code (210) 246-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
__________________________________ _______________________
Common Stock, $1 Par Value New York Stock Exchange
$3.125 Convertible Preferred Stock New York Stock Exchange
Preference Share Purchase Rights New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE.
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter
period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
The aggregate market value on January 31, 1997, of the registrant's
Common Stock, $1.00 par value ("Common Stock"), held by nonaffiliates of the
registrant, based on the average of the high and low prices as quoted in the
New York Stock Exchange Composite Transactions listing for that date, was
approximately $1.3 billion. As of January 31, 1997, 44,273,350 shares of
the registrant's Common Stock were issued and outstanding.
<PAGE>
CONTENTS
PAGE
PART I
Item 1. Business. . . . .. . . . . . . . . . . . . . . . .
Proposed Restructuring . . . . . . . . . . . . . .
Refining and Marketing . . . . . . . . . . . . . .
Refining Operations . . . . . . . . . . . . . .
Sales . . . . . . . . . . . . . . . . . . . . .
Feedstock Supply . . . . . . . . . . . . .. . .
Factors Affecting Operating Results . . . . . .
Natural Gas Related Services . . . . . . . . . . .
Transmission System . . . . . . . . . . . . . .
Sales and Marketing . . . . . . . . . . . . . .
Transportation. . . . . . . . . . . . . . . . .
Supply and Storage. . . . . . . . . . . . . . .
Natural Gas Liquids . . . . . . . . . . . . . .
Electric Power. . . . . . . . . . . . . . . . .
Governmental Regulations . . . . . . . . . . . . .
Federal Regulation. . . . . . . . . . . . . . .
Texas Regulation. . . . . . . . . . . . . . . .
Competition. . . . . . . . . . . . . . . . . . . .
Refining and Marketing. . . . . . . . . . . . .
Natural Gas Related Services. . . . . . . . . .
Environmental Matters. . . . . . . . . . . . . . .
Employees. . . . . . . . . . . . . . . . . . . . .
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
Item 10. Directors and Executive Officers of the
Registrant. . . . . . . . . . . . . . . . . . .
Directors of the Registrant. . . . . . . . . . . .
Executive Officers of the Registrant . . . . . . .
Section 16(a) Beneficial Ownership Reporting
Compliance. . . . . . . . . . . . . . . . . . .
Item 11. Executive Compensation . . . . . . . . . . . . . .
Summary Compensation . . . . . . . . . . . . . . .
Stock Option Grants and Related Information. . . .
Retirement Benefits. . . . . . . . . . . . . . . .
Compensation of Directors. . . . . . . . . . . . .
Arrangements with Certain Officers and Directors .
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions . .
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. The Company is a diversified energy company
engaged in the production, transportation and marketing of environmentally
clean fuels and products. The Company's core businesses are specialized
refining and natural gas related services. The Company owns a specialized
petroleum refinery in Corpus Christi, Texas (the "Refinery"), and refines
high-sulfur atmospheric residual oil into premium products, primarily
reformulated gasoline ("RFG"), and markets those refined products. The
Company also has a network of approximately 7,500 miles of natural gas
transmission and gathering lines throughout Texas. The Company purchases
natural gas for resale to distribution companies, electric utilities, other
pipelines and industrial customers throughout North America, and provides
gas transportation and price risk management services to third parties. The
Company also owns and operates eight natural gas processing plants and is a
major producer and marketer of natural gas liquids ("NGLs"). The Company is
also a marketer of electric power.
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 11 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."
PROPOSED RESTRUCTURING
On January 31, 1997, the Company announced that its Board of
Director's had approved an agreement and plan of merger with PG&E
Corporation ("PG&E") to combine the Company's natural gas related services
business with PG&E following the spin-off of the Company's refining and
marketing business to the Company's shareholders (the "Restructuring").
Under the terms of the merger agreement, the Company's natural gas related
services business will be merged with a wholly owned subsidiary of PG&E.
PG&E will acquire the Company's natural gas related services business for
approximately $1.5 billion, plus adjustments for working capital and other
considerations. PG&E will issue $722.5 million of common stock, subject to
certain closing adjustments, in exchange for outstanding shares of Energy's
common stock, and will assume certain outstanding debt and other
liabilities. Each Energy shareholder will receive a fractional share of
PG&E common stock (trading on the New York Stock Exchange under the symbol
"PCG") for each Energy share; the amount of PG&E stock to be received will
be based on the average price of the PG&E common stock during a period
preceding the closing of the transaction and the number of Energy shares
issued and outstanding at the time of the closing.
Energy's shareholders will also receive one share of the spun-off
refining and marketing company for each share of Energy common stock. The
refining and marketing company will retain the Valero name and will
apply to be listed on the New York Stock Exchange. The refining and
marketing company expects to aggressively pursue acquisitions and strategic
alliances in the refining and marketing industry. The spin-off of the
refining and marketing business and the merger with PG&E are expected to be
tax-free transactions. However, on February 6, 1997, President Clinton's
budget recommendations to Congress called for new legislation that, if
enacted, may require Energy to pay federal income tax upon the consummation
of the Restructuring on the amount of gain equal to the excess of the value
of the refining and marketing company stock distributed to Energy's
stockholders over Energy's basis in such stock. Even though this
legislation has not yet been introduced in Congress, the proposal would be
effective for distributions after the date of first committee action. It is
uncertain whether any such legislation ultimately will be enacted, whether
its effective date provision may be modified, or when committee action in
Congress may first occur. The Company believes it is likely that any
legislation ultimately enacted will provide an exemption for transactions
like the Restructuring for which definitive agreements were executed prior
to introduction of the President's budget; however, if the proposal is
enacted or pending prior to consummation of the Restructuring with an
effective date provision that could cause Energy to be subject to tax, the
tax opinions described below may not be available. The Restructuring
transactions are subject to approval by the Company's shareholders, the
Securities and Exchange Commission, and certain regulatory agencies as well
as receipt of favorable tax opinions. The Company expects to hold a
special meeting of stockholders (in lieu of an annual meeting) to consider
the Restructuring transactions in June 1997. The Restructuring
transactions are expected to be completed by mid-1997. However, there can
be no assurance that the various approvals and opinions will be given or
that the conditions to consummating the transactions will be met.
REFINING AND MARKETING
Refining Operations
The Refinery processes high-sulfur atmospheric tower bottoms, a type
of residual fuel oil ("resid"), and other feedstocks into a product slate of
higher value products, principally RFG and middle distillates. The Refinery
can produce approximately 171,500 barrels per day of refined products, with
gasoline and gasoline-related products comprising approximately 85% of the
Refinery's production, and middle distillates comprising the remainder. The
Refinery can produce all of its gasoline as RFG and all of its diesel fuel
as low-sulfur diesel. The Refinery has substantial flexibility to vary its
mix of gasoline products to meet changing market conditions. For additional
information regarding refining and marketing operating results for the three
years ended December 31, 1996, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
The Refinery's principal operating units include its
hydrodesulfurization unit ("HDS Unit") and the heavy oil cracking complex
("HOC"). The HDS Unit removes sulfur and metals from resid to improve the
resid's subsequent cracking characteristics. The HDS Unit has a capacity of
approximately 70,000 barrels per day. The HOC processes feedstock primarily
from the HDS Unit, and has a capacity of approximately 74,000 barrels per
day. The Refinery's other significant units include a 36,000 barrel-per-day
"Hydrocracker" (which produces reformer feed naphtha from the Refinery's gas
oil and distillate streams), a 36,000 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
31,000 barrel-per-day reformate splitter (which separates a benzene
concentrate stream from reformate produced at the Reformer), a
30,000 barrel-per-day crude unit, and a 24,000 barrel-per-day vacuum unit.
Also located at the Refinery are the Company's MTBE Plant (the
"MTBE Plant") and "MTBE/TAME Unit." The MTBE Plant can produce approxi-
mately 17,000 barrels per day of methyl tertiary butyl ether ("MTBE") from
butane and methanol feedstocks. MTBE is an oxygen-rich, high-octane
gasoline blendstock produced by reacting methanol and isobutylene, and is
used to manufacture oxygenated and reformulated gasolines. The Company can
blend the MTBE produced at the Refinery into the Company's own gasoline
production or sell the MTBE separately. The Refinery's "MTBE/TAME Unit"
converts certain streams produced by the HOC into MTBE and tertiary amyl
methyl ether ("TAME"). TAME, like MTBE, is an oxygen-rich, high-octane
gasoline blendstock. The MTBE Plant and MTBE/TAME Unit enable the Company
to produce approximately 22,500 barrels per day of total oxygenates.
Substantially all of the methanol feedstocks required for the production of
oxygenates at the Refinery can be provided by a methanol plant owned by a
joint venture between the Company and Hoechst Celanese Chemical Group, Inc.
(the "Methanol Plant"). The Methanol Plant can produce approximately 13,000
barrels per day of methanol.
In January 1997, the Company placed into service a "Xylene
Fractionation Unit" which recovers xylenes from the Reformer's reformate
stream. The fractionated xylene may be sold into the petrochemical
feedstock market for use in the production of paraxylene. The Xylene
Fractionation Unit can recover a mixed xylene stream of approximately 6,500
barrels per day. The MTBE Plant, MTBE/TAME Unit, Xylene Fractionation Unit
and related facilities diversify the Company's product mix and enable the
Company to pursue the higher margin product markets.
In 1996, the Company completed scheduled turnarounds on its HDS Unit,
Hydrocracker, Reformer, and MTBE Plant. The capacity of the MTBE Plant was
increased by approximately 1,500 barrels per day. During the second quarter
of 1996, the Company experienced unscheduled down time at the Refinery
because of two power outages. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Results of Operations." The
Refinery's other principal refining units operated during 1996 without
significant unscheduled down time. However, the Methanol Plant in Clear
Lake suffered an explosion in early December. There were no injuries, but
the Company's share of repair costs is estimated to be $2.5 million. The
plant is expected to resume operations in late February 1997. The MTBE
Plant was down for nine days in January 1997 to replace a portion of
catalyst in the unit. During 1997, the HDS Unit is scheduled to be down
for approximately 18 days in the fourth quarter to replace the catalyst
in the unit. The crude unit is scheduled to be down for approximately
14 days in the second quarter of 1997 for a maintenance turnaround
designed to increase the unit's capacity.
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, 1996. Average throughput margin
per barrel is computed by subtracting total direct product cost of sales
from product sales revenues and dividing the result by throughput volumes.
Year Ended December 31,
1996 1995 1994
Throughput volumes (Mbbls per day). . . . 170 160 146
Average throughput margin per barrel. . . $5.29 $6.25 $5.36
Sales volumes (Mbbls per day) . . . . . . 291 231<F1> 140
[FN]
<F1> Revised for 1995 to include sales volumes related to certain refining
and marketing trading activities previously classified as a reduction
of cost of sales.
The Company sells refined products under term contracts as well as on
a spot and truck rack basis. A truck rack sale is a sale to a customer that
provides trucks to take delivery at loading facilities. In 1996, term, spot
and truck rack sales volumes accounted for approximately 35%, 49% and 16%,
respectively, of total gasoline and distillate sales. Sales of refined
products under term contracts are made principally to large oil companies.
Spot sales of the Company's refined products are made to large oil companies
and gasoline distributors. The principal purchasers of the Company's
products from truck racks have been wholesalers and jobbers in the eastern
and midwestern United States. The Company's products are transported
through common-carrier pipelines, barges and tankers. Interconnects with
common-carrier pipelines give the Company the flexibility to sell products
to the northeastern, midwestern or southeastern United States.
The Company plans to continue to produce a high percentage of its
refined products as RFG and focus marketing efforts on the RFG and oxygenate
markets. Approximately 50% of the Company's RFG production is under
contract to supply wholesale gasoline marketers in Texas at market-related
prices; another 17% is under contract to gasoline marketers in the northeast
United States, which is currently the largest RFG market in the United
States. In 1996, the Company also supplied approximately 1.5 million
barrels of "CARB II" gasoline in the West Coast markets in connection with
the commencement of the California Air Resources Board's gasoline program.
See "Refining and Marketing - Factors Affecting Operating Results."
Feedstock Supply
The predominant feedstock for the Refinery is resid produced at
refineries outside the United States. Most of the large refineries in the
United States are able to convert internally produced resid into higher
value end-products. Many overseas refineries, however, are less
sophisticated, process smaller portions of resid internally, and therefore
produce larger volumes of resid for sale. As a result, the Company acquires
and expects to acquire most of its resid in international markets. These
supplies are loaded aboard chartered vessels and are subject to the usual
maritime hazards. The Company maintains insurance on its feedstock cargos.
The Company has entered into several term agreements for the supply
of approximately 58,000 barrels per day of resid feedstocks at market-
related prices which provide for approximately 70% of the Company's
estimated resid feedstock requirements for 1997. These supply agreements
include an agreement with the Saudi Arabian Oil Company to provide an
average of 36,000 barrels per day of A960 resid from its Ras Tanura refinery
to the Company through mid-1998. The Company believes that if any of its
existing feedstock arrangements were interrupted or terminated, supplies of
resid could be obtained from other sources or on the open market; however,
the Company could be required to incur higher feedstock costs or substitute
other types of resid, thereby producing less favorable operating results.
Over the past few years, demand for the type of resid feedstock now
processed at the Refinery has increased in relation to the availability of
supply. See "Refining and Marketing - Factors Affecting Operating Results."
The Company also recently entered into term contracts for the supply of
crude oil feedstocks for the Refinery's crude unit, including a contract for
approximately 22,000 barrels per day of Daqing sweet crude oil for the first
six months of 1997, and a contract for approximately 8,000 barrels per day
of domestically produced crude extending through 1997. The remainder of the
Refinery's resid and crude feedstocks are purchased at market-based prices
under short-term contracts.
All of the butane and methanol feedstocks required to operate the
MTBE Plant are available through the Company's operations. The Company also
supplies at least one-half of the Methanol Plant's natural gas feedstock
requirements.
The Company owns refining feedstock and product storage facilities
with a capacity of approximately 6.9 million barrels. Approximately
4.4 million barrels of storage capacity are heated tanks for heavy
feedstocks. The Company also leases fuel oil and refined product storage
facilities in various locations, including approximately 600,000 barrels
of gasoline storage in the Houston area. See Note 14 of Notes to
Consolidated Financial Statements. The Company also owns dock facilities
at the Refinery that can unload simultaneously two 150,000 dead-weight ton
capacity ships and can dock larger crude carriers after partial unloading.
Factors Affecting Operating Results
The Company's refining and marketing operating results are affected
by the relationship between refined product prices and resid prices, which
in turn are largely determined by market forces. The price of resid is
affected by the relationship between the growth in the demand for fuel oil
and other products (which increases crude oil demand, thereby increasing the
supply of resid when more crude oil is processed) and worldwide additions to
resid conversion capacity (which has the effect of reducing the available
supply of resid). The crude oil and refined products 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.
Because the Refinery is more complex than many conventional
refineries, and is designed principally to process resid rather than crude
oil, its operating costs per barrel are generally higher than those of most
conventional refineries. But because resid usually sells at a large enough
discount to crude oil, the Company is generally able to recover its higher
operating costs and generate higher margins than many conventional refiners
that use crude oil as their principal feedstock. Moreover, through recent
technology improvements, the Refinery has improved its ability to process
different types of feedstocks, including synthetic domestic heavy oil blends
that have been successfully processed in the HDS Unit.
Saudi Arabian Oil Company has advised the Company that it plans to
begin operation of certain new resid conversion units in 1998 at the Ras
Tanura refining complex in Saudi Arabia. As a result, the production of
resid at Ras Tanura for export is expected to be significantly reduced. The
resid feedstock purchased by the Company from Saudi Arabian Oil Company is
produced at Ras Tanura. Accordingly, a reduction in resid production at Ras
Tanura could adversely affect the price or availability of resid feedstocks
in the future. The Company expects resid to continue to sell at a discount
to crude oil, but is unable to predict future relationships between the
supply of and demand for resid. Installation of additional refinery crude
distillation and upgrading facilities, price volatility, international
political developments and other factors beyond the control of the Company
are likely to continue to play an important role in refining industry
economics.
Because the Refinery is able to manufacture all of its gasoline as
RFG and can produce approximately 22,500 barrels per day of total
oxygenates, certain federal and state clean-fuels programs significantly
affect the operations of the Company and the markets in which the Company
sells its refined products. First, the EPA's oxygenated fuel program under
the Clean Air Act Amendments of 1990 (the "Clean Air Act") requires for
certain winter months that areas designated nonattainment for carbon
monoxide use gasoline that contains a prescribed amount of clean burning
oxygenates.<F2> Second, the EPA's RFG program under the Clean Air Act is
required in areas designated "extreme" or "severe" nonattainment for ozone.
In addition to these nonattainment areas, approximately 43 of the 87 areas
that were designated as "serious," "moderate," or "marginal" nonattainment
for ozone also "opted in" to the RFG program to decrease their emissions of
hydrocarbons and toxic pollutants.<F3> In 1996, California adopted a
state-wide, year-round program requiring the use of gasoline that meets more
restrictive emissions specifications than the federally mandated RFG. Under
the California gasoline program, areas not subject to either the federal
oxygenated fuels program or the federal RFG program may use between zero and
2.7 percent oxygen by weight in their gasoline (sometimes known as "CARB II"
gasoline) so long as the gasoline meets the California emissions standards.
[FN]
<F2> Oxygenates are liquid hydrocarbon compounds containing oxygen.
Gasoline that contains oxygenates usually has lower carbon monoxide
emissions than conventional gasoline. The Clean Air Act and certain
state laws require oxygenated gasoline to have a minimum oxygen
content of 2.7 percent by weight. As of September 1996, only 31 of
the original 42 areas designated as nonattainment for carbon monoxide
remain designated as nonattainment. As areas have come into
"attainment," they generally have left the oxygenated fuels program.
However, Minnesota elected to use oxygenated gasoline statewide and
year-round beginning in 1997, and other states are considering
similar requirements.
<F3> The use of RFG reduces the emissions of ozone-forming compounds,
carbon monoxide and air toxics such as benzene. RFG is manufactured
in compliance with the EPA's "simple model" (i) by substantially
reducing the amount of aromatics and benzene from gasoline, (ii) by
adding an oxygenate (primarily MTBE or ethanol), and (iii) by
reducing the vapor pressure of the gasoline during summer months.
The oxygen content of RFG must average at least 2.1 percent by
weight over the yearly reporting period. The benzene content must
average less than 0.95 percent by volume over the yearly reporting
period. The governor of Arizona recently petitioned the EPA to
"opt-in" the Phoenix area into the RFG program. In 1998, RFG will
be certified using the EPA's "complex model" which will evaluate a
gasoline based on its overall quality and emissions performance
rather than solely on discrete parameters.
MTBE margins are affected by the price of the MTBE and its
feedstocks, methanol and butane, as well as the demand for RFG, oxygenated
gasoline, and premium gasoline. The worldwide movement to reduce lead in
gasoline is expected to increase worldwide demand for oxygenates to replace
the octane provided by lead-based compounds. The general United States
growth in gasoline demand as well as additional "opt-ins" by certain areas
into the EPA clean fuels programs are expected to continue to grow the
demand for MTBE.
NATURAL GAS RELATED SERVICES
The Company's natural gas related services business<F4> is a
midstream natural gas business offering value-added services and products to
producers and end-users throughout North America. The Company owns and
operates natural gas pipeline systems serving Texas intrastate markets, and
the Company markets natural gas throughout North America through
interconnections with interstate pipelines. The Company's natural gas
pipeline and marketing operations consist principally of gathering,
processing, storage and transportation of natural gas, and the marketing of
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 also owns and
operates eight gas processing plants and is a major producer and marketer of
NGLs. The Company's NGL operations include the gathering of natural gas,
the extraction of NGLs from natural gas, the fractionation of mixed NGLs
into component products (e.g., ethane, propane, butane, natural gasoline),
and the transportation and marketing of NGLs. Through its natural gas
related services business, the Company also markets electric power and
engages in price-risk management activities to complement and enhance its
merchant business.
[FN]
<F4> These operations are conducted primarily through Valero Natural Gas
Partners, L.P. ("VNGP, L.P.") and its subsidiaries (the
"Partnership"). These operations were acquired in connection with
the 1994 merger described in Note 3 of Notes to Consolidated
Financial Statements. For a discussion of the Company's method of
accounting for its investment in the Partnership, see Note 1 of Notes
to Consolidated Financial Statements. For comparability purposes,
the information and statistics presented in this Part I for 1994
reflect the consolidation of the Partnership with Energy for all of
such year on a pro forma basis.
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 7,500 miles of mainlines,
lateral lines and gathering lines. The Transmission System is located
primarily along the Texas Gulf Coast and throughout South Texas and is
positioned to access most of the major producing and consuming regions in
the United States. The Transmission System extends westerly to near Pecos,
Texas; northerly to near the Dallas-Fort Worth area; easterly to Carthage,
Texas, near the Louisiana border; and southerly into Mexico near Reynosa.
The Transmission System includes 39 mainline compressor stations with a
total of approximately 181,000 horsepower, together with gas processing
plants, dehydration and gas treating plants and numerous measuring and
regulating stations. The Transmission System is able to handle widely
varying loads caused by changing supply and demand patterns. The Trans-
mission System also supports the power generation grid in Texas, providing
opportunities to trade these markets using gas and power interchangeably.
The Transmission System's average annual throughput<F5> was approximately
2.8 Bcf<F6> per day in 1996. The Company's owned and leased pipeline systems
have 74 interconnects with 21 intrastate pipelines, 43 interconnects with
14 interstate pipelines, and one interconnect with Pemex in South Texas.
[FN]
<F5> This amount includes gas sales and transportation volumes through the
Transmission System in 1996, and does not include off-system sales of
approximately 0.6 Bcf per day.
<F6> Mcf (thousand cubic feet) is a standard unit for measuring natural
gas volumes at a pressure base of 14.65 pounds per square inch
absolute and at 60 degrees Fahrenheit. The term "MMcf" means million
cubic feet, and the term "Bcf" means billion cubic feet. The term
"Btu" means British Thermal Unit, a standard measure of heating
value. The number of MMBtu's of total natural gas deliveries is
approximately equal to the number of Mcf's of such deliveries. The
terms MMBtu, BBtu and TBtu mean million Btu's, billion Btu's, and
trillion Btu's, respectively.
Sales and Marketing
The following table sets forth the Company's gas sales volumes and
average gas sales prices for the three years ended December 31, 1996.
Year Ended December 31,
1996 1995 1994
Intrastate sales (MMcf per day) . . 700 656 633
Interstate sales (MMcf per day) . . 993 773 506
Total . . . . . . . . . . . . 1,693 1,429 1,139
Average gas sales price per Mcf . . $2.55 $1.74 $2.07
Sales of natural gas accounted for approximately 50%, 50% and 45% of
the Company's total daily gas volumes for 1996, 1995 and 1994, 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 1996, the Company sold
natural gas under hundreds of separate short- and long-term gas sales
contracts. Total gas sales volumes made by the Company increased 77% over a
four-year period from approximately 957 MMcf per day in 1992 to 1,693 MMcf
per day in 1996. The Company's off-system marketing business, which
increased from 70 MMcf per day of sales in 1992 to 599 MMcf per day in 1996,
was a large contributor to this increase.
The Company's gas sales are made primarily to gas distribution
companies, electric utilities, gas marketers, other pipeline companies and
industrial users. The Company's gas sales contracts with its intrastate
customers generally require the Company to provide a fixed and determinable
quantity of gas; however, certain gas sales contracts with intrastate
customers provide for either maximum volumes or total customer requirements.
The gas sold to local distribution companies ("LDCs") is resold to consumers
in a number of cities including San Antonio, Dallas, Austin, Corpus Christi
and Chicago. The Company continues to emphasize diversification of its
customer base through interstate sales. By the end of 1996, the Company had
secured contracts to provide gas supply and swing services to certain LDCs,
electric utilities and industrial customers primarily in the midwest,
northwest and western United States providing for deliveries of up to
approximately 815 MMcf per day with terms ranging from one to three years.
The Company has marketing offices located throughout Texas as well as
in Los Angeles, Chicago, Louisville and Calgary, and offers a broad range of
marketing and gas related services.
- The Company's Market Center Services Program ("Market
Center"), provides pricing and price-risk management services to both
gas producers and end users. The Market Center uses financial
instruments such as futures, swaps and options to manage the price-
risk exposure within the Company, and to offer customized pricing
arrangements with both the Company's suppliers and its customers.
Activities of the Market Center have improved the Company's ability
to capture and optimize gas transportation, storage and sales
margins, as well as manage gas price volatility for the Company's gas
processing business. See Note 6 of Notes to Consolidated Financial
Statements.
- In 1996, the Company formed its Midwest Retail Natural Gas
Marketing Group to provide natural gas and related services to
industrial and commercial customers in the greater Chicago area.
This retail marketing group expands and complements the Company's
wholesale gas marketing and power marketing businesses.
- The Company operates the Waha Hub in West Texas. The Waha Hub
serves as the designated delivery point for the Streamline electronic
trading system and the futures contracts offered by the Kansas City
Board of Trade.
- "Velocity," the Company's intrastate electronic bulletin
board, was introduced to customers in November 1995. Velocity is
designed to improve communications between the Company and its
customers and to enable customers to monitor and control their
natural gas volumes in a more timely manner.
- Valero Field Services Company was established in 1995 to
provide gas gathering, compression, dehydration and treating services
around the Transmission System and in those areas that are complemen-
tary to the Company's anticipated growth. The field services unit
seeks to build and diversify the Company's gas supply portfolio and
create synergistic opportunities with the Company's other gas
businesses.
- In 1995, the Company expanded its marketing business into the
electricity market. See "Natural Gas Related Services - Electric
Power."
Transportation
The following table sets forth the Company's gas transportation
volumes and average transportation fees for the three years ended
December 31, 1996.
Year Ended December 31,
1996 1995 1994
Transportation volumes (MMcf per day). . 1,665 1,430 1,398
Average transportation fee per Mcf . . . $.089 $.094 $.102
Gas transportation and exchange transactions (collectively referred
to as "transportation") accounted for approximately 50%, 50% and 55% of the
Company's total daily gas volumes for 1996, 1995 and 1994, respectively.
The Company's natural gas operations have been positively affected by an
emerging trend of west-to-east movement of gas across the United States
caused by increased production in western supply basins, the pipeline
expansions from Canada and the Rocky Mountains and increasing demand for
power generation in the East and Southeast. Transportation rates are often
higher on eastbound transmission than on east-to-west transmission. The
Company transports gas for third parties under hundreds of long-term,
short-term and spot 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.
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.
During 1996, the Company purchased natural gas under hundreds of
separate contracts. A majority of the Company's gas supplies are obtained
from sources with multiple connections, and the Company frequently competes
on a monthly basis for available gas supplies. The Company's ability to
process natural gas attracts significant gas supplies to the Transmission
System. In 1996, the Company secured approximately 480 MMcf per day of
natural gas supplies from natural gas producers under agreements to process,
transport or purchase their natural gas for terms ranging generally from one
to seven years. Because of the extensive coverage of the Transmission
System, 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 approxi-
mately 7.2 Bcf of gas available for withdrawal. Natural gas can be
continuously withdrawn from the facility at initial rates of up to approxi-
mately 850 MMcf per day. The facility has the ability to inject gas at
initial rates of approximately 360 MMcf per day. The Company supplemented
its own natural gas storage capacity by leasing during 1996 an additional
6.8 Bcf of third-party storage capacity for the 1996-97 winter heating
season.
Natural Gas Liquids
The Company's NGL operations provide strong integration among the
Company's core businesses. The Company's ability to process natural gas is
a value-added service offered to producers and attracts additional
quantities of gas throughput to the Transmission System. The principal
source of gas for processing is from the Transmission System. Production
from the Company's NGL plants provides butane feedstocks for the production
of oxygenates (primarily MTBE) at the Refinery.
The Company's NGL production for 1996 was approximately 29.6 million
barrels, averaging 80,900 barrels per day. The 1996 NGL production
represents the Company's seventh consecutive year for record production
volumes. The Company sold two of its gas processing plants in West Texas
effective August 1, 1995. Processing capacity lost by the sale of these
plants was more than offset, however, by significant expansions and
upgrading projects completed at certain of the Company's other plants. The
table below sets forth production volumes, average NGL market prices, and
average gas costs related to the Company's NGL plant production for the
three years ended December 31, 1996.
Year Ended December 31,
1996 1995 1994
NGL plant production (Mbbls per day) . 80.9 80.3 79.5
Average market price per gallon<F7>. . $.354 $.258 $.265
Average gas cost per Mcf . . . . . . . $1.93 $1.40 $1.75
[FN]
<F7> Represents the average Houston area market prices, net of certain
location differentials, for individual NGL products weighted by
relative volumes of each product produced.
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. The Company's
primary markets for NGLs are petrochemical plants and refineries. 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 1996, approximately 83% of the Company's
butane production was used as a feedstock for the Refinery's MTBE Plant.
The Company's gas processing plants are located primarily in South
Texas and process approximately 1.4 Bcf of gas per day. Each of the
Company's plants is situated along the Transmission System. The Company
also owns and operates approximately 510 miles (350 miles of which are
located in South Texas) of NGL pipelines and fractionation facilities at
three locations including a facility in the Corpus Christi area. The
Company fractionated an average of 83,000 barrels per day in 1996, including
all of the NGL output from its processing plants, except for one.
Approximately 9% of these volumes represented NGLs fractionated for third
parties. In South Texas, the Company gathers NGLs from five of its
processing plants and transports these NGLs through its own pipelines to its
fractionation facilities in the Corpus Christi area. The Company's
remaining NGL pipelines are used to deliver NGLs to end-users and major
common-carrier NGL pipelines, which ultimately deliver NGLs to their
principal markets.
