FORM 10-K/A
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1993
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-9433
VALERO NATURAL GAS PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
Delaware 74-2448118
(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 Units of Limited Partner New York Stock Exchange
Interests
Securities registered pursuant to Section 12(g) of the Act:
NONE.
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value on February 14, 1994 of the
registrant's Common Units held by nonaffiliates of the
registrant, based on the average of the high and low prices as
quoted in the New York Stock Exchange Composite Transactions
listing for such date, was approximately $114 million.
Indicated below is the number of units outstanding of the
registrant's only class of Partnership Units, as of February 14,
1994.
Number of Units
Title of Class Outstanding
Common Units of Limited Partner Interests 18,486,538
<PAGE>
CONTENTS
PAGE
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . .
Recent Developments. . . . . . . . . . . . . . .
Proposed Merger with Energy. . . . . . . . . .
Decline of Crude Oil and NGL Prices. . . . . .
Natural Gas Operations . . . . . . . . . . . . .
General. . . . . . . . . . . . . . . . . . . .
Pipeline Facilities. . . . . . . . . . . . . .
Gas Sales. . . . . . . . . . . . . . . . . . .
Intrastate Sales . . . . . . . . . . . . . .
Interstate Sales . . . . . . . . . . . . . .
Gas Transportation and Exchange. . . . . . . .
Gas Supply . . . . . . . . . . . . . . . . . .
Gas Storage Facilities . . . . . . . . . . . .
Natural Gas Liquids Operations . . . . . . . . .
General. . . . . . . . . . . . . . . . . . . .
Gas Processing Facilities. . . . . . . . . . .
Fractionation and Other Facilities . . . . . .
NGL Supply and Sales . . . . . . . . . . . . .
Governmental Regulations . . . . . . . . . . . .
Texas Regulation . . . . . . . . . . . . . . .
Federal Regulation . . . . . . . . . . . . . .
Environmental Matters. . . . . . . . . . . . . .
Competition. . . . . . . . . . . . . . . . . . .
Natural Gas. . . . . . . . . . . . . . . . . .
Natural Gas Liquids. . . . . . . . . . . . . .
Employees. . . . . . . . . . . . . . . . . . . .
PART II
Item 7. Management's Discussion and Analysis of
Financial Condition and Results of
Operations . . . . . . . . . . . . . . . . . . .
<PAGE>
PART I
ITEM 1. BUSINESS
Valero Natural Gas Partners, L.P. ("VNGP, L.P.") was
established under the Delaware Revised Uniform Limited
Partnership Act on January 28, 1987, and commenced actual
operations on March 25, 1987, when Valero Energy Corporation and
its subsidiaries restructured their natural gas and natural gas
liquids operations by transferring such operations to the
Partnership (defined herein). Unless otherwise required by the
context, the term "Energy" as used herein refers to Valero Energy
Corporation and its consolidated subsidiaries, both individually
and collectively, and the term "Partnership" as used herein
refers to VNGP, L.P. and its consolidated subsidiaries. VNGP,
L.P.'s principal executive offices are located at 530 McCullough
Avenue, San Antonio, Texas 78215 (telephone number
(210) 246-2000).
VNGP, L.P. holds a 99% limited partner interest in
Valero Management Partnership, L.P. (the "Management
Partnership") and certain subsidiary partnerships established
subsequent to the creation of the Partnership. The Management
Partnership holds a 99% limited partner interest in eleven
subsidiary operating partnerships which existed at the time VNGP,
L.P. was established and one subsidiary operating partnership
formed in 1992 (collectively, the "Subsidiary Operating
Partnerships"). Valero Natural Gas Company ("VNGC"), a wholly
owned subsidiary of Energy, is the general partner of both VNGP,
L.P. and the Management Partnership (in such capacities, the
"General Partner") and holds a 1% general partner interest in
each partnership. Various subsidiaries of VNGC serve as general
partners (in such capacities, the "Subsidiary General Partners")
of and hold 1% general partner interests in each Subsidiary
Operating Partnership. Unless the context otherwise requires,
any references to VNGP, L.P., the Management Partnership or any
of the original Subsidiary Operating Partnerships regarding any
period prior to March 25, 1987, should be construed to refer, as
appropriate, to Energy, VNGC or the corresponding subsidiaries of
Energy or VNGC that transferred their natural gas and natural gas
liquids operations to the Partnership; references to the
Partnership with respect to such period should be construed to
refer to VNGC and such subsidiaries. For additional information
with respect to the 1987 restructuring, see Note 1 -
"Organization and Control" of Notes to Consolidated Financial
Statements.
The Partnership operates in two business segments:
Natural Gas and Natural Gas Liquids. For additional operational,
financial and statistical information regarding these operations,
see "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and Note 4 of Notes to Consolidated
Financial Statements. For information with respect to cash
provided by and used in the Partnership's operations, see
"Management's Discussion and Analysis of Financial Condition and
Results of Operations - Liquidity and Capital Resources."
RECENT DEVELOPMENTS
Proposed Merger with Energy
In October 1993, Energy publicly announced its proposal
to acquire the 9.7 million issued and outstanding common units of
limited partner interests ("Common Units") in VNGP, L.P. held by
persons other than Energy (the "Public Unitholders") pursuant to
a merger of VNGP, L.P. with a wholly owned subsidiary of Energy
(the "Merger"). The Board of Directors of VNGC appointed a
special committee of outside directors (the "Special Committee")
to consider the Merger and to determine the fairness of the
transaction to the Public Unitholders. The Special Committee
thereafter retained independent financial and legal advisors to
assist the Special Committee. Upon the recommendation of the
Special Committee, the Board of Directors of VNGC unanimously
approved the Merger. Effective December 20, 1993, Energy,
VNGP, L.P. and VNGC entered into an agreement of merger (the
"Merger Agreement") providing for the Merger. In the Merger, the
Common Units held by the Public Unitholders will be converted
into the right to receive cash in the amount of $12.10 per Common
Unit. As a result of the Merger, VNGP, L.P. would become a
wholly owned subsidiary of Energy. There can be no assurance,
however, that the Merger will be completed.
Consummation of the Merger is subject to, among other
things, (i) approval of the Merger Agreement by the holders of a
majority of the issued and outstanding Common Units;
(ii) approval by a majority of the Common Units held by the
Public Unitholders voted at a special meeting of holders of
Common Units to be called to consider the Merger Agreement;
(iii) satisfactory waivers, consents or amendments to certain of
Energy's financial agreements; and (iv) completion of an
underwritten public offering of convertible preferred stock by
Energy. A proposal to approve the Merger Agreement will be
submitted to the holders of Common Units at the special meeting
of Unitholders expected to be scheduled during the second quarter
of 1994. Prior to the special meeting, the holders of Common
Units will receive a proxy statement fully describing the Merger
and explaining the manner in which holders of Common Units may cast
their votes (the "Proxy Statement"). Energy owns approximately
47.5% of the outstanding Common Units and intends to vote its
Common Units in favor of the Merger. The foregoing discussion
of the Merger omits certain information contained in
the Merger Agreement and the Proxy Statement. Statements made in
this Report concerning the Merger are qualified by and are made
subject to the more detailed information contained in the Merger
Agreement and the Proxy Statement.
Decline of Crude Oil and NGL Prices
Beginning in November 1993, crude oil prices fell
significantly and have not recovered to prior levels. The price
decline resulted from a number of factors including the decision
by the Organization of Petroleum Exporting Companies ("OPEC") to
forego cuts in crude oil production, weakened global demand for
crude oil, increasing production from non-OPEC areas and concerns
related to the re-entry of Iraq into world oil markets. Natural
gas liquids ("NGL") prices also fell in conjunction with the
decline in crude oil prices. Record-high NGL inventories also
depressed NGL prices. Because of depressed NGL sales prices and
the high cost of natural gas from which such liquids are
extracted, NGL margins were very depressed in the fourth quarter
of 1993, requiring the Partnership to cease operations for
20 days in December 1993 at one of its gas processing plants and
to suspend the production of ethane for 28 days in December at
two other plants due to lack of profitability. See "Natural Gas
Liquids Operations - NGL Supply and Sales." The Partnership
continues to monitor the market conditions affecting the
profitability of its gas processing plants with a view to
modifying as needed any operations that appear unprofitable.
During the first quarter of 1994, NGL prices have increased
modestly since late December 1993, but remain below first quarter
1993 levels. Concurrently, natural gas prices and resulting
shrinkage costs have increased during the first quarter of 1994
compared to the same period in 1993. Accordingly, the
Partnership's operating income is expected to be substantially
lower in the first quarter of 1994 than in the fourth quarter of
1993.
NATURAL GAS OPERATIONS
General
The Partnership owns and operates natural gas pipeline
systems principally serving Texas intrastate markets. Through
interconnections with interstate pipelines, the Partnership also
markets natural gas throughout the United States. The
Partnership's natural gas pipeline and marketing operations
consist principally of purchasing, gathering, transporting and
selling natural gas to gas distribution companies, electric
utilities, other pipeline companies and industrial customers, and
transporting natural gas for producers, other pipelines and end
users.
Pipeline Facilities
The Partnership's principal natural gas pipeline system
is the intrastate gas system ("Transmission System") operated by
Valero Transmission, L.P. ("Transmission") in the State of Texas.
(References to Transmission prior to March 25, 1987 refer to
Valero Transmission Company, a wholly owned subsidiary of VNGC,
as the previous owner of the Transmission System. References to
Transmission on or after March 25, 1987 refer to Valero
Transmission, L.P., a Subsidiary Operating Partnership, as
successor owner of the Transmission System.) The Transmission
System generally consists of large diameter transmission lines
which receive gas at central gathering points and move the gas to
delivery points. The Transmission System also includes numerous
small diameter lines connecting individual wells and common
receiving points to the Transmission System's larger diameter
lines.
The Partnership's wholly owned, jointly owned and leased
natural gas pipeline systems include approximately 7,200 miles of
mainlines, lateral lines and gathering lines. These pipeline
systems are located along the Texas Gulf Coast and throughout
South Texas and extend westerly to near Pecos, Texas; northerly
to near the Dallas-Fort Worth area, easterly to Carthage, Texas,
near the Louisiana border and southerly into Mexico near Reynosa.