The Company sells NGLs that have been extracted, transported and
fractionated in the Company's facilities as well as 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
petrochemical industry represents an expanding principal market for NGLs due
to increasing market demand for ethylene-derived products. Petrochemical
demand for NGLs is projected to remain strong through 1997 with the
announcement of several expansions to existing petrochemical facilities
and the start-up of new ethylene plants along the Texas Gulf Coast in the
next few years. A majority of this incremental capacity is projected to be
built by independent petro-chemical companies with little affiliated NGL
production, which may improve market liquidity for NGLs and create market
opportunities for major NGL producers. However, planned facilities
additions may be delayed or canceled, and no assurances can be given that
the proposed petrochemical facilities will be completed.
Electric Power
Deregulation of the electric utility and power industry also offers
new opportunities for natural gas companies. In 1995, the Company formed
Valero Power Services Company to provide risk management and marketing
services to the electric power industry. The Company offers to wholesale
customers hourly, daily and monthly energy trading services, transmission
services, emissions allowances, generation capacity transactions including
fuel-to-energy conversions, and fuel-to-energy swaps. In addition,
wholesale customers are offered an array of risk management tools for
managing their costs and reliability associated with power procurement. The
Company's initial power marketing efforts are concentrated in the central
United States. Valero Power Services Company is a member of the Western
Systems Power Pool, the Southwest Power Pool, the Electric Reliability
Council of Texas, the Mid-Continent Area Power Pool, the Southeastern
Electric Reliability Council and the Mid-America Interconnected Network.
The Company began trading power in January 1996, and marketed approximately
2 million megawatt hours during 1996.
GOVERNMENTAL REGULATIONS
Federal Regulation
The Company's operations are subject to numerous federal and state
environmental statutes and regulations. See "Environmental Matters." The
Company's pipeline system is an intrastate business not subject to direct
regulation by the Federal Energy Regulatory Commission ("FERC"). Although
the Company's interstate gas sales and transportation activities are subject
to specific FERC regulations, these regulations do not change the Company's
overall regulatory status. FERC Order No. 636 ("Order 636") effectively
transformed the interstate gas industry into a service-oriented business
with natural gas and transportation trading as separate commodities.
Because of Order 636, local distribution companies ("LDCs") and power
generation companies are responsible for acquiring their own gas supplies,
including managing their needs for swing, transportation and storage
services. 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. 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,
the Company can more effectively compete for sales of natural gas to LDCs
and other customers outside Texas.
Texas Regulation
The Railroad Commission of Texas ("RRC") regulates the intrastate
transportation, sale, delivery and pricing of natural gas in Texas by
intrastate pipeline and distribution systems, including those of the
Company. The RRC's gas proration rule requires purchasers to take gas by
priority categories, ratably among producers without undue discrimination,
with high-priority gas (gas from wells primarily producing oil and certain
special allowable gas) having higher priority than gas well gas (gas from
wells primarily producing gas), notwithstanding any contractual commitments.
The RRC rules are intended to bring production allowables in line with
estimated market demand. For pipelines, the RRC approves intrastate sales
and transportation rates and all proposed changes to such rates. Under
applicable statutes and current RRC practice, however, larger volume
industrial sales and transportation charges may be changed without a rate
case before the RRC if the parties to the transactions agree to the rate
changes. Currently, the price of natural gas sold under a majority of the
Company's gas sales contracts is not regulated by the RRC, and the Company
may generally enter into any sales contract that it is able to negotiate
with customers. NGL pipeline transportation is also subject to regulation
by the RRC through the filing of tariffs and compliance with safety
standards. To date, the impact of this regulation on the Company's
operations has not been significant.
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. It obtains all of its resid feedstock from unaffiliated
sources. Many of the Company's competitors 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 (and brand-name recognition) 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 or feedstock shortages.
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 should be
able to comply with the Clean Air Act and future environmental legislation
more easily than older refineries, and will not be required to spend
significant additional capital for environmental compliance. In 1996, the
Corpus Christi area was approved as a "flexible attainment region" ("FAR")
by the EPA and the Texas Natural Resource Conservation Commission ("TNRCC").
Under the Clean Air Act, the FAR designation will allow local officials to
design and implement an ozone prevention strategy customized for the
community. This designation also prevents the EPA from designating the
Corpus Christi area as "nonattainment" for a five-year period while
agreed-upon control strategies are being initiated to reduce
ozone formation. The FAR designation should provide greater flexibility
to the Company with respect to future expansion projects at the Refinery.
The Company produces enough oxygenates to blend all of its gasoline
as RFG and to sell additional quantities of oxygenates to third parties who
require oxygenates for blending. RFG generally sells at a premium over
conventional gasoline. Most of the refining industry uses the conventional
"3-2-1 crack spread" (which assumes the input of three parts of West Texas
Intermediate crude oil and the output of two parts gasoline and one part
diesel) as an approximation for gross margins; however, the Company produces
premium products such as RFG and low-sulfur diesel and also produces a
higher percentage of its refined products as gasoline. Thus, the Company's
"85-15 clean fuels crack spread" (85% RFG, 15% low-sulfur diesel) has
provided a wider margin than the typical crack spread experienced by a
conventional refiner.
Natural Gas Related Services
The natural gas industry is expected to remain highly competitive
with respect to both gas supply and markets. Changes in the gas markets
during recent periods of deregulation have significantly increased
competition. However, the Company has not only maintained but has increased
its throughput volumes since implementation of Order 636. Because of
Order 636, the Company now can guarantee long-term supplies of natural gas
to be delivered to buyers at interstate locations. See "Governmental
Regulations - Federal Regulation." The Transmission System has considerable
flexibility in providing connections between many producing and consuming
areas and is able to handle widely varying loads caused by changing supply
and demand patterns. The Transmission System is well positioned to provide
swing services both in and outside Texas because of its proximity to supply
and its numerous interconnections with other pipeline systems. See "Natural
Gas Related Services - Transmission System."
In recent years, certain of the Company's intrastate pipeline
competitors have acquired or have been acquired by interstate pipelines.
These combined entities generally have capital resources substantially
greater than those of the Company and, notwithstanding Order 636's "open
access" regulations, may realize economies of scale and other economic
advantages in acquiring, selling and transporting natural gas.
Additionally, the combination of intrastate and interstate pipelines within
one organization may in some instances enable competitors to lower gas
prices and transportation fees, and thereby increase price competition in
the Company's intrastate and interstate markets. Consequently, the
Company's competitors in the near future are likely to be a smaller number
of larger energy service firms that can offer "one-stop shopping" for the
customer's energy needs, whether the needs are physical, managerial, or
financial for the respective energy commodity.
The economics of natural gas processing depends principally on the
relationship between natural gas costs and NGL prices. When this
relationship is favorable, the NGL processing business is 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. The Company believes
that the level of competition in NGL processing has increased over the past
years 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. Moreover, the Company's NGL production and
marketing operations complement its natural gas related services, enabling
the Company to provide integrated processing, transportation, and marketing
solutions to its producer clients, giving the Company a competitive
advantage over NGL marketers and transporters that lack such capability.
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 TNRCC and the RRC. The regulatory requirements relate
primarily to water and storm water discharges, waste management and air
pollution control measures. In 1996, capital expenditures for the Company's
refining operations attributable to compliance with environmental
regulations were approximately $5 million and are currently estimated to be
$7 million for 1997. These amounts are exclusive of any amounts related to
constructed facilities for which the portion of expenditures relating to
compliance with environmental regulations is not determinable. For a
discussion of the effects of the Clean Air Act's oxygenated gasoline and RFG
programs on the Company's refining operations, see "Refining and Marketing -
Factors Affecting Operating Results."
The Company's capital expenditures for environmental control
facilities related to its natural gas related services operations were not
material in 1996 and are not expected to be material in 1997. Currently,
expenditures are made to comply with regulations for air emissions, solid
waste management and waste water applicable to various facilities. In 1991,
environmental legislation was passed in Texas that conformed Texas law with
the Clean Air Act to allow Texas to administer the federal programs. The
EPA granted interim approval of the Texas Title V operating permit program
in mid-1996, and many of the Company's gas processing plants and gas
pipeline facilities became subject to requirements for submitting
applications to the TNRCC for new operating permits. As required by
applicable regulations, permit applications for 10% of the Company's gas
processing plants and gas pipeline facilities that are subject to the
regulations were filed in January 1997, with the balance to be filed in July
1997. Although proposed monitoring requirements may increase operating
costs, they are not expected to have a material adverse effect on the
Company's operations or financial condition.
EMPLOYEES
As of January 31, 1997, the Company had 1,673 employees.
<PAGE>
ITEM 2. PROPERTIES
The Company's properties include a petroleum refinery and related
facilities, eight natural gas processing plants, and various natural gas and
NGL pipelines, gathering lines, fractionation facilities, compressor
stations, treating plants and related facilities, all located in Texas.
Substantially all of the Company's refining fixed assets are pledged as
security under deeds of trust securing industrial revenue bonds issued on
behalf of Valero Refining and Marketing Company. Substantially all of the
Company's gas systems and processing facilities are pledged as collateral
for the First Mortgage Notes of Valero Management Partnership, L.P. See
Note 5 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 14 of Notes to Consolidated Financial Statements.
ITEM 3. LEGAL PROCEEDINGS
Franchise Fee Litigation. City of Edinburg v. Rio Grande Valley Gas
Company, Valero Energy Corporation, Southern Union Company, et al., 92nd
State District Court, Hidalgo County, Texas (filed August 31, 1995). The
Company and Southern Union Company ("Southern Union") are defendants in a
lawsuit brought by the City of Edinburg, Texas (the "City") regarding
certain ordinances of the City that granted franchises to Rio Grande Valley
Gas Company ("RGV") and its predecessors allowing RGV to sell and distribute
natural gas within the City. On September 30, 1993, Energy sold the common
stock of RGV to Southern Union. The City alleges that the defendants used
RGV's facilities to sell or transport natural gas in Edinburg in violation
of the ordinances and franchises granted by the City, and that RGV (now
Southern Union) has not fully paid all franchise fees due the City. The
City also alleges that the defendants used the public property of the City
without compensating the City for such use, and alleges conspiracy and alter
ego claims involving all defendants. The City seeks alleged actual damages
of $50 million and unspecified punitive damages related to amounts allegedly
due under the RGV franchise, City ordinances and state law. In addition,
the City of Pharr, Texas, filed an intervention seeking certification of a
class, with itself as class representative, consisting of all cities served
by franchise by Southern Union. The court certified the class and severed
the claims of the City of Pharr and the class from the original City of
Edinburg lawsuit. The City of Pharr subsequently amended its petition
deleting all Valero entities as defendants. The original trial judge was
disqualified upon motion of the defendants (such disqualification was upheld
on appeal), and a new trial judge has been assigned to preside over both the
City of Edinburg and City of Pharr litigation. The City of Edinburg lawsuit
is scheduled for trial on August 11, 1997. In 1996, the South Texas cities
of Alton and Donna also independently intervened as plaintiffs in the
Edinburg lawsuit filed in the 92nd State District Court in Hidalgo County.
These lawsuits subsequently were severed from the Edinburg lawsuit. The
claims asserted by the cities of Alton and Donna are substantially similar
to the Edinburg litigation claims. Damages are not quantified.
Southern Union Cross-Claim. In connection with the City of
Edinburg lawsuit, Southern Union filed a cross-claim against Energy,
alleging, among other things, that Southern Union is entitled to
indemnification pursuant to the purchase agreement under which Energy sold
RGV to Southern Union. Southern Union also asserts claims related to a 1985
settlement among Energy, RGV and the Railroad Commission of Texas regarding
certain gas contract pricing terms. This pricing claim was recently severed
into a separate lawsuit. Southern Union's claims include, among other
things, damages for indemnification, breach of contract, negligent misrepre-
sentation and fraud.
Newly Filed Franchise Fee Litigation. City of La Joya v. Rio
Grande Valley Gas Company, Valero Energy Corporation, Southern Union
Company, et al., 92nd State District Court, Hidalgo County, Texas (filed
December 27, 1996). City of San Benito, City of Primera, and City of Port
Isabel v. Rio Grande Valley Gas Company, Valero Energy Corporation, Southern
Union Company, et al., 107th State District Court, Cameron County, Texas
(filed December 31, 1996). City of San Juan, City of La Villa, City of
Penitas, City of Edcouch, and City of Palmview v. Rio Grande Valley Gas
Company, Valero Energy Corporation, Southern Union Company, et al., 93rd
State District Court, Hidalgo County, Texas (filed December 27, 1996).
Three additional lawsuits were filed in South Texas during December 1996
making allegations substantially similar to those in the City of Edinburg
litigation. The City of La Joya lawsuit was brought as a class action on
behalf of the City of La Joya and all similarly situated cities having
ordinances or agreements with the defendants. In these three lawsuits, the
defendants are alleged to have excluded certain revenues from their
calculations of franchise taxes and are alleged to have provided
unauthorized gas transportation services to third parties. Plaintiffs seek
actual and exemplary, but as yet unspecified, damages.
J.M. Davidson, Inc. v. Valero Energy Corporation; Valero
Hydrocarbons, L.P.; et al., transferred to the 49th State District Court,
Webb County, Texas (originally filed January 21, 1993 in Duval County).
This lawsuit is based upon construction work performed by the plaintiff at
one of the Company's gas processing plants in 1991 and 1992. The plaintiff
alleges that it performed work for the defendants for which it was not
compensated. The plaintiff asserts claims for breach of contract, quantum
meruit, and numerous other contract and tort claims. The plaintiff seeks
actual damages, on each of its causes of action, of approximately
$1.25 million and punitive damages of at least four times the amount of
actual damages. No trial date has been set.
The Long Trusts v. Tejas Gas Corporation; Valero Transmission, L.P.;
et al., 123rd Judicial District Court, Panola County, Texas (filed March 1,
1989). On April 15, 1994, certain trusts (the "Long Trusts") named certain
subsidiaries of the Company as additional defendants (the "Valero
Defendants") to a lawsuit filed in 1989 by the Long Trusts against Tejas Gas
Corporation ("Tejas"), a supplier with whom the Valero Defendants have
contractual relationships under gas purchase contracts. To resolve certain
potential disputes with respect to the gas purchase contracts, the Valero
Defendants agreed to bear a substantial portion of any settlement or
nonappealable final judgment rendered against Tejas. In January 1993, the
District Court ruled in favor of the Long Trusts' motion for summary
judgment against Tejas. Damages, if any, were not determined. The Long
Trusts seek $50 million in damages from the Company as a result of the
Valero Defendants' alleged interference between the Long Trusts and Tejas,
plus punitive damages in excess of treble the amount of actual damages
proven at trial. The Long Trusts also seek approximately $56 million in
take-or-pay damages from Tejas, and $70 million as damages for Tejas's
failure to take the Long Trusts' gas ratably. 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. No trial date has been set.
Mizel v. Valero Energy Corporation, Valero Natural Gas Company, and
Valero Natural Gas Partners, L.P., removed to the United States District
Court for the Western District of Texas (originally filed May 1, 1995 in the
United States District Court for the Southern District of California). This
is a federal securities fraud lawsuit filed by a former owner of limited
partnership interests of VNGP, L.P. Plaintiff alleges that the proxy
statement used in connection with the solicitation of votes for approval of
the merger of VNGP, L.P. with the Company contained fraudulent misrepresen-
tations. Plaintiff also alleges breach of fiduciary duty in connection with
the merger transaction. The subject matter of this lawsuit was the subject
matter of a prior Delaware class action lawsuit which was settled prior to
consummation of the merger. The Company believes that plaintiff's claims
have been settled and released by the prior class action settlement.
Pending in the district court is the memorandum issued by the magistrate
assigned to the case which recommends approval of the defendants' motion for
summary judgment.
Teco Pipeline Company v. Valero Energy Corporation, et al., 215th
State District Court, Harris County, Texas (filed April 24, 1996). Energy
and certain of its subsidiaries have been sued by Teco Pipeline Company
("Teco") regarding the operation of the Company's 340-mile West Texas
pipeline. In 1985, a subsidiary of Energy sold a 50% undivided interest in
the pipeline and entered into a joint venture through an ownership agreement
and an operating agreement, each dated February 28, 1985, with the purchaser
of the interest. In 1988, Teco succeeded to that purchaser's 50% interest.
A subsidiary of Energy has at all times been the operator of the pipeline.
Notwithstanding the written ownership and operating agreements, the
plaintiff alleges that a separate, unwritten partnership agreement exists,
and that the defendants have exercised improper dominion over such alleged
partnership's affairs. The plaintiff also alleges that the defendants acted
in bad faith by negatively affecting the economics of the joint venture in
order to provide financial advantages to facilities or entities owned by the
defendants and by allegedly usurping for the defendants' own benefit certain
opportunities available to the joint venture. The plaintiff asserts causes
of action for breach of fiduciary duty, fraud, tortious interference with
business relationships, and other claims, and seeks unquantified actual and
punitive damages. The Company's motion to compel arbitration was denied,
but has been appealed. The Company has filed a counterclaim alleging that
the plaintiff breached its own obligations to the joint venture and
jeopardized the economic and operational viability of the pipeline by its
actions. The Company is seeking unquantified actual and punitive damages.
Sinco Pipeline Rupture Litigation. Adams, et al. v. Colonial
Pipeline Company; Valero Transmission, L.P.; et al., 157th State District
Court, Harris County, Texas (filed August 31, 1995). Aldridge, et al. v.
Colonial Pipeline Company, Valero Management Company, et al., 295th State
District Court, Harris County, Texas (filed October 18, 1996). American
Plant Food Corporation, et al., v. Colonial Pipeline Company; Texaco, Inc.;
Valero Energy Corporation; et al., 80th State District Court, Harris County,
Texas (filed June 1, 1995). Anderson, et al. v. Colonial Pipeline Company,
Valero Management Company, et al., 113th State District Court, Harris
County, Texas (filed October 17, 1996). Barr, et al. v. Colonial Pipeline
Company, Valero Transmission, L.P., et al., 334th State District Court,
Harris County, Texas (filed October 18, 1996). Benavides, et al. v.
Colonial Pipeline Company; Valero Transmission, L.P.; et al., 93rd State
District Court, Hidalgo County, Texas (filed August 31, 1995). Brackett, et
al. v. Colonial Pipeline Company, Valero Transmission, L.P., et al., 11th
State District Court, Harris County, Texas (filed October 18, 1996).
Brewer, et al. v. Colonial Pipeline Company, Valero Transmission, L.P.,
et al., 133rd State District Court, Harris County, Texas (filed October 18,
1996). Hayward, et al. v. Colonial Pipeline Company, Valero Trans-
mission, L.P., et al., 129th State District Court, Harris County, Texas
(filed October 18, 1996). Hornbeck, et al. v. Colonial Pipeline Company,
Valero Transmission, L.P., et al., 56th State District Court, Galveston
County, Texas (filed October 18, 1996). Johnson, et al. v. Colonial
Pipeline Company, Valero Transmission, L.P., et al., 333rd State District
Court, Harris County, Texas (filed October 18, 1996). Layton, et al. v.
Colonial Pipeline Company, Valero Transmission, L.P., et al., 131st State
District Court, Harris County, Texas (filed October 18, 1996). Navarro,
et al. v. Colonial Pipeline Company, et al., 281st State District Court,
Harris County, Texas (filed November 7, 1994). Durst, et al.
(Intervenors) v. Colonial Pipeline Company, Valero Transmission, L.P.,
et al., 281st State District Court, Harris County, Texas. Flores
(Intervenor) v. Colonial Pipeline Company, Valero Transmission, L.P.,
et al., 281st State District Court, Harris County, Texas. Approximately
15 lawsuits have been filed against various pipeline owners and other
parties, including the Company, in connection with the rupture of several
pipelines and fire as a result of severe flooding of the San Jacinto River
in Harris County, Texas on October 20, 1994. The plaintiffs are property
owners in surrounding areas who allege that the defendant pipeline owners
were negligent and grossly negligent in failing to bury the pipelines at a
proper depth to avoid rupture or explosion and in allowing the pipelines to
leak chemicals and hydrocarbons into the flooded area. The plaintiffs
assert claims for property damage, costs for medical monitoring, personal
injury and nuisance. Plaintiffs seek an unspecified amount of actual and
punitive damages.
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. Javelina Company has been named as a
defendant in ten lawsuits filed since 1993 in state district courts in
Nueces County, and Duval County, Texas. Eight of the suits include as
defendants other companies that own refineries or other industrial
facilities in Nueces County. These suits were brought by a number of
plaintiffs who reside in neighborhoods near the facilities. The plaintiffs
claim injuries relating to alleged exposure to toxic chemicals, and
generally claim that the defendants were negligent, grossly negligent and
committed trespass. The plaintiffs claim personal injury and property
damages resulting from soil and ground water contamination and air pollution
allegedly caused by the operations of the defendants. The plaintiffs seek
an unspecified amount of actual and punitive damages. The remaining two
suits were brought by plaintiffs who either live or have businesses near the
Javelina plant. The plaintiffs in these suits allege claims similar to
those described above and seek unspecified actual and punitive damages.
The Company is also a party to additional claims and legal
proceedings arising in the ordinary course of business. The Company believes
it is unlikely that the final outcome of any of the claims or proceedings to
which the Company is a party, including those described above, would have a
material adverse effect on the Company's financial statements; however, due
to the inherent uncertainty of litigation, the range of possible loss, if
any, cannot be estimated with a reasonable degree of precision and there can
be no assurance that the resolution of any particular claim or proceeding
would not have an adverse effect on the Company's results of operations for
the interim period in which such resolution occurred.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
fourth quarter of 1996.
<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 January 31, 1997, there were approximately 6,240 holders of
record and an estimated 18,000 additional beneficial owners of Energy's
Common Stock.
The range of the high and low sales prices of the Common Stock as
quoted in The Wall Street Journal, New York Stock Exchange-Composite
Transactions listing, and the amount of per-share dividends for each quarter
in the preceding two years, are set forth in the tables shown below:
<TABLE>
<CAPTION>
Common Stock Dividends
1996 1995 Per Common Share
Quarter Ended High Low High Low 1996 1995
<S> <C> <C> <C> <C> <C> <C>
March 31 . . . . . . . $26 1/2 $22 1/8 $18 5/8 $16 $.13 $.13
June 30. . . . . . . . 29 24 1/2 22 7/8 17 3/4 .13 .13
September 30 . . . . . 25 1/2 20 1/4 25 5/8 19 5/8 .13 .13
December 31. . . . . . 30 21 7/8 25 7/8 22 1/2 .13 .13
</TABLE>
The Energy Board of Directors declared a quarterly dividend of $.13
per share of Common Stock at its January 23, 1997 meeting. Dividends are
considered quarterly by the Energy Board of Directors and may be paid only
when approved by the Board.
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The selected financial data set forth below for the year ended
December 31, 1996 is derived from the Company's Consolidated Financial
Statements contained elsewhere herein. The selected financial data for the
years ended prior to December 31, 1996 is derived from the selected
financial data contained in the Company's Annual Report on Form 10-K for the
year ended December 31, 1995 except as noted below.
The following summaries are in thousands of dollars except for per
share amounts:
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994<F1> 1993 1992
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . $4,990,681 $3,197,872<F2> $1,837,440 $1,222,239 $1,234,618
OPERATING INCOME . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 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
NET INCOME . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282<F3> $ 36,424 $ 83,919
Less: Preferred stock dividend
requirements. . . . . . . . . . . . 11,327 11,818 9,490 1,262 1,475
NET INCOME APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . . . $ 61,374 $ 48,020 $ 7,792<F3> $ 35,162 $ 82,444
EARNINGS PER SHARE OF
COMMON STOCK . . . . . . . . . . . . . . . $ 1.40 $ 1.10 $ .18<F3> $ .82 $ 1.94
TOTAL ASSETS . . . . . . . . . . . . . . . . $3,134,774<F3> $2,861,880<F3> $2,816,558<F3> $1,764,437 $1,759,100
LONG-TERM OBLIGATIONS AND
REDEEMABLE PREFERRED STOCK . . . . . . . . $ 869,450 $1,042,541 $1,034,470 $ 499,421 $ 497,308
DIVIDENDS PER SHARE OF COMMON
STOCK. . . . . . . . . . . . . . . . . . . $ .52 $ .52 $ .52 $ .46 $ .42
<FN>
<F1> Reflects the consolidation of the Partnership as of May 31, 1994.
<F2> Revised to include revenues from certain refining and marketing trading activities previously classified
as a reduction of cost of sales.
<F3> Restated to reflect the effects of a prior period adjustment resulting in a charge to 1994 income for an
acquisition expense accrual originally charged to property, plant and equipment. See "Restatement of
Financial Information" in Note 1 of Notes to Consolidated Financial Statements.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
PROPOSED RESTRUCTURING
On January 31, 1997, the Company announced that its Board of
Directors had approved an agreement and plan of merger with PG&E Corporation
("PG&E") to combine the Company's natural gas related services business (see
"Segment Reporting" below) with PG&E following the spin-off of the Company's
refining and marketing business to the Company's shareholders (the
"Restructuring"). The Restructuring was the result of a management
recommendation announced in November 1996 to pursue strategic alternatives
involving the Company's principal business activities. See "Liquidity and
Capital Resources" below and Note 2 of Notes to Consolidated Financial
Statements for additional information about the Restructuring.
SEGMENT REPORTING
Effective January 1, 1996, the Company's natural gas and natural gas
liquids ("NGL") businesses were reported as one industry segment for
financial reporting purposes (described herein as "natural gas related
services") in recognition of the Company's increasing integration of these
business activities due to the restructuring of the interstate natural gas
pipeline industry in 1993 through FERC Order 636 and the resulting
transformation of the U.S. natural gas industry into a more market and
customer-oriented environment. The Company's ability to gather, transport,
market and process natural gas, among other things, are value-added services
offered to producers and attract additional quantities of gas to the
Company's pipeline system and processing plants through integrated business
arrangements. Prior to 1996, the Company's natural gas and NGL businesses
were reported as separate industry segments. The primary effect of this
change on the Company's segment disclosures was the elimination of volume,
revenue and income amounts related to natural gas fuel and shrinkage volumes
sold to and transported for the natural gas liquids segment by the natural
gas segment. The Company's 1995 and 1994 financial and operating highlights
which follow under "Results of Operations," and the discussion of the
Company's natural gas and NGL businesses which follows under "Results of
Operations - 1995 Compared to 1994 - Segment Results," have been revised
from that contained in the Company's Annual Report on Form 10-K for the year
ended December 31, 1995 to reflect this change in segment reporting.
ACQUISITION OF VNGP, L.P.
As described in Note 3 of Notes to Consolidated Financial Statements,
the merger of VNGP, L.P. with Energy was consummated on May 31, 1994. As a
result of such merger, VNGP, L.P. became a subsidiary of Energy. The
accompanying consolidated statements of income of the Company for the years
ended December 31, 1996, 1995 and 1994 reflect the Company's 100% interest
in the Partnership's operations after May 31, 1994 and its effective equity
interest of approximately 49% for all periods prior to and including May 31,
1994. Because 1994 results of operations for the Company's natural gas
related services segment are not comparable to subsequent and prior periods
due to the VNGP, L.P. merger, the discussion of this segment which follows
under "Results of Operations - 1995 Compared to 1994 - Segment Results" is
based on pro forma operating results for 1994 that reflect the consolidation
of the Partnership with Energy for all of such year.
The following discussion contains certain estimates, predictions,
projections and other "forward-looking statements" (within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934) that involve various risks and uncertainties. While
these forward-looking statements, and any assumptions upon which they are
based, are made in good faith and reflect the Company's current judgment
regarding the direction of its business, actual results will almost always
vary, sometimes materially, from any estimates, predictions, projections,
assumptions, or other future performance suggested herein. Some important
factors (but not necessarily all factors) that could affect the Company's
sales volumes, growth strategies, future profitability and operating
results, or that otherwise could cause actual results to differ materially
from those expressed in any forward-looking statement include the following:
renewal or satisfactory replacement of the Company's residual oil ("resid")
feedstock arrangements as well as market, political or other forces
generally affecting the pricing and availability of resid and other refinery
feedstocks, refined products, natural gas supplies or natural gas liquids;
accidents or other unscheduled shutdowns affecting the Company's, its
suppliers' or its customers' pipelines, plants, machinery or equipment;
excess industry capacity; competition from products and services offered by
other energy enterprises; changes in the cost or availability of third-party
vessels, pipelines and other means of transporting feedstocks and products;
state and federal environmental, economic, safety and other policies and
regulations, any changes therein, and any legal or regulatory delays or
other factors beyond the Company's control; execution of planned capital
projects; weather conditions affecting the Company's operations or the areas
in which the Company's products are marketed; adverse rulings, judgments, or
settlements in litigation or other legal matters, including unexpected
environmental remediation costs in excess of any reserves; the introduction
or enactment of legislation, including tax legislation affecting the
proposed merger with PG&E; and adverse changes in the credit ratings
assigned to the Company's debt securities and trade credit. The Company
undertakes no obligation to publicly release the result of any revisions to
any such forward-looking statements that may be made to reflect events or
circumstances after the date hereof or to reflect the occurrence of
unanticipated events.