The Partnership operates and jointly owns in equal portions with
Texas Utilities Fuel Company ("TUFCO") a 395-mile pipeline
extending from Waha, near Fort Stockton, Texas, to near Ennis,
Texas, south of the Dallas-Fort Worth area. An addition to this
line also extends 58 miles into East Texas from Ennis to Bethel,
Texas, and is jointly owned 39% by TUFCO (which operates the
line), 39% by Lone Star Gas Company and 22% by the Partnership.
The Partnership also operates and jointly owns in equal portions
with TECO Pipeline Company a 340-mile pipeline system and related
facilities extending from Waha to New Braunfels, near
San Antonio, Texas. The Partnership owns a 3.5-mile, 24-inch
pipeline that connects the Partnership's pipeline near Penitas in
South Texas to Petroleos Mexicanos's ("PEMEX") 42-inch pipeline
outside Reynosa, Mexico. The Partnership leases and operates
several pipelines, including approximately 240 miles of 24-inch
pipeline leased from TUFCO that extends from near Dallas to near
Houston, and approximately 105 miles of pipeline leased from
Energy that extends the Partnership's North Texas pipeline
further into East Texas from Bethel to Carthage (the "East Texas
pipeline"). These integrated systems include 39 mainline
compressor stations with a total of approximately
162,000 horsepower, together with gas processing plants,
dehydration and gas treating plants and numerous measuring and
regulating stations. The Partnership's pipeline systems have
considerable flexibility in providing connections between many
producing and consuming areas. The Partnership's owned and
leased pipeline systems have 70 interconnects with 22 intrastate
pipelines and 38 interconnects with 12 interstate pipelines.
The Partnership's pipeline systems are able to handle
widely varying loads caused by changing supply and demand
patterns. Annual average throughput was approximately 2.5 Bcf
(1) per day in 1993, and has been in excess of 2 Bcf per day in
recent years. The system has served peak demands at hourly rates
of flow significantly in excess of these daily averages.
Although capacity in the Partnership's pipeline systems is
generally expected to be adequate for the foreseeable future,
seasonal factors can significantly influence gas sales and
transportation volumes.
[FN]
(1) All volumes of natural gas referred to herein are stated at a
pressure base of 14.65 pounds per square inch absolute and at 60
degrees Fahrenheit and in most instances are rounded to the
nearest major multiple. The term "Mcf" means thousand cubic
feet, the term "MMcf" means million cubic feet and the term "Bcf"
means billion cubic feet. The term "Btu" means British Thermal
Unit, a standard measure of heating value. The term "MMBtu's"
means million Btu's. The number of MMBtu's of total natural gas
deliveries is approximately equal to the number of Mcf's of such
deliveries.
Gas Sales
The Partnership's gas sales are made principally through
the Subsidiary Operating Partnerships which operate special
marketing programs ("SMPs"). The Subsidiary Operating
Partnerships operating the SMPs are Reata Industrial Gas, L.P.
("Reata"), Valero Industrial Gas, L.P. ("Vigas") and VLDC, L.P.
("VLDC"). Reata buys its gas supply from producers, marketers
and certain intrastate pipelines and resells the gas in the
intrastate market on both a long-term basis and a short-term
interruptible basis. Vigas acquires gas supply directly from gas
producers and sells the gas on a short-term interruptible basis
and a term basis to intrastate and interstate markets. VLDC
serves short-term intrastate sales markets with supplies of both
intrastate and interstate gas. In addition, some of the
Partnership's gas sales are made by Valero Gas Marketing, L.P.
("Valero Gas Marketing"), Val Gas, L.P. ("Val Gas") and Rivercity
Gas, L.P. ("Rivercity"). Valero Gas Marketing engages primarily
in off-system sales. Val Gas primarily purchases and resells
natural gas in interstate commerce. Rivercity sells gas on a
short-term, interruptible basis. Most of the gas sold by Reata,
Vigas, VLDC, Val Gas and Rivercity is transported through the
Transmission System by Transmission. Transmission sells natural
gas under long-term contracts to a few remaining intrastate
customers. However, because of various factors described below,
most of the industrial and other gas sales customers previously
served by Transmission, including local distribution companies
("LDCs") and electric utilities, now purchase gas in the spot
market, including purchases from the Subsidiary Operating
Partnerships operating the SMPs, or have entered into gas
transportation contracts with Transmission to transport gas
acquired by the customers directly from producers or other
suppliers. Accordingly, Transmission is primarily a transporter
rather than a seller of natural gas. See "Natural Gas
Operations - Gas Transportation and Exchange" below.
During 1993, the Partnership sold natural gas under
hundreds of separate short-term and long-term gas sales contracts
to numerous customers in both the intrastate and interstate
markets. The Partnership's gas sales are made primarily to gas
distribution companies, electric utilities, other pipeline
companies and industrial users. The gas sold to distribution
companies is resold to consumers in a number of cities including
San Antonio, Dallas, Austin, Corpus Christi and Chicago.
Although the expiration dates of the Partnership's gas sales
contracts range from 1994 to 2001, many of the Partnership's
short-term sales contracts have expired or will expire by their
terms in 1994 or are terminable on a day-to-day, month-to-month
or similar basis by either the Partnership or the party to whom
gas is sold. The General Partner anticipates that most of these
contracts will be renewed for an additional term or converted to
transportation arrangements, or that the gas sold under these
contracts will be marketed to other customers.
The Partnership's gas sales and transportation volumes
(in MMcf per day) for the three years ended December 31, 1993,
are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Intrastate sales:
SMPs and other . . . . . . . . . . 642 552 545
Transmission . . . . . . . . . . . 57 78 103
Total intrastate sales . . . . 699 630 648
Interstate sales . . . . . . . . . . 281 259 363
Total sales. . . . . . . . . . 980 889 1,011
Transportation . . . . . . . . . . . 1,566 1,301 1,132
Total gas throughput . . . . . 2,546 2,190 2,143
</TABLE>
In 1993, the Partnership's ten largest gas sales
customers accounted for approximately 33% of its total
consolidated operating revenues and approximately 48% of its
total consolidated daily gas sales volumes. During 1993, sales
of natural gas accounted for approximately 38% of total daily
Partnership gas throughput volumes. The Partnership's largest
gas sales customer is San Antonio City Public Service ("CPS").
See "Natural Gas Operations - Gas Sales - Intrastate Sales."
Through the SMPs, the Partnership continues to emphasize
sales under term contracts. During 1993, the Partnership
continued to expand its term sales to LDCs who have been seeking
to convert purchase obligations from interstate pipelines into
firm transportation arrangements. In 1993, about 55% of the
Partnership's gas sales were made under term contracts. Term
contracts are becoming more prevalent in the industry and the
Partnership's gas sales under term contracts are expected to
increase over the next several years. See "Natural Gas
Operations - Gas Sales - Interstate Sales" and "Competition -
Natural Gas." The Partnership has also emphasized the
transportation of natural gas for producers and sales customers.
See "Natural Gas Operations - Gas Transportation and Exchange."
The Partnership's natural gas operations have been
affected by an emerging trend of west-to-east movement of gas
across the United States resulting from growing productive
capacity in western supply basins, the completion of new pipeline
capacity from such basins to the U.S. West Coast and increasing
demand for power generation in the East and Southeast. The
General Partner believes that in many of the pipelines serving
this market, west-to-east capacity is becoming constrained. The
General Partner believes that over time, improving transportation
margins resulting from these capacity constraints may warrant
additional west-to-east capacity additions and that the
Partnership would be positioned to participate in such
opportunities if it had the financial flexibility to make the
necessary capital expenditures. See "Natural Gas Operations -
Pipeline Facilities" and "Properties."
Under current regulations of the Railroad Commission of
Texas (the "Railroad Commission"), Transmission, like other gas
purchasers, is required to take ratably first casinghead gas (2)
and certain special allowable gas (casinghead gas and special
allowable gas that are the last to be shut in during periods of
reduced market demand are referred to collectively as "high-
priority" gas) produced from wells connected to Transmission's
pipeline systems and, if Transmission's sales volumes exceed the
amounts of such high-priority gas available, thereafter to take
by specific category other gas, including gas well gas, from
wells from which Transmission purchases gas on a ratable basis to
the extent of market demand. See "Governmental
Regulations - Texas Regulation." Most of the casinghead gas
under contract to Transmission was acquired under older,
long-term contracts which provided for relatively high prices,
together with price escalation provisions under the Natural Gas
Policy Act of 1978 (the "NGPA"). The majority of these contracts
did not contain allowances for price reductions when market
prices declined or contain so-called "market-out" provisions that
permit a purchaser to terminate a contract if market conditions
render the contract uneconomical. As a result, the cost of the
high-priority gas connected to Transmission's system under its
older contracts has remained substantially higher than the cost
of alternative gas supplies. Accordingly, most of Transmission's
major customers have switched upon contract expiration from the
noninterruptible service provided by Transmission to alternative
suppliers including the Subsidiary Operating Partnerships
operating the SMPs, causing Transmission's sales to decline
significantly. For additional information concerning
Transmission's cost of gas and gas sales price, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations."
[FN]
(2) The Partnership generally purchases "casinghead gas"
(defined as gas produced from wells primarily producing oil) and
"gas well gas" (defined as gas produced from wells primarily
producing gas).
Intrastate Sales
In 1993, the Partnership sold approximately 699 MMcf per
day of gas to its core intrastate market, representing
approximately 71% of total daily gas sales volumes, compared to
630 MMcf per day (71%) in 1992 and 648 MMcf per day (64%) in
1991. The majority of the Partnership's daily intrastate sales
are made through its SMPs (92%, 88% and 84% in 1993, 1992 and
1991, respectively) with the remainder made by Transmission.
The Partnership's sales to CPS are made principally by Reata.
Effective July 1, 1992, the Partnership was awarded a new
contract with CPS to supply 100% of CPS's natural gas
requirements. The contract is effective until 2002, subject to
possible renegotiation of certain contract terms beginning
in 1997. As a result of the CPS contract, the Partnership's
gas sales volumes to CPS increased significantly in 1993.
Natural gas sales to CPS in 1993 represented approximately
11% of the Partnership's total consolidated operating revenues
and approximately 18% of the Partnership's total consolidated
daily gas sales volumes. Except for the CPS contract, the
Partnership's gas sales contracts between the SMPs and the
Partnership's intrastate customers generally require the
Partnership to provide a fixed and determinable quantity of gas
rather than total customer requirements. The Partnership's gas
sales contracts between Transmission and its intrastate customers
generally provide for either maximum volumes or total
requirements, subject to priorities and allocations established
by the Railroad Commission.
Since December 31, 1979, Transmission's gas sales to its
customers have been made at prices established by an order (the
"Rate Order") of the Railroad Commission. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and Note 6 of Notes to Consolidated Financial
Statements for a discussion of Transmission's rates and the terms
of the 1993 settlement of a customer's audit of Transmission's
weighted average cost of gas. The price of natural gas sold
under the SMPs is not currently regulated by the Railroad
Commission, and the Subsidiary Operating Partnerships operating
the SMPs may generally enter into any sales contract that they
are able to negotiate with customers. See "Governmental
Regulations - Texas Regulation."
Interstate Sales
In 1993, the Partnership sold, through its SMPs,
approximately 281 MMcf per day of gas to interstate markets,
representing approximately 29% of total daily gas sales volumes,
compared to 259 MMcf per day (29%) in 1992 and 363 MMcf per day
(36%) in 1991. The Partnership pursued opportunities resulting
from favorable market fundamentals and the implementation of
Federal Energy Regulatory Commission ("FERC") Order No. 636
("Order 636") in 1993. The Partnership is continuing to
emphasize diversification of its customer base through interstate
sales and has enjoyed recent success in interstate markets,
adding new term natural gas sales in 1993, mostly in the Midwest,
Northeast and Western United States, which provide for deliveries
of up to 260 MMcf per day. For information regarding Order 636,
which has created new supply, marketing and transportation
opportunities for the Partnership in the interstate market, see
"Governmental Regulations - Federal Regulation" and
"Competition - Natural Gas."
Gas Transportation and Exchange
Gas transportation and exchange transactions
(collectively referred to as "gas transportation" or
"transportation") constitute the largest portion of the
Partnership's natural gas throughput, representing 62%, 59% and
53% of total daily Partnership gas throughput volumes for 1993,
1992 and 1991, respectively. Gas transportation involves several
types of transactions. The common element of a gas
transportation transaction is that the gas is neither purchased
nor sold by the Partnership; instead, the Partnership receives
natural gas on a Btu basis at one point and redelivers an
equivalent amount of gas on a Btu basis at another point for a
negotiated fee and fuel allowance. See "Natural Gas Operations -
Gas Sales" for a discussion of the emerging trend of west-to-east
movement of gas across the United States.
The Partnership transports gas for third parties under
hundreds of separate transportation contracts. The Partnership's
transportation contracts generally limit the Partnership's
maximum transportation obligation (subject to available capacity)
but generally do not provide for any minimum transportation
requirement. Although the expiration dates of the Partnership's
transportation contracts range from 1994 to 2000, many of the
Partnership's transportation contracts expire by their terms in
1994, or are terminable on a day-to-day, month-to-month or
similar basis by the party for whom gas is being transported or
exchanged. The General Partner anticipates that most of these
transportation contracts will be renewed for additional terms or
continued in effect on some other basis. See "Competition -
Natural Gas."
The Partnership's transportation customers include major
oil and natural gas producers and pipeline companies. In 1993,
the Partnership's ten largest gas transportation customers
accounted for approximately 3% of its total consolidated
operating revenues and approximately 69% of its total
consolidated daily transportation volumes. The Partnership's
principal contracts with its largest transportation customer
expire in 1998 and provide for dedication of volumes of
approximately 200 MMcf per day.
The Partnership's delivery of natural gas to Mexico
through the Partnership's connection to PEMEX's pipeline near
Reynosa, Mexico decreased in 1993. Mexico generally decreased
the amount of its natural gas imports in 1993. In December 1993,
Mexico became a net exporter of natural gas to Texas through a
pipeline connection with PEMEX owned by a competitor of the
Partnership. The Partnership's total natural gas sales and
transportation deliveries to Mexico were approximately 56 MMcf
per day in 1993 compared to 75 MMcf per day in 1992 and 31 MMcf
per day in 1991. The Partnership expects to receive
authorization from the FERC in 1994 to operate the Partnership's
pipeline connection to PEMEX for the purpose of importing natural
gas from Mexico.
Gas volumes transported for or exchanged with others (in
MMcf per day) by the Partnership and the Partnership's average
transportation fee for the three years ended December 31, 1993,
are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
Transportation volumes . . . . . . . 1,566 1,301 1,132
Average transportation fee per Mcf . $.108 $.118 $.135
</TABLE>
Gas Supply
Gas supplies available to the Partnership for purchase
and resale or transportation include supplies of gas committed
under both short- and long-term contracts with independent
producers as well as additional gas supplies contracted for
purchase from pipeline companies, gas processors and other
suppliers that own or control reserves. There are no reserves of
natural gas dedicated to the Partnership and the Partnership does
not own any gas reserves other than gas in underground storage,
which comprises an insignificant portion of the Partnership's gas
supplies. See "Natural Gas Operations - Gas Storage Facilities."
Because of recent changes in the natural gas industry, gas
supplies have become increasingly subject to shorter term
contracts, rather than long-term dedications.
During 1993, the Partnership purchased natural gas under
hundreds of separate contracts. Surplus gas supplies, if
available, may be purchased to supplement the Partnership's
delivery capability during peak use periods. These contractual
relationships usually are supplemented by a physical
interconnection between the Partnership's pipeline system and
either the wellhead, field gathering system or other delivery
point. A majority of the Partnership's gas supplies are obtained
from sources with multiple connections. In such instances, the
Partnership frequently competes on a monthly basis for available
gas supplies. Purchases from the Partnership's ten largest
suppliers accounted for approximately 37% of total Partnership
gas purchase volumes for 1993.
The Partnership's sources of gas supplies are located in
most of the major producing areas of Texas but are concentrated
primarily in the Delaware, Midland and Val Verde basins of West
Texas, the Maverick basin of South-Central Texas, the Texas Gulf
Coast and the East Texas basin. Because of the extensive
coverage within the State of Texas by the Partnership's pipeline
systems, the General Partner believes that the Partnership can
access a number of supply areas. While there can be no assurance
that the Partnership will be able to acquire new gas supplies in
the future as it has in the past, the General Partner believes
that Texas will remain a major producing state, and that for the
foreseeable future the Partnership will be able to compete
effectively with other producers and to connect sufficient new gas
supplies in order to meet customer demand.
Gas Storage Facilities
Valero Gas Storage Company ("Gas Storage"), a wholly
owned subsidiary of VNGC, operates an underground gas storage
facility (the "Wilson Storage Facility") in Wharton County,
Texas. The current storage capacity of the Wilson Storage
Facility is approximately 7.2 Bcf of gas available for
withdrawal. Natural gas can be continuously withdrawn from the
facility at initial rates of up to approximately 800 MMcf of gas
per day and at declining delivery rates thereafter until the
inventory is depleted. See Note 5 of Notes to Consolidated
Financial Statements for a discussion of the Partnership's use of
the Wilson Storage Facility through certain lease and other
agreements. To meet new Order 636 term business, the Partnership
supplemented its own natural gas storage capacity by securing
during 1993 an additional 6 Bcf of third-party storage capacity
for the 1993-94 winter heating season.
NATURAL GAS LIQUIDS OPERATIONS
General
The Partnership's NGL operations include the processing
of natural gas to extract a mixed NGL stream of ethane, propane,
butanes and natural gasoline conducted by Valero Hydrocarbons,
L.P. ("Hydrocarbons"), and the separation ("fractionation") of
mixed NGLs into component products and the transportation and
marketing of NGLs conducted by Valero Marketing, L.P.
("Marketing"). Extracted NGLs are transported to downstream
fractionation facilities and end-use markets through NGL
pipelines owned or leased by the Partnership and certain
common carrier NGL pipelines. Extraction is the process of
removing NGLs from the gas stream, thereby reducing the Btu
content and volume of incoming gas (referred to as "shrinkage").
In addition, some gas from the gas stream is consumed as fuel
during processing.
The Partnership receives revenues from the extraction of
NGLs principally through the sale of NGLs extracted in its owned
and leased gas processing plants and the collection of processing
fees charged for the extraction of NGLs owned by others. The
Partnership compensates gas suppliers for shrinkage and fuel
usage in various ways, including sharing NGL profits, returning
extracted NGLs to the supplier or replacing an equivalent amount
of gas. The primary markets for NGLs are petrochemical plants
(all NGLs), refineries (butanes and natural gasoline), and
domestic fuel distributors (propane). Because of these uses, NGL
prices are generally set by or in competition with prices for
refined products in the petrochemical, fuel and motor gasoline
markets.
Gas Processing Facilities
The Partnership currently owns eight gas processing
plants. In addition, the Partnership operates and leases from
Energy a 200-million cubic foot per day turboexpander gas
processing plant in South Texas near Thompsonville. See Note 5
of Notes to Consolidated Financial Statements. These owned and
leased plants are located in the western and southern regions of
Texas and process approximately 1.3 Bcf of gas per day. During
1993, the Partnership sold its only off-system gas processing
plant in West Texas. Accordingly, each of the Partnership's
owned or leased plants is now situated along the Transmission
System. The Partnership's NGL production is sold primarily in
the Corpus Christi, Texas and Mont Belvieu (Houston) markets. A
substantial portion of the Partnership's butane production is
sold to Energy as feedstock for Energy's refinery in Corpus
Christi (the "Refinery").
Of the eight gas processing plants owned by the
Partnership, four are located on leased premises, although
substantially all of the plant equipment is owned rather than
leased. Leases for the premises expire on various dates from
1995 to 2006. One of the leases is renewable for an additional
term. The nonrenewable leases do not expire until the years
2000, 2001 and 2006, respectively. The General Partner believes
that the operations of the Partnership will not be materially
affected by the expiration of the leases. In most cases,
satisfactory arrangements can be made through the renewal of
leases, the purchase of leased premises or the relocation of
plant equipment.
In 1993, the Partnership achieved a record NGL
production of approximately 24.8 million barrels for the year.
Volumes of NGLs produced at the Partnership's owned and leased
plants (in thousands of barrels per day) and the average market
price per gallon and average gas cost per MMbtu for the three
years ended December 31, 1993, are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
NGL plant production . . . . . . . . 67.9 57.2 50.5
Average market price per gallon (3). $.290 $.314 $.326
Average gas cost per MMbtu . . . . . $1.96 $1.61 $1.42
<FN>
(3) Represents the average Houston area market prices for
individual NGL products weighted by relative volumes of each
product produced.