<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, 1996. For 1995
and 1994, operating revenues and operating income (loss) by segment and
certain natural gas related services operating statistics have been restated
to conform to the 1996 presentation. The amounts in the following table are
in thousands of dollars, unless otherwise noted:
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
OPERATING REVENUES:
Refining and marketing <F1>. . . . . . . . . . . . . . . . . . . . . . . $2,757,801 $1,950,657 $1,090,368
Natural gas related services <F2>. . . . . . . . . . . . . . . . . . . . 2,445,504 1,396,468 784,287
Other <F2> . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 126 42,639
Intersegment eliminations <F2> . . . . . . . . . . . . . . . . . . . . . (212,747) (149,379) (79,854)
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440
OPERATING INCOME (LOSS):
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660
Natural gas related services <F2>. . . . . . . . . . . . . . . . . . . . 132,178 83,180 61,944
Corporate general and administrative expenses and other, net <F2>. . . . (41,315) (35,901) (14,679)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 125,925
Equity in earnings (losses) of and income from:
Valero Natural Gas Partners, L.P. <F3> . . . . . . . . . . . . . . . . . $ - $ - $ (10,698)
Joint ventures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,899 $ 4,827 $ 2,437
Loss on investment in Proesa joint venture . . . . . . . . . . . . . . . . $ (19,549) $ - $ -
(Provision for) reversal of acquisition expense accrual <F5> . . . . . . . $ 18,698 $ (2,506) $ (16,192)
Other income, net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,921 $ 5,248 $ 3,431
Interest and debt expense, net . . . . . . . . . . . . . . . . . . . . . . $ (95,177) $ (101,222) $ (76,921)
Net income <F5>. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282
Net income applicable to common stock <F5> . . . . . . . . . . . . . . . . $ 61,374 $ 48,020 $ 7,792
Earnings per share of common stock <F5>. . . . . . . . . . . . . . . . . . $ 1.40 $ 1.10 $ .18
PRO FORMA OPERATING INCOME (LOSS) <F4>:
Refining and marketing . . . . . . . . . . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660
Natural gas related services . . . . . . . . . . . . . . . . . . . . . . 132,178 83,180 69,769
Corporate general and administrative expenses and other, net . . . . . . (41,315) (35,901) (22,486)
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 200,909 $ 188,791 $ 125,943
OPERATING STATISTICS:
Refining and marketing:
Throughput volumes (Mbbls per day) . . . . . . . . . . . . . . . . . . 170 160 146
Average throughput margin per barrel . . . . . . . . . . . . . . . . . $ 5.29 $ 6.25 $ 5.36
Sales volumes (Mbbls per day) <F1> . . . . . . . . . . . . . . . . . . 291 231 140
Natural gas related services <F4>:
Gas volumes (MMcf per day):
Sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,693 1,429 1,139
Transportation . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,665 1,430 1,398
Total gas volumes. . . . . . . . . . . . . . . . . . . . . . . . . 3,358 2,859 2,537
Average gas sales margin per Mcf . . . . . . . . . . . . . . . . . . . $ .146 $ .162 $ .184
Average gas transportation fee per Mcf . . . . . . . . . . . . . . . . $ .089 $ .094 $ .102
NGL plant production:
Production volumes (Mbbls per day) . . . . . . . . . . . . . . . . . 80.9 80.3 79.5
Average NGL market price per gallon. . . . . . . . . . . . . . . . . $ .354 $ .258 $ .265
Average gas cost per Mcf . . . . . . . . . . . . . . . . . . . . . . $ 1.93 $ 1.40 $ 1.75
Average NGL margin per gallon. . . . . . . . . . . . . . . . . . . . $ .103 $ .080 $ .076
<FN>
<F1> Revised for 1995 to include revenues and associated volumes related to certain refining and marketing
trading activities previously classified as a reduction of cost of sales.
<F2> Reflects the consolidation of the Partnership commencing June 1, 1994.
<F3> 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 period prior
to June 1, 1994.
<F4> Operating income (loss) presented herein for 1994 represents pro forma amounts that reflect the
consolidation of the Partnership with Energy for all of such year. Operating statistics for the natural
gas related services segment for 1994 represent pro forma statistics that reflect such consolidation.
<F5> Restated for 1994 to reflect the effects of a prior period adjustment resulting in a charge to income for
an acquisition expense accrual originally charged to property, plant and equipment. See "Restatement of
Financial Information" in Note 1 of Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
1996 COMPARED TO 1995
Consolidated Results
The Company reported net income of $72.7 million, or $1.40 per share,
for the year ended December 31, 1996 compared to $59.8 million, or $1.10 per
share, for the year ended December 31, 1995. For the fourth quarter of
1996, net income was $18.8 million, or $.37 per share, compared to $12.9
million, or $.23 per share, for the fourth quarter of 1995. Net income and
earnings per share increased during the 1996 fourth quarter and total year
compared to the same periods in 1995 due primarily to a significant increase
in operating income from the Company's natural gas related services
business, partially offset by a decrease in refining and marketing operating
income and an increase in corporate expenses. Lower net interest expense
also contributed to the increase in net income and earnings per share,
partially offset by higher income taxes.
Operating revenues increased $1.8 billion, or 56%, to $5 billion
during 1996 compared to 1995 due to an approximate $1 billion, or 75%
increase in natural gas related services revenues and an approximate
$800 million, or 41% increase in refining and marketing revenues. Operating
income increased $12.1 million, or 6%, to $200.9 million during 1996
compared to 1995 due to a $49 million, or 59% increase in natural gas
related services operating income, partially offset by a $31.5 million, or
22% decrease in refining and marketing operating income and a $5.4 million
increase in corporate expenses resulting primarily from higher employee-
related and other costs. Changes in operating revenues and operating income
by business segment are explained below under "Segment Results."
During the fourth quarter of 1996, the Company wrote off its
investment in its joint venture project to design, construct and operate a
plant in Mexico to produce methyl tertiary butyl ether ("MTBE") and accrued
an estimate of additional liabilities associated with such investment
resulting in a loss of $19.5 million (see Note 7 of Notes to Consolidated
Financial Statements). Also in the fourth quarter of 1996, the Company
recorded $16.6 million of income representing the reversal of the excess
portion of an accrual established in May 1994 to cover expected costs
related to the Company's acquisition of the publicly held units of VNGP,
L.P. Net interest and debt expense decreased $6 million to $95.2 million
during 1996 compared to 1995 due primarily to a decrease in bank
borrowings and paydowns of certain outstanding nonbank debt, partially
offset by the issuance of medium-term notes ("Medium-Term Notes") in the
first half of 1995 (see "Liquidity and Capital Resources"). Income tax
expense increased $5.7 million in 1996 compared to 1995 due primarily to
higher pre-tax income.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and marketing
operations increased $807.1 million, or 41%, to $2.8 billion during 1996
compared to 1995 due primarily to a 26% increase in sales volumes and a 12%
increase in the average sales price per barrel. The increase in sales
volumes was due primarily to increased volumes from trading and rack
marketing activities, and a 6% increase in average daily throughput volumes
resulting from various unit improvements and enhancements made during 1995
and a reduced impact on production due to unit turnarounds which occurred in
1996 compared to 1995, partially offset by the effects of two second quarter
1996 power outages at the Refinery. The average sales price per barrel
increased due primarily to higher gasoline and distillate prices which
generally followed an increase in crude oil prices during 1996.
Operating income from the Company's refining and marketing operations
decreased $31.5 million, or 22%, to $110 million during 1996 compared to
1995 due primarily to a decrease in total throughput margins and higher
operating expenses. The decrease in total throughput margins was due
primarily to lower oxygenate margins resulting from higher butane feedstock
costs, particularly in the fourth quarter, lower margins on sales of
petrochemical feedstocks, and decreased results from price risk management
activities. These decreases in throughput margins were partially offset by
the increase in throughput volumes noted above, higher distillate margins,
and an improvement in discounts on purchases of resid feedstocks. Operating
expenses increased due primarily to costs associated with the methanol plant
which was placed in service in late August 1995 and higher variable costs
resulting from increased throughput at the Refinery.
The Company has entered into various term feedstock supply agreements
for approximately 58,000 barrels per day of resid which are based on market
prices and extend through 1997, including an agreement with the Saudi
Arabian Oil Company for approximately 36,000 barrels per day which extends
through mid-1998. These agreements provide approximately 70% of the
Refinery's estimated daily resid feedstock requirements for 1997. The
Company believes that if any of its existing resid feedstock arrangements
were interrupted or terminated, supplies of resid 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 few years, if any such
interruptions or terminations did occur, the Company could be required to
incur higher resid feedstock costs or substitute other types of resid,
thereby producing less favorable operating results. The Company also has
two agreements to supply feedstock for the Refinery's crude unit; one with
the Chinese state-owned oil company for approximately 22,000 barrels per day
of sweet crude oil extending through June 1997, and one with a domestic
refiner for approximately 8,000 barrels per day of crude oil extending
through the end of 1997. The remainder of the Refinery's resid and crude
feedstocks are purchased at market-based prices under short-term contracts.
Production from the Company's joint venture methanol plant normally provides
all of the methanol feedstock presently required for the Refinery's
production of oxygenates used in reformulated gasoline ("RFG").
In 1996, a maintenance turnaround and a catalyst change for the
Refinery's hydrodesulfurization unit (the "HDS Unit") were completed in
July, a turnaround of the Refinery's MTBE Plant was completed in September
during which its capacity was increased by approximately 1,500 barrels per
day, and turnarounds of the Refinery's hydrocracker and naphtha reformer
units were completed in December. In early December, an explosion occurred
at the methanol plant as it was being shut down for repairs. The Company's
share of repair costs is estimated to be $2.5 million, and the plant is
expected to resume operations in late February 1997. In 1995, a
maintenance turnaround and a catalyst change for the HDS Unit and
turnarounds of the hydrocracker and naphtha reformer units were all
completed in April of that year. During 1997, the crude unit is
scheduled for a maintenance turnaround in the second quarter designed
to increase the unit's capacity, and the HDS Unit is scheduled for a
maintenance turnaround and a catalyst change in the fourth quarter.
The Company enters into various exchange-traded and over-the-counter
financial instrument contracts with third parties to manage price risk
associated with refining feedstock and fuel purchases, refined product
inventories and refining operating margins. Although such activities are
intended to limit the Company's exposure to loss during periods of declining
margins, such activities could tend to reduce the Company's participation in
rising margins. In 1996, refining throughput margins were reduced by $1.2
million as a result of hedging activities compared to a $12.8 million
benefit in 1995. The 1995 benefit resulted primarily from favorable price
swap contracts on methanol, as methanol prices dropped by over 70% during
that year. In 1996 and 1995, the Company was also able to reduce its
operating costs by $2.8 million and $1 million, respectively, as a result of
hedges on refining natural gas fuel requirements. See Note 1 under "Price
Risk Management Activities" and Note 6 of Notes to Consolidated Financial
Statements.
Natural Gas Related Services
Operating revenues from the Company's natural gas related services
operations increased $1 billion, or 75%, to $2.4 billion during 1996
compared to 1995 due primarily to a 47% increase in average natural gas
sales prices, an 18% increase in natural gas sales volumes, primarily
off-system sales, a 37% increase in average NGL market prices, and a 28%
increase in NGL sales volumes. Natural gas sales prices and volumes were
higher due to increased demand for natural gas to replenish low industry-
wide natural gas storage inventories drawn down by extreme cold winter
weather during the 1996 first quarter and which remained below 1995 levels
during all of 1996. Natural gas demand also increased due to early cold
weather during the 1996 fourth quarter. NGL market prices increased as a
result of historically low NGL inventory levels, firm petrochemical and
refining demand, and strong crude oil and refined product prices. NGL sales
volumes were higher due primarily to an increase in NGL marketing
activities.
Operating income from the Company's natural gas related services
operations increased $49 million, or 59%, to $132.2 million during 1996
compared to 1995 due primarily to higher margins on NGL production and to a
lesser extent to increases in total gas sales margins, natural gas
transportation revenues and income from NGL trading activities. Total
margins on NGL production were higher due to the substantial increase in
average NGL market prices noted above and to an approximate $16 million
increase in benefits from price risk management activities which limited the
increase in natural gas fuel and shrinkage costs. Total gas sales margins
increased due primarily to the increase in off-system sales volumes noted
above and increased benefits from price risk management activities,
partially offset by an increase in fuel costs. Natural gas transportation
revenues were higher due to a 16% increase in transportation volumes
resulting from increased marketing activities, partially offset by a 5%
decrease in average transportation fees. NGL trading income increased due
primarily to the increase in NGL marketing activities noted above. NGL
production volumes increased slightly in 1996 compared to 1995 as production
increases at various plants resulting from the completion in 1995 and 1996
of certain operational improvements and production enhancements generally
offset the effects of the sale of two West Texas processing plants in August
1995.
Demand for natural gas continues to be affected by the operation of
various nuclear and coal power plants in the Company's core service area.
At full operation, the South Texas Project nuclear plant ("STP") in Bay
City, Texas and the Comanche Peak nuclear plant near Ft. Worth, Texas
displace approximately 650 MMcf per day and 600 MMcf per day of natural gas
demand, respectively. In addition, coal-fired electrical generation
facilities owned and operated by San Antonio City Public Service displace a
portion of natural gas demand.
The Company's gas sales and transportation businesses are based
primarily on competitive market conditions and contracts negotiated with
individual customers. The Company has been able to mitigate, to some
extent, the effect of competitive industry conditions by aggressive
marketing efforts to increase gas sales and transportation volumes,
particularly in its off-system marketing business with local distribution
and industrial companies throughout the United States, and by the flexible
use of its strategically located pipeline system. However, gas sales and
transportation margins remain under intense pressure as the natural gas
industry continues to adjust to deregulation and the customer-driven market
that has developed since FERC Order 636 was enacted.
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 provide for the sale of gas at
its weighted average cost, as defined ("WACOG"), plus a margin. 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. As a result of
contracts expiring in 1998, the majority of storage costs previously
included in WACOG (see Note 14 of Notes to Consolidated Financial
Statements), will no longer be recovered through these gas sales rates.
The Company's NGL operations benefit from the strategic location of
its facilities in relation to natural gas supplies and markets, particularly
in South Texas which is a core supply area for the Company's natural gas and
NGL operations. Currently, approximately 93% of the Company's NGL
production comes from plants in South Texas and the Texas Gulf Coast. 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. 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.
The Company enters into various exchange-traded and over-the-counter
financial instrument contracts with third parties to manage price risk
associated with its natural gas storage, natural gas marketing and NGL
operations. Such activities are intended to manage price risk but may
result in gas, fuel and shrinkage costs either higher or lower than those
that would have been incurred absent such activities. In 1996 and 1995,
total gas sales margins benefitted from gas cost reductions of $23.4 million
and $12 million, respectively, resulting from price risk management
activities. Of these amounts, $12.6 million and $5.6 million, respectively,
were recognized in each year's fourth quarter. In addition, in 1996 and
1995, total margins on NGL production benefitted from fuel and shrinkage
cost reductions of $19.7 million and $4.1 million, respectively, resulting
from price risk management activities. For all such activities, an
additional $16.6 million and $3.8 million was deferred at December 31, 1996
and 1995, respectively, which is recognized as a reduction to cost of sales
in the subsequent year. See Note 1 under "Price Risk Management Activities"
and Note 6 of Notes to Consolidated Financial Statements.
1995 COMPARED TO 1994
Consolidated Results
The Company reported net income of $59.8 million, or $1.10 per share,
for the year ended December 31, 1995 compared to $17.3 million, or $.18 per
share, for the year ended December 31, 1994. For the fourth quarter of
1995, net income was $12.9 million, or $.23 per share, compared to net
income of $3.9 million, or $.02 per share, for the fourth quarter of 1994.
Net income and earnings per share increased during 1995 compared to 1994 due
primarily to a significant increase in operating income from the Company's
refining and marketing operations, improved operating results from the
Company's natural gas related services business, including the effect of the
May 31, 1994 merger of VNGP, L.P. with Energy, and the nonrecurring recognition
in expense in 1994 of an accrual for loss contingencies recorded in connection
with the merger of VNGP, L.P. with Energy. The increases in net income
and earnings per share resulting from these factors were partially offset by
increases in corporate expenses, net interest expense and income tax expense
and the nonrecurring recognition in income in 1994 of deferred management
fees resulting from the VNGP, L.P. merger. The increase in earnings per
share was also partially offset by an increase in preferred stock dividend
requirements resulting from the issuance in March 1994 of 3.45 million
shares of Energy's $3.125 Convertible Preferred Stock. See Note 9 of Notes
to Consolidated Financial Statements.
Operating revenues increased $1.4 billion, or 74%, to $3.2 billion
during 1995 compared to 1994 due primarily to an increase in operating
revenues from refining and marketing operations which is explained below
under "Segment Results" and the inclusion of operating revenues attributable
to Partnership operations in all of 1995 versus only the months of June
through December in 1994. Other operating revenues decreased $42.5 million
due to the elimination of management fee revenues received by the Company
from the Partnership as a result of the VNGP, L.P. merger.
Operating income increased $62.9 million, or 50%, to $188.8 million
during 1995 compared to 1994 due primarily to an increase in operating
income from refining and marketing operations and to the inclusion of
Partnership operating income in all of 1995 versus only the months of June
through December in 1994. Partially offsetting these increases in operating
income was an increase in corporate expenses, net, resulting primarily from
the nonrecurring recognition in income in 1994 of deferred management fees
resulting from the VNGP, L.P. merger, the allocation of corporate expenses
to the Partnership in 1994 for the periods prior to the VNGP, L.P. merger
and an increase in compensation expense.
As a result of the VNGP, L.P. merger and the Company's change in the
method of accounting for its investment in the Partnership from the equity
method to the consolidation method, the Company did not report equity in
earnings (losses) of and income from the Partnership for 1995 and the months
of June through December in 1994. See "Segment Results" below for a
discussion of the Company's natural gas related services operations,
including 100% of the operations of the Partnership on a pro forma basis for
1994. Equity in earnings of joint ventures increased $2.4 million to $4.8
million for 1995 compared to 1994 due to an increase in the Company's equity
in earnings of Javelina. Javelina's earnings increased due primarily to
higher product prices as a result of strong product demand from the
petrochemical industry, as well as lower feedstock costs.
Net interest and debt expense increased $24.3 million to $101.2
million during 1995 compared to 1994 due primarily to the inclusion of
Partnership interest expense in all of 1995 versus only the months of June
through December in 1994, and to a lesser extent to the issuance of
Medium-Term Notes in December 1994 and the first half of 1995. Income tax
expense increased $24.6 million to $35.3 million in 1995 compared to 1994
due primarily to higher pre-tax income.
Segment Results
Refining and Marketing
Operating revenues from the Company's refining and marketing
operations increased $860.3 million, or 79%, to $2 billion during 1995
compared to 1994 due primarily to a 65% increase in sales volumes and a 9%
increase in the average sales price per barrel. The increase in sales
volumes was due primarily to higher purchases for resale of conventional
gasoline to supply rack customers as a result of the Company's conversion of
its Refinery operations to produce primarily RFG beginning in the fourth
quarter of 1994, a 10% increase in throughput volumes resulting from various
unit improvements completed during the latter part of 1994 and first half of
1995, and additional sales volumes in 1995 related to increased fuel oil
trading activities. The average sales price per barrel increased due to
higher refined product prices, including higher prices received on sales of
RFG and other higher-value products.
Operating income from the Company's refining and marketing operations
increased $62.8 million, or 80%, to $141.5 million during 1995 compared to
1994 due primarily to an increase in total throughput margins partially
offset by an increase in operating and other expenses. Total throughput
margins increased due to higher margins on sales of RFG, oxygenates and
petrochemical feedstocks, the effects of the unit improvements noted above,
and the nonrecurrence of a turnaround of the Refinery's heavy oil cracking
complex completed during the latter part of 1994, net of the effect of unit
turnarounds which occurred in 1995 as described below. The increase in
total throughput margins resulting from these factors was partially offset
by a decrease in conventional refined product margins ("crack spread")
resulting primarily from depressed gasoline markets in early 1995
attributable to uncertainties pertaining to the general acceptance of RFG
and oxygenates. Costs for the Company's resid feedstocks increased in 1995
compared to 1994 due to a continuing worldwide decrease in resid supplies
resulting from the addition of new refinery upgrading capacity and increased
production of light sweet crude oil in relation to heavy crude oil.
However, the effect of such increased resid costs on throughput margins was
more than offset by a decrease in other feedstock costs, including a $7.5
million increase in benefits from price risk management activities,
approximately $7 million of which was attributable to fourth quarter
operations. Although operating expenses increased approximately 4% due
primarily to higher costs resulting from increased throughput, operating
expenses per barrel decreased by approximately 5%. Selling and
administrative expenses increased due to higher compensation and other
expenses, while depreciation expense increased approximately 4% due to
capital expenditures incurred during the latter part of 1994 and in 1995.
In 1995 and 1994, refining feedstock costs were reduced by $12.8
million and $5.3 million, respectively, as a result of price risk management
activities. In addition, in 1995 the Company was able to reduce its
operating costs by $1 million as a result of such activities. In 1994, the
effect of such activities on operating costs was not significant.
Natural Gas Related Services
Operating income from the Company's natural gas related services
operations was $83.2 million for 1995 compared to pro forma operating income
of $69.8 million for 1994. The $13.4 million, or 19%, increase was due
primarily to an increase in total gas sales margins and other operating
revenues, higher margins on NGL production, a decrease in NGL transportation
and fractionation costs, and a decrease in operating, selling and
administrative expenses. The increase in operating income resulting from
these factors was partially offset by decreases in natural gas
transportation revenues and NGL revenues from transportation and
fractionation of third party plant production. Total gas sales margins
increased due to a 25% increase in gas sales volumes, reductions in gas
costs resulting from price risk management activities, and the nonrecurrence
of certain settlements relating to measurement and customer billing
differences which adversely affected 1994. The increase in total gas sales
margins resulting from these factors was partially offset by reduced
volumetric gains and lower unit margins due primarily to an increase in
lower-margin spot and off-system sales. Total margins on NGL production were
higher due to a decrease in fuel and shrinkage costs resulting from a 20%
decrease in the average cost of natural gas, which more than offset a 3%
decrease in the average NGL market price. Average natural gas costs
decreased due to surplus industry capacity and benefits from price risk
management activities, while average NGL prices decreased due to weak ethane
prices resulting from above-normal inventory levels. The decrease in
operating, selling and administrative expenses was due primarily to the
nonrecurrence of certain adverse settlements in 1994, including
$6.8 million related to a settlement with the City of Houston regarding a
franchise fee dispute, partially offset by higher ad valorem tax,
maintenance and compensation expenses. The decrease in transportation
revenues was due primarily to an 8% decrease in average transportation fees.
NGL production volumes increased slightly in 1995 compared to 1994 as volume
increases in 1995 resulting from the addition of new natural gas supplies
under processing agreements with natural gas producers and operational
improvements and production enhancements at certain of the Company's NGL
plants were mostly offset by volume decreases resulting primarily from the
sale of two West Texas processing plants in August 1995.
In 1995, total gas sales margins benefitted from gas cost reductions
of $12 million resulting from price risk management activities, $5.6
million of which was recognized in the fourth quarter, compared to $2.1
million in 1994 on a pro forma basis. In addition, in 1995 total margins on
NGL production benefitted from fuel and shrinkage cost reductions of
$4.1 million resulting from price risk management activities. In 1994, the
effect of such activities on fuel and shrinkage costs was not significant.
For all such activities, an additional $3.8 million and $6.8 million was
deferred at December 31, 1995 and 1994, respectively, which is recognized as
a reduction to cost of sales in the subsequent year.
Other
Pro forma corporate general and administrative expenses and other,
net, increased $13.4 million during 1995 compared to 1994 due primarily to
the nonrecurring recognition in income in 1994 of deferred management fees
resulting from the Merger, as noted above, and an increase in compensation
expense.
OUTLOOK
Refining and Marketing
Over the next few years, light product demand is expected to grow
moderately and refining capacity in the U.S. is expected to remain tight.
However, the ongoing restructuring of the refining industry to improve
performance as a result of poor margins experienced in recent years will
create an extremely competitive business environment. The Company entered
into several new feedstock arrangements in 1996 and will continue to explore
various opportunities, both domestically and abroad, to diversify its
sources of feedstock supply. The Company expects resid to continue to sell
at a discount to crude oil, but is unable to predict the amount of such
discount or future relationships between the supply of and demand for resid.
Domestic gasoline demand, which increased by 1%, 1.5% and 1.7% in
1996, 1995 and 1994, respectively, is expected to continue to grow over the
next several years due to slowing gains in fuel efficiency for passenger
cars, higher sales of light trucks and sport-utility vehicles which average
fewer miles per gallon than passenger cars, higher speed limits and an
increasing number of miles driven. The demand for RFG increased in 1996 to
over 30% of the total demand for gasoline in the U.S. following the
implementation of the California Air Resources Board's "CARB II" gasoline
program, and may continue to increase if areas of the country whose ozone
emissions exceed permitted levels are permitted and elect to "opt in" to the
RFG program to reduce their emission levels. The demand for oxygenates,
including MTBE, is expected to increase due to the future need to replace
the octane displaced by the worldwide movement to reduce the use of lead in
gasoline, and to growing demand for oxygenated gasolines. The Company's
Refinery throughput volumes are expected to benefit from the full year
effect of various unit improvements and enhancements made during 1996 and no
significant unit turnarounds being scheduled in 1997.
Natural Gas Related Services
Due to its desirability as a clean-burning fuel, demand for natural
gas has remained strong and is expected to continue to grow due primarily to
increasing demand in utility and non-utility electric generation
applications and in industrial, particularly cogeneration, applications.
Natural gas supplies should be sufficient to meet the growth in natural gas
demand due to anticipated increases in domestic productive and storage
capacity and in Canadian imports. As a result of the implementation of FERC
Order No. 636 in 1993 and other efforts to reduce regulation, the Company's
natural gas related services business continues to adjust to the
transformation of the U.S. natural gas industry into a more market-oriented
environment where increasing competition and market efficiencies are
pressuring margins for all categories of business. In response to such
conditions, the Company is continuing to emphasize growth of off-system
sales by diversification of its customer base through marketing offices
located throughout the nation and in Canada, and to further develop and
expand its slate of value-added services, such as gas gathering and related
activities, gas processing, gas transportation, volume and capacity
management, price risk management, power marketing, NGL marketing and
beginning in 1996, retail gas marketing. To capitalize on the continuing
growth of west-to-east movement of gas across the United States, the Company
intends to further increase its capacity to move gas across Texas through
pipeline debottlenecking and other projects. The demand for NGLs is
expected to remain strong as a result of continued economic growth,
petrochemical plant expansions and the addition of new independent
petrochemical facilities, and increased production of oxygenated and
reformulated gasolines. The Company is continuing to emphasize the addition
of new natural gas supplies under processing agreements with natural gas
producers and the development and expansion of market alternatives for its
NGL production. In order to accommodate an increase in natural gas
supplies, the Company has increased and plans to further increase the
processing capacity at certain of its NGL plants and fractionation
facilities through various expansion projects. As a result of the
development of the above-noted natural gas related services business
opportunities, the Company believes that it should be able to increase its
natural gas, NGL and power marketing volumes in 1997.
Due to rapid consolidation taking place in the natural gas and power
industries in an effort to lower fixed costs per unit and improve profits in
an increasingly competitive environment, competitors to the Company's
natural gas related services business were becoming larger and more
sophisticated. As a result , the Company began exploring the possibility of
its natural gas related services business becoming part of a larger
organization to remain competitive in the future and announced in November
1996 that its Board of Directors had approved a management recommendation to
pursue a strategic alliance for such operations. On January 31, 1997, the
Company announced that its natural gas related services business would be
merged with PG&E Corporation following the spin-off of the Company's
refining and marketing business. See "Proposed Restructuring" above and
Note 2 of Notes to Consolidated Financial Statements.
LIQUIDITY AND CAPITAL RESOURCES
PROPOSED RESTRUCTURING
As described above, the Company's refining and marketing business,
which is conducted through Valero Refining and Marketing Company ("VRMC"),
a wholly owned subsidiary of Energy, is expected to be spun-off as a
separate company to the Company's shareholders at the time of the
Restructuring. Such refining and marketing business currently obtains
working capital financing from Energy pursuant to Energy's $300 million
revolving bank credit and letter of credit facility and certain uncommitted
short-term bank credit lines and uncommitted bank letter of credit
facilities obtained by Energy as described below under "Current Structure."
At the time of the spin off, the refining and marketing company expects to
have established a separate unsecured five-year, $600 million revolving
bank credit and letter of credit facility which can be used to fund working
capital needs and other general corporate purposes, including the issuance
of letters of credit and the funding of a dividend payable to Energy
pursuant to the terms of the agreement and plan of merger with PG&E.
Borrowings under this new facility are expected to bear interest at either
LIBOR plus a margin, a base rate defined generally as the federal funds
rate plus a margin, or a money-market rate. In addition, the refining and
marketing company expects to pay various fees and expenses in connection
with this new facility. The interest margins and fees are expected to
fluctuate based upon the levels of certain financial ratios or the credit
ratings assigned from time to time to the refining and marketing company's
long-term debt and are expected to be comparable to those currently paid
by Energy. The credit facility is expected to contain various covenants,
which may include certain financial covenants such as a minimum fixed
charge coverage ratio, a maximum permitted debt to capitalization ratio
and a minimum net worth test. The refining and marketing company may
also obtain short-term uncommitted revolving credit or letter of credit
facilities, the lenders, issuers, amounts, terms and conditions of which
cannot currently be determined.