</TABLE>
The Partnership also operates for a fee two natural gas
processing plants in South Texas owned by Energy under operating
agreements with Energy. See Note 1 - "Transactions with Energy"
of Notes to Consolidated Financial Statements. Total production
at all plants operated by the Partnership, including both the
Partnership's owned and leased plants and the two plants owned by
Energy, averaged 77,400 barrels per day in 1993.
The Partnership and a major South Texas natural gas
producer have executed a letter of intent which, subject to
the execution of a binding contract and the closing of the
transaction, provides for the processing, transportation and
purchase of natural gas by the Partnership. Under the proposed
agreement, the producer will dedicate up to 300 MMcf per day of
natural gas production in South Texas to the Partnership for up
to 10 years, beginning in June 1994. The Partnership currently
processes approximately 150 MMcf per day of the producer's natural
gas under arrangements that expire in 1994 and 1995. The General
Partner anticipates that the Partnership will continue to pursue
opportunities to expand its NGL operations in South Texas.
Fractionation and Other Facilities
The Partnership owns fractionation facilities located at
the Partnership's Shoup gas processing plant near Corpus Christi,
at the Partnership's Armstrong gas processing plant near Yoakum,
Texas and at the Refinery. In addition, the Partnership leases
from Energy a depropanizer constructed at the Shoup plant and
a butane splitter constructed at the Refinery. See Note 5 of
Notes to Consolidated Financial Statements. In 1993, the
Partnership fractionated an average of 70,000 barrels per day
compared to 68,000 barrels per day in 1992 and 51,000 barrels per
day in 1991. Approximately 25%, 38% and 28% of the total volumes
fractionated in 1993, 1992 and 1991, respectively, represented
NGLs fractionated for third parties.
The Partnership also owns or leases approximately 375
miles of NGL pipelines that transport NGLs from gas processing
plants to fractionation facilities. The NGL pipelines also
connect with end users and major common-carrier NGL pipelines,
which ultimately deliver NGLs to the principal NGL markets. The
Partnership's NGL pipelines are located principally in South
Texas and West Texas. In South Texas, the Partnership owns 200
miles of NGL pipelines that directly or indirectly connect four
of the Partnership's owned processing plants and five processing
plants owned by third parties to the Partnership's fractionation
facilities near Corpus Christi. The South Texas system also
delivers NGLs from the Corpus Christi fractionation facilities to
end users and to a major common carrier NGL pipeline. Another
important NGL pipeline owned by the Partnership is located in
Southeast Texas and transports NGLs from the Partnership's
Armstrong plant and fractionation facility near Yoakum to an end
user. The Partnership leases from Energy 48 miles of NGL product
pipeline that connects the Thompsonville plant to the
Partnership's existing NGL pipeline in Freer, Texas. See Note 5
of Notes to Consolidated Financial Statements. The Partnership
also operates a 59-mile NGL products pipeline in South Texas
owned by Energy.
NGL Supply and Sales
The Partnership sells NGLs that have been extracted,
transported and fractionated in the Partnership's facilities and
NGLs purchased in the open market from numerous suppliers under
long-term, short-term and spot contracts. The Partnership's
largest NGL suppliers include major refineries and natural gas
processors. Its ten largest suppliers accounted for
approximately 63% of total NGL purchases in 1993. The
Partnership markets substantially greater volumes of NGLs than it
produces. During 1993, the Partnership sold to third parties on
average 94,500 barrels of NGLs per day compared to an average of
93,600 barrels per day in 1992 and 75,600 barrels per day in
1991.
The Partnership's contracts for the purchase, sale,
transportation and fractionation of NGLs both long-term and
short-term are generally with longstanding customers and
suppliers of the Partnership. The Partnership's long-term
contracts generally provide for monthly pricing adjustments based
on prices established in the principal NGL markets. The
Partnership's principal source of gas for processing is from the
Transmission System. To compensate Transmission's gas sales
customers for Btu reductions associated with the extraction of
NGLs from Transmission System gas, the Rate Order requires
Transmission to adjust the calculation of its weighted average
cost of gas to reflect the Btu shrinkage associated with customer
gas. The Partnership obtains additional gas supplies from
specific producers connected to the Transmission System through
gas processing agreements having terms that vary from a few
months to several years. Substantially all of the contracts with
third parties under which Hydrocarbons processes gas may be
suspended from month-to-month without advance notice at the
option of Hydrocarbons and are subject to termination at the
option of either party after short notice periods. The
profitability of individual processing arrangements is regularly
monitored so that action can be taken to terminate or modify any
arrangements that appear unprofitable as a result of declining
market conditions.
Because of various factors affecting the market price of
NGLs and natural gas, there is for each hydrocarbon component
found in any gas stream a price at which it is more profitable to
leave the component in the natural gas stream rather than to
extract the component and sell it separately as a NGL. Such
prices may vary among processing plants depending on specific
contractual arrangements, plant efficiencies and other factors.
For example, the Partnership has elected at certain times to
reduce the production of ethane by leaving ethane in the gas
stream rather than selling it as a separate product. During 1992
and 1991, the Partnership elected to maximize ethane recoveries
due to favorable market conditions that prevailed during such
periods. However, for certain periods during the fourth quarter
of 1993 and the first quarter of 1994, the Partnership
temporarily ceased the production of ethane at certain of its gas
processing plants because of the depressed market price for
ethane during such periods.
The Partnership's largest NGL customers include
petrochemical companies and major refiners, including Energy.
The Partnership's ten largest NGL customers accounted for
approximately 85% of the Partnership's total 1993 NGL product
sales revenues (22% of which was attributable to Energy's
refining operations). The petrochemical industry is a principal
market for NGLs and is expanding due to increasing market demand
for ethylene-derived products. As of the end of 1993, NGLs
represented about 68% of the total feedstock to the ethylene
crackers in the United States. During 1994, petrochemical
industry demand for NGLs is expected to continue to expand. In
the Partnership's immediate marketing area, additional NGL demand
in 1994 is expected to come from the Refinery's butane upgrade
facility and from the proposed start-up in early 1994 of an
ethylene plant on the Texas Gulf Coast expected to increase the
NGL base demand by approximately 30,000 to 40,000 barrels per day
by the end of 1994. In the longer term, the petrochemical
industry's increased requirements for NGLs are expected to
establish higher floor prices that should continue to support
profitable operation of gas processing facilities. In addition,
NGL demand should continue to increase as a result of existing
and future facilities that consume normal butane or isobutane.
GOVERNMENTAL REGULATIONS
Certain of the Partnership's subsidiaries, including
Transmission, are subject to regulations issued by the Railroad
Commission under the Cox Act, the Gas Utilities Regulatory Act
("GURA") and the Natural Resources Code, all of which are Texas
statutes, and the federal NGPA. In addition, certain activities
of Transmission and Val Gas are subject to the regulations of the
FERC under the NGPA and the Department of Energy Organization
Act of 1977 (the "DOE Act"). On January 1, 1993, all gas prices
were deregulated pursuant to the Natural Gas Wellhead Decontrol
Act of 1989. The Partnership's activities are also subject to
various federal, state and local environmental statutes and
regulations. See "Environmental Matters."
Texas Regulation
The Railroad Commission regulates the intrastate
transportation, sale, delivery and pricing of natural gas in
Texas by intrastate pipeline and distribution systems, including
those of the Partnership. Transmission and VLDC are regulated by
the Railroad Commission. The authority of the Railroad
Commission to regulate the Partnership's SMPs is unclear, except
with respect to conservation rules. Sales under the SMPs have
not been regulated by the Railroad Commission to date.
During 1992, the Railroad Commission revised its rules
governing the production and purchase of natural gas. The
Railroad Commission's gas proration rule (the "gas proration
rule") prohibits the production of gas in excess of market
demand. Under the gas proration rule, producers may not tender
and deliver volumes of gas in excess of their market demand.
Similarly, gas purchasers, including pipelines and purchasers
offering SMPs, may not take volumes of gas in excess of their
market demand. The gas proration rule further requires
purchasers to take gas by priority categories, ratably among
producers, without undue discrimination, and with high-priority
gas having higher priority than gas well gas, notwithstanding any
contractual commitments. For a discussion of the effect of the
gas proration rule on the operations of Transmission, see
"Natural Gas Operations - Gas Sales" above. Such revised rules
are intended to simplify the previous system of nominations and
to bring production allowables in line with estimated market
demand.
For pipelines, the Railroad Commission approves
intrastate sales and transportation rates and all proposed
changes to such rates. Changes in the price of gas sold to gas
distribution companies are subject to rate determination in a
rate case before the Railroad Commission. Under applicable
statutes and current Railroad Commission practice, larger volume
industrial sales and transportation charges may be changed
without a rate case if the parties to the transactions agree to
the rate changes and make certain representations. Rates for
Transmission's sales customers are governed by the Rate Order.
See "Management's Discussion and Analysis and Results of
Operations."
A new rate case may be initiated at the request of any
customer or by Transmission, or by the Railroad Commission on its
own initiative. No rate case involving Transmission has taken
place since the date of the Rate Order. The determination of any
rate change would be based on cost-of-service rate regulation
principles, including a return-on-rate base calculation and the
recovery of certain operating costs and depreciation. While
there can be no assurance in this regard, the General Partner
believes that the results of any such rate proceeding would not
materially adversely affect the Partnership's financial position
or results of operations. See Note 6 of Notes to Consolidated
Financial Statements for a discussion of the 1993 settlement of a
certain customer's audit of Transmission's weighted average cost
of gas.
NGL pipeline transportation is also subject to
regulation by the Railroad Commission. The Railroad Commission
requires the filing of tariffs and compliance with environmental
and safety standards. To date, the impact of this regulation on
the Partnership's operations has not been significant. The
Railroad Commission also has regulatory authority over gas
processing operations, but has not exercised such authority.
Federal Regulation
The Partnership's 7,200-mile pipeline system is an
intrastate business not subject to direct regulation by the FERC.
Although the Partnership's interstate sales and transportation
activities are subject to specific FERC regulations, these
regulations do not change the Partnership's overall regulatory
status. The Partnership's operations are more significantly
affected by the implementation of FERC Order 636 related to
restructuring of the interstate natural gas pipeline industry.