VRMC currently has outstanding $90 million of 10-1/4% industrial
revenue refunding bonds and $8.5 million of 10-5/8% industrial revenue
bonds issued in 1987. See Note 5 of Notes to Consolidated Financial
Statements. The industrial revenue bonds may be called and redeemed on
June 1, 1997 at 103% of their principal amount. VRMC intends to refund
the existing industrial revenue bonds through issuance, prior to the
June 1, 1997 redemption date, of four new series of refunding revenue
bonds, having the same aggregate principal amount. VRMC expects to
issue the new bonds on a floating rate basis and for the bonds to be
secured by a letter of credit to be issued under the bank credit
facility described above. Based on the currently existing interest
rate environment and because the bonds will be issued as floating
rate debt as opposed to fixed rated debt, the interest rates on the
refunding revenue bonds will be substantially lower than the rates
on the existing industrial revenue bonds. The refunding revenue bonds
are expected to have a weighted average life of approximately 16 years
from their date of issuance and to be subject to a mandatory sinking
fund requirement.
The Company believes that the spun-off refining and marketing company
will have sufficient funds from operations, and to the extent necessary,
from the public and private capital markets and bank markets, to fund its
ongoing operating requirements.
CURRENT STRUCTURE
Net cash provided by the Company's operating activities increased
$120 million to $275.8 million in 1996 compared to 1995 due primarily to the
increase in income described above under "Results of Operations" and to the
changes in current assets and current liabilities detailed in Note 1 of
Notes to Consolidated Financial Statements under "Statements of Cash Flows."
Included in such changes was a substantial increase in accounts payable in
1996 offset to a large extent by increases in accounts receivable and
inventories. Accounts payable and accounts receivable increased in 1996 due
to higher commodity prices and increased purchase and sales volumes of
refined products, natural gas and NGLs. Refining inventories increased in
1996 due to increased rack and wholesale marketing activities, while
refining inventories decreased in 1995 resulting from a decrease in volumes
available under crude feedstock contracts, above-normal low-sulphur HOC
feedstock inventories at the end of 1994 in anticipation of a turnaround of
the HDS Unit in the first quarter of 1995, and above-normal refined product
inventories at the end of 1994 attributable to uncertainties related to the
implementation of the new RFG regulations. Prepaid expenses and other
decreased in 1996 compared to an increase in 1995 due to lower commodity
deposits and deferrals, while accrued interest decreased in 1996 compared to
an increase in 1995 as a result of timing differences on interest payments
for certain nonbank debt. During 1996, the Company utilized the cash
provided by its operating activities, a portion of its existing cash
balances, proceeds from issuances of common stock related to the Company's
employee benefit plans, and proceeds from dispositions of various
nonessential properties to fund capital expenditures and deferred turnaround
and catalyst costs, reduce bank debt, repay principal on certain outstanding
nonbank debt, pay common and preferred stock dividends, and redeem a portion
of its outstanding Cumulative Preferred Stock, $8.50 Series A ("Series A
Preferred Stock").
Energy currently maintains an unsecured $300 million revolving bank
credit and letter of credit facility that is available for general corporate
purposes including working capital needs and letters of credit. Borrowings
under this facility bear interest at either LIBOR plus .50% (inclusive of a
facility fee), prime or a competitive money market rate. The Company is
also charged various fees, including various letter of credit fees. As of
December 31, 1996, Energy had approximately $273 million available under
this committed bank credit facility for additional borrowings and letters of
credit. Energy also has $190 million of uncommitted short-term bank credit
lines and $170 million of uncommitted bank letter of credit facilities, of
which $108 million and $129 million, respectively, were available as of
December 31, 1996 for additional borrowings and letters of credit. The
Company was in compliance with all covenants contained in its various debt
facilities as of December 31, 1996. See Notes 4 and 5 of Notes to
Consolidated Financial Statements.
In the first quarter of 1995, the Securities and Exchange Commission
declared effective Energy's shelf registration statement to offer up to $250
million principal amount of additional debt securities, including Medium-
Term Notes, $96.5 million of which were issued in 1995. The net proceeds
were used for general corporate purposes, including the repayment of
existing indebtedness, financing of capital projects and additions to
working capital. See Note 5 of Notes to Consolidated Financial Statements.
No additional Medium-Term Notes have been issued since June 1995 and none
are expected to be issued in the future. The Company's ratio of earnings to
fixed charges, as computed based on rules promulgated by the Commission, was
1.98 for the year ended December 31, 1996.
During 1996, the Company expended approximately $165 million for
capital investments, including capital expenditures and deferred turnaround
and catalyst costs. Of this amount, $93 million related to refining and
marketing operations while $66 million related to natural gas related
services operations. Included in the refining and marketing amount was $36
million for turnarounds of the Refinery's HDS Unit, MTBE Plant, and
hydrocracker and naphtha reformer units. For 1997, the Company currently
expects to incur approximately $175 million for capital expenditures and
deferred turnaround and catalyst costs.
During 1996, the Company entered into a sublease agreement for unused
space in its corporate headquarters office complex. The sublease has a
primary term of 20 years, with the sublessee having an option to terminate
the lease after 10 years. The sublessee is scheduled to occupy the premises
in phases, with full occupancy currently expected in 1997. The sublease
reduced the Company's rent expense in 1996 by $.5 million and is expected to
reduce future rent expense by approximately $2.1 million per year once fully
occupied.
Dividends on Energy's Common Stock are considered quarterly by the
Energy Board of Directors, and may be paid only when approved by the Board.
The current quarterly dividend rate on Energy's Common Stock of $.13 per
share has remained unchanged since the fourth quarter of 1993. 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
markets, to fund its ongoing operating requirements. The Company expects
that to the extent necessary, it can raise additional funds from time to
time through equity or debt financings; however, except for borrowings under
bank credit agreements, 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 related services operations have a
concentration of customers in the natural gas transmission and distribution,
and 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 not collateralized.
The Company is subject to environmental regulation at the federal,
state and local levels. The Company's capital expenditures for
environmental control and protection for its refining and marketing
operations totalled approximately $5 million in 1996 and are expected to be
approximately $7 million in 1997. 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 related services operations have not been material to
date and are not expected to be material in 1997. 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 federal operating permits under provisions of the
Clean Air Act Amendments of 1990 (the "Clean Air Act"). In addition, Clean
Air Act provisions will require many of the Company's gas processing plants
and gas pipeline facilities to obtain new operating permits. However, the
Clean Air Act is not expected to have any significant adverse impact on the
Company's operations and the Company does not anticipate that it will be
necessary to expend any material amounts in addition to those mentioned
above to comply with such legislation. The Company is not aware of any
material environmental remediation costs related to its operations.
Accordingly, no amount has been accrued for any contingent environmental
liability.
In June 1996, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 125,
"Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," which establishes new accounting and
reporting standards for transfers and servicing of financial assets and
extinguishments of liabilities. The statement is effective for transactions
occurring after December 31, 1996. Based on information currently known by
the Company, this statement will not have a material effect on the Company's
consolidated financial statements.
<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, 1996 and 1995, 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, 1996. 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.
As explained in Note 1 to the financial statements, the Company has
restated its consolidated balance sheets as of December 31, 1996 and 1995,
its consolidated statements of common stock and other stockholders' equity
for each of the three years in the period ended December 31, 1996, and its
consolidated statements of income and cash flows for the year ended
December 31, 1994, to change the accounting for a contingency which was
recorded in conjunction with the acquisition of Valero Natural Gas
Partners, L.P. in May of 1994.
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, 1996 and 1995, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
San Antonio, Texas
February 14, 1997 (except with respect to the
matters discussed in Notes 1, 2 and 3, as to which the
date is May 9, 1997)
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
<CAPTION>
December 31,
A S S E T S 1996 1995
<S> <C> <C>
CURRENT ASSETS:
Cash and temporary cash investments. . . . . . . . . . . . . . . . . . . . . $ 19,847 $ 28,054
Cash held in debt service escrow . . . . . . . . . . . . . . . . . . . . . . 37,746 36,627
Receivables, less allowance for doubtful accounts of $1,624 (1996) and
$1,193 (1995). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 566,088 339,189
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212,134 140,822
Current deferred income tax assets . . . . . . . . . . . . . . . . . . . . . 22,408 29,530
Prepaid expenses and other . . . . . . . . . . . . . . . . . . . . . . . . . 29,946 47,321
888,169 621,543
PROPERTY, PLANT AND EQUIPMENT - including construction in
progress of $45,824 (1996) and $37,472 (1995), at cost . . . . . . . . . . . 2,787,431 2,682,694
Less: Accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . 708,352 622,123
2,079,079 2,060,571
INVESTMENT IN AND ADVANCES TO JOINT VENTURES . . . . . . . . . . . . . . . . . 29,192 41,890
DEFERRED CHARGES AND OTHER ASSETS. . . . . . . . . . . . . . . . . . . . . . . 138,334 137,876
$3,134,774 $2,861,880
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:
Short-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 82,000 $ -
Current maturities of long-term debt . . . . . . . . . . . . . . . . . . . . 72,341 81,964
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 661,273 312,672
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,082 31,104
Other accrued expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . 39,458 42,542
875,154 468,282
LONG-TERM DEBT, less current maturities. . . . . . . . . . . . . . . . . . . . 868,300 1,035,641
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279,938 270,813
DEFERRED CREDITS AND OTHER LIABILITIES . . . . . . . . . . . . . . . . . . . . 34,407 56,031
REDEEMABLE PREFERRED STOCK, SERIES A, issued 1,150,000 shares,
outstanding 11,500 (1996) and 69,000 (1995) shares . . . . . . . . . . . . . 1,150 6,900
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 (1996 and 1995) shares ($172,500 aggregate
involuntary liquidation value) . . . . . . . . . . . . . . . . . . . . 3,450 3,450
Common stock, $1 par value - 75,000,000 shares authorized; issued
44,185,513 (1996) and 43,739,380 (1995) shares . . . . . . . . . . . . . 44,186 43,739
Additional paid-in capital . . . . . . . . . . . . . . . . . . . . . . . . . 540,133 530,177
Unearned Valero Employees' Stock Ownership Plan Compensation . . . . . . . . (8,783) (11,318)
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 496,839 458,343
Treasury stock, -0- (1996) and 6,904 (1995) common shares, at cost . . . . . - (178)
1,075,825 1,024,213
$3,134,774 $2,861,880
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars, Except Per Share Amounts)
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440
COSTS AND EXPENSES:
Cost of sales and operating expenses. . . . . . . . 4,606,320 2,830,636 1,561,225
Selling and administrative expenses . . . . . . . . 81,665 78,120 66,258
Depreciation expense. . . . . . . . . . . . . . . . 101,787 100,325 84,032
Total . . . . . . . . . . . . . . . . . . . . . . 4,789,772 3,009,081 1,711,515
OPERATING INCOME . . . . . . . . . . . . . . . . . . . 200,909 188,791 125,925
EQUITY IN EARNINGS (LOSSES) OF AND INCOME FROM:
Valero Natural Gas Partners, L.P. . . . . . . . . . - - (10,698)
Joint ventures. . . . . . . . . . . . . . . . . . . 3,899 4,827 2,437
LOSS ON INVESTMENT IN PROESA JOINT VENTURE . . . . . . (19,549) - -
(PROVISION FOR) REVERSAL OF ACQUISITION EXPENSE ACCRUAL 18,698 (2,506) (16,192)
OTHER INCOME, NET. . . . . . . . . . . . . . . . . . . 4,921 5,248 3,431
INTEREST AND DEBT EXPENSE:
Incurred. . . . . . . . . . . . . . . . . . . . . . (99,505) (105,921) (79,286)
Capitalized . . . . . . . . . . . . . . . . . . . . 4,328 4,699 2,365
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . 113,701 95,138 27,982
INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . 41,000 35,300 10,700
NET INCOME . . . . . . . . . . . . . . . . . . . . . . 72,701 59,838 17,282
Less: Preferred stock dividend requirements. . . . 11,327 11,818 9,490
NET INCOME APPLICABLE TO COMMON STOCK. . . . . . . . . $ 61,374 $ 48,020 $ 7,792
EARNINGS PER SHARE OF COMMON STOCK . . . . . . . . . . $ 1.40 $ 1.10 $ .18
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING (in thousands). . . . . . . . . . . . . 43,926 43,652 43,370
DIVIDENDS PER SHARE OF COMMON STOCK. . . . . . . . . . $ .52 $ .52 $ .52
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
(Thousands of Dollars)
<CAPTION>
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, 1993 . . $ - 43,391,685 $43,392 $371,303 $(15,958) $446,931 $(3,371)
Net income . . . . . . . . . - - - - - 17,282 -
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) 433,059 -
Net income . . . . . . . . . - - - - - 59,838 -
Dividends on Series A
Preferred Stock. . . . . . - - - - - (1,075) -
Dividends on Convertible
Preferred Stock. . . . . . - - - - - (10,781) -
Dividends on Common Stock. . - - - - - (22,698) -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . - - - - 2,388 - -
Deficiency payment tax
effect . . . . . . . . . . - - - (9,106) - - -
Shares repurchased and
shares issued pursuant
to employee stock plans
and other. . . . . . . . . - 275,511 275 2,670 - - (178)
BALANCE, December 31, 1995 . . 3,450 43,739,380 43,739 530,177 (11,318) 458,343 (178)
Net income . . . . . . . . . - - - - - 72,701 -
Dividends on Series A
Preferred Stock. . . . . . - - - - - (587) -
Dividends on Convertible
Preferred Stock. . . . . . - - - - - (10,781) -
Dividends on Common Stock. . - - - - - (22,837) -
Unearned Valero Employees'
Stock Ownership Plan
compensation . . . . . . . - - - - 2,535 - -
Shares repurchased and
shares issued pursuant
to employee stock plans
and other. . . . . . . . . - 446,133 447 9,956 - - 178
BALANCE, December 31, 1996 . . $3,450 44,185,513 $44,186 $540,133 $ (8,783) $496,839 $ -
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
<CAPTION>
Year Ended December 31,
1996 1995 1994
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation expense . . . . . . . . . . . . . . . . . . . . 101,787 100,325 84,032
Loss on investment in Proesa joint venture . . . . . . . . . 19,549 - -
Provision for (reversal of) acquisition expense accrual. . . (18,698) 2,506 16,192
Amortization of deferred charges and other, net. . . . . . . 32,458 32,352 19,452
Changes in current assets and current liabilities. . . . . . 50,232 (31,636) (95,597)
Deferred income tax expense . . . . . . . . . . . . . . . . 20,000 4,700 7,000
Equity in (earnings) losses in excess of distributions:
Valero Natural Gas Partners, L.P.. . . . . . . . . . . . . - - 16,179
Joint ventures . . . . . . . . . . . . . . . . . . . . . . (3,899) (4,304) (2,437)
Changes in deferred items and other, net . . . . . . . . . . 1,671 (7,959) 6,008
Net cash provided by operating activities. . . . . . . . . 275,801 155,822 68,111
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . (128,453) (124,619) (80,738)
Deferred turnaround and catalyst costs . . . . . . . . . . . . . (36,389) (35,590) (21,999)
Investment in and advances to joint ventures, net. . . . . . . . 1,197 (2,018) (9,229)
Investment in Valero Natural Gas Partners, L.P.. . . . . . . . . - - (124,264)
Assets leased to Valero Natural Gas Partners, L.P. . . . . . . . - - (1,886)
Distributions from Valero Natural Gas Partners, L.P. . . . . . . - - 2,789
Dispositions of property, plant and equipment. . . . . . . . . . 6,834 13,531 4,504
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . 637 70 898
Net cash used in investing activities. . . . . . . . . . . . . (156,174) (148,626) (229,925)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in short-term debt, net . . . . . . . . . . . . . . . . 82,000 - -
Long-term borrowings . . . . . . . . . . . . . . . . . . . . . . 65,000 508,500 574,100
Long-term debt reduction . . . . . . . . . . . . . . . . . . . . (240,229) (473,357) (509,385)
Increase in cash held in debt service escrow for principal . . . (1,875) (1,875) (22,768)
Common stock dividends . . . . . . . . . . . . . . . . . . . . . (22,837) (22,698) (22,554)
Preferred stock dividends. . . . . . . . . . . . . . . . . . . . (11,368) (11,856) (8,600)
Issuance of Convertible Preferred Stock, net . . . . . . . . . . - - 167,878
Issuance of common stock . . . . . . . . . . . . . . . . . . . . 11,225 6,129 4,178
Purchases of treasury stock. . . . . . . . . . . . . . . . . . . (4,000) (4,445) (927)
Repurchase of Series A Preferred Stock . . . . . . . . . . . . . (5,750) (5,750) (1,150)
Net cash provided by (used in) financing activities. . . . . . (127,834) (5,352) 180,772
NET INCREASE (DECREASE) IN CASH AND TEMPORARY
CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . . (8,207) 1,844 18,958
CASH AND TEMPORARY CASH INVESTMENTS AT
BEGINNING OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . 28,054 26,210 7,252
CASH AND TEMPORARY CASH INVESTMENTS AT
END OF PERIOD. . . . . . . . . . . . . . . . . . . . . . . . . . $ 19,847 $ 28,054 $ 26,210
<FN>
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
VALERO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation and Basis of Presentation
The accompanying consolidated financial statements include the
accounts of Valero Energy Corporation ("Energy") and subsidiaries
(collectively referred to herein as the "Company"). All significant
intercompany transactions have been eliminated in consolidation. Certain
prior period amounts have been reclassified for comparative purposes.
Energy conducts its refining and marketing operations through its
wholly owned subsidiary, Valero Refining and Marketing Company ("VRMC"), and
VRMC's operating subsidiaries (collectively referred to herein as
"Refining"). Prior to and including May 31, 1994, the Company accounted for
its effective equity interest of approximately 49% in Valero Natural Gas
Partners, L.P. ("VNGP, L.P.") and VNGP, L.P.'s consolidated subsidiaries,
including Valero Management Partnership, L.P. (the "Management Partnership")
and various subsidiary operating partnerships ("Subsidiary Operating
Partnerships") (collectively referred to herein as the "Partnership") using
the equity method of accounting. Effective May 31, 1994, the Company
acquired through a merger the 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 3).
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Revenue Recognition
Revenues generally are recorded when services have been provided or
products have been delivered. Changes in the fair value of financial
instruments related to trading activities are recognized in income
currently. See "Price Risk Management Activities" below.
Price Risk Management Activities
The Company enters into various exchange-traded and over-the-counter
financial instrument contracts with third parties to hedge the purchase
costs and sales prices of inventories, operating margins and certain
anticipated transactions. Such contracts are designated at inception as a
hedge where there is a direct relationship to the price risk associated with
the Company's inventories or future purchases and sales of commodities used
in the Company's operations. Hedges of inventories are accounted for under
the deferral method with gains and losses included in the carrying amounts
of inventories and ultimately recognized in cost of sales as those
inventories are sold. Hedges of anticipated transactions are also accounted
for under the deferral method with gains and losses on these transactions
recognized in cost of sales when the hedged transaction occurs. Gains and
losses on early terminations of financial instrument contracts designated as
hedges are deferred and included in cost of sales in the measurement of the
hedged transaction. Certain of the Company's hedging activities could tend
to reduce the Company's participation in rising margins but are intended to
limit the Company's exposure to loss during periods of declining margins.
The Company also enters into various exchange-traded and over-the-
counter financial instrument contracts with third parties for trading
purposes. Contracts entered into for trading purposes are accounted for
under the fair value method. Changes in the fair value of these contracts
are recognized as gains or losses in cost of sales currently and are
recorded in the Consolidated Balance Sheets in "Prepaid expenses and
other" and "Accounts payable" 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 6.
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 the cost of
feedstocks and produced products determined primarily under the last-in,
first-out ("LIFO") method of inventory pricing and the cost of products
purchased for resale determined under the weighted average cost method. The
excess of the replacement cost of the Company's LIFO inventories over their
LIFO values was approximately $51 million at December 31, 1996. 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, 1996 and 1995 were as follows (in
thousands) (see Note 6):
December 31,
1996 1995
Refinery feedstocks. . . . . . . . . . . $ 42,744 $ 48,295
Refined products and blendstocks . . . . 99,398 41,967
Natural gas in underground storage . . . 40,609 31,156
NGLs . . . . . . . . . . . . . . . . . . 5,190 3,280
Materials and supplies . . . . . . . . . 24,193 16,124
$212,134 $140,822
Refinery feedstock and refined product and blendstock inventory
volumes totalled 7.4 million barrels ("MMbbls") and 6.2 MMbbls as of
December 31, 1996 and 1995, respectively. Natural gas inventory volumes
totalled approximately 10 billion cubic feet ("Bcf") and 11.7 Bcf as of
December 31, 1996 and 1995, respectively.
Prepaid Expenses and Other
Prepaid expenses and other as of December 31, 1996 and 1995 were as
follows (in thousands):
December 31,
1996 1995
Commodity deposits and deferrals (see Note 6). . $18,914 $34,553
Prepaid insurance. . . . . . . . . . . . . . . . 6,737 8,663
Prepaid benefits expense . . . . . . . . . . . . 2,794 2,187
Other. . . . . . . . . . . . . . . . . . . . . . 1,501 1,918
$29,946 $47,321
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 under the composite method of depreciation. Gains or losses on
sales or other dispositions of major units of property are credited or
charged to income.
Major classes of property, plant and equipment as of December 31, 1996
and 1995 were as follows (in thousands):
December 31,
1996 1995
Refining and marketing - processing facilities. . $1,634,430 $1,596,832
Natural gas related services - transmission,
gathering, processing and storage facilities . . 988,234 945,408
Other . . . . . . . . . . . . . . . . . . . . . . 118,943 102,982
Construction in progress. . . . . . . . . . . . . 45,824 37,472
$2,787,431 $2,682,694
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. During early 1996, a detailed study of the
Company's fixed asset lives was completed by a third-party consultant for
the majority of the Company's refining and marketing and natural gas related
services assets. As a result of such study, effective January 1, 1996, the
Company adjusted the weighted-average remaining lives of the assets subject
to the study, utilizing the composite method of depreciation, to better
reflect the estimated periods during which such assets are expected to
remain in service. The effect of this change in accounting estimate on
depreciation expense for 1996 was insignificant. A summary of the principal
rates used in computing the annual provision for depreciation, primarily
utilizing the composite method and including estimated salvage values, is as
follows:
Weighted
Range Average
Refining and marketing - processing
facilities . . . . . . . . . . . . . . . . . 3.6% - 4.9% 4.4%
Natural gas related services - transmission,
gathering, processing and storage
facilities . . . . . . . . . . . . . . . . . 4.3% - 5.3% 4.7%
Other. . . . . . . . . . . . . . . . . . . . . 6% - 45% 25.3%
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 included in
noncurrent other assets was $26 million as of December 31, 1996. Such
amount is expected to be recovered over the next five years through natural
gas sales rates charged to certain customers.
Catalyst and Refinery Turnaround Costs
Catalyst costs are deferred when incurred and amortized over the
estimated useful life of that catalyst, normally one to three years.
Refinery turnaround costs are deferred when incurred and amortized over that
period of time estimated to lapse until the next turnaround occurs.
Other Deferred Charges
Other deferred charges consist of technological royalties and
licenses, contract costs, debt issuance costs, and certain other costs.
Technological royalties and licenses are amortized over the estimated useful
life of each particular related asset. Contract costs are amortized over
the term of the related contract. Debt issuance costs are amortized by the
effective interest method over the estimated life of each instrument or
facility.
Other Accrued Expenses
Other accrued expenses as of December 31, 1996 and 1995 were as
follows (in thousands):
December 31,
1996 1995
Accrued taxes. . . . . . . . . . . . . . . . . . . . .$19,633 $16,433
Other accrued employee benefit costs (see Note 13) . . 8,688 11,047
Current portion of accrued pension cost (see Note 13). 4,265 4,695
Accrued lease expense. . . . . . . . . . . . . . . . . 3,006 4,566
Other. . . . . . . . . . . . . . . . . . . . . . . . . 3,866 5,801
$39,458 $42,542
Fair Value of Financial Instruments
The carrying amounts of the Company's financial instruments
approximate fair value, except for long-term debt and certain financial
instruments used in price risk management activities. See Notes 5 and 6.
Earnings Per Share
Earnings per share of common stock were computed, after recognition
of preferred stock dividend requirements, based on the weighted average
number of common shares outstanding during each year. For the years ended
December 31, 1996, 1995 and 1994, the conversion of the Convertible
Preferred Stock (see Note 9) 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, 1996, 1995 and 1994 was 43,926,026, 43,651,914 and 43,369,836,
respectively.
Statements of Cash Flows
In order to determine net cash provided by operating activities, net
income has been adjusted by, among other things, changes in current assets
and current liabilities, excluding changes in cash and temporary cash
investments, cash held in debt service escrow for principal, current
deferred income tax assets, short-term debt and current maturities of
long-term debt. Also excluded are the Partnership's current assets and
liabilities as of the acquisition date (see Note 3). The changes in the
Company's current assets and current liabilities, excluding the items noted
above, are shown in the following table as an (increase) decrease in current
assets and an increase (decrease) in current liabilities. The Company's
temporary cash investments are highly liquid, low-risk debt instruments
which have a maturity of three months or less when acquired. (Dollars in
thousands.)
Year Ended December 31,
1996 1995 1994
Cash held in debt service
escrow for interest . . . . $ 756 $ 689 $(12,673)
Receivables, net. . . . . . . (226,899) (106,916) (64,150)
Inventories . . . . . . . . . (71,312) 41,267 (21,785)
Prepaid expenses and other. . 17,375 (22,304) 142
Accounts payable. . . . . . . 344,418 38,825 (4,295)
Accrued interest. . . . . . . (11,022) 11,411 3,901
Other accrued expenses. . . . (3,084) 5,392 3,263
Total . . . . . . . . . . . $ 50,232 $ (31,636) $(95,597)
The following table provides information related to cash interest and
income taxes paid by the Company for the periods indicated (in thousands):
Year Ended December 31,
1996 1995 1994
Interest - net of amount capitalized
of $4,328 (1996), $4,699 (1995) and
$2,365 (1994). . . . . . . . . . . . $105,519 $86,553 $72,023
Income taxes . . . . . . . . . . . . . 19,043 23,935 3,931
Noncash investing activities for 1995 included the reclassification
to "Deferred charges and other assets" of $12.1 million of contract costs,
previously included in "Property, plant and equipment" on the Consolidated
Balance Sheets. Noncash investing activities for 1994 included the accrual
of the remaining $60 million payment made in 1995 for the Company's interest
in a methanol plant renovation project.
Accounting Changes
In June 1996, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 125,
"Accounting for Transfers and Servicing of Financial Assets and
Extinguishments of Liabilities," which establishes new accounting and
reporting standards for transfers and servicing of financial assets and
extinguishments of liabilities. The statement is effective for transactions
occurring after December 31, 1996. Based on information currently known by
the Company, this statement will not have a material effect on the Company's
consolidated financial statements.
SFAS No. 123, "Accounting for Stock-Based Compensation," issued by
the FASB in October 1995, encourages, but does not require companies to
measure and recognize in their financial statements a compensation cost for
stock-based employee compensation plans based on the "fair value" method of
accounting set forth in the statement. The Company has chosen to continue
to account for its employee stock compensation plans using the "intrinsic
value" method of accounting set forth in Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
Interpretations. Accordingly, compensation cost for stock options is
measured as the excess, if any, of the quoted market price of the Company's
common stock at the date of the grant over the amount an employee must pay
to acquire the stock. See Note 13 for the pro forma effects on net income
and earnings per share had compensation cost for the Company's stock-based
compensation plans been determined consistent with SFAS No. 123.
Effective January 1, 1996, the Company adopted SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." This statement establishes accounting standards
for the impairment of long-lived assets, certain identifiable intangibles,
and goodwill related to assets to be held and used, and for long-lived
assets and certain identifiable intangibles to be disposed of. This
statement is required to be applied prospectively for assets to be held and
used, while its initial application to assets held for disposal is required
to be reported as the cumulative effect of a change in accounting principle.
Since adoption, no impairment losses have been recognized in the Company's
consolidated financial statements. However, see Note 7 for a discussion of
the Company's write-off in the fourth quarter of 1996 of its equity method
investment in its Mexico joint venture project.
Restatement of Financial Information
The Company has restated its financial statements for the years ended
December 31, 1996, 1995 and 1994. This action was taken to change the
accounting for a contingency which was recorded in conjunction with the
acquisition of VNGP, L.P. in May of 1994. For a further discussion of the
nature of the contingency, see Note 3, "Acquisition of Valero Natural Gas
Partners, L.P."
As of the date of the acquisition of VNGP, L.P., the Company's management
believed that it was probable that a liability had been incurred resulting
from the acquisition. Although the specific amount of the contingency could
not be determined as of the date of the acquisition, the Company believed that
the liability would be within a range of amounts that could be reasonably
estimated as of that date. Accordingly, the Company recorded a liability in
the amount of $14.8 million, representing the minimum amount of the range
determined by management. The liability was originally recorded as a cost of
the acquisition. Since the contingency arose as a result of the acquisition
and represented an obligation of the Company rather than an obligation of
VNGP, L.P., the income statement for 1994 has been restated to charge the
acquisition contingency to expense, rather than property, plant, and equipment,
as of the date of the acquisition. As a result of this change, the balances
of property, plant, and equipment, deferred income taxes, and retained earnings
have been restated in the Consolidated Balance Sheets as of December 31, 1996
and 1995. The impact of this change on the Consolidated Statement of Income
for the year ended December 31, 1994, is summarized below (dollars in
thousands):
Year Ended December 31, 1994
As Reported As Restated
Income before income taxes. . . . . . . . $42,782 $27,982
Income tax expense. . . . . . . . . . . . 15,900 10,700
Net income. . . . . . . . . . . . . . . . 26,882 17,282
Net income applicable to common stock . . 17,392 7,792
Earnings per share of commong stock . . . .40 .18
2. SUBSEQUENT EVENTS
Acquisition of Basis Petroleum, Inc.
The Company and Salomon Inc ("Salomon") have entered into a stock
purchase agreement pursuant to which Valero has acquired the stock of
Basis Petroleum, Inc. ("Basis") from Salomon for $285 million, plus
approximately $200 million for inventories and other working capital.
Basis owns and operates three petroleum refineries located in Texas and
Louisiana and markets refined products. The three refineries have a
total crude oil processing capacity of about 310,000 barrels per day.
The acquisition will be accounted for using the purchase method of
accounting. Therefore, the results of operations of Basis will be
included in the consolidated financial statements of the Company
commencing on May 1, 1997. The stock purchase agreement provides for
Salomon to receive up to 10 additional payments following each anniversary
date of the closing of the acquisition. These annual earn-out payments
would be based on the difference between a stated base refining "crack
spread" and the theoretical spread computed using actual average quoted
prices, and calculated using a nominal average annual throughput of
100 million barrels. These payments are limited to $35 million in any
year and $200 million in the aggregate. Any such participation payments,
if made, will be accounted for as an additional cost of the acquisition
of Basis by the Company and will be depreciated over the remaining lives
of the assets to which the additional cost is allocated. The purchase
price was paid, in part, with 3,429,796 shares of Energy common stock having
a fair market value of approximately $120 million, with the remainder paid
in cash.
Proposed Restructuring
In November 1996, the Company publicly announced that its Board of
Directors had approved a management recommendation to pursue strategic
alternatives involving the Company's principal business activities. Such
alternatives included seeking a strategic alliance for the Company's natural
gas related services business and a spin-off of its petroleum refining and
marketing operations. In response to the Company's solicitation for
indications of interest, a number of companies submitted written proposals
to engage in a strategic alliance with the Company, and the Company invited
a final group of five companies to participate in a more extensive due
diligence review. On January 31, 1997, the Company announced that its Board
of Directors had approved an agreement and plan of merger with PG&E
Corporation ("PG&E") to combine the Company's natural gas related services
business with PG&E following the spin-off of the Company's refining and
marketing business to the Company's shareholders (the "Restructuring").
Under the terms of the merger agreement, the Company's natural gas related
services business will be merged with a wholly owned subsidiary of PG&E.
PG&E will acquire the Company's natural gas related services business for
approximately $1.5 billion, plus adjustments for working capital and other
considerations. PG&E will issue $722.5 million of common stock, subject to
certain closing adjustments, in exchange for outstanding shares of Energy's
common stock, and will assume approximately $777.5 million of net debt and
other liabilities. Each Energy shareholder will receive a fractional share
of PG&E common stock (trading on the New York Stock Exchange under the
symbol "PCG") for each Energy share; the amount of PG&E stock to be received
will be based on the average price of the PG&E common stock during a period
preceding the closing of the transaction and the number of Energy shares
issued and outstanding at the time of the closing. Energy's shareholders
will also receive one share of the spun-off refining and marketing company
for each share of Energy common stock. The refining and marketing company
will retain the Valero Energy Corporation name and will apply to be listed
on the New York Stock Exchange. The refining and marketing company expects
to aggressively pursue acquisitions and strategic alliances in the refining
and marketing industry. The spin-off of the refining and marketing business
and the merger with PG&E are expected to be tax-free transactions. However,
on February 6, 1997, President Clinton's budget recommendations to Congress
called for new legislation that, if enacted, may require Energy to pay
federal income tax upon the consummation of the Restructuring on the amount
of gain equal to the excess of the value of the refining and marketing
company stock distributed to Energy's stockholders over Energy's basis in
such stock. Even though this legislation has not yet been introduced in
Congress, the proposal would be effective for distributions after the date
of first committee action. It is uncertain whether any such legislation
ultimately will be enacted, whether its effective date provision may be
modified, or when committee action in Congress may first occur. The
Company believes it is likely that any legislation ultimately enacted
will provide an exemption for transactions like the Restructuring for
which definitive agreements were executed prior to introduction of the
President's budget; however, if the proposal is enacted or pending prior
to consummation of the Restructuring with an effective date provision that
could cause Energy to be subject to tax, the tax opinions described below
may not be available. The Restructuring transactions are subject to
approval by the Company's shareholders, the Securities and Exchange
Commission, and certain regulatory agencies, and receipt of favorable
tax opinions. The Company expects to hold a special meeting of
stockholders (in lieu of an annual meeting) in June 1997 to consider the
Restructuring transactions; such transactions are expected to be completed
by mid-1997. However, there can be no assurance that the various approvals
or opinions will be given or that the conditions to consummating the
transactions will be met.
3. ACQUISITION OF VALERO NATURAL GAS PARTNERS, L.P.
In March 1994, Energy issued Convertible Preferred Stock (see Note 9)
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 was accounted for as a purchase and the purchase price was
allocated to the assets acquired and liabilities assumed based on estimated
fair values resulting in part from an independent appraisal of the property,
plant and equipment of the Partnership. The consolidated statements of
income of the Company 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 for
all periods thereafter.
In conjunction with the acquisition of the Partnership by the Company,
the Company recorded in 1994 a $14.8 million loss representing the Company's
estimate of certain costs resulting from the acquisition of the Public Units
of VNGP, L.P. See Note 1,"- Restatement of Financial Information." The
reserve was established as a result of various claims and lawsuits filed
against the Company to block the merger or to increase the price offered by
the Company for the purchase of the outstanding Public Units, and the
Company's determination that it was probable that losses were expected from
successful assertion of claims relative to the acquisition. In late 1996,
upon receipt by the Company of a favorable ruling by the magistrate hearing
the sole remaining lawsuit related to the acquisition (as described in Note
15), the Company reversed all remaining reserves pertaining to the
acquisition.
The following unaudited pro forma financial information of Valero
Energy Corporation and subsidiaries assumes that the above described
transactions occurred for all of 1994. Such pro forma information is not
necessarily indicative of the results of future operations.
Year Ended
December 31,
1994
(Thousands of dollars,
except per share amounts)
Operating revenues. . . . . . . . . . . . $2,333,982
Operating income. . . . . . . . . . . . . 125,943
Net income. . . . . . . . . . . . . . . . 9,789
Net loss applicable to common stock . . . (2,158)
Loss per share of common stock. . . . . . (.05)
Prior to the merger, the Company entered into transactions with the
Partnership commensurate with its status as the General Partner. The
Company charged the Partnership a management fee equal to the direct and
indirect costs incurred by it on behalf of the Partnership. In addition,
the Company purchased natural gas and NGLs from the Partnership and sold
NGLs to the Partnership. The Company paid the Partnership a fee for
operating certain of the Company's assets. Also, the Company and the
Partnership entered into other transactions, including certain leasing
transactions.
The following table summarizes transactions between the Company and
the Partnership for the five months ended May 31, 1994 (in thousands):
Five Months
Ended May 31,
1994
NGL purchases and services from the Partnership . . . . $36,536
Natural gas purchases from the Partnership. . . . . . . 9,672
Sales of NGLs and natural gas, and transportation
and other charges to the Partnership . . . . . . . . 11,385
Management fees billed to the Partnership for
direct and indirect costs. . . . . . . . . . . . . . 34,299
Interest income from capital lease transactions . . . . 5,481
4. SHORT-TERM DEBT
Energy currently maintains nine separate short-term bank lines of
credit totalling $190 million, $82 million of which was outstanding at
December 31, 1996 at a weighted average interest rate of 6.81%. Five of
these lines are cancellable on demand, and the others expire at various
times in 1997. 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.
5. LONG-TERM DEBT AND BANK CREDIT FACILITIES
Long-term debt balances as of December 31, 1996 and 1995 were as
follows (in thousands):
December 31,
1996 1995
Valero Refining and Marketing Company:
Industrial revenue bonds:
Marine terminal and pollution control revenue
bonds, Series 1987A bonds, 10 1/4%, due
June 1, 2017. . . . . . . . . . . . . . . . . $ 90,000 $ 90,000
Marine terminal revenue bonds, Series
1987B bonds, 10 5/8%, due June 1, 2008 . . . 8,500 8,500
Valero Energy Corporation:
$300 million revolving bank credit and
letter of credit facility, 6% at
December 31, 1996, due November 1, 2000. . . . 25,000 120,000
10.58% Senior Notes, due December 30, 2000. . . . 140,343 187,714
9.14% VESOP Notes, due February 15, 1999
(see Note 13) . . . . . . . . . . . . . . . . . 5,083 6,819
Medium-Term Notes . . . . . . . . . . . . . . . . 228,500 228,500
Valero Management Partnership, L.P. First
Mortgage Notes. . . . . . . . . . . . . . . . . . 443,215 476,072
Total long-term debt . . . . . . . . . . . . . . 940,641 1,117,605
Less current maturities. . . . . . . . . . . . . 72,341 81,964
$ 868,300 $1,035,641
Energy currently maintains an unsecured $300 million revolving bank
credit and letter of credit facility that is available for general corporate
purposes including working capital needs and letters of credit. Borrowings
under this facility bear interest at either LIBOR plus .50% (inclusive of a
facility fee), prime or a competitive money market rate. The Company is
also charged various fees, including various letter of credit fees. As of
December 31, 1996, Energy had approximately $273 million available under
this committed bank credit facility for additional borrowings and letters of
credit. Energy also has $170 million of uncommitted bank letter of credit
facilities, approximately $129 million of which were available as of
December 31, 1996 for additional letters of credit.
In 1992, Energy filed with the Securities and Exchange Commission
(the "Commission") a shelf registration statement which was used to offer
$150 million principal amount of Medium-Term Notes, $132 million of which
were outstanding at December 31, 1996. In 1994, Energy filed another shelf
registration statement with the Commission to offer up to $250 million
principal amount of additional debt securities, including Medium-Term Notes,
$96.5 million of which were issued and outstanding at December 31, 1996.
As of December 31, 1996, Energy's outstanding Medium-Term Notes had a
remaining weighted average life of approximately 7.5 years and a weighted
average interest rate of approximately 8.3%. No Medium-Term Notes have
been issued since June 1995 and none are expected to be issued in the
future.
The Management Partnership's First Mortgage Notes are currently
comprised of five remaining series due serially from 1997 through 2009, and
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, 1996,
the First Mortgage Notes had a remaining weighted average life of
approximately 5.5 years and a weighted average interest rate of 10.13% 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, 1996, $37.7
million had been deposited with the Mortgage Note Indenture trustee
("Trustee") in an escrow account. The amount on deposit is classified as a
current asset (cash held in debt service escrow) and the liability to be
paid off when the cash is released by the Trustee from escrow is classified
as a current liability.
The indenture of mortgage and deed of trust pursuant to which the
First Mortgage Notes were issued (the "Mortgage Note Indenture") contains
covenants prohibiting the Management Partnership and the Subsidiary
Operating Partnerships (collectively referred to herein as the "Operating
Partnerships") from incurring additional indebtedness, including any
additional First Mortgage Notes, other than (i) up to $50 million of
indebtedness to be incurred for working capital purposes (provided that for
a period of 45 consecutive days during each 16 consecutive calendar month
period no such indebtedness will be permitted to be outstanding) and (ii) up
to the amount of any future capital improvements financed through the
issuance of debt or equity by VNGP, L.P. and the contribution of such
amounts as additional equity to the Management Partnership. The Mortgage
Note Indenture also prohibits the Operating Partnerships from (a) creating
new indebtedness unless certain cash flow to debt service requirements are
met; (b) creating certain liens; or (c) making cash distributions in any
quarter in excess of the cash generated in the prior quarter, less (i)
capital expenditures during such prior quarter (other than capital
expenditures financed with certain permitted indebtedness), (ii) an amount
equal to one-half of the interest to be paid on the First Mortgage Notes on
the interest payment date occurring in or next following such prior quarter
and (iii) an amount equal to one-quarter of the principal required to be
paid on the First Mortgage Notes on the principal payment date occurring in
or next following such prior quarter, plus cash which could have been
distributed in any prior quarter but which was not distributed. The
Operating Partnerships are further prohibited from purchasing or owning any
securities of any person or making loans or capital contributions to any
person other than investments in the Subsidiary Operating Partnerships,
advances and contributions of up to $20 million per year and $100 million in
the aggregate to entities engaged in substantially similar business
activities as the Operating Partnerships, temporary investments in certain
marketable securities and certain other exceptions. The Mortgage Note
Indenture also prohibits the Operating Partnerships from consolidating with
or conveying, selling, leasing or otherwise disposing of all or any material
portion of their property, assets or business as an entirety to any other
person unless the surviving entity meets certain net worth requirements and
certain other conditions are met, or from selling or otherwise disposing of
any part of the Mortgaged Property, subject to certain exceptions.
The Company was in compliance with all covenants contained in its
various debt facilities as of December 31, 1996.
Based on long-term debt outstanding at December 31, 1996, maturities
of long-term debt, including sinking fund requirements and excluding
borrowings under bank credit facilities, for the years ending December 31,
1998 through 2001 are approximately $75 million, $73.2 million, $85.6
million and $94.5 million, respectively. Maturities of long-term debt under
Energy's revolving bank credit and letter of credit facility for the year
ended December 31, 2000 are $25 million.
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
$1,039 million and $1,275 million at December 31, 1996 and 1995,
respectively.
6. PRICE RISK MANAGEMENT ACTIVITIES
Refining and Marketing Hedging Activities
The Company uses over-the-counter price swaps, 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.
Swaps, options and futures contracts at the end of 1996 and 1995 had
remaining terms of less than one year. As of December 31, 1996 and 1995,
13% and 19%, respectively, of the Company's refining inventory position was
hedged. The amount of deferred hedge losses included as an increase to
refinery inventories was $.8 million and $1 million as of December 31, 1996
and 1995, respectively. The following is a summary of the contract amounts
and range of prices of the Company's contracts held or issued to hedge
refining inventories as of December 31, 1996 and 1995:
1996 1995
Payor Receiver Payor Receiver
Swaps:
Volumes (Mbbls). 497 497 - -
Price (per bbl). $17.50-$17.57 $17.31-$17.38 - -
Options:
Volumes (Mbbls). - - - 150
Price (per bbl). - - - $24.36-$24.78
Futures:
Volumes (Mbbls). - 981 250 1,327
Price (per bbl). - $24.87-$29.65 $22.71-$23.83 $17.57-$24.55
The Company also hedges anticipated transactions. Over-the-counter
price swaps, options and futures are used to hedge refining operating
margins for periods up to 12 months by locking in components of the margins,
including the resid discount, the conventional crack spread and the premium
product differentials. As of December 31, 1996 and 1995, less than 2% of
the Company's anticipated 1997 and 1996 refining margin, respectively, were
hedged. There were no significant explicit deferrals of hedging gains or
losses related to these anticipated transactions as of either year end.
The following table is a summary of the contract or notional amounts and
range of prices of the Company's contracts held or issued to hedge refining
margins as of December 31, 1996 and 1995. Volumes shown for swaps
represent notional volumes which are used to calculate amounts due under
the agreements and do not represent volumes exchanged.
1996 1995
Payor Receiver Receiver
Swaps:
Volumes (Mbbls). . 6,000 28,300 525
Price (per bbl). . $.53-$4.90 $.74-$3.55 $34.23-$35.81
Options:
Volumes (Mbbls). . 750 - -
Price (per bbl) . $25.00-$32.76 - -
Futures:
Volumes (Mbbls). . 1,312 1,410 14
Price (per bbl). . $26.46-$30.87 $21.74-$30.39 $18.95-$19.50
Natural Gas Related Services Hedging Activities
The Company uses futures, price swaps and over-the-counter and
exchange-traded options to hedge gas storage. These financial instrument
contracts run for periods of up to three months. The Company also enters
into basis swaps for location differentials at fixed prices which generally
extend for periods up to three months. As of December 31, 1996 and 1995, 59%
and 26%, respectively, of the Company's natural gas inventory position was
hedged. The amount of deferred hedge gains (losses) included as a reduction
(increase) of natural gas inventories was $(7.8) million and $.9 million as
of December 31, 1996 and 1995, respectively. The following is a summary of
the contract or notional amounts and range of prices of the Company's
contracts held or issued to hedge natural gas inventories as of December 31,
1996 and 1995. Volumes shown for swaps and basis swaps represent notional
volumes which are used to calculate amounts due under the agreements and do
not represent volumes exchanged.
1996 1995
Payor Receiver Payor Receiver
Swaps:
Volumes (MMcf) . 8,155 9,155 1,000 1,000
Price (per Mcf). $3.20-$4.37 $2.72-$4.25 $1.91 $2.87-$3.45
Options:
Volumes (MMcf) . 33,290 33,850 12,000 23,000
Price (per Mcf). $2.20-$2.60 $2.50-$3.30 $1.90-$2.50 $1.90-$2.50
Futures:
Volumes (MMcf) . 31,710 36,970 17,480 15,430
Price (per Mcf). $2.12-$4.57 $2.08-$4.37 $1.77-$3.45 $1.75-$3.45
Basis Swaps:
Volumes (MMcf) . 2,000 4,096 500 2,120
Price (per Mcf). $(.16)-$.32 $(.60)-$.19 $.63 $.13-$.85
The Company also uses futures, price swaps and over-the-counter and
exchange-traded options to hedge certain anticipated transactions, including
anticipated natural gas purchase requirements for NGL plant shrinkage and
refining operations, natural gas liquids sales, and commitments to buy and
sell natural gas at fixed prices. These financial instrument contracts
extend through the year 2001. The Company also enters into basis swaps for
location differentials at fixed prices which extend through the year 2001.
As of December 31, 1996 and 1995, 12% and 29%, respectively, of the
Company's anticipated annual NGL plant shrinkage requirements, and 11% and
29%, respectively, of Refining's anticipated annual natural gas
requirements, were hedged. Explicitly deferred gains from hedges of these
anticipated transactions of $24.4 million and $3.9 million, as of
December 31, 1996 and 1995, respectively, will be recognized when the
hedged transaction occurs. The following table is a summary of the contract
or notional amounts and range of prices of the Company's contracts held or
issued to hedge anticipated natural gas purchase requirements for NGL plant
shrinkage and refining operations, natural gas purchase and sales
commitments, and anticipated NGL production volumes as of December 31,
1996 and 1995. Volumes shown for swaps and basis swaps represent notional
volumes which are used to calculate amounts due under the agreements and do
not represent volumes exchanged.
<TABLE>
<CAPTION>
Total Total
Expected Maturity Date 1996 1995
1997 1998-2001 Balance Balance
Payor Receiver Payor Receiver Payor Receiver Payor Receiver
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Swaps:
Volumes (MMcf) . 28,353 13,327 14,422 - 42,775 13,327 55,277 26,111
Price (per Mcf).$1.54-$4.55 $1.65-$4.25 $2.06 - $1.54-$4.55 $1.65-$4.25 $1.31-$3.45 $1.71-$4.34
Volumes (Mbbls). 3,080 980 - - 3,080 980 - -
Price (per bbl).$9.35-$28.77 $10.71-$20.37 - - $9.35-$28.77 $10.71-$20.37 - -
Options:
Volumes (MMcf) . 26,565 21,195 - - 26,565 21,195 10,340 9,073
Price (per Mcf).$1.66-$3.50 $1.61-$4.00 - - $1.66-$3.50 $1.61-$4.00 $1.66-$3.25 $1.50-$2.45
Volumes (Mbbls). 75 975 - - 75 975 - -
Price (per bbl).$17.43 $14.07-$16.80 - - $17.43 $14.07-$16.80 - -
Futures:
Volumes (MMcf) . 90,810 82,200 740 - 91,550 82,200 105,020 52,680
Price (per Mcf).$1.72-$4.57 $1.75-$4.56 $2.35-$2.51 - $1.72-$4.57 $1.75-$4.56 $1.50-$3.45 $1.50-$3.61
Volumes (Mbbls). 1,223 1,803 - - 1,223 1,803 - -
Price (per bbl).$14.99-$28.81 $15.33-$27.62 - - $14.99-$28.81 $15.33-$27.62 - -
Basis Swaps:
Volumes (MMcf) . 32,296 36,961 11,224 40,470 43,520 77,431 16,787 98,541
Price (per Mcf).$(.66)-$.24 $(.32)-$.35 $(.52)-$(.06) $(.30)-$(.26) $(.66)-$.24 $(.32)-$.35 $.06-$1.06 $.03-$.85
</TABLE>
The following table discloses the carrying amount and fair value of
the Company's refining, natural gas and NGL contracts held or issued for
non-trading purposes as of December 31, 1996 and 1995 (dollars in
thousands):
1996 1995
Assets (Liabilities) Assets (Liabilities)
Carrying Fair Carrying Fair
Amount Value Amount Value
Swaps . . . . . . . $ 7,184 $13,853 $ 98 $1,557
Options . . . . . . . 1,101 (2,638) (91) 429
Futures . . . . . . . 21,116 21,116 217 217
Basis Swaps. . . . . . - 2,809 - 5,823
Total . . . . . . . $29,401 $35,140 $224 $8,026
Trading Activities
The Company enters into transactions for trading purposes using its
fundamental and technical analysis of market conditions to earn additional
revenues. The types of instruments used include futures, price swaps, basis
swaps and over-the-counter and exchange-traded options. Except in limited
circumstances, these contracts run for periods of up to 12 months, with the
exception of basis swaps which extend through the year 2000. The following
table is a summary of the contract amounts and range of prices of the
Company's contracts held or issued for trading purposes as of December 31,
1996 and 1995:
<TABLE>
<CAPTION>
Total Total
Expected Maturity Date 1996 1995
1997 1998-2000 Balance Balance
Payor Receiver Payor Receiver Payor Receiver Payor Receiver
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Swaps:
Volumes (MMcf) . 4,520 4,160 - - 4,520 4,160 23,430 24,950
Price (per Mcf).$3.25-$4.25 $3.15 -$4.25 - - $3.25 -$4.25 $3.15-$4.25 $1.79-$3.44 $1.71-$3.44
Volumes (Mbbls). 400 400 - - 400 400 2,925 2,250
Price (per bbl).$4.25-$4.55 $4.20-$4.72 - - $4.25-$4.55 $4.20-$4.72 $1.80-$4.14 $2.40-$4.18
Options:
Volumes (MMcf) . 15,000 15,310 - - 15,000 15,310 36,100 18,000
Price (per Mcf).$2.10-$5.20 $1.65-$5.20 - - $2.10-$5.20 $1.65-$5.20 $1.60-$3.25 $1.60-$2.40
Volumes (Mbbls). - 275 - - - 275 - 150
Price (per bbl). - $25.20 - - - $25.20 - $17.50-$19.00
Futures:
Volumes (MMcf) . 39,420 41,390 - - 39,420 41,390 63,650 59,280
Price (per Mcf).$1.87-$4.50 $2.09-$4.58 - - $1.87-$4.50 $2.09-$4.58 $1.64-$3.44 $1.67-$3.67
Volumes (Mbbls). - - - - - - 100 450
Price (per bbl). - - - - - - $23.42-$23.44 $18.24-$19.00
Basis Swaps:
Volumes (MMcf) . 27,000 30,460 11,850 27,275 38,850 57,735 11,620 42,000
Price (per Mcf).$(.32)-$.38 $(.32)-$.40 $(.10)-$(.10) $(.08)-$(.05) $(.32)-$.38 $(.32)-$.40 $.07-$.47 $.03-$.22
</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 periods ended December 31, 1996 and 1995 (dollars in
thousands):
Fair Value of Assets (Liabilities)
Average Ending Net Gains(Losses)
1996 1995 1996 1995 1996 1995
Swaps. . . . .$ (102) $ (329) $ (560) $ 245 $ 613 $(2,143)
Options. . . . (93) 1,026 (1,047) 297 8,270 (3,273)
Futures. . . . 1,951 2,030 926 6,739 4,016 8,822
Basis Swaps. . 1,705 487 1,072 1,266 277 2,706
Total. . . .$3,461 $3,214 $ 391 $8,547 $13,176 $ 6,112
Market and Credit Risk
The Company's price risk management activities involve the receipt or
payment of fixed price commitments into the future. These transactions give
rise to market risk, the risk that future changes in market conditions may
make an instrument less valuable. The Company closely monitors and manages
its exposure to market risk on a daily basis in accordance with policies
limiting net open positions. Concentrations of customers in the refining
and natural gas industries may impact the Company's overall exposure to
credit risk, in that the customers in each specific industry may be
similarly affected by changes in economic or other conditions. The Company
believes that its counterparties will be able to satisfy their obligations
under contracts.
7. INVESTMENTS
The Company currently owns a 35% interest in Productos Ecologicos,
S.A. de C.V. ("Proesa"), a Mexican corporation which is involved in a
project (the "Project") to design, construct and operate a plant in Mexico
to produce methyl tertiary butyl ether ("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"). Beginning in December 1994, the
Mexican peso experienced substantial devaluation, interest rates in Mexico
increased significantly and Mexican economic conditions deteriorated.
Because of these factors, in January 1995 the Board of Directors of Energy
determined that the Company would suspend further investment in the Project
pending the resolution of certain key issues. During 1995 and continuing in
1996, the Project participants engaged in negotiations among themselves and
with potential additional participants in an attempt to restructure the
participants' ownership interests in Proesa and arrange funding for the
Project. To date, financing on terms satisfactory to the participants has
not been available. During the fourth quarter of 1996, the Company
determined that it is unlikely that the Project can go forward.
Accordingly, the Company wrote off its $16.5 million investment in Proesa
and accrued a provision for additional liabilities associated with such
investment of $3 million.
8. REDEEMABLE PREFERRED STOCK
In December of 1996, Energy redeemed 57,500 shares ($5,750,000) of
its Cumulative Preferred Stock, $8.50 Series A ("Series A Preferred Stock"),
at $100 per share. The redemption of the remaining balance (11,500 shares
or $1,150,000) is expected to occur prior to December 1, 1997.
9. CONVERTIBLE PREFERRED STOCK
In March 1994, Energy issued 3,450,000 shares of its $3.125
convertible preferred stock ("Convertible Preferred Stock") with a stated
value of $50 per share and received cash proceeds, net of underwriting
discounts, of approximately $168 million. Each share of Convertible
Preferred Stock is convertible at the option of the holder into shares of
Energy common stock ("Common Stock") at an initial conversion price of
$27.03. The Convertible Preferred Stock may not be redeemed prior to
June 1, 1997. Thereafter, the Convertible Preferred Stock may be redeemed,
in whole or in part at the option of Energy, at a redemption price of
$52.188 per share through May 31, 1998, and at ratably declining prices
thereafter, plus dividends accrued to the redemption date.
10. PREFERENCE SHARE PURCHASE RIGHTS
On November 25, 1995, Energy made a dividend distribution of one
Preference Share Purchase Right ("Right") for each outstanding share of
Common Stock, replacing similar expiring rights distributed on November 25,
1985. Until exercisable, the Rights are not transferable apart from Common
Stock. Each Right will entitle shareholders to buy one-hundredth (1/100) of
a share of a newly issued series of Junior Participating Serial Preference
Stock, Series III, at an exercise price of $75 per Right.
<PAGE>
11. INDUSTRY SEGMENT INFORMATION
<TABLE>
<CAPTION>
Year Ended December 31,
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Operating revenues:
Refining and marketing. . . . . . . . . . . . . . . . . $2,757,801 $1,950,657 $1,090,368
Natural gas related services. . . . . . . . . . . . . . 2,445,504 1,396,468 784,287
Other . . . . . . . . . . . . . . . . . . . . . . . . . 123 126 42,639
Intersegment eliminations . . . . . . . . . . . . . . . (212,747) (149,379) (79,854)
Total . . . . . . . . . . . . . . . . . . . . . . . . $4,990,681 $3,197,872 $1,837,440
Operating income (loss):
Refining and marketing. . . . . . . . . . . . . . . . . $ 110,046 $ 141,512 $ 78,660
Natural gas related services. . . . . . . . . . . . . . 132,178 83,180 61,944
Corporate general and administrative
expenses and other, net . . . . . . . . . . . . . . . (41,315) (35,901) (14,679)
Total . . . . . . . . . . . . . . . . . . . . . . . 200,909 188,791 125,925
Equity in earnings (losses) of and income from:
Valero Natural Gas Partners, L.P. . . . . . . . . . . . - - (10,698)
Joint ventures. . . . . . . . . . . . . . . . . . . . . 3,899 4,827 2,437
Loss on investment in Proesa joint venture. . . . . . . . (19,549) - -
(Provision for) reversal of acquisition expense accrual . 18,698 (2,506) (16,192)
Other income, net . . . . . . . . . . . . . . . . . . . . 4,921 5,248 3,431
Interest and debt expense, net. . . . . . . . . . . . . . (95,177) (101,222) (76,921)
Income before income taxes. . . . . . . . . . . . . . . $ 113,701 $ 95,138 $ 27,982
Identifiable assets:
Refining and marketing. . . . . . . . . . . . . . . . . $1,621,998 $1,524,065 $1,528,621
Natural gas related services. . . . . . . . . . . . . . 1,366,050 1,162,724 1,119,347
Other . . . . . . . . . . . . . . . . . . . . . . . . . 145,248 150,141 149,688
Investment in and advances to joint ventures. . . . . . 29,192 41,890 41,162
Intersegment eliminations and reclassifications . . . . (27,714) (16,940) (22,260)
Total . . . . . . . . . . . . . . . . . . . . . . . . $3,134,774 $2,861,880 $2,816,558
Depreciation expense:
Refining and marketing. . . . . . . . . . . . . . . . . $ 52,680 $ 55,032 $ 52,956
Natural gas related services. . . . . . . . . . . . . . 44,211 40,881 26,636
Other . . . . . . . . . . . . . . . . . . . . . . . . . 4,896 4,412 4,440
Total . . . . . . . . . . . . . . . . . . . . . . . . $ 101,787 $ 100,325 $ 84,032
Capital additions:
Refining and marketing. . . . . . . . . . . . . . . . . $ 56,673 $ 29,039 $ 119,748
Natural gas related services. . . . . . . . . . . . . . 65,671 33,489 18,860
Other . . . . . . . . . . . . . . . . . . . . . . . . . 6,109 2,091 2,130
Total . . . . . . . . . . . . . . . . . . . . . . . . $ 128,453 $ 64,619 $ 140,738
</TABLE>
The Company's core businesses are specialized refining and natural
gas related services. Effective January 1, 1996, the Company's natural gas
and NGL businesses were reported as one industry segment for financial
reporting purposes (described herein as "natural gas related services") in
recognition of the Company's increasing integration of these business
activities due to the restructuring of the interstate natural gas pipeline
industry in 1993 through FERC Order 636 and the resulting transformation of
the U.S. natural gas industry into a more market and customer-oriented
environment. The Company's ability to gather, transport, market and process
natural gas, among other things, are value-added services offered to
producers and attract additional quantities of gas to the Company's pipeline
system and processing plants through integrated business arrangements.