Order 636 requires pipelines subject to FERC jurisdiction to
provide unbundled marketing, transportation, storage and load
balancing services on a nondiscriminatory basis to producers
and end users instead of offering only combined packages of
services. This allows companies like the Partnership to
provide these component services separately from the
transportation provided by the interstate pipelines. The
"unbundling" of services under Order 636 allows LDCs and other
customers to choose the combination of services that best meet
their needs at the lowest total cost, thus increasing competition
in the interstate natural gas industry. As a result of
Order 636, the Partnership can more effectively compete for sales
of natural gas to LDCs and other natural gas customers located
outside Texas. See "Competition - Natural Gas."
In 1988, the FERC issued Order No. 497 (amended in 1989
by Order 497-A), which addresses possible abuses in relationships
between interstate natural gas pipelines and their marketing or
brokering affiliates. This order contains standards of conduct
and reporting requirements intended to prevent preferential
treatment of an affiliated marketer by an interstate pipeline in
providing transportation services. The General Partner believes
that Order No. 497, as amended, has assisted the Partnership in
competing for developing interstate markets.
ENVIRONMENTAL MATTERS
The Partnership's operation and construction of
pipelines, plants and other facilities for transporting,
processing, treating or storing natural gas and other products
are subject to environmental regulation by federal, state and
local authorities, including the Environmental Protection Agency
("EPA"), the Texas Natural Resource Conservation Commission
("TNRCC"), the Texas General Land Office and the Railroad
Commission. Compliance with regulations promulgated by these
various governmental authorities increases the cost of planning,
designing, initial installation and operation of the
Partnership's facilities. The regulatory requirements relate to
water and storm water discharges, waste management and air
pollution control measures.
Although the Partnership continues to monitor its
compliance with environmental regulations through audits and
other procedures, the Partnership's expenditures for
environmental control facilities were not material in 1993 and
are not expected to be material in 1994. Currently, expenditures
are made to comply with air emission regulations and solid waste
management regulations applicable to various facilities.
The Partnership will continue to be subject to
regulations concerning wastes and air emissions, including new
federal operating permit requirements for certain air emission
sources. Proposed regulations regarding enhanced monitoring and
other programs for the detection of certain releases may also
affect the Partnership's operations. The Partnership anticipates
increased regulation of wastes by the Railroad Commission, and
increased control of air toxins together with additional
permitting requirements from the EPA regarding storm water
discharges from industrial and construction activities. However,
the General Partner does not expect these requirements to have a
material adverse effect on the Partnership's financial position
or results of operations.
COMPETITION
Natural Gas
Changes in the gas markets during the recent period of
deregulation under FERC Order 636 have resulted in significantly
increased competition. Despite the increased competition, the
Partnership generally has been able to take advantage of the
increased business opportunities resulting from the
implementation of Order 636. Accordingly, the Partnership has
not only maintained but has increased its throughput volumes.
Under Order 636, the Partnership can more effectively compete for
sales of natural gas to LDCs and other customers located outside
Texas. See "Governmental Regulations - Federal Regulation."
Contracting practices in the natural gas industry generally are
moving away from the spot, interruptible type of sales prevalent
in recent years, and toward "firm" and term contracts that
require gas suppliers to commit to specified deliveries of gas
without the option of interrupting service and penalize gas
suppliers for failure to perform in accordance with their
contractual commitments. Because of Order 636, the Partnership
now can guarantee long-term supplies of natural gas to be
delivered to buyers at interstate locations. The Partnership can
charge a fee for this guarantee, which together with
transportation charges, can exceed the amount that the
Partnership could receive for merely transporting natural gas.
The Partnership has enjoyed recent success in entering into such
contracts. See "Natural Gas Operations - Gas Sales - Interstate
Sales." Because of the location of the Transmission System, the
General Partner believes that the Partnership is able to compete
for new gas supplies and new gas sales and transportation
customers. The financial strength of potential suppliers will be
an important consideration to LDCs and other customers when
contracting for firm supplies of natural gas. Accordingly, the
General Partner believes that substantial amounts of working
capital and capital expenditures for gas inventories, storage,
pipeline connections and financial hedging products (e.g.,
futures contracts) will be required to compete effectively for
additional business under Order 636. See "Properties."
The General Partner believes that the natural gas and
NGL industries are undergoing a period of reorganization and
consolidation as major energy companies divest operations that
are not part of their core operations and smaller entities
combine to compete more effectively in the present natural gas
environment. Through ongoing reorganizations and consolidations
in the industry, certain assets may become available for
acquisition by the Partnership including natural gas and NGL
pipelines, gathering facilities, processing plants and NGL
fractionation facilities. The General Partner believes that
certain trends in the natural gas industry will create additional
business opportunities and require additional capital
expenditures for companies that wish to compete effectively in
interstate natural gas markets. These trends include an emerging
west-to-east movement of natural gas across the United States,
the increasing importance of South Texas as a major natural gas
supply area and opportunities created by Order 636.
Many of the market areas served by the Partnership's gas
systems are also served by pipelines of other companies; however,
the location of the Partnership's facilities in major producing
and marketing areas is believed to provide a competitive
advantage. Although gas competes with other fuels, gas to gas
competition continues to set pricing levels. The Partnership
does not anticipate that fuel oil pricing will reach parity with
spot natural gas prices in the foreseeable future, rendering
unlikely any significant switch to fuel oil or other alternate
fuels by the Partnership's intrastate customers. Significant
decreases in the price of fuel oil historically have led to some
switching of load in the interstate market, although the impact
on the Partnership has been indirect and immaterial. The
Partnership's electric power generation and industrial customers
have the ability to substitute alternate fuels for a portion of
their current natural gas deliveries. This capability is
generally reserved for periods of natural gas curtailment, as the
continued disparity in price and the added cost of delivery,
storage and handling of alternate fuels limit their long-term
use. Demand for natural gas continues to be affected by the
operation of various nuclear and coal power plants in the
Partnership's service area. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
In recent years, certain intrastate pipelines with which
the Partnership had traditionally competed have acquired or have
been acquired by interstate pipelines. These combined entities
generally have capital resources substantially greater than those
of the Partnership and, notwithstanding Order 636's "open access"
regulations, may realize economies of scale and other economic
advantages in acquiring, selling and transporting natural gas.
The acquisition of gas supply is capital intensive, as it
frequently requires installation of new gathering lines to reach
sources of gas. Additionally, the combination of intrastate and
interstate pipelines within one organization may in some
instances enable competitors to lower gas prices and
transportation fees, and thereby increase price competition in
the Partnership's intrastate and interstate markets.
The U.S.-Canada free trade agreement and changes in
Canadian export regulations have increased Canadian natural gas
imports into the United States. Under the recently adopted North
American Free Trade Agreement, Canadian natural gas imports into
the United States are expected to continue. Canadian imports have
increased competition in the interstate markets in which the
Partnership competes for natural gas sales and have affected natural
gas availability and prices in the Texas intrastate market. As a
result, competition in the natural gas industry is expected to
remain intense.
Natural Gas Liquids
The consumption of NGLs marketed in the United States is
divided among four distinct markets. NGLs are primarily consumed
in the production of petrochemicals (mainly ethylene), followed
by motor gasoline production, residential and commercial heating,
and agricultural uses. Other hydrocarbon alternatives, primarily
refinery-based products, are available for each NGL for most end
uses. For some end uses, including residential and commercial
heating, a conversion from NGLs to other natural hydrocarbon
products requires significant expense or delay, but for others,
such as ethylene and industrial fuel uses, a conversion from NGLs
to other natural hydrocarbon products could be made without
significant delay or expense.
Because certain NGLs are used in the production of motor
gasoline and compete directly with other refined products in the
fuel and petrochemical feedstock markets, NGL prices are set by
or compete with petroleum-derived products. Consequently,
changes in crude and refined product prices cause NGL prices to
change as well. See "Recent Developments - Decline of Crude Oil
and NGL Prices." The economics of natural gas processing depends
principally on the relationship between natural gas costs and NGL
prices. When this relationship has been favorable, the NGL
processing business has been highly competitive. The General
Partner believes that competitive barriers to entering the
business are generally low. Moreover, improvements in
NGL-recovery technology have improved the economics of NGL
processing and have increased the attractiveness of many
processing opportunities. In recent years, NGL margins have been
subject to the extreme volatility of energy prices in general.
The General Partner believes that the level of competition in NGL
processing has increased over the past year and generally will
become more competitive in the longer term as the demand for NGLs
increases.
EMPLOYEES
The Partnership has no employees of its own.
PART II
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
PROPOSED MERGER WITH ENERGY
As fully described in Item 1 - "Business-Recent
Developments," in October 1993, Energy publicly announced its
proposal to acquire the issued and outstanding Common Units in
VNGP, L.P. held by the Public Unitholders and effective
December 20, 1993, Energy, VNGP, L.P. and VNGC entered into the
Merger Agreement providing for the merger of VNGP, L.P. with a
wholly owned subsidiary of Energy subject to various conditions.
The General Partner has approved the merger because it believes
that the Partnership, in its present form, has insufficient
financial flexibility to participate fully in opportunities that
are expected to arise in the natural gas and NGL businesses, that
the ability of the Partnership to compete effectively in these
businesses will be enhanced through the merger and that the
Partnership could lose its competitive position if it does not
pursue such opportunities when and if they become available. The
General Partner also believes that conflicts of interest between
the Partnership and Energy can be eliminated and that
administrative efficiencies can be realized through the merger.
See "Results of Operations" and "Liquidity and Capital Resources"
below.
On January 25, 1994, the VNGC Board of Directors
declared a cash distribution of $.125 per Common Unit for the
fourth quarter of 1993 that is payable March 1, 1994 to holders
of record as of February 7, 1994. If the merger occurs after
March 9, 1994, the General Partner intends and expects to declare
and pay a pro rata distribution to holders of record of the
Common Units on the effective date of the merger based upon the
number of days elapsed between February 7, 1994 and such
effective date.
RESULTS OF OPERATIONS
The following are the Partnership's financial and
operating highlights for each of the three years in the period
ended December 31, 1993 (in thousands of dollars, except as
otherwise noted).