Prior to 1996, the Company's natural gas and NGL businesses were reported as
separate industry segments. The primary effect of this change on the
Company's segment disclosures was the elimination of volume, revenue and
income amounts related to natural gas fuel and shrinkage volumes sold to and
transported for the natural gas liquids segment by the natural gas segment.
Amounts for 1995 and 1994 shown above have been restated to conform to the
1996 presentation.
At its refinery in Corpus Christi, Refining converts high-sulfur
atmospheric residual oil into premium products, primarily reformulated
gasoline ("RFG"), and sells those products principally on a spot, truck rack
and term contract basis. Spot and term sales of Refining's products are
made principally to larger oil companies and gasoline distributors in the
northeastern, midwestern and southeastern United States. In 1996, the
Company also began sales of "CARB" gasoline into the West Coast market in
connection with the startup of the California Air Resources Board's
statewide CARB gasoline program. This program requires the use of gasoline
which meets more restrictive air quality specifications than the federally
mandated RFG. The principal purchasers of Refining's products from truck
racks have been wholesalers and jobbers in the eastern and midwestern United
States. The Company's natural gas related services business consists of:
purchasing, gathering, processing, storing, transporting and selling natural
gas, principally to gas distribution companies, electric utilities, pipeline
companies and industrial customers; transporting natural gas for producers,
other pipelines and end users in North America; extracting natural gas
liquids, principally from natural gas throughput of the Company's pipeline
operations; fractionating, transporting and selling natural gas liquids,
principally to petrochemical plants, refineries and domestic fuel
distributors in the Corpus Christi and Mont Belvieu (Houston) areas; and
marketing electric power throughout the United States. Intersegment revenue
eliminations relate primarily to the refining and marketing segment's
purchases of feedstocks and fuel gas from the natural gas related services
segment. In 1996, the Company had no significant amount of export sales and
no significant foreign operations, and no single customer accounted for more
than 10% of the Company's 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 3). Capital additions in 1994 include the accrual of
the remaining $60 million payment made in 1995 for the Company's interest in
a methanol plant renovation project.
12. INCOME TAXES
Components of income tax expense were as follows (in thousands):
Year Ended December 31,
1996 1995 1994
Current:
Federal. . . . . . . . . . . $20,996 $29,674 $ 3,535
State. . . . . . . . . . . . 4 926 165
Total current . . . . . . 21,000 30,600 3,700
Deferred:
Federal. . . . . . . . . . . 20,000 4,700 7,000
Total income tax expense. $41,000 $35,300 $10,700
Total income tax expense differs from the amount computed by applying
the statutory federal income tax rate to income before income taxes. The
reasons for these differences are as follows (in thousands):
Year Ended December 31,
1996 1995 1994
Federal income tax expense
at the statutory rate. . . . $39,800 $33,300 $ 9,800
State income taxes, net of
federal income tax benefit . - 600 100
Other - net. . . . . . . . . . 1,200 1,400 800
Total income tax expense . $41,000 $35,300 $10,700
The tax effects of significant temporary differences representing
deferred income tax assets and liabilities are as follows (in thousands):
December 31,
1996 1995
Deferred income tax assets:
Tax credit carryforwards . . . . . . $ 21,835 $ 33,001
Other. . . . . . . . . . . . . . . . 43,214 25,570
Total deferred income tax assets . $ 65,049 $ 58,571
Deferred income tax liabilities:
Depreciation . . . . . . . . . . . . $(291,315) $(262,700)
Other. . . . . . . . . . . . . . . . (31,264) (37,154)
Total deferred income tax
liabilities. . . . . . . . . . . $(322,579) $(299,854)
At December 31, 1996, the Company had an alternative minimum tax
("AMT") credit carryforward of approximately $21.3 million which is
available to reduce future federal income tax liabilities. The AMT credit
carryforward has no expiration date. The Company has not recorded any
valuation allowances against deferred income tax assets as of December 31,
1996.
The Company's taxable years through 1992 are closed to adjustment by
the Internal Revenue Service. The Company believes that adequate provisions
for income taxes have been reflected in its consolidated financial
statements.
13. 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, 1996 and 1995 (in thousands):
December 31,
1996 1995
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $76,448 (1996) and $65,420 (1995). . . . . .$78,441 $66,085
Projected benefit obligation for services rendered to date .$99,435 $87,609
Plan assets at fair value. . . . . . . . . . . . . . . . . . 92,486 68,619
Projected benefit obligation in excess of plan assets. . . . 6,949 18,990
Unrecognized net gain from past experience different
from that assumed. . . . . . . . . . . . . . . . . . . . . 5,700 2,335
Prior service cost not yet recognized in net periodic
pension cost . . . . . . . . . . . . . . . . . . . . . . . (5,305) (5,033)
Unrecognized net asset at beginning of year. . . . . . . . . 1,341 1,483
Additional minimum liability accrual . . . . . . . . . . . . - 1,948
Accrued pension cost . . . . . . . . . . . . . . . . . . .$ 8,685 $19,723
Net periodic pension cost for the years ended December 31, 1996, 1995
and 1994 included the following components (in thousands):
Year Ended December 31,
1996 1995 1994
Service cost - benefits earned during
the period . . . . . . . . . . . . . $ 4,622 $ 3,465 $ 3,981
Interest cost on projected benefit
obligation . . . . . . . . . . . . . 6,309 5,455 4,990
Actual (return) loss on plan assets. . (12,424) (14,376) 1,820
Net amortization and deferral. . . . . 6,651 9,637 (6,135)
Net periodic pension cost. . . . . $ 5,158 $ 4,181 $ 4,656
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 the latest 10 years of credited service under the plan.
The weighted-average discount rate used in determining the actuarial present
value of the projected benefit obligation was 7.25% as of December 31, 1996
and 1995. The rate of increase in future compensation levels used in
determining the projected benefit obligation as of December 31, 1996 and
1995 was 4% for nonexempt personnel and 3% for exempt personnel. The
expected long-term rate of return on plan assets was 9.25% as of
December 31, 1996 and 1995. 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 1996,
1995 and 1994 were approximately $14.2 million, $4.3 million and $5 million,
respectively, and are currently estimated to be $4.3 million in 1997. The
tables at the beginning of this note include amounts related to the SERP.
The Company is the sponsor of the Valero Energy Corporation Thrift
Plan ("Thrift Plan") which is an employee profit sharing plan.
Participation in the Thrift Plan is voluntary and is open to employees of
the Company who become eligible to participate following the completion of
three months of continuous employment. Participating employees may make a
base contribution from 2% up to 8% of their annual base salary, depending
upon months of contributions by a participant. Thrift Plan participants are
automatically enrolled in the VESOP (see below). The Company makes
contributions to the Thrift Plan to the extent employees' base contributions
exceed the amount of the Company's contribution to the VESOP for debt
service. Prior to 1994, the Company matched 100% of the employee
contributions. In 1994, the Thrift Plan was amended to provide for a total
Company match in both the Thrift Plan and the VESOP aggregating 75% of
employee base contributions, with an additional contribution of up to 25%
subject to certain conditions. Participants may also make a supplemental
contribution to the Thrift Plan of up to an additional 10% of their annual
base salary which is not matched by the Company. There were no Company
contributions to the Thrift Plan in 1996 or 1995, while approximately
$42,000 was contributed during 1994.
In 1989, the Company established the Valero Employees' Stock
Ownership Plan ("VESOP") which is a leveraged employee stock ownership plan.
Pursuant to a private placement in 1989, the VESOP issued notes in the
principal amount of $15 million, maturing February 15, 1999 (the "VESOP
Notes"). The net proceeds from this private placement were used by the
VESOP trustee to fund the purchase of Common Stock. During 1991, the
Company made an additional loan of $8 million to the VESOP which was also
used by the Trustee to purchase Common Stock. This second VESOP loan
matures on August 15, 2001. The number of shares of Common Stock released
at any semi-annual payment date is based on the proportion of debt service
paid during the year to remaining debt service for that and all subsequent
periods times the number of unreleased shares then outstanding. As
explained above, the Company's annual contribution to the Thrift Plan is
reduced by the Company's contribution to the VESOP for debt service. During
1996, 1995 and 1994, the Company contributed $3,372,000, $3,170,000 and
$3,160,000, respectively, to the VESOP, comprised of $525,000, $678,000 and
$819,000, respectively, of interest on the VESOP Notes and $3,072,000,
$2,918,000 and $2,777,000, respectively, of compensation expense.
Compensation expense is based on the VESOP debt principal payments for the
portion of the VESOP established in 1989 and 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. Dividends paid on unallocated shares were used to reduce
the Company's contributions to the VESOP during 1996, 1995 and 1994 by
$225,000, $426,000 and $436,000, respectively. VESOP shares of Common Stock
are considered outstanding for earnings per share computations. As of
December 31, 1996 and 1995, the number of allocated shares were 1,052,454
and 940,470, respectively, the number of committed-to-be-released shares
were 62,918 and 62,918, respectively, and the number of suspense shares were
583,301 and 772,055, 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 offered by the Company through a self-insured plan
and a health maintenance organization 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, 1996 and
1995 (in thousands):
December 31,
1996 1995
Accumulated benefit obligation:
Retirees. . . . . . . . . . . . . . . . . $11,930 $10,295
Fully eligible active plan participants . 390 331
Other active plan participants. . . . . . 17,571 13,504
Total accumulated benefit obligation. . 29,891 24,130
Unrecognized loss . . . . . . . . . . . . . (4,498) (4,586)
Unrecognized prior service cost . . . . . . (3,909) -
Unrecognized transition obligation. . . . . (10,334) (10,987)
Accrued postretirement benefit cost . . . $11,150 $ 8,557
Net periodic postretirement benefit cost for the years ended
December 31, 1996, 1995 and 1994 included the following components (in
thousands):
December 31,
1996 1995 1994
Service cost - benefits attributed to service during
the period. . . . . . . . . . . . . . . . . . . . . $1,091 $ 860 $1,196
Interest cost on accumulated benefit obligation . . . 1,716 1,769 1,686
Amortization of unrecognized transition obligation. . 653 766 948
Amortization of prior service cost. . . . . . . . . . - - (84)
Amortization of unrecognized net loss . . . . . . . . 110 - 75
Net periodic postretirement benefit cost. . . . . $3,570 $3,395 $3,821
For measurement purposes, the assumed health care cost trend rate was
7% in 1996, 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, 1996 by $5.2 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit cost for the
year then ended by $.7 million. The weighted-average discount rate used in
determining the accumulated postretirement benefit obligation as of
December 31, 1996 and 1995 was 7.25%.
Stock Option and Bonus Plans
As of December 31, 1996, the Company has various fixed and
performance-based stock compensation plans which are described below. The
Company applies APB Opinion No. 25 and related Interpretations in accounting
for its plans. Accordingly, no compensation cost has been recognized for
its fixed stock option plans. The compensation cost reflected in net income
for its stock-based compensation plans was $2.6 million and $1.7 million for
1996 and 1995, respectively. Had compensation cost for the Company's
stock-based compensation plans been determined based on the fair value at
the grant dates for 1996 and 1995 awards under those plans consistent with
the method of SFAS No. 123, the Company's net income and earnings per share
for the years ended December 31, 1996 and 1995 would have been reduced to the
pro forma amounts indicated below:
December 31,
1996 1995
Net Income . . . . . As Reported $72,701 $59,838
Pro Forma $70,427 $58,373
Earnings per share . As Reported $ 1.40 $ 1.10
Pro Forma $ 1.35 $ 1.07
Because the SFAS No. 123 method of accounting has not been applied to
awards granted prior to January 1, 1995, the resulting pro forma
compensation cost may not be representative of that to be expected in future
years.
The Company's Executive Stock Incentive Plan (the "ESIP") authorizes
the grant of various stock and stock-related awards to executive officers
and other key employees. Awards available under the ESIP include options to
purchase shares of Common Stock, stock appreciation rights ("SARs"),
restricted stock, performance awards and other stock-based awards. A total
of 2,100,000 shares may be issued under the ESIP, of which no more than
750,000 shares may be issued as restricted stock. Under the ESIP, 110,500
options, 97,000 shares of restricted stock and 64,830 shares under
performance awards were granted during 1996, while 1,043,581 awards were
available for grant as of December 31, 1996. In addition to options
available under the ESIP, the Company also has three non-qualified stock
option plans, Stock Option Plan No. 5, Stock Option Plan No. 4, and Stock
Option Plan No. 3, collectively referred to herein as the "Stock Option
Plans," and a non-employee director stock option plan. Awards under the
Stock Option Plans are granted to key officers, employees and prospective
employees of the Company. As of December 31, 1996, there were 46,705 and
48,000 shares available for grant under the Stock Option Plans and
non-employee director plan, respectively.
Under the terms of the ESIP, the Stock Option Plans and the
non-employee director plan, the exercise price of the options granted will
not be less than 100%, 75%, or 100%, respectively, of the fair market value
of Common Stock at the date of grant. As of December 31, 1996, all
outstanding options contain exercise prices not less than fair market value
at date of grant. Stock options become exercisable pursuant to the
individual written agreements between the Company and the participants,
generally either at the end of a three-year period beginning on the date
of grant or in three equal annual installments beginning one year after
the date of grant, with unexercised options expiring ten years from the
date of grant. A summary of the status of the Company's stock option plans,
including options granted under the ESIP, the Stock Option Plans and the
non-employee director plan, as of December 31, 1996, 1995, and 1994, and
changes during the years then ended is presented in the table below:
<TABLE>
<CAPTION>
1996 1995 1994
Weighted- Weighted- Weighted-
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning
of year. . . . . . . . . . 3,928,267 $20.69 2,575,902 $21.51 1,261,624 $23.69
Granted . . . . . . . . . . 757,920 27.44 1,599,463 18.99 1,343,919 19.43
Exercised. . . . . . . . . . (418,117) 19.28 (171,604) 17.08 (7,555) 14.53
Forfeited. . . . . . . . . . (38,978) 22.17 (74,428) 21.12 (22,086) 21.90
Expired . . . . . . . . . . - - (1,066) 18.36 - -
Outstanding at end
of year. . . . . . . . . . 4,229,092 22.02 3,928,267 20.69 2,575,902 21.51
Exercisable at end
of year. . . . . . . . . . 2,525,957 21.71 1,531,718 22.30 708,055 23.13
Weighted-average fair
value of options
granted. . . . . . . . . . $6.25 $4.50 N/A
</TABLE>
The following table summarizes information about stock options
outstanding under the ESIP, the Stock Option Plans and the non-employee
director plan as of December 31, 1996:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
Range Number Weighted-Avg. Number
of Outstanding Remaining Weighted-Avg. Exercisable Weighted-Avg.
Exercise Prices at 12/31/96 Contractual Life Exercise Price at 12/31/96 Exercise Price
<S> <C> <C> <C> <C> <C>
$14.52-$21.88 2,460,074 7.5 years $19.02 1,499,074 $19.17
$22.13-$29.75 1,769,018 7.4 26.20 1,026,883 25.41
$14.52-$29.75 4,229,092 7.5 22.02 2,525,957 21.71
</TABLE>
The fair value of each option grant was estimated on the date of
grant using the Black-Scholes option-pricing model with the following
weighted-average assumptions used for grants in 1996 and 1995, respectively:
risk-free interest rates of 6.4 percent and 6.7 percent; expected
dividend yields of 1.9 percent and 2.8 percent; expected lives of 3.1
years and 3.2 years; and expected volatility of 25.5 percent and 29.5
percent.
For each share of stock that can be purchased thereunder pursuant to
a stock option, Stock Option Plans No. 3 and 4 provide that a SAR may also
be granted. A SAR is a right to receive a cash payment equal to the
difference between the fair market value of Common Stock on the exercise
date and the option price of the stock to which the SAR is related. SARs
under Stock Option Plans No. 3 and 4 are exercisable only upon the exercise
of the related stock options. At the end of each reporting period within
the exercise period, the Company records an adjustment to deferred
compensation expense based on the difference between the fair market value
of Common Stock at the end of each reporting period and the option price of
the stock to which the SAR is related. As of December 31, 1996, 89,087 SARs
were outstanding and exercisable, at a weighted-average exercise price of
$14.52 per share. During 1996, 21,316 SARs were exercised at a weighted-
average exercise price of $14.52 per share and 600 SARs were forfeited.
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. As
of December 31, 1996, there were 6,927 shares available for award. No
shares were awarded under this plan in 1996, while 9,000 and 3,000 shares
were awarded under this plan during 1995 and 1994, respectively. 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.
14. LEASE AND OTHER COMMITMENTS
The Company has major long-term operating lease commitments in
connection with a gas storage facility, its corporate headquarters office
complex and various facilities and equipment used to store, transport and
produce refinery feedstocks and/or refined products. The gas storage
facility lease has a remaining primary term of three years, and, subject to
certain conditions, one eight-year optional renewal period during which the
lease payments decrease by one-half and one or more additional optional
renewal periods of five years each at fair market rentals. The corporate
headquarters lease has a remaining primary term of 15 years with five
optional renewal periods of five years each. In 1996, the Company entered
into a sublease agreement for unused space in its corporate headquarters
office complex. The sublease has a primary term of 20 years, with the
sublessee having an option to terminate the lease after 10 years. The
sublessee is occupying the premises in phases, with full occupancy currently
expected in 1997. The Company's long-term refinery feedstock and refined
product storage and transportation leases have remaining primary terms
of up to 5.3 years with optional renewal periods of up to 10 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 of up to 10 years for
significant leases. The related future minimum lease payments as of
December 31, 1996, including amounts to be received under the corporate
headquarters office complex sublease, are as follows (in thousands):
<TABLE>
<CAPTION>
Gas
Storage Office
Facility Complex Refining Other
Primary
Lease Sublease
<S> <C> <C> <C> <C> <C>
1997 . . . . . . . . . . . $ 9,832 $ 4,570 $ (2,088) $ 6,028 $1,502
1998 . . . . . . . . . . . 10,156 4,570 (2,088) 7,886 1,490
1999 . . . . . . . . . . . 10,438 4,570 (2,088) 7,761 966
2000 . . . . . . . . . . . 5,221 4,570 (2,088) 4,977 292
2001 . . . . . . . . . . . - 4,570 (2,088) 4,075 134
Remainder. . . . . . . . . - 40,771 (9,971) 1,359 616
Total minimum lease
payments. . . . . . . . $35,647 $63,621 $(20,411) $32,086 $5,000
</TABLE>
The future minimum lease payments listed above exclude operating leases
having initial or remaining noncancelable lease terms of one year or less.
Consolidated rental expense under operating leases, excluding amounts paid
in connection with the gas storage facility and net of amounts related to
the office complex sublease, amounted to approximately $31,663,000,
$29,313,000, and $14,040,000 for 1996, 1995 and 1994 (including Partnership
rents commencing June 1, 1994), 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 of
VNGP, L.P. with Energy, 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 such merger.
Gas storage facility rentals paid by the Partnership for the period
prior to the VNGP, L.P. merger, and paid by the Company for the period
subsequent to the such merger, totalling $10,438,000 per year for 1996,
1995 and 1994, 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.
15. LITIGATION AND CONTINGENCIES
City of Edinburg and Related Litigation. The Company and Southern
Union Company ("Southern Union") are defendants in a lawsuit brought by the
City of Edinburg, Texas (the "City") regarding certain ordinances of the
City that granted franchises to Rio Grande Valley Gas Company ("RGV") and
its predecessors allowing RGV to sell and distribute natural gas within the
City. RGV was formerly owned by Energy. On September 30, 1993, Energy sold
the common stock of RGV to Southern Union. The City alleges that the
defendants used RGV's facilities to sell or transport natural gas in
Edinburg in violation of the ordinances and franchises granted by the City,
and that RGV (now Southern Union) has not fully paid all franchise fees due
the City. The City also alleges that the defendants used the public
property of the City without compensating the City for such use, and alleges
conspiracy and alter ego claims involving all defendants. The City seeks
alleged actual damages of $50 million and unspecified punitive damages
related to amounts allegedly due under the RGV franchise, City ordinances
and state law. In addition, the City of Pharr, Texas, filed an intervention
seeking certification of a class, with itself as class representative,
consisting of all cities served by franchise by Southern Union. The court
certified the class and severed the claims of the City of Pharr and the
class from the original City of Edinburg lawsuit. The City of Pharr
subsequently amended its petition deleting all Valero entities as
defendants. The original trial judge was disqualified upon motion of the
defendants (such disqualification was upheld on appeal), and a new trial
judge has been assigned to preside over both the City of Edinburg and City
of Pharr litigation. The City of Edinburg lawsuit is scheduled for trial on
August 11, 1997. In 1996, the South Texas cities of Alton and Donna also
independently intervened as plaintiffs in the Edinburg lawsuit filed in the
92nd State District Court in Hidalgo County. These lawsuits subsequently
were severed from the Edinburg lawsuit. The claims asserted by the cities
of Alton and Donna are substantially similar to the Edinburg litigation
claims. Damages are not quantified. In connection with the City of
Edinburg lawsuit, Southern Union filed a cross-claim against Energy,
alleging, among other things, that Southern Union is entitled to
indemnification pursuant to the purchase agreement under which Energy sold
RGV to Southern Union. Southern Union also asserts claims related to a 1985
settlement among Energy, RGV and the Railroad Commission of Texas regarding
certain gas contract pricing terms. This pricing claim was recently severed
into a separate lawsuit. Southern Union's claims include, among other
things, damages for indemnification, breach of contract, negligent
misrepresentation and fraud. Three additional lawsuits were filed during
December 1996 by certain other municipalities in South Texas making
allegations substantially similar to those in the City of Edinburg
litigation. In these three lawsuits, the defendants are alleged to have
excluded certain revenues from their calculations of franchise taxes and are
alleged to have provided unauthorized gas transportation services to third
parties. The plaintiffs seek actual and exemplary, but as yet, unspecified,
damages.
Teco Pipeline Company. Energy and certain of its subsidiaries have
been sued by Teco Pipeline Company ("Teco") regarding the operation of the
Company's 340-mile West Texas pipeline. In 1985, a subsidiary of Energy
sold a 50% undivided interest in the pipeline and entered into a joint
venture through an ownership agreement and an operating agreement, each
dated February 28, 1985, with the purchaser of the interest. In 1988, Teco
succeeded to that purchaser's 50% interest. A subsidiary of Energy has at
all times been the operator of the pipeline. Notwithstanding the written
ownership and operating agreements, the plaintiff alleges that a separate,
unwritten partnership agreement exists, and that the defendants have
exercised improper dominion over such alleged partnership's affairs. The
plaintiff also alleges that the defendants acted in bad faith by negatively
affecting the economics of the joint venture in order to provide financial
advantages to facilities or entities owned by the defendants and by
allegedly usurping for the defendants' own benefit certain opportunities
available to the joint venture. The plaintiff asserts causes of action for
breach of fiduciary duty, fraud, tortious interference with business
relationships, and other claims, and seeks unquantified actual and punitive
damages. The Company's motion to compel arbitration was denied, but has
been appealed. The Company has filed a counterclaim alleging that the
plaintiff breached its own obligations to the joint venture and jeopardized
the economic and operational viability of the pipeline by its actions. The
Company is seeking unquantified actual and punitive damages.
Sinco Pipeline Rupture Litigation. Approximately 15 lawsuits have
been filed against various pipeline owners and other parties, including the
Company, arising from the rupture of several pipelines and fire as a result
of severe flooding of the San Jacinto River in Harris County, Texas on
October 20, 1994. The Company is a defendant in 10 of these lawsuits. The
plaintiffs are property owners in surrounding areas who allege that the
defendant pipeline owners were negligent and grossly negligent in failing to
bury the pipelines at a proper depth to avoid rupture or explosion and in
allowing the pipelines to leak chemicals and hydrocarbons into the flooded
area. The plaintiffs assert claims for property damage, costs for medical
monitoring, personal injury and nuisance, and seek an unspecified amount of
actual and punitive damages.
J.M. Davidson, Inc. 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 one of the
Company's gas processing plants in 1991 and 1992. The plaintiff alleges
that it performed work for the defendants for which it was not compensated.
The plaintiff asserts claims for fraud, quantum meruit, and numerous other
tort claims. The plaintiff seeks actual damages, on each of its causes of
action, of approximately $1.25 million, plus retainage, interest and
attorneys fees, and punitive damages of at least four times the amount of
actual damages. No trial date has been set.
The Long Trusts. On April 15, 1994, certain trusts named certain
subsidiaries of the Company as additional defendants (the "Valero
Defendants") to a lawsuit filed in 1989 by the trusts against a supplier
with whom the Valero Defendants have contractual relationships under gas
purchase contracts. In order to resolve certain potential disputes with
respect to the gas purchase contracts, the Valero Defendants agreed to bear
a substantial portion of any settlement or any nonappealable final judgment
rendered against the supplier. In January 1993, the District Court ruled in
favor of the trusts' motion for summary judgment against the supplier.
Damages, if any, were not determined. The trusts seek $50 million in
damages from the Valero Defendants as a result of the Valero Defendants'
alleged interference between the trusts and the supplier, plus punitive
damages in excess of treble the amount of actual damages proven at trial.
The trusts also seek approximately $56 million in take-or-pay damages from
the supplier and $70 million as damages for the supplier's failure to take
the trusts' gas ratably. 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. No
trial date has been set.
Mizel. A federal securities fraud lawsuit was filed against Energy
and certain of its subsidiaries by a former owner of limited partnership
interests of VNGP, L.P. The plaintiff alleges that the proxy statement used
in connection with the solicitation of votes for approval of the Merger of
the Company and VNGP, L.P. contained fraudulent misrepresentations. The
plaintiff also alleges breach of fiduciary duty in connection with the
merger transaction. The subject matter of this lawsuit was the subject
matter of a prior Delaware class action lawsuit which was settled prior to
consummation of the Merger. The Company believes that the plaintiff's
claims have been settled and released by the prior class action settlement.
Pending in the district court is a memorandum issued by the magistrate
assigned to the case which recommends approval of the Company's motion for
summary judgment.
Javelina. Valero Javelina Company, a wholly owned subsidiary of
Energy, owns a 20% general partner interest in Javelina Company
("Javelina"), a general partnership that owns a refinery off-gas processing
plant in Corpus Christi. Javelina has been named as a defendant in ten
lawsuits filed since 1993 in state district courts in Nueces County and
Duval County, Texas. Eight 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. The plaintiffs seek an unspecified amount of
actual and punitive damages. The remaining two suits were brought by
plaintiffs who either live or have businesses near the Javelina plant. The
plaintiffs in these suits allege claims similar to those described above and
seek unspecified actual and punitive damages.
The Company is also a party to additional claims and legal
proceedings arising in the ordinary course of business. The Company
believes it is unlikely that the final outcome of any of the claims or
proceedings to which the Company is a party, including those described
above, would have a material adverse effect on the Company's financial
statements; however, due to the inherent uncertainty of litigation, the
range of possible loss, if any, cannot be estimated with a reasonable degree
of precision and there can be no assurance that the resolution of any
particular claim or proceeding would not have an adverse effect on the
Company's results of operations for the interim period in which such
resolution occurred.
16. QUARTERLY RESULTS OF OPERATIONS (Unaudited)
The results of operations by quarter for the years ended December 31,
1996 and 1995 were as follows (in thousands of dollars, except per share
amounts):
<TABLE>
<CAPTION>
Operating Operating Net Earnings Per Share
Revenues Income Income Of Common Stock
<S> <C> <C> <C> <C>
1996-Quarter Ended:
March 31. . . . . . . . . . . . . $1,110,098<F1> $ 52,238 $19,914 $ .39
June 30 . . . . . . . . . . . . . 1,152,737 54,433 20,841 .41
September 30. . . . . . . . . . . 1,123,527 40,025 13,146 .23
December 31 . . . . . . . . . . . 1,604,319 54,213 18,800 .37
Total . . . . . . . . . . . . . $4,990,681 $200,909 $72,701 $1.40
1995-Quarter Ended:
March 31. . . . . . . . . . . . . $ 690,535 $ 28,667 $ 3,759 $ .02
June 30 . . . . . . . . . . . . . 775,822<F2> 54,953 20,522 .40
September 30. . . . . . . . . . . 803,670<F2> 57,781 22,630 .45
December 31 . . . . . . . . . . . 927,845<F2> 47,390 12,927 .23
Total . . . . . . . . . . . . . $3,197,872<F2> $188,791 $59,838 $1.10
<FN>
<F1> Revised from the amount shown in the Company's Form 10-Q for the three months ended
March 31, 1996 to include revenues from certain NGL trading activities previously
classified as a reduction of cost of sales.