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
OPERATING REVENUES:
Natural gas:
Sales. . . . . . . . . . . . . . . . . . $ 840,066 $ 689,076 $ 710,996
Transportation . . . . . . . . . . . . . 60,186 53,950 53,230
Natural gas liquids. . . . . . . . . . . . 441,741 466,017 390,708
Intersegment eliminations. . . . . . . . . (15,535) (11,914) (10,933)
Total. . . . . . . . . . . . . . . . . . $1,326,458 $1,197,129 $1,144,001
OPERATING INCOME:
Natural gas. . . . . . . . . . . . . . . . $ 53,458 $ 32,484 $ 37,140
Natural gas liquids. . . . . . . . . . . . 26,020 57,357 62,694
Total. . . . . . . . . . . . . . . . . . $ 79,478 $ 89,841 $ 99,834
NET INCOME . . . . . . . . . . . . . . . . . $ 14,447 $ 24,986 $ 37,036
NET INCOME PER LIMITED PARTNER UNIT. . . . . $ .72 $ 1.27 $ 1.90
OPERATING STATISTICS:
Natural gas:
Gas throughput volumes (MMcf per day):
Gas sales. . . . . . . . . . . . . . . 980 889 1,011
Gas transportation . . . . . . . . . . 1,566 1,301 1,132
Total gas throughput . . . . . . . . 2,546 2,190 2,143
Average gas sales price per Mcf. . . . . $ 2.34 $ 2.11 $ 1.92
Average gas transportation fee per Mcf . $ .108 $ .118 $ .135
Natural gas liquids:
Plant production (MBbls per day) . . . . 67.9 57.2 50.5
Sales volumes (MBbls per day) (1). . . . 94.5 93.6 75.6
Average market price per gallon (2). . . $ .290 $ .314 $ .326
Average gas cost per MMBtu . . . . . . . $ 1.96 $ 1.61 $ 1.42
<FN>
(1) Including NGLs purchased from third parties.
(2) Represents the average Houston area market prices for
individual NGL products weighted by relative volumes of
each product produced.
</TABLE>
General
The Partnership's net income for 1993 decreased $10.5
million, or 42%, compared to 1992 due primarily to a $10.4
million, or 12% decrease in operating income. In the fourth
quarter of 1993, a $4.5 million decrease in operating income
resulted in a net loss of $2.1 million compared to net income of
$2.3 million in the fourth quarter of 1992. Increased operating
income from the Partnership's natural gas operations was more
than offset by decreased operating income from the Partnership's
natural gas liquids ("NGL") operations for both the annual and
quarterly periods, as explained below.
The Partnership's natural gas operating results improved
in 1993 due to, among other things, improvement in market
fundamentals as natural gas supply and demand have become more
balanced, and increased business opportunities resulting from the
implementation of Federal Energy Regulatory Commission ("FERC")
Order No. 636 ("Order 636"). Order 636 requires, among other
things, that pipelines subject to FERC jurisdiction provide
"unbundled" transportation, storage and load balancing services
on a nondiscriminatory basis to producers and end users instead
of offering only combined packages of services. This change has
resulted in increased competition in the natural gas industry.
Although no Subsidiary Operating Partnership is directly subject
to Order 636, it has created new interstate supply, marketing
and transportation opportunities for the Partnership. However,
the General Partner believes that substantial amounts of working
capital and capital expenditures for gas inventories, storage
facilities, pipeline connections and related facilities, and for
financial hedging products, such as gas futures contracts, will
be required to compete effectively for additional business under
Order 636. See "Governmental Regulations-Federal Regulation" and
"Competition-Natural Gas" under Item 1 - "Business" for
additional information regarding Order 636 and its effect on the
Partnership's business.
In addition to the opportunities and challenges created
by Order 636, the Partnership's natural gas operations have also
been affected by an emerging trend of west-to-east movement of
gas across the United States resulting from growing productive
capacity in western supply basins, the completion of new pipeline
capacity from such basins to the U.S. West Coast and increasing
demand for power generation in the East or Southeast. The
General Partner believes that this west-to-east shift in natural
gas supply patterns is well underway, and that in many of the
pipelines able to serve this market, including pipelines operated
by the Partnership, west-to-east capacity is becoming
constrained. The General Partner believes that, over time, these
capacity constraints may warrant additional west-to-east capacity
additions and that the Partnership would be positioned to
participate in such opportunities. Because natural gas is a
clean burning fuel, environmental concerns are expected to
increase long-term demand for natural gas which should benefit
the Partnership's natural gas throughput volumes.
The Partnership benefitted in 1993 from an increase in
demand for natural gas resulting from the shutdown of both units
of the South Texas Project nuclear plant ("STP") in Bay City,
Texas during most of 1993 due to operational problems. At full
operation, the STP displaces approximately 650 MMcf per day of
natural gas demand. The Partnership currently expects that the
STP will resume full operations in the second quarter of 1994,
displacing a portion of the Partnership's gas sales volumes and
reducing Partnership operating income. Demand for natural gas in
the Partnership's core service area is also expected to be
affected by the continued operation of other nuclear and coal-
fired power plants. The first and second units of the Comanche
Peak nuclear plant near Ft. Worth, Texas, both 1,150 megawatt
("MW") units, commenced operations in 1991 and 1993,
respectively, and combine to displace approximately 600 MMcf per
day of gas demand. In addition, San Antonio City Public Service,
the Partnership's largest gas sales customer, commenced
commercial operations in 1992 of a 500 MW coal-fired electrical
generation facility which displaces a portion of the
Partnership's gas sales volumes.
The Partnership's gas sales are made by (i) the
Partnership's special marketing programs ("SMPs") and certain
other subsidiary operating partnerships which are not SMPs and
(ii) Valero Transmission, L.P. ("Transmission"). Gas
transportation is conducted primarily by Transmission. Gas sales
and transportation volumes (in MMcf per day), average gas sales
prices and average gas transportation fees for the years ended
December 31, 1993, 1992 and 1991 were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
1993 1992 1991
<S> <C> <C> <C>
SMPs and other sales volumes:
Intrastate . . . . . . . . . . . . . . . . . . . . 642 552 545
Interstate . . . . . . . . . . . . . . . . . . . . 281 259 363
Total SMPs and other sales volumes . . . . . . . 923 811 908
Transmission sales volumes (intrastate). . . . . . . 57 78 103
Total sales volumes. . . . . . . . . . . . . . . 980 889 1,011
SMPs and other's average gas sales price per Mcf . . $ 2.18 $ 1.86 $ 1.62
Transmission's average gas sales price per Mcf . . . $ 4.86 $ 4.71 $ 4.57
Transportation volumes . . . . . . . . . . . . . . . 1,566 1,301 1,132
Average gas transportation fee per Mcf . . . . . . . $ .108 $ .118 $ .135
</TABLE>
The Partnership's SMPs and other gas sales and
transportation business are based primarily on competitive market
conditions and contracts negotiated with individual customers.
The Partnership has been able to mitigate, to some extent, the
effect of competitive industry conditions by the flexible use of
its strategically located pipeline system and its aggressive
marketing efforts. Sales volumes in the SMPs and other's
intrastate and interstate markets and total transportation
volumes increased in 1993 compared to 1992 due to, among other
things, aggressive efforts to generate business related to the
implementation of FERC Order 636 and the west-to-east shift in
natural gas supply patterns, and the shutdown of the STP during
most of 1993. In 1992, the Partnership established a Market
Center Services Program to provide price risk management services
to gas producers and end users through the use of forward
contracts and other tools which have traditionally been used in
financial risk management. The General Partner believes that the
"value-added" services provided through this program allow the
Partnership to effectively compete in the post-Order 636
environment. The Partnership also utilizes such price risk
management techniques to manage the cost of gas consumed in its
NGL operations, and manage price risk associated with its natural
gas storage and marketing activities. In 1993 and 1992, the
Partnership recognized $18.7 million and $12.9 million,
respectively, in gas cost reductions and other benefits from this
program. An additional $5.1 million and $3.6 million in other
reductions of cost of gas was generated by transactions entered
into in 1993 and 1992, respectively, which is recognized in
income in the subsequent year as the related gas is sold. The
Market Center Services Program benefitted in 1993 and 1992 from
the volatility of natural gas prices and the Partnership's
successful anticipation of price movements. Increased stability
in natural gas prices, however, could reduce the benefits
generated by this program in 1994.
Transmission's sales are made to intrastate customers
under contracts which originated in the 1960s and 1970s with 20-
to 30-year terms. These contracts were full requirements, no-
notice service contracts governed by a rate order (the "Rate
Order") issued in 1979 by the Railroad Commission of Texas (the
"Railroad Commission"). The Rate Order provides for Transmission
to sell gas at its weighted average cost of gas, as defined
("WACOG"), plus a margin of $.15 per Mcf. In addition to the
cost of gas purchases, Transmission's WACOG has included storage,
gathering and other fixed costs totalling approximately $19
million per year (see customer audit settlement agreement
discussed below for adjustments to such amount), and amortization
of deferred gas costs related to the settlement of take-or-pay
and related claims (see Note 1 - "Other Assets" and Note 6 of
Notes to Consolidated Financial Statements). Transmission's gas
purchases include high-cost casinghead gas and certain special
allowable gas that Transmission is required to purchase
contractually and under the Railroad Commission's priority rules.
Transmission's sales volumes have been decreasing with the
expiration of its sales contracts. As a result of these factors,
Transmission's WACOG and gas sales price are substantially in
excess of market clearing levels, as shown in the table above.
In July 1992, a contract representing approximately 37% of
Transmission's sales volumes for the first six months of 1992
expired by its own terms, reducing Transmission's and the
Partnership's cash flow and income in 1992 and 1993.
Transmission's WACOG has been periodically audited by
certain of its customers, as allowed under the Rate Order. One
such customer (the "Customer") questioned the application of
certain of Transmission's current rate policies to future periods
in light of the decreases that have occurred in Transmission's
throughput, and the Customer has recently completed its audit of
Transmission's WACOG with respect thereto. For 1993, the
Customer represented approximately 70% of Transmission's sales
volumes and such percentage is expected to increase as other
sales contracts expire and are not renewed. As a result of the
Customer's audit, Transmission and the Customer entered into a
settlement agreement which excludes certain of the fixed costs
described above from Transmission's WACOG, effective with July
1993 sales, resulting in a reduction of the Partnership's annual
net income by approximately $6 million. Upon the termination of
Transmission's gas sales contract with the Customer in 1998,
Transmission's fixed costs, including storage (see Note 5 of
Notes to Consolidated Financial Statements), would be charged to
income instead of recovered through its gas sales rates.
Transmission expects to recover its deferred gas costs over a
period of approximately eight years. The recovery of any
additional payments made in connection with any future
settlements would be limited.