<F2> Revised to include revenues from certain refining and marketing trading activities
previously classified as a reduction of cost of sales.
</TABLE>
<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
DIRECTORS OF THE REGISTRANT
The following table sets forth information concerning the current
directors of Energy. The information contained herein is based partly on
data furnished by the directors and partly on the Company's records.
There is no family relationship among any of the executive officers or
directors of Energy, and, except for the entities bearing the "Valero"
name, none of the organizations or corporations described in the
biographical information in this Item 10 is an affiliate of Energy.
<TABLE>
<CAPTION>
_________________________________________________________________________________________________________
Age
Executive as of
Officer December Present Current
Position(s) Held or Director 31, Term Director
Name with Energy Since 1996 Expires Class
_________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C>
William E. Greehey Director, Chairman 1979 60 1998 III
of the Board and
Chief Executive
Officer
Edward C. Benninger Director, President 1979 54 1997 II
Ronald K. Calgaard Director 1996 59 1999 I
Robert G. Dettmer Director 1991 65 1998 III
A. Ray Dudley Director 1988 72 1997 II
Ruben M. Escobedo Director 1994 59 1998 III
James L. Johnson Director 1991 69 1997 II
Lowell H. Lebermann Director 1986 57 1998 III
Susan Kaufman Purcell Director 1994 54 1999 I
_________________________________________________________________________________________________________
</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. He retired from
his positions as President and Chief Executive Officer in June 1996. Upon
request of the Board, Mr. Greehey resumed his position as Chief Executive
Officer following the resignation of Mr. Becraft in November 1996. Mr.
Greehey is also a director of Weatherford Enterra, Inc. and Santa Fe Energy
Resources, Inc.
Mr. Benninger has served as a director of Energy since 1990. He was
elected President and Chief Financial Officer of Energy in 1996. He had
served as Executive Vice President of Energy since 1989, and previously
served as Chief Operating Officer of Valero Natural Gas Company from 1992 to
1995. He has served in various other capacities with the Company since
1975.
Dr. Calgaard has been a director of Energy since 1996. He has served
as President of Trinity University, San Antonio, Texas, since 1979.
Dr. Calgaard previously served as a director of Valero Natural Gas Company
from 1987 until 1994.
Mr. Dettmer was elected as a director of Energy in 1991. He retired
from PepsiCo, Inc. in 1996 after serving as Executive Vice President and
Chief Financial Officer since 1986.
Mr. Dudley has served as a director of Energy since 1988 and currently
serves as an independent consultant in the petroleum industry. Mr. Dudley
served in various capacities with Tenneco Oil Company from 1959 until his
retirement in 1987.
Mr. Escobedo was elected as a director of Energy in 1994. He has been
with his own public accounting firm, Ruben Escobedo & Company, CPAs, in San
Antonio, Texas since its formation in 1977. Mr. Escobedo also serves as a
director of Frost National Bank of San Antonio, N.A. ("Frost Bank") and
previously served as a director of Valero Natural Gas Company from 1989
to 1994. In its capacity as Trustee for certain employee benefit plans
of Energy, Frost Bank shares voting and dispositive power with respect to
a number of shares of Energy common stock. See "Item 12. Security
Ownership of Certain Beneficial Owners and Management."
Mr. Johnson has been a director of Energy since 1991. He previously
served as Chairman and Chief Executive Officer of GTE Corporation from 1988
to 1992, and since 1992 has served as Chairman Emeritus. Mr. Johnson also
serves as a director of CellStar Corporation, FINOVA Group, Inc.,
Harte-Hanks Communications, Inc., The Mutual Life Insurance Company of New
York and Walter Industries, Inc.
Mr. Lebermann was elected as a director of Energy in 1986, and
previously served on Energy's Board from 1979 to 1983. Mr. Lebermann has
been President of Centex Beverage, Inc., a beverage distributor, in Austin,
Texas, since 1981. Mr. Lebermann is also a director of Station Casinos, Inc.
and of Franklin Federal Bankcorp, a Federal Savings Bank, Austin, Texas.
Dr. Purcell was elected as a director of Energy in 1994. She has
served as Vice President of the Americas Society in New York, New York since
1989 and is also Vice President of the Council of the Americas. She is a
consultant for several international and national firms and serves on the
boards of several mutual funds, including The Argentina Fund, The Latin
America Dollar Income Fund and Scudder World Income Opportunities Fund.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information as of December 31,
1996 regarding the current 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.
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 1996
_______________________________________________________________________________________________________
<S> <C> <C> <C>
William E. Greehey Director, Chairman of the Board 1979 60
and Chief Executive Officer
Edward C. Benninger Director, President and 1979 54
Chief Financial Officer
Stan L. McLelland Executive Vice President 1981 51
and General Counsel
*E. Baines Manning Executive Vice President of 1992 56
Valero Refining and
Marketing Company
*Terrence E. Ciliske Executive Vice President of 1996 42
Valero Natural Gas Company
Peter A. Fasullo Senior Vice President - 1996 43
Corporate Development
Gregory C. King Vice President 1997 36
______________________________________________________________________________________________________
</TABLE>
[FN]
* Mr. Manning and Mr. Ciliske 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.
Biographical information for Mr. Greehey and Mr. Benninger is
contained above under the caption "Directors of the Registrant."
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. McLelland also serves as a director of IGC
Communications, Inc., which is not affiliated with the Company.
Mr. Manning has served as Executive Vice President of Valero Refining
and Marketing Company since 1995 and in various other capacities within the
Company's refining division since 1986.
Mr. Ciliske was elected Executive Vice President of Valero Natural
Gas Company in 1996, prior to which he served in various other capacities
within the Company's natural gas related services divisions since 1983.
Mr. Fasullo was elected Senior Vice President - Corporate Development
in 1996, prior to which he served in various other capacities within the
Company since 1983.
Mr. King was elected Vice President in 1997, and has served as
Associate General Counsel since joining the Company in 1993. Prior to
joining the Company, Mr. King was a partner at the law firm of Bracewell &
Patterson, L.L.P., Houston, Texas, where he had been employed since 1985.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934, as amended
("Exchange Act"), requires Energy's executive officers, directors, and
greater than 10 percent to stockholders to file certain reports of ownership
and changes in ownership. Based on a review of the copies of such forms
received and written representations from certain reporting persons, Energy
believes that, during the year ended December 31, 1996, its executive
officers, directors and greater than 10 percent stockholders were in
compliance with applicable requirements of Section 16(a).
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION
The following table provides a summary of compensation paid to the
persons serving as Energy's CEO, and to its four other most highly
compensated executive officers, for services rendered in all capacities to
the Company for the last three years. Benefits under health care,
disability, term life insurance, vacation and other plans available to
employees generally are not included herein.
<TABLE>
<CAPTION>
Summary Compensation Table (1994-1996)
______________________________________________________________________________________________________________________________
Long-Term Compensation
Restricted Securities
Annual Compensation Stock Underlying All Other
Name and Bonus Awards Options/ LTIP Compensation
Position(s) Year Salary($) ($)(1) ($)(2) SARS(#) Payouts(3) ($)(4)
______________________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C> C> <C>
William E.
Greehey(5) 1996 $497,337 $670,739 $1,545,362 5,000 $325,000 $928,949
Director, Chairman 1995 684,540 560,000 431,250 0 0 73,007
of the Board and 1994 622,020 0 0 355,300 0 71,664
Chief Executive
Officer of Energy
F. Joseph Becraft(5)
Director, President 1996 $450,030 $ 0 $276,250 40,000 $271,138 $4,252
and Chief Executive 1995 266,680 180,000 421,875 120,000 0 4,252
Officer of Energy
Edward C.
Benninger(5) 1996 $357,180 $335,370 $497,500 25,000 $ 93,698 $28,541
Director and President 1995 342,600 210,000 189,750 0 0 27,016
of Energy 1994 335,040 0 0 125,500 0 27,598
Stan L. McLelland
Executive Vice 1996 $300,930 $111,812 $ 0 25,000 $ 70,200 $25,631
President and General 1995 278,700 162,000 138,000 0 0 23,313
Counsel of Energy 1994 262,380 0 0 82,600 0 23,836
E. Baines Manning(6)
Executive Vice 1996 $253,230 $122,989 $ 0 18,000 $ 58,500 $18,758
President of Valero 1995 231,420 120,000 51,750 0 0 12,468
Refining and 1994 216,420 0 0 63,500 0 15,524
Marketing Company
Terrence E. Ciliske(6)
Executive Vice 1996 $180,156 $167,701 $ 51,000 3,400 $ 36,823 $10,670
President of Valero
Natural Gas Company
______________________________________________________________________________________________________________________________
</TABLE>
[FN]
(1) In 1994, executives received no bonuses. For 1995, executives
received bonuses payable 70% in cash and 30% in Common Stock. For
1996, executives received bonuses payable 25% in cash and 75% in
Common Stock.
(2) For each named executive officer, the number of shares of Restricted
Stock held at December 31, 1996, and the value thereof, based on the
closing market price of the Common Stock at December 31, 1996, was as
follows: Mr. Greehey: 62,073 shares -- $1,776,840; Mr. Benninger:
27,333 shares -- $782,407; Mr. McLelland: 5,333 shares -- $152,667;
Mr. Manning: 2,000 shares -- $57,250; and Mr. Ciliske: 3,400 shares --
$97,325. Dividends are paid on the Restricted Stock at the same rate
as on Energy's unrestricted Common Stock. The grants of Restricted
Stock to Messrs. Greehey and Benninger will vest upon completion of
the Restructuring transaction or, if such transaction is not
consummated, would vest in annual increments of 33 1/3% beginning
on the first anniversary of the grant date. The grant of Restricted
Stock to Mr. Becraft vested upon his resignation; Mr. Becraft did not
hold Restricted Stock at December 31, 1996.
(3) LTIP payouts are the number of performance share awards vested for
1996 multiplied by the market price per share on the vesting date.
For more information see the notes following the table entitled "Long
Term Incentive Plans-Awards in Last Fiscal Year."
(4) Amounts include Company contributions pursuant to the Employee Stock
Plans, and that portion of interest accrued under the Executive
Deferred Compensation Plan which is deemed to be at "above-market"
rates under applicable SEC rules. Messrs. Greehey, Becraft,
Benninger, McLelland, Manning, and Ciliske were allocated $31,460,
$10,975, $25,574, $21,074, $18,758, and $10,670, respectively, as a
result of Company contributions to employee stock plans for 1996, and
$9,066, $0, $2,967, $4,557, $0, and $0, respectively, as a result of
"above-market" allocations to the Executive Deferred Compensation Plan
for 1996. Messrs. Becraft, Manning and Ciliske do not participate in
the Executive Deferred Compensation Plan. Amounts for Mr. Greehey
also include executive insurance policy premiums with respect to cash
value life insurance (not split-dollar life insurance) in the amount
of $13,000 for 1994 and 1995 and $7,583 for 1996; such amounts for
1996 also include (i) consulting fees ($141,667), Board fees
($29,833), SERP payments ($278,862) and the interest component of
deferred compensation plan payments ($27,648) made during the period
following his retirement and prior to his reemployment, and
(ii) payments made following his retirement for Excess Thrift Plan
balances ($339,617) and unused vacation ($63,213). Payments received
during Mr. Greehey's retirement directly from the Pension Plan are
excluded.
(5) Mr. Becraft was employed by the Company beginning May 1, 1995, and was
elected President of Energy on January 1, 1996 and Chief Executive
Officer of Energy on June 30, 1996. Mr. Greehey resigned from his
position as Chief Executive Officer of Energy on June 30, 1996. Mr.
Becraft resigned from his positions as President and Chief Executive
Officer of Energy on November 20, 1996, whereupon Mr. Greehey was
reappointed Chief Executive Officer of Energy. At that time, the
Board also promoted Mr. Benninger from Executive Vice President to
President of Energy.
(6) The Board of Directors of Energy has determined to include Mr.
Ciliske and Mr. Manning in the Summary Compensation Table in
accordance with Rule 3b-7 under the Exchange Act. Mr. Ciliske was not
an executive officer of Energy for any part of 1994 or 1995.
STOCK OPTION GRANTS AND RELATED INFORMATION
The following table provides further information regarding the grants
of stock options to the named executive officers reflected in the Summary
Compensation Table.
<TABLE>
<CAPTION>
Option/SAR Grants in the Last Fiscal Year
______________________________________________________________________________________________________________________
Number of Percent of
Securities Total
Underlying Options/
Options/ SARs Granted Market
SARs to Employees Exercise or Price at Grant Date
Granted in Fiscal Base Price Grant Date Expiration Present Value $
Name (#)(1) Year (/$/Sh) ($/Sh) Date (2)
______________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
William E. Greehey 5,000 .69% $25.3125 $25.3125 07/01/2006 $ 29,580
F. Joseph Becraft 40,000 5.56% $27.5625 $27.5625 05/30/2006 259,440
Edward C. Benninger 25,000 3.47% $27.5625 $27.5625 05/30/2006 162,150
Stan L. McLelland 25,000 3.47% $27.5625 $27.5625 05/30/2006 162,150
E. Baines Manning 18,000 2.50% $27.5625 $27.5625 05/30/2006 116,748
Terrence E. Ciliske 7,500 1.04% $27.5625 $27.5625 05/30/2006 48,645
2,500 .35% $25.3125 $25.3125 07/01/2006 14,790
______________________________________________________________________________________________________________________
</TABLE>
[FN]
(1) Options granted in 1996 vest (become exercisable and nonforfeitable)
in equal increments over a three year period from the date of grant.
In the event of a change of control of Energy (including stockholder
approval of the Restructuring, such options would also become
immediately exercisable pursuant to provisions of the plan or of an
executive severance agreement. Under the terms of the plan, the
exercise price and tax withholding obligations related to exercise
may be paid by delivery of already owned shares or by offset of the
underlying shares, subject to certain conditions.
(2) A variation of the Black-Scholes option pricing model was used to
determine grant date present value. This model is designed to value
publicly traded options. Options issued under the Company's option
plans are not freely traded, and the exercise of such options is
subject to substantial restrictions. Moreover, the Black-Scholes
model does not give effect to either risk of forfeiture or lack of
transferability. The estimated values under the Black-Scholes model
are based on assumptions as to variables such as interest rates,
stock price volatility and future dividend yield. The estimated
grant date present values presented in this table were calculated
using an expected average option term of 3.32 years, a risk-free rate
of return of 6.41%, an average volatility rate of 25.4% for the
options expiring 5/30/2006 and 25.17% for the options expiring
7/01/2006, and a dividend yield of 1.88% for the options expiring
5/30/2006 and 2.04% for the options expiring 7/01/2006. The
actual value of stock options could be zero; realization of any
positive value depends upon the actual future performance of the
Common Stock, the continued employment of the option holder
throughout the vesting period and the timing of the exercise of
the option. Accordingly, the values set forth in this table may
not be achieved.
The following table provides information regarding securities
underlying options exercisable at December 31, 1996, and options exercised
during 1996, for the executive officers named in the Summary Compensation
Table:
<TABLE>
<CAPTION>
Aggregated Option/SAR Exercises in Last Fiscal Year
and FY-End Option/SAR Values
______________________________________________________________________________________________________________________
Value of Unexercised
Shares Number of Securities In-the-Money
Acquired Value Underlying Unexercised Options/SARs at
on Exercise Realized Options/SARs at FY-End(#) FY-End ($) (1)
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
______________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C> <C>
William E. Greehey - - 510,184 5,000 $4,522,154 $ 15,625
F. Joseph Becraft - - 160,000 - 1,167,500 -
Edward C. Benninger - - 62,472 133,833 364,587 1,031,800
Stan L. McLelland - - 47,857 96,266 328,157 682,762
E. Baines Manning - - 38,217 72,833 270,792 524,300
Terrence E. Ciliske - - 24,019 25,400 158,628 155,588
______________________________________________________________________________________________________________________
</TABLE>
[FN]
(1) Represents the dollar value obtained by multiplying the number of
unexercised options/SARs by the difference between the stated
exercise price per share of the options/SARs and the average market
price per share of Energy's Common Stock on December 31, 1996.
Long-Term Incentive Awards
The following table provides information regarding long-term incentive
awards made to the named executive officers reflected in the Summary
Compensation Table.
<TABLE>
<CAPTION>
Long-Term Incentive Plans - Awards in Last Fiscal year (1)
______________________________________________________________________________________________________________________________
Estimated Future Payouts
Under Non-Stock Price-Based Plans
Performance
Number of or Other Period
Shares, Units Until Maturation Threshold Target Maximum
Name or Other Rights or Payout (# Shares) (# Shares) (# Shares)
______________________________________________________________________________________________________________________________
<S> <C> <C> <C> <C> <C>
William E. Greehey 10,000 12/31/96 0 10,000 20,000
10,000 12/31/97 0 10,000 20,000
10,000 12/31/98 0 10,000 20,000
F. Joseph Becraft 3,634 12/31/96 0 3,634 7,268
3,633 12/31/97 0 3,633 7,266
3,633 12/31/98 0 3,633 7,266
Edward C. Benninger 2,884 12/31/96 0 2,884 5,768
2,883 12/31/97 0 2,883 5,766
2,883 12/31/98 0 2,883 5,766
Stan L. McLelland 2,160 12/31/96 0 2,160 4,320
2,160 12/31/97 0 2,160 4,320
2,160 12/31/98 0 2,160 4,320
E. Baines Manning 1,800 12/31/96 0 1,800 3,600
1,800 12/31/97 0 1,800 3,600
1,800 12/31/98 0 1,800 3,600
Terrence E. Ciliske 1,134 12/31/96 0 1,134 2,268
1,134 12/31/97 0 1,134 2,268
1,134 12/31/98 0 1,134 2,268
______________________________________________________________________________________________________________________________
</TABLE>
[FN]
(1) Long-term incentive awards are grants of performance shares
("Performance Shares") made under the Executive Stock Incentive Plan.
(2) Total shareholder return ("TSR") during a specified "performance
period" was established as the performance measure for determining
what portion of the 1996 Performance Share awards will vest. For
purposes of the Performance Share awards, TSR is measured by dividing
the sum of (a) the net change in the price of a share of Energy's
Common Stock between the beginning of the performance period and the
end of the performance period, and (b) the total dividends paid on the
Common Stock during the performance period, by (c) the price of a
share of Energy's Common Stock at the beginning of the performance
period. Each 1996 Performance Share award is subject to vesting in
three increments, based upon the Company's TSR during overlapping
three-year periods, with the first such three-year period for the 1996
grants beginning January 1, 1994 and ending December 31, 1996. At the
end of the three-year performance period, the Company's TSR is
compared to the TSR for each company in a target group of
approximately 16 companies. Energy and the companies in the target
group are then ranked by quartile. At the end of each performance
period, participants earn 0%, 50%, 100% or 150% of the initial grant
amount for such period depending upon whether the Company's TSR is in
the last, 3rd, 2nd or 1st quartile of the target group; 200% will be
earned if the Company ranks highest in the group. Amounts not earned
in a given three-year period can be carried forward for one additional
three-year period and up to 100% of the carried amount can still be
earned, depending upon the quartile achieved for such subsequent
period.
RETIREMENT BENEFITS
The following table shows the estimated annual gross benefits payable
under Energy's Pension Plan ("Pension Plan"), Supplemental Pension Plan and
Supplemental Executive Retirement Plan ("SERP") upon retirement at age 65,
based upon the assumed compensation levels and years of service indicated
and assuming an election to have payments continue for the benefit of the
life of the participant only.
<TABLE>
<CAPTION>
Estimated Annual Pension Benefits at Age 65
_________________________________________________________________________________
Years of Service
Covered _____________________________________________________________
Compensation 15 20 25 30 35
_________________________________________________________________________________
<S> <C> <C> <C> <C> <C>
$ 200,000 $ 55,000 $ 73,000 $ 92,000 $110,000 $128,000
300,000 84,000 112,000 141,000 169,000 197,000
400,000 114,000 151,000 189,000 227,000 265,000
500,000 143,000 190,000 238,000 286,000 333,000
600,000 172,000 229,000 287,000 344,000 401,000
700,000 201,000 268,000 336,000 403,000 470,000
800,000 231,000 307,000 384,000 461,000 538,000
900,000 260,000 346,000 433,000 520,000 606,000
1,000,000 289,000 385,000 482,000 578,000 674,000
1,100,000 318,000 424,000 531,000 637,000 743,000
1,200,000 348,000 463,000 579,000 695,000 811,000
1,300,000 377,000 502,000 628,000 754,000 879,000
_________________________________________________________________________________
</TABLE>
Energy maintains a noncontributory defined benefit Pension Plan in
which virtually all employees are eligible to participate and under which
contributions for individual participants are not determinable. Energy also
maintains a noncontributory, nonqualified Supplemental Pension Plan which
provides supplemental pension benefits to certain highly compensated
employees to the extent that the pension benefits otherwise payable to such
employees from the Pension Plan would exceed benefits permitted under
applicable regulations to be paid from a tax-qualified defined benefits
plan. Accrued contributions for the 1996 Pension Plan year were
approximately 5.5% of total covered compensation. No contributions were
made to the Supplemental Pension Plan. The Pension Plan (supplemented, as
necessary, by the Supplemental Pension Plan) provides a monthly pension at
normal retirement equal to 1.6% of the participant's average monthly
compensation (based upon the participant's base earnings during the 60
consecutive months of the participant's credited service affording the
highest such average) times the participant's years of credited service,
plus .35% times the product of the participant's years of credited service
(maximum 35 years) multiplied by the excess of the participant's average
monthly compensation over the lesser of 1.25 times the monthly average
(without indexing) of the social security wage bases for the 35-year period
ending with the year the participant attains social security retirement age,
or the monthly average of the social security wage base in effect for the
year that the participant retires.
Energy also maintains the SERP, a non-qualified plan providing
additional pension benefits to certain executive officers and employees of
the Company. Energy's obligations under the SERP are substantially fully
funded through investments held in a trust established for the SERP under
which Frost National Bank of San Antonio, N.A., serves as trustee. During
1996 contributions aggregating $9.2 million were made to the SERP Trust.
Compensation for purposes of the Pension Plan and Supplemental Pension
Plan includes only salary as reported in the Summary Compensation Table and
excludes cash bonuses. For purposes of the SERP, the participant's most
highly compensated consecutive 36 months of service during the participant's
last 10 years of employment (rather than 60 months) are considered, and
bonuses are included. Accordingly, the amounts reported in the Summary
Compensation Table under the headings "Salary" and "Bonus" constitute
covered compensation for purposes of the SERP. Pension benefits are not
subject to any deduction for social security or other offset amounts.
Credited years of service for the period ended December 31, 1996 for
the executive officers named in the Summary Compensation Table are as
follows: Mr. Greehey -- 33 years; Mr. Becraft -- 6 years; Mr. Benninger --
22 years; Mr. McLelland -- 18 years; Mr. Manning -- 10 years, and
Mr. Ciliske -- 13 years. The credited service for Mr. Becraft and Mr.
McLelland includes five years and two years service, respectively, credited
pursuant to the terms of their employment by the Company and for which
benefits are payable only from the SERP. See also "Arrangements with
Certain Officers and Directors."
COMPENSATION OF DIRECTORS
Non-employee directors receive a retainer fee of $18,000 per year, plus
$1,000 for each Board and committee meeting attended ($500 for telephonic
meetings). Each director is also reimbursed for expenses of meeting
attendance. Directors who are employees of the Company receive no
compensation (other than reimbursement of expenses) for serving as
directors.
Energy maintains the 1990 Restricted Stock Plan for Non-Employee
Directors ("Director Stock Plan") and the Non-Employee Director Stock Option
Plan ("Director Option Plan") to supplement the compensation paid to
non-employee directors and increase their identification with the interests
of Energy's stockholders through ownership of Common Stock ("Director
Stock"). Under the Director Stock Plan, non-employee directors receive
grants of Director Stock that vest (become nonforfeitable) in three equal
annual installments. Upon election to the Board, each non-employee director
receives a grant, the value of which is determined annually based on changes
in the consumer price index and which is expected to be approximately
$54,000 for 1997. Annual installments usually vest on or about
the date of the annual meeting of stockholders. When all of the Director
Stock previously granted to a director is fully vested and the director is
reelected for an additional term, or his term of office otherwise continues
after his Director Stock is fully vested, another similar grant is made.
However, if a director is not eligible for reelection due to Energy's
mandatory retirement policy or if a director does not intend to stand for
reelection, the grant is reduced pro rata based on the number of years
remaining to the end of that director's term.
The Director Option Plan provides non-employee directors of Energy
automatic annual grants of stock options for Energy's Common Stock. To the
extent necessary, the plan is administered by the Compensation Committee of
the Board of Directors. The plan provides that each new non-employee
director elected to the Energy Board automatically receives an initial grant
of 5,000 options. On the date of each subsequent annual meeting of
stockholders of Energy, each non-employee director (other than new
non-employee directors receiving their initial grant of 5,000 options)
automatically receives a grant of 1,000 additional options. Stock options
awarded under the Director Option Plan have an exercise price equal to the
market price of the Common Stock on the date of grant. The initial grant
of options to each non-employee director vests in three equal annual
installments on each anniversary date of the grant. The subsequent annual
grants of 1,000 options vest fully six months following the date of grant.
All options expire ten years following the date of grant. Options vest
and remain exercisable in accordance with their original terms in the case
of a director retiring from the Board. In the event of a "Change of
Control" as defined in the Director Option Plan, all options previously
granted under the plan immediately become vested or exercisable upon the
date of the Change of Control, except as otherwise provided in the plan.
The Director Option Plan also provides for adjustment in the number of
options to prevent dilution or enlargement of the benefits or potential
benefits intended under the plan in the event the Compensation Committee
determines that any dividend or other distribution, recapitalization,
stock split, reverse stock split, reorganization, merger, consolidation,
split-up, spin-off, combination, repurchase, or exchange of shares of
Energy or other similar corporate transaction or event affects the
common stock of Energy.
Under the Retirement Plan for Non-Employee Directors ("Retirement
Plan"), non-employee directors become entitled to a retirement benefit upon
completion of five years of service. The annual benefit at retirement is
equal to 10% of the highest annual cash retainer paid to the director during
his or her service on the Board, multiplied by the number of full and
partial years of service (not to exceed 10 years). Such benefit is then
paid for a period equal to the shorter of the director's number of years of
service or the director's lifetime, but in no event for longer than 10
years. The Retirement Plan provides no survivor benefits and is an unfunded
plan paid from the general assets of the Company.
ARRANGEMENTS WITH CERTAIN OFFICERS AND DIRECTORS
Energy entered into an employment agreement with Mr. Greehey dated
May 16, 1990 which expired June 9, 1995. The agreement provided that
Mr. Greehey would be entitled to receive certain post-retirement benefits,
including office facilities and secretarial support until age 69, transfer
of certain club memberships, the vesting of previously granted stock option
and restricted stock grants, certain medical and life insurance benefits and
the right to certain supplemental amounts under the SERP. In November 1994,
Energy's Board of Directors approved resolutions continuing such
post-retirement benefits, notwithstanding the termination of such agreement.
Effective upon his retirement from his positions as President and Chief
Executive Officer in June 1996, the specified post-retirement benefits were
provided to Mr. Greehey and he was requested to continue to serve as
Chairman of the Board. Energy and Mr. Greehey also entered into a
consulting agreement pursuant to which Mr. Greehey received compensation at
the rate of $340,000 per annum for providing general advice and consulting
services, as well as management services for particular projects.
Mr. Greehey was reemployed by Energy on November 21, 1996, and the
consulting agreement terminated at that time. In order to clarify
Mr. Greehey's continuing benefit arrangements, the Board determined that,
following Mr. Greehey's ultimate retirement from active employment, he
will continue to be eligible to receive substantially the same office and
secretarial support, medical and life insurance benefits and supplemental
SERP benefits as were provided following his earlier retirement.
Effective May 1, 1995, Energy entered into an employment agreement
with Mr. Becraft expiring April 30, 2000. Under the agreement, Mr. Becraft
was entitled to receive a minimum base salary of $400,000 per annum, and to
participate in the Company's executive incentive bonus plan, restricted
stock plans, option plans and SERP; for purposes of determining benefits
payable under the SERP, Mr. Becraft's prior service from 1984-1989 was
credited. Mr. Becraft was elected Chief Executive Officer of Energy
effective July 1, 1996, and his base salary was increased to $500,000 at
that time. Energy subsequently entered into a separation agreement with Mr.
Becraft effective November 20, 1996. The separation agreement provided
that, through April 30, 2000, Mr. Becraft will continue to receive his
then-effective base salary. Additionally, the agreement provided for the
immediate vesting of previously granted stock options, restricted stock and
performance shares; office and secretarial support for a six-month period;
transfer of a club membership; certain health benefits until the original
expiration date of the employment agreement; assignment of a life insurance
policy; and certain tax planning services.