In the course of making gas sales and providing
transportation services to customers, Transmission experiences
measurement and other volumetric differences related to the
amounts of gas received and delivered. Transmission has in the
past experienced overall net volume gains due to such differences
and its Rate Order allows such volumes to be sold to its
customers. Transmission historically has derived a substantial
benefit from such sales. The amount included in operating income
in 1993 was substantially the same as in 1992. However, the
implementation of more precise gas measurement equipment and
standards and the reduction in Transmission's total sales
volumes, discussed above, is expected to reduce operating income
from such sales in future periods.
The profitability of the Partnership's NGL operations
depends principally on the margin between NGL sales prices and
the cost of the natural gas from which such liquids are extracted
("shrinkage cost"). The Partnership's natural gas liquids
operations were adversely affected in 1993 by a decrease in NGL
market prices, particularly in the fourth quarter. Beginning in
late November 1993, crude oil prices fell significantly resulting
from a decision by the Organization of Petroleum Exporting
Countries ("OPEC") at its November 23, 1993 meeting not to
curtail members' production of crude oil, together with weak
worldwide demand for crude oil, increasing production from non-
OPEC areas and continuing discussions regarding the possibility
of Iraq's re-entry into the world oil markets. In conjunction
with the crude oil price decline, refined product and NGL prices
also fell significantly. Strong natural gas prices throughout
1993 increased shrinkage costs, also adversely affecting NGL
margins and operating results. Partially offsetting the effects
of reduced NGL prices and high shrinkage costs in 1993 were
higher production levels from the Partnership's owned and leased
gas processing plants. The Partnership's processing capacity and
production volumes increased in 1993 compared to 1992 due to a
full year's production from various 1992 facility expansions and
improvements, and various 1993 upgrades at certain processing
plants. See Note 5 of Notes to Consolidated Financial Statements
for a description of the Thompsonville gas processing plant
leased by the Partnership from Energy effective December 1, 1992.
The Partnership's NGL operations should benefit in the longer
term from the expected continued growth in demand for NGLs as
petrochemical feedstocks and in the production of methyl tertiary
butyl ether ("MTBE"). MTBE is an oxygenate produced from butane
feedstocks which can be used as a component of "reformulated"
gasoline mandated by the Clean Air Act Amendments of 1990 (the
"Clean Air Act"). The demand for NGLs, particularly natural
gasoline, will continue to be affected seasonally, however, by
Federal Environmental Protection Agency ("EPA") regulations
limiting gasoline volatility during the summer months.
The Partnership's NGL operations benefit from the
efficiency of its operations and 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
Partnership's natural gas and NGL operations. Approximately 80%
of the Partnership's NGL production comes from plants in South
Texas and the Texas Gulf Coast. However, as the Partnership's
existing South Texas NGL pipeline and fractionation facilities
are operating at or near capacity, the Partnership anticipates
incurring either increased third-party transportation and
fractionation fees or substantial capital expenditures in the
future in order to develop incremental South Texas NGL production
opportunities.
During the first quarter of 1994, NGL prices have
increased modestly since late December 1993, but remain below
first quarter 1993 levels. Concurrently, natural gas prices and
resulting shrinkage costs have increased during the first quarter
of 1994 compared to the same period in 1993. As a result,
Partnership operating income is expected to be substantially
lower in the first quarter of 1994 compared to the fourth quarter
of 1993.
The General Partner believes that the natural gas and
NGL industries are undergoing a period of consolidation and
restructuring that may create opportunities to enhance the
Partnership's operating results through acquisitions, strategic
business alliances and the various natural gas and NGL business
opportunities described above. However, the General Partner also
believes that the Partnership will be unable to maintain its
competitive position, resulting in adverse operating results, if
it does not pursue such opportunities when and if they arise, and
that currently, the Partnership does not have the financial
flexibility to make the capital expenditures necessary to
successfully pursue such opportunities. See "Liquidity and
Capital Resources" for a discussion of current limitations on the
Partnership's ability to make capital expenditures and incur
additional financing and reasons why the General Partner believes
that the proposed merger with Energy would, among other things,
provide the financial flexibility necessary for the Partnership
to pursue opportunities in the natural gas and NGL businesses
that would otherwise be unavailable to it.
1993 Compared to 1992
Natural Gas
Operating revenues from the Partnership's natural gas
operations increased $157.3 million, or 21%, during 1993 compared
to 1992 due primarily to a 10% increase in daily natural gas
sales volumes, an 11% increase in average natural gas sales
prices and a 12% increase in transportation revenues. These
increases were due to continued strong demand for natural gas
resulting from tightening natural gas supplies, industry-wide
replenishment of natural gas storage inventories and the shutdown
of both units of the STP. For the fourth quarter of 1993,
natural gas operating revenues increased $16.5 million, or 8%,
compared to the same period in 1992 due primarily to a 19%
increase in daily natural gas sales volumes, partially offset by
a 9% decrease in average natural gas sales prices. Daily natural
gas sales volumes increased due to the factors noted above, while
gas sales prices decreased due primarily to a return of natural
gas storage inventories to more normal levels in the 1993 fourth
quarter compared to below normal levels in the 1992 period.
The above noted increase in transportation revenues for
1993 compared to 1992 was due to a 20% increase in daily
transportation volumes which more than offset the effect of an 8%
decrease in average transportation fees. The increase in daily
transportation volumes resulted from the continued shutdown of
the STP, increased west-to-east movement of gas across Texas,
increased gas shrinkage volumes transported for the Partnership's
NGL operations and increased volumes transported under
settlements of take-or-pay and other claims at discounted rates.
See Note 6 of Notes to Consolidated Financial Statements.
Average transportation fees were adversely affected by intense
industry competition and the increase in discounted
transportation volumes noted above. In the fourth quarter of
1993, the effect on transportation revenues of a 4% increase in
daily transportation volumes was substantially offset by a 3%
decrease in average transportation fees compared to the fourth
quarter of 1992.
Operating income from the Partnership's natural gas
operations increased $21 million, or 65%, for 1993 compared to
1992 due to the increase in sales volumes and transportation
revenues noted above, certain favorable measurement, fuel usage
and customer billing adjustments and the increase in income
generated by the Partnership's Market Center Services Program
discussed above under "General." Partially offsetting these
increases in natural gas operating income was a decrease in the
recovery of Transmission's fixed costs resulting from the
customer audit settlement also discussed above under "General."
For the fourth quarter of 1993, natural gas operating income
increased $9.8 million to $15.8 million compared to $6 million in
the fourth quarter of 1992 due to the factors noted above.
Natural Gas Liquids
Operating revenues from the Partnership's NGL operations
decreased $24.3 million, or 5%, in 1993 compared to 1992 due
primarily to a decrease in average NGL market prices in the last
six months of 1993 compared to the same period in 1992 resulting
from the significant decline in refined product prices discussed
above under "General" and continuing high levels of NGL
inventories. NGL sales volumes for 1993 were flat compared to
1992 as a 19% increase in daily production volumes resulting from
various 1992 facility expansions and improvements was offset by a
27% decrease in trading volumes.
Operating income from the Partnership's NGL operations
decreased $31.3 million, or 55%, in 1993 compared to 1992 due to
the sharp decline in NGL prices noted above and an increase in
fuel and shrinkage costs resulting from a 22% increase in the
cost of natural gas. The decline in NGL prices resulted in a
$1.4 million operating loss from NGL operations for the fourth
quarter of 1993 compared to operating income of $12.9 million for
the fourth quarter of 1992. Also adversely affecting fourth
quarter 1993 operating results compared to 1992 was a 4% decrease
in NGL sales volumes and an increase in depreciation expense
resulting from the recognition in the 1992 period of a change in
the estimated useful lives of the majority of the Partnership's
NGL facilities from 14 to 20 years retroactive to January 1,
1992.
1992 Compared To 1991
Natural Gas
Operating revenues from the Partnership's natural gas
operations decreased $21.2 million, or 3%, during 1992 compared
to 1991 due primarily to a decrease in natural gas sales revenues
resulting from a 12% decrease in daily natural gas sales volumes,
partially offset by a 10% increase in average natural gas sales
prices. The increase in average gas sales prices was due to
lower-than-normal inventories of natural gas in storage and a
reduction in natural gas production resulting from the effects of
Hurricane Andrew in the 1992 third quarter.
Transportation revenues were flat in 1992 compared to
1991 as a 15% increase in daily transportation volumes was
largely offset by a 13% decrease in average transportation fees.
Transportation volumes increased due to the commencement of
operations of a pipeline crossing into Mexico in the third
quarter of 1992, increased business generated through the East
Texas pipeline leased from Energy and an increase in gas
shrinkage volumes transported for the Partnership's NGL
operations. Average transportation fees decreased due to market
pressures and because of the expiration on September 30, 1991 of
a transportation contract that provided for a quarterly
reservation fee.
Operating income from the Partnership's natural gas
operations decreased $4.6 million, or 12%, during 1992 compared
to 1991 due to the factors discussed above and higher pipeline
transportation expense related to higher total gas throughput
volumes. Operating income for 1992 was also reduced by a fourth
quarter charge of $3.0 million to natural gas operations
representing its allocable portion of the cost of a voluntary
early retirement program implemented by Energy during the last
quarter of 1992.
Natural Gas Liquids
Operating revenues from the Partnership's NGL operations
increased $75.3 million, or 19%, during 1992 compared to 1991 due
to a 24% increase in daily NGL sales volumes as well as increased
fees and revenues from processing, transporting and fractionating
volumes for third parties. The increase in NGL sales volumes was
due to a 13% increase in daily production volumes resulting from
facility expansions and increased sales volumes related to the
Partnership's NGL trading activities. The increase in operating
revenues as a result of the above factors was partially offset by
a 4% decrease in the average NGL market price resulting from
lower refined product prices in the fourth quarter of 1992.
Operating income from the Partnership's NGL operations
decreased $5.4 million, or 9%, during 1992 compared to 1991 due
to a decrease in the average NGL market price, higher shrinkage
costs and higher operating expenses due primarily to a $1.4
million charge to NGL operations for its allocable portion of the
cost of Energy's early retirement program described above. The
decrease in operating income as a result of these factors was
partially offset by an increase in production, transportation and
fractionation volumes and a $5.6 million decrease in depreciation
expense resulting from the above noted increase in the estimated
useful lives of the majority of the Partnership's NGL facilities
from 14 to 20 years effective January 1, 1992.