Energy has entered into agreements (the "Severance Agreements") with
Messrs. Greehey, Benninger, McLelland and Manning which provide certain
payments and other benefits in the event of their termination of employment
under certain circumstances. The Severance Agreements provide that if the
executive leaves the Company for any reason (other than death, disability or
normal retirement) within two years after a "change of control," the
executive will receive a lump sum cash payment equal to three times, in the
cases of Messrs. Greehey and McLelland, and two times, in the cases of
Messrs. Benninger and Manning, his highest compensation during any
consecutive 12-month period in the prior three years. The executive will
also be entitled to accelerated exercise of stock options and SARs and
accelerated vesting of restricted stock previously granted. The agreements
also provide for special retirement benefits if the executive would have
qualified for benefits under the Pension Plan had he remained with the
Company for the three-year period following such termination, for
continuance of life and health insurance coverages and other fringe benefits
for such three-year period and for relocation assistance. Messrs. Greehey,
Benninger, McLelland and Manning have each executed waivers providing that
the consummation of the transactions contemplated by the Merger Agreement
will not constitute a "change of control" for purposes of such Severance
Agreements.
In connection with pursuing various strategic alternatives, including
the Restructuring, Energy entered into Management Stability Agreements
("Stability Agreements") and Incentive Bonus Agreements ("Incentive
Agreements") with various key executives, including Mr. Terrence E.
Ciliske, Executive Vice President of Valero Natural Gas Company and
Mr. Peter A. Fasullo, Senior Vice President-Corporate Development.
These agreements are intended to assure the continued availability of
Messrs. Ciliske and Fasullo in the event of certain transactions
culminating in a "change of control" of Energy and/or a divestiture of
one of the Company's principal businesses. Under the Stability Agreements,
in the event either of such executive's employment is terminated within
two years after a change of control or divestiture transaction has occurred,
and termination is not voluntary or the result of death, permanent
disability, retirement or certain other defined circumstances, the
executive would be entitled to receive a lump sum cash payment equal to the
sum of (i) two times the highest annual compensation paid to such executive
during the prior three year period, plus an amount equal to the executive's
average annual incentive bonus over the prior three years; the continuation
of life, disability and health insurance coverages for two years; and
certain relocation assistance. The executives would also be entitled to
accelerated vesting of all previously granted stock options, SARs and
restricted stock. Under the Incentive Agreements, if the executive
continues to be employed by the Company and a merger or another qualifying
transaction is accomplished, the executive will be entitled to receive a
cash incentive bonus payment equal to one times the executive's highest
annual base salary during the prior three year period. In the case of Mr.
Ciliske, all of such payment is payable at the closing of the transaction,
and in the case of Mr. Fasullo, 60% of such payment is payable at closing
and 40% is payable six months following closing or, under certain
circumstances, upon his earlier termination of employment.
In connection with Mr. Greehey's then-pending retirement, in May 1996
the Compensation Committee approved special retirement arrangements that
would be applicable to Messrs. Benninger and McLelland if they deferred
their retirement from the Company to after June 30, 1996. Under these
arrangements, upon their ultimate retirement, Messrs. Benninger and
McLelland would each receive eight supplemental retirement "points," to be
divided between age and credited service in such proportions as each shall
elect at the time of retirement. In addition, for the year in which he
retires each executive will be entitled to a prorated executive incentive
bonus and tax preparation services. Each executive would also be entitled
to accelerated vesting of all previously granted stock options and
Restricted Stock, and Mr. Benninger's existing club membership would be
transferred to him without cost.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth information as of December 31, 1996,
with respect to each entity known to Energy to be the beneficial owner of
more than five percent of its Common Stock, based solely upon a statement on
Schedule 13G filed by such entity with the Securities and Exchange
Commission ("SEC"):
<TABLE>
<CAPTION>
______________________________________________________________________________________________
Shares
Name and Address Beneficially Percent
Title of Class of Beneficial Owner Owned of Class
______________________________________________________________________________________________
<S> <C> <C> <C>
Common Stock Franklin Resources, Inc.(1) 6,366,167 14.4%
777 Mariners Island Blvd.
San Mateo, CA 94404
Common Stock Merrill Lynch & Co., Inc.(2) 4,160,610 9.4%
World Financial Center, North Tower
250 Vessey Street
New York, NY 10281
Common Stock Frost National Bank of 4,027,492 9.1%
San Antonio, N.A.(3)
100 West Houston Street
San Antonio, TX 78205
Common Stock The Capital Group Companies, Inc.(4) 3,292,700 7.4%
75 State Street
Boston, MA 02109
Common Stock Wellington Management Company(5) 2,841,946 6.4%
75 State Street
Boston, MA 02109
______________________________________________________________________________________________
</TABLE>
[FN]
(1) Franklin Resources, Inc. has reported that it and certain of its
shareholders and subsidiaries have sole voting power with respect to
5,960,170 shares, shared voting power with respect to 459,997 shares
and shared dispositive power with respect to 6,366,167 shares.
(2) Merrill Lynch & Co., Inc. has reported that it has shared voting power
with respect to 4,160,610 shares while certain of its subsidiaries
have shared voting power and shared dispositive power with respect to
up to 4,160,610 shares.
(3) Frost National Bank of San Antonio, N.A. has reported that it has
shared voting and dispositive power with respect to 4,027,492 shares
in its capacity as Trustee for the Valero Energy Corporation Thrift
Plan, Valero Energy Corporation Employees' Stock Ownership Plan,
Valero Employees' Stock Ownership Plan, Valero Energy Corporation
Benefits Trust and Valero Energy Corporation Supplemental Executive
Retirement Plan.
(4) The Capital Group Companies, Inc. has reported in a Schedule 13G that
it and certain investment management subsidiaries have sole voting
power with respect to 600 shares and sole dispositive power with
respect to 3,292,700 shares. One such subsidiary, Capital Research
and Management Company, has also reported that it has sole
dispositive power with respect to 2,823,180 of such shares.
(5) Wellington Management Company, LLP ("Wellington") has filed a
Schedule 13G reporting shared dispositive power with respect to
2,841,946 shares and shared voting power with respect to 126,099
shares.
In addition, all 11,500 outstanding shares of Series A Preferred Stock
are held by American General Corporation, P.O. Box 3855, Houston,
Texas 77253; no filing of Schedule 13G or 13D is required with respect
thereto.
Except as otherwise indicated, the following table sets forth
information as of February 1, 1997, regarding Common Stock and $3.125
Convertible Preferred Stock beneficially owned (or deemed to be owned)
by each current director, each executive officer named in the Summary
Compensation Table, and all current directors and executive officers of
Energy as a group. Such information has been furnished to Energy by such
persons and cannot be independently verified by Energy. The $3.125
Convertible Preferred Stock has no ordinary voting rights.
<TABLE>
<CAPTION>
_______________________________________________________________________________________________
Common Stock
Shares $3.125 Percent
Name of Beneficially Shares Under Convertible of Class
Beneficial Owner (1) Owned Exercisable Preferred (Common
(2)(3)(4) Options(5) Stock(2) Stock)(2)
________________________________________________________________________________________________
<S> <C> <C> <C> <C>
F. Joseph Becraft(6) 46,012 160,000 0 *
Edward C. Benninger 127,864 70,805 1,000 *
Ronald K. Calgaard 2,142 1,667 0 *
Robert G. Dettmer(7) 5,877 3,000 0 *
A. Ray Dudley 8,141 3,000 0 *
Ruben M. Escobedo(8) 3,094 3,000 0 *
William E. Greehey 383,161 510,184 4,385 2.02%
James L. Johnson 3,852 3,000 0 *
Lowell H. Lebermann 2,244 3,000 0 *
E. Baines Manning 47,959 42,550 1,000 *
Stan L. McLelland 109,120 53,532 0 *
Susan Kaufman Purcell 2,289 3,000 0 *
All executive officers and 803,276 908,092 6,385 3.87%
directors as a group, including
the persons named above
(15 persons)(9)
______________________________________________________________________________________________
</TABLE>
[FN]
* Indicates that the percentage of beneficial ownership does not exceed 1%
of the class.
(1) The business address for all beneficial owners listed above is 530
McCullough Avenue, San Antonio, Texas 78215.
(2) No executive officer or director of Energy owns any class of equity
securities of Energy other than Common Stock and $3.125 Convertible
Preferred Stock. Neither any such person, nor all such persons as
a group, owns 1% or more of the $3.125 Convertible Preferred Stock.
The calculation for Percent of Class includes shares listed under
the captions "Shares Beneficially Owned" and "Shares Under Exercisable
Options."
(3) Includes shares allocated pursuant to various employee stock plans
available to its employees generally (collectively, the "Employee
Stock Plans"), as well as shares granted under Energy's Restricted
Stock Bonus and Incentive Stock Plan (the "Restricted Stock Plan"),
Executive Stock Incentive Plan ("ESIP") and the Director Plan.
Except as otherwise noted, each person named in the table, and each
other executive officer, has sole power to vote or direct the vote of
all such shares beneficially owned by him or her. Except as
otherwise noted, each person named in the table, and each other
executive officer, has sole power to dispose or direct the
disposition of shares beneficially owned by him or her. Common Stock
granted under the Restricted Stock Plan, ESIP and the Director Plan
("Restricted Stock") may not be disposed of until vested.
(4) Does not include shares that could be acquired under options, which
information is set forth in the second column.
(5) Includes shares subject to options that are exercisable within 60
days from February 1, 1997. Such shares may not be voted unless the
options are exercised. Options that may become exercisable within
such 60 day period only in the event of a change of control of Energy
are excluded. None of the current executive officers or directors
of Energy holds any rights to acquire Common Stock except through
exercise of stock options.
(6) Mr. Becraft resigned effective November 20, 1996.
(7) Includes shares held by spouse.
(8) Includes shares held by spouse and shares held in a trust.
(9) Certain officers of Energy not designated as executive officers by
the Board of Directors do not perform the duties of executive
officers and are not classified as "executive officers" for purposes
of this report.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company has invested through a subsidiary approximately $9.7
million in a program to drill coal seam gas wells in New Mexico. In order
to share the drilling and other risks inherent in this project, various
officers and employees of the Company were permitted to invest as general
partners in a partnership to which the subsidiary's interest was assigned.
The Board determined in 1992 that this transaction was fair to the Company.
During 1992 and 1993 Messrs. Greehey, Benninger, McLelland and Manning
invested approximately $207,000, $52,000, $156,000 and $104,000,
respectively, to acquire respective interests of 2.0%, .50%, 1.5% and 1.0%
in the project. No additional investments were made by these executive
officers during 1994 or 1996. During 1995, a company owned by Mr. Manning
purchased an additional .25% interest in the project from another investor.
During 1996, Messrs. Greehey, Benninger, McLelland and Manning (including
such company) received cash distributions of $45,680, $11,420, $34,260 and
$28,550, respectively, attributable to their investments. Additionally,
all investors in the project may be eligible to utilize certain federal
income tax credits applicable to the project.
Except as disclosed herein, no executive officer or director or
director of Energy has been indebted to the Company, or has acquired a
material interest in any transaction to which the Company is a party, during
the last fiscal year.
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) 1. Financial Statements. The following Consolidated Financial
Statements of Valero Energy Corporation and its subsidiaries are included in
Part II, Item 8 of this Form 10-K/A:
Page
Report of independent public accountants . . . . .
Consolidated balance sheets as of
December 31, 1996 and 1995 . . . . . . . . . .
Consolidated statements of income for the
years ended December 31, 1996, 1995 and
1994 . . . . . . . . . . . . . . . . . . . . . .
Consolidated statements of common stock and
other stockholders' equity for the years
ended December 31, 1996, 1995 and 1994 . . . . .
Consolidated statements of cash flows for the
years ended December 31, 1996, 1995 and
1994 . . . . . . . . . . . . . . . . . . . . . .
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/A or as part of
Valero Energy Corporation's Form 10-K filed on February 27, 1997, are the
following exhibits:
*2.1 -- Agreement and Plan of Merger, dated as of January 31,
1997, among Valero Energy Corporation, PG&E Corporation,
and PG&E Acquisition Corporation. The Company agrees to
furnish supplementally any omitted schedule or exhibit
to the Commission upon request.
*2.2 -- Form of Agreement and Plan of Distribution to be
executed by Valero Energy Corporation and Valero
Refining and Marketing Company pursuant to the Agreement
and Plan of Merger described in Exhibit 2.1 to this
Form 10-K. The Company agrees to furnish supplementally
any omitted schedule or exhibit to the Commission upon
request.
*2.3 -- Form of Employee Benefits Agreement to be executed by
Valero Energy Corporation and Valero Refining and
Marketing Company pursuant to the Agreement and Plan of
Merger described in Exhibit 2.1 to this Form 10-K. The
Company agrees to furnish supplementally any omitted
schedule or exhibit to the Commission upon request.
*2.4 -- Form of Tax Sharing Agreement to be executed by Valero
Energy Corporation, Valero Refining and Marketing
Company, and PG&E Corporation pursuant to the Agreement
and Plan of Merger described in Exhibit 2.1 to this
Form 10-K. The Company agrees to furnish supplementally
any omitted schedule or exhibit to the Commission upon
request.
2.5 -- Agreement of Merger, dated December 20, 1993, among
Valero Energy Corporation, Valero Natural Gas Partners,
L.P., Valero Natural Gas Company and Valero Merger
Partnership, L.P.--incorporated by reference from
Exhibit 2.1 to Amendment No. 2 to the Valero Energy
Corporation Registration Statement on Form S-3
(Commission File No. 33-70454, filed December 29, 1993).
3.1 -- Restated Certificate of Incorporation of Valero Energy
Corporation--incorporated by reference from Exhibit 4.1
to the Valero Energy Corporation Registration Statement
on Form S-8 (Commission File No. 33-53796, filed October
27, 1992).
3.2 -- By-Laws of Valero Energy Corporation, as amended and
restated October 17, 1991--incorporated by reference
from Exhibit 4.2 to the Valero Energy Corporation
Registration Statement on Form S-3 (Commission File No.
33-45456, filed February 4, 1992).
3.3 -- Amendment to By-Laws of Valero Energy Corporation, as
adopted February 25, 1993--incorporated by reference
from Exhibit 3.3 to the Valero Energy Corporation Annual
Report on Form 10-K (Commission File No. 1-4718, filed
February 26, 1993).
4.1 -- Rights Agreement, dated as of October 26, 1995, between
Valero Energy Corporation and Harris Trust and Savings
Bank, as Rights Agent--incorporated by reference from
Exhibit 1 to the Valero Energy Corporation Current
Report on Form 8-K (Commission File No. 1-4718, filed
October 27, 1995).
4.2 -- $300,000,000 Credit Agreement, dated as of November 1,
1995, among Valero Energy Corporation, Morgan Guaranty
and Trust Company of New York as Administrative Agent,
and Bank of Montreal as Syndication Agent and Issuing
Bank, and the banks and co-agents party thereto--
incorporated by reference from Exhibit 10.1 to the
Valero Energy Corporation Quarterly Report on Form 10-Q
(Commission File No. 1-4718, filed November 9, 1995).
4.3 -- Form of Indenture of Mortgage and Deed of Trust and
Security Agreement, dated as of March 25, 1987 (the
"Indenture"), from Valero Management Partnership, L.P.
to State Street Bank and Trust Company (successor to
Bank of New England) and Brian J. Curtis, as Trustees -
incorporated by reference from Exhibit 4.1 to the Valero
Natural Gas Partners, L.P. Quarterly Report on Form 10-Q
(Commission File No. 1-9433, filed May 15, 1987).
4.4 -- First Supplemental Indenture, dated as of March 25,
1987, to the Indenture--incorporated by reference from
Exhibit 4.2 to the Valero Natural Gas Partners, L.P.
Quarterly Report on Form 10-Q (Commission File No.
1-9433, filed May 15, 1987).
4.5 -- Second Supplemental Indenture, dated as of March 25,
1987, to the Indenture--incorporated by reference from
Exhibit 4.1 to the Valero Natural Gas Partners, L.P.
Quarterly Report on Form 10-Q (Commission File No.
1-9433, filed July 31, 1987).
4.6 -- Fourth Supplemental Indenture, dated as of June 15,
1988, to the Indenture--incorporated by reference from
Exhibit 4.6 to the Valero Natural Gas Partners, L.P.
Registration Statement on Form S-8 (Registration No.
33-26554, filed January 13, 1989).
4.7 -- Fifth Supplemental Indenture, dated as of December 1,
1988, to the Indenture--incorporated by reference from
Exhibit 4.7 to the Valero Natural Gas Partners, L.P.
Registration Statement on Form S-8 (Registration No.
33-26554, filed January 13, 1989).
4.8 -- Seventh Supplemental Indenture, dated as of August 15,
1989, to the Indenture--incorporated by reference from
Exhibit 4.6 to the Valero Natural Gas Partners, L.P.
Annual Report on Form 10-K (Commission File No. 1-9433,
filed March 1, 1990).
4.9 -- Ninth Supplemental Indenture, dated as of October 19,
1990, to the Indenture--incorporated by reference from
Exhibit 4.7 to the Valero Natural Gas Partners, L.P.
Annual Report on Form 10-K (Commission File No. 1-9433,
filed February 25, 1991).
+10.1 -- Valero Energy Corporation Executive Deferred
Compensation Plan, amended and restated as of October
21, 1986--incorporated by reference from Exhibit 10.16
to the Valero Energy Corporation Annual Report on
Form 10-K (Commission File No. 1-4718, filed
February 26, 1988).
+10.2 -- Valero Energy Corporation Key Employee Deferred
Compensation Plan, amended and restated as of October
21, 1986--incorporated by reference from Exhibit 10.17
to the Valero Energy Corporation Annual Report on
Form 10-K (Commission File No. 1-4718, filed February
26, 1988).
*+10.3 -- Valero Energy Corporation Restricted Stock Bonus and
Incentive Stock Plan, as amended and restated
November 21, 1996.
*+10.4 -- Valero Energy Corporation Stock Option Plan No. 3, as
amended and restated August 22, 1996.
*+10.5 -- Valero Energy Corporation Stock Option Plan No. 4, as
amended and restated August 22, 1996.
*+10.6 -- Valero Energy Corporation 1990 Restricted Stock Plan for
Non-Employee Directors, as amended and restated
August 22, 1996.
*+10.7 -- Valero Energy Corporation Supplemental Executive
Retirement Plan, as amended and restated effective
January 1, 1996.
*+10.8 -- Valero Energy Corporation Executive Incentive Bonus
Plan, as amended and restated January 23, 1997.
*+10.9 -- Valero Energy Corporation Executive Stock Incentive
Plan, as amended and restated November 21, 1996.
*+10.10 -- Valero Energy Corporation Non-Employee Director Stock
Option Plan, as amended and restated November 21, 1996.
+10.11 -- 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).
*+10.12 -- Schedule of Executive Severance Agreements.
+10.13 -- 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).
+10.14 -- Modification of Employment Agreement between Valero
Energy Corporation and William E. Greehey, dated
November 29, 1994--incorporated by reference from
Exhibit 10.12 to the Valero Energy Corporation Annual
Report on Form 10-K (Commission File No. 1-4718, filed
March 1, 1995).
+10.15 -- Indemnity Agreement, dated as of February 24, 1987,
between Valero Energy Corporation and William E.
Greehey--incorporated by reference from Exhibit 10.16 to
the Valero Energy Corporation Annual Report on Form 10-K
(Commission File No. 1-4718, filed February 26, 1993).
*+10.16 -- Schedule of Indemnity Agreements.
*+10.17 -- Incentive Bonus Agreement, dated as of November 21,
1996, between Valero Energy Corporation and Terrence E.
Ciliske.
*+10.18 -- Incentive Bonus Agreement, dated as of November 21,
1996, between Valero Energy Corporation and Peter A.
Fasullo.
*+10.19 -- Incentive Bonus Agreement, dated as of November 21,
1996, between Valero Energy Corporation and Gregory C.
King.
*+10.20 -- Management Stability Agreement, dated as of November 1,
1996, between Valero Energy Corporation and Terrence E.
Ciliske.
*+10.21 -- Management Stability Agreement, dated as of November 1,
1996, between Valero Energy Corporation and Peter A.
Fasullo.
*+10.22 -- Management Stability Agreement, dated as of November 1,
1996, between Valero Energy Corporation and Gregory C.
King.
*+10.23 -- Waiver and Agreement, dated as of November 21, 1996,
between Valero Energy Corporation and William E.
Greehey.
*+10.24 -- Schedule of Waiver 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 May 13,
1997.
*24.1 -- Power of Attorney, dated February 27, 1997 (set forth on
the signatures page of Valero Energy Corporation's
Form 10-K).
**27.1 -- Financial Data Schedule (reporting financial information
as of and for the year ended December 31, 1996).
**27.2 -- Restated Financial Data Schedule (reporting financial
information as of and for the year ended December 31,
1995).
**27.3 -- Restated Financial Data Schedule (reporting financial
information as of and for the year ended December 31,
1994).
________________
* Filed with Valero Energy Corporation's Form 10-K on February 27, 1997.
+ Identifies management contracts or compensatory plans or arrangements
filed as an exhibit to Valero Energy Corporation's Form 10-K pursuant
to Item 14(c) of Form 10-K.
** The Financial Data Schedule and Restated Financial Data Schedules 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 are
included as exhibits only to the electronic filing of this Form 10-K/A
in accordance with Item 601(c) of Regulation S-K and Section 401 of
Regulation S-T.
*** Filed herewith.
Copies of exhibits filed as a part of this Form 10-K/A and Valero
Energy Corporation's Form 10-K may be obtained by stockholders of record
at a charge of $.15 per page, minimum $5.00 each request. Direct inquiries
to Rand C. Schmidt, Corporate Secretary, Valero Energy Corporation,
P.O. Box 500, San Antonio, Texas 78292.
Pursuant to paragraph 601(b)(4)(iii)(A) of Regulation S-K, the
registrant has omitted from the foregoing listing of exhibits, and hereby
agrees to furnish to the Commission upon its request, copies of certain
instruments, each relating to long-term debt not exceeding 10% of the total
assets of the registrant and its subsidiaries on a consolidated basis.
(b) Reports on Form 8-K. A report on Form 8-K dated November 21,
1996 was filed electronically on December 31, 1996, reporting Item 5. Other
Events, in connection with the Board's approval to pursue a strategic
transaction relating to the Company's principal business activities.
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. 33-14455 (filed May 21,
1987), No. 33-38045 (filed December 3, 1990), No. 33-53796 (filed October
27, 1992), No. 33-59040 (filed March 3, 1993), No. 33-52533 (filed March 7,
1994), No. 33-59217 (filed May 10, 1995), No. 33-63703 (filed October 26,
1995), and No. 333-02987 (filed April 3, 1996).
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/ Rand C. Schmidt
(Rand C. Schmidt, Attorney-in-Fact)
Date: May 13, 1997
<PAGE>
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
Director, Chairman of the
Board and Chief Executive
Officer (Principal
William E. Greehey* Executive Officer) May 13, 1997
Director, President
and Chief Financial Officer
(Principal Financial
Edward C. Benninger* and Accounting Officer) May 13, 1997
Ronald K. Calgaard* Director May 13, 1997
Robert G. Dettmer* Director May 13, 1997
A. Ray Dudley* Director May 13, 1997
James L. Johnson* Director May 13, 1997
Lowell H. Lebermann* Director May 13, 1997
Susan Kaufman Purcell* Director May 13, 1997
*By: /s/ Rand C. Schmidt
(Rand C. Schmidt, Attorney-in-Fact)
<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,
1996 1995 1994
<S> <C> <C> <C>
COMPUTATION OF EARNINGS PER SHARE
ASSUMING NO DILUTION:
Net income. . . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282
Less: Preferred stock dividend requirements. . . . (11,327) (11,818) (9,490)
Net income applicable to common stock . . . . . . . $ 61,374 $ 48,020 $ 7,792
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . . . . 43,926,026 43,651,914 43,369,836
Earnings per share assuming no dilution . . . . . . $ 1.40 $ 1.10 $ .18
COMPUTATION OF EARNINGS PER SHARE
ASSUMING FULL DILUTION:
Net income. . . . . . . . . . . . . . . . . . . . $ 72,701 $ 59,838 $ 17,282
Less: Preferred stock dividend requirements. . . (11,327) (11,818) (9,490)
Add: Reduction of preferred stock dividends
applicable to the assumed conversion of
Convertible Preferred Stock . . . . . . . . . . 10,781 10,781 8,325
Net income applicable to common stock
assuming full dilution. . . . . . . . . . . . . $ 72,155 $ 58,801 $ 16,117
Weighted average number of shares of common
stock outstanding . . . . . . . . . . . . . . . 43,926,026 43,651,914 43,369,836
Weighted average common stock equivalents
applicable to stock options . . . . . . . . . . 632,967 413,809 56,926
Weighted average shares issuable upon
conversion of Convertible Preferred Stock . . . 6,381,798 6,381,798 4,948,079
Weighted average shares used for computation. . . 50,940,791 50,447,521 48,374,841
Earnings per share assuming full dilution . . . . $ 1.42<F1> $ 1.17<F1> $ .33<F1>
<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.
</TABLE>
<TABLE>
EXHIBIT 12.1
VALERO ENERGY CORPORATION
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in Thousands)
<CAPTION>
Year Ended Year Ended Year Ended Year Ended
December 31, December 31, 1994 December 31, 1993 December 31,
1996 1995 Pro Forma<F1> Historical Pro Forma<F1> Historical 1992
<S> <C> <C> <C> <C> <C> <C> <C>
Pretax income from continuing
operations <F5>. . . . . . . . . . . . . $113,701 $ 95,138 $ 16,489 $ 27,982 $ 76,698 $ 68,224 $131,419
Add (Deduct):
Net interest expense <F4> . . . . . . . . 95,177 101,222 98,695 76,921 89,413 37,182 30,423
Amortization of previously capitalized
interest . . . . . . . . . . . . . . . . 6,061 6,820 6,847 6,282 6,300 4,998 4,544
Interest portion of rental expense <F2> . 14,034 13,251 8,259 6,695 8,003 4,316 4,214
Distributions (less than)/in excess of
equity in earnings of VNGP, L.P. <F3>. . - - - 18,968 - (4,970) (1,067)
Distributions (less than) equity in
earnings of joint ventures <F4>. . . . . (3,899) (4,304) (2,437) (2,437) - - -
Earnings as defined. . . . . . . . . . . $225,074 $212,127 $127,853 $134,411 $180,414 $109,750 $169,533
Net interest expense <F4>. . . . . . . . . $ 95,177 $101,222 $ 98,695 $ 76,921 $ 89,413 $ 37,182 $ 30,423
Capitalized interest . . . . . . . . . . . 4,328 4,699 2,558 2,365 14,048 12,335 15,853
Interest portion of rental expense <F2>. . 14,034 13,251 8,259 6,695 8,003 4,316 4,214
Fixed charges as defined . . . . . . . . $113,539 $119,172 $109,512 $ 85,981 $111,464 $ 53,833 $ 50,490
Ratio of earnings to fixed charges . . . . 1.98x 1.78x 1.17x 1.56x 1.62x 2.04x 3.36x
<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.
<F5> The 1994 historical and pro forma amounts have been restated to reflect the effects of a prior period adjustment
resulting in a charge to 1994 income for an acquisition expense accrual originally charged to property, plant and
equipment.
</TABLE>
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/A into the Company's previously filed
Registration Statements on Form S-8 (File Nos. 33-14455, 33-38045, 33-53796,
33-52533, 33-59040, 33-59217, 33-63703, 333-02987) and on Form S-3 (File No.
33-56441).
/s/ ARTHUR ANDERSEN LLP
San Antonio, Texas
May 13, 1997
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1996 AND THE CONSOLIDATED
STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1996 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 57,593
<SECURITIES> 0
<RECEIVABLES> 567,712
<ALLOWANCES> 1,624
<INVENTORY> 212,134
<CURRENT-ASSETS> 888,169
<PP&E> 2,787,431
<DEPRECIATION> 708,352
<TOTAL-ASSETS> 3,134,774
<CURRENT-LIABILITIES> 875,154
<BONDS> 868,300
1,150
3,450
<COMMON> 44,186
<OTHER-SE> 1,028,189
<TOTAL-LIABILITY-AND-EQUITY> 3,134,774
<SALES> 4,990,681
<TOTAL-REVENUES> 4,990,681
<CGS> 4,789,772
<TOTAL-COSTS> 4,789,772
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 95,177
<INCOME-PRETAX> 113,701
<INCOME-TAX> 41,000
<INCOME-CONTINUING> 72,701
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 72,701
<EPS-PRIMARY> 1.40
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 64,681
<SECURITIES> 0
<RECEIVABLES> 340,382
<ALLOWANCES> 1,193
<INVENTORY> 140,822
<CURRENT-ASSETS> 621,543
<PP&E> 2,682,694
<DEPRECIATION> 622,123
<TOTAL-ASSETS> 2,861,880
<CURRENT-LIABILITIES> 468,282
<BONDS> 1,035,641
6,900
3,450
<COMMON> 43,739
<OTHER-SE> 977,024
<TOTAL-LIABILITY-AND-EQUITY> 2,861,880
<SALES> 3,197,872
<TOTAL-REVENUES> 3,197,872
<CGS> 3,009,081
<TOTAL-COSTS> 3,009,081
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 101,222
<INCOME-PRETAX> 95,138
<INCOME-TAX> 35,300
<INCOME-CONTINUING> 59,838
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 59,838
<EPS-PRIMARY> 1.10
<EPS-DILUTED> 0
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<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> 2,657,915
<DEPRECIATION> 531,501
<TOTAL-ASSETS> 2,816,558
<CURRENT-LIABILITIES> 460,767
<BONDS> 1,021,820
12,650
3,450
<COMMON> 43,464
<OTHER-SE> 955,966
<TOTAL-LIABILITY-AND-EQUITY> 2,816,558
<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> 27,982
<INCOME-TAX> 10,700
<INCOME-CONTINUING> 17,282
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 17,282
<EPS-PRIMARY> .18
<EPS-DILUTED> 0
</TABLE>