Other
Other income, net, decreased $3.4 million during 1992
compared to 1991 due primarily to a decrease in interest earned
on temporary cash investments resulting from lower balances of
cash available for investment and lower interest rates. Interest
and debt expense decreased in 1992 compared to 1991 due primarily
to a decrease in the balance of First Mortgage Notes outstanding,
a decrease in interest cost associated with the East Texas
pipeline capital lease obligation to Energy resulting from the
settlement of certain litigation and increased capitalized
interest resulting from an increase in Partnership capital
expenditures. These decreases were partially offset by an
increase in interest cost associated with the fractionation
facility and Thompsonville Project capital lease obligations to
Energy.
LIQUIDITY AND CAPITAL RESOURCES
The Partnership in the past has generated cash through a
combination of sources to meet its debt service requirements,
make capital expenditures, pay cash distributions to partners and
finance settlements of take-or-pay and related claims. These
sources have included cash flow from operations, the issuance of
additional First Mortgage Notes, financial support from Energy
through capital lease financing and other transactions,
reductions in working capital requirements, and asset sales.
In 1993, the Partnership's operating cash flow was
reduced by depressed NGL product prices, higher natural gas
shrinkage costs, continued intense competition in the natural gas
industry and the reduction of Transmission's sales volumes. See
"Results of Operations" above. These conditions are expected to
continue into 1994 resulting in a reduction of the Partnership's
cash flows from operations.
The Partnership, through the Management Partnership,
issued $550 million principal amount of First Mortgage Notes in
1987 and an additional $75 million of First Mortgage Notes in
1988. However, under the terms of the Mortgage Indenture, the
Management Partnership and the Subsidiary Operating Partnerships,
the principal operating and asset ownership subsidiaries of the
Partnership, are not permitted to issue any additional long-term
debt without the issuance of additional partners' equity. The
General Partner does not anticipate any such issuance as it
believes that the partnership form of business organization does
not allow for the raising of significant additional equity
capital, and that issuance of any additional equity securities,
if feasible, would likely have a negative impact on the existing
holders of Common Units. Debt service on the First Mortgage
Notes, including payments into escrow for both principal and
interest, was $81 million, $80.6 million and $79.2 million for
1993, 1992 and 1991, respectively, and will be $81 million, $80.9
million, $80.4 million, $79.6 million and $75.9 million for the
years 1994 through 1998, respectively. See Note 3 of Notes to
Consolidated Financial Statements.
Commencing in 1991, the Partnership entered into a
series of leasing transactions with Energy to provide financial
support for certain Partnership capital expenditure projects that
were approved by the Board of Directors of the General Partner.
These projects, which had a total cost of approximately $101
million, consisted of the East Texas Pipeline Extension, the
Fractionator Expansion Project and the Thompsonville Project and
are being leased by Energy to the Partnership under capital
leases. See Note 5 of Notes to Consolidated Financial Statements
for additional information with regard to these leases and a
schedule of minimum lease payments. The leasing transactions
between the Partnership and Energy have enabled the Partnership
to engage in capital expansions and business opportunities that
would otherwise have been unavailable to it. However, the rate
of return available to Energy from such transactions is limited
to the lease payments specified in the lease and any related tax
benefits. Additionally, in 1991, a Unitholder commenced a class
action and derivative lawsuit against the General Partner, Energy
and certain of their respective officers and directors relating,
in part, to such leasing transactions. As a result of these and
other factors, the Partnership and Energy do not intend to enter
into any further significant leasing transactions.
In 1989, Energy purchased 400,000 Common Units directly
from VNGP, L.P. for an aggregate of $6.5 million, or $16.24 per
Common Unit, and made a simultaneous capital contribution to
VNGP, L.P., thereby increasing its equity interest in the
Partnership from approximately 48% to over 49%. However, Energy
cannot purchase any significant number of additional Common Units
without exceeding a 50% ownership interest in the Partnership and
being required under applicable accounting rules to consolidate
the operations and indebtedness of the Partnership for financial
reporting purposes. Energy believes that it is not in the best
interest of its shareholders to consolidate the operations and
indebtedness of the Partnership without owning all of the
Partnership's businesses and assets.
The Partnership and Energy also enter into various types
of transactions in the normal course of business on
market-related terms and conditions as described in Note 1 of
Notes to Consolidated Financial Statements - "Transactions with
Energy." To the extent that net amounts are payable by the
Partnership to Energy from time to time, these transactions also
constitute a type of working capital funding provided by Energy
to the Partnership. The net amount owed by the Partnership to
Energy was $31.8 million and $13.5 million at December 31,
1993 and 1992, respectively.
From time to time, the Partnership has generated cash to
reinvest in its business through the sale of nonstrategic assets.
In 1990 and 1991, the Partnership sold its interest in two
off-system natural gas processing plants in Oklahoma and related
contract rights and realized net cash proceeds of approximately
$22 million. In 1993, the Partnership sold a small off-system
gas processing plant in West Texas. The General Partner believed
that the sale of these assets was desirable because the plants
were located off-system and they were not a part of the
Partnership's core businesses, and because the Partnership was
able to sell the assets at a favorable price. However, the
General Partner believes that sales of assets are not a
dependable source of cash that can be relied upon in planning the
Partnership's investment activities.
The Partnership has not historically required
significant amounts of working capital because cash receipts on
billings for sales and cash payments for purchases occur
principally in the same month. Since the inception of the
Partnership, the General Partner has significantly reduced the
Partnership's working capital position (current assets less
current liabilities) from a level of $29.5 million at March 31,
1987 to a negative $33 million at December 31, 1992 and a
negative $48.3 million at December 31, 1993. The reduction in
working capital requirements has generated a significant amount
of cash, which the Partnership has been able to use for capital
expenditures, debt service and cash distributions. However, the
General Partner believes that, not only is a significant further
reduction in the Partnership's working capital requirements
unlikely to be realized, but that working capital requirements
are likely to increase in the future due to increasing gas
storage inventories resulting from the Partnership's efforts to
compete for interstate sales under FERC Order 636. To the extent
that the Partnership's negative working capital position results
in a cash need, the General Partner anticipates that the
Partnership will utilize its available short-term bank lines,
among other things, to satisfy its short-term cash requirements.
As described in Note 2 of Notes to Consolidated
Financial Statements, the Partnership, through the Management
Partnership, currently has five short-term bank lines totalling
$80 million. The Mortgage Note Indenture requires that at least
$20 million of revolving credit agreements be maintained at all
times; however, no more than $50 million of borrowings are
permitted to be outstanding at any time. All of the bank lines
mature at various times during 1994. If the proposed merger with
Energy does not occur, the General Partner believes that these
bank lines could be renewed or replaced with other short-term
lines during 1994 on terms and conditions similar to those
currently existing. If the proposed merger with Energy is
completed, the General Partner anticipates that new bank credit
agreements will be negotiated and that the Partnership's existing
short-term bank lines will be cancelled. The Partnership had
borrowings of as much as $39.9 million under its short-term bank
lines during 1993. Although no borrowings were outstanding under
these bank lines at December 31, 1993, the Partnership has
incurred borrowings in 1994 of up to $42.9 million in order to
fund increased working capital requirements. The Partnership's
short-term bank lines are subject to a requirement, pursuant to
the Mortgage Note Indenture, to have no balances outstanding for
a period of 45 consecutive days during each 16 consecutive
calendar months (referred to herein as a "clean-up period"). The
Partnership completed a clean-up period during June 1993, and
therefore will be required to complete another clean-up period by
September 1994.
At the time of formation of the Partnership, the General
Partner estimated that capital expenditures of approximately
$30 million to $35 million would be sufficient to maintain the
operations of the Partnership and that the operating cash flows
of the Partnership would be sufficient to allow some additional
level of capital expenditures to sustain, improve or expand
operations. The Partnership Agreement currently provides that
subject to certain exceptions, the General Partner will limit
annual consolidated capital expenditures to the greater of $35
million or 30% of operating cash flow, and to the extent annual
capital expenditures exceed such limits, the General Partner is
required to use its best efforts to finance such excess. The
Partnership's capital expenditures totalled $36.1 million in
1993, $35.9 million in 1992 and $33.1 million in 1991. In
addition, as described above, lease transactions with Energy were
entered into for certain facilities with approximate total costs
of $75 million for leases commencing in 1991 and $26 million for
leases commencing in 1992. The capital leases with Energy were
necessary to permit the Partnership to undertake those capital
projects and remain in compliance with the capital expenditure
guidelines described above. The General Partner believes that,
due to the Partnership's lack of financial flexibility as a
result of the factors described above, the Partnership in its
present form would not be able to continue making capital
expenditures at these levels and, therefore, would likely be
unable to participate fully in opportunities to improve and
expand its operations or to take advantage of the types of
opportunities, such as those described in "Results of Operations-
General" above, that may arise in the natural gas and NGL
businesses over the next several years. At the same time, the
General Partner believes that the Partnership must continue to
make substantial capital investments in facilities needed to
access gas supplies and markets and expand its NGL processing and
transportation capabilities in order for it to maintain its
capacity to compete in the current industry environment. Subject
to consummation of the proposed merger with Energy described
above, Partnership capital expenditures are expected to be
approximately $40 million in 1994.
When the Partnership was formed, the Partnership assumed
Energy's liability with respect to a number of claims and
lawsuits involving allegations that Transmission had failed to
take, or pay for, natural gas under gas purchase contracts. The
Partnership has settled substantially all of the take-or-pay
claims previously brought against it, and believes that it has
settled substantially all of the significant take-or-pay claims
that are likely to be made. Amounts paid in settlement of
take-or-pay claims are treated as deferred gas costs and are
included in the Partnership's "deferred charges and other assets"
until recovered through sales of gas by Transmission. However,
the resolution of such claims resulted in deferred gas costs that
were greater, and have been recovered more slowly through sales
due to Transmission's decreasing sales volumes, than had been
anticipated at the time of formation of the Partnership. At
December 31, 1993, the unrecovered balance of deferred gas costs
was $67 million, compared with $72 million at December 31, 1992.
Additionally, during 1988, 1989 and the first half of 1990, the
Partnership's operating income from NGL operations was
substantially below prior (and subsequent) levels. As a result
of these factors, capital that might otherwise have been
available for capital projects has been used to make take-or-pay
settlements and finance deferred gas costs. Accordingly, the
ability of the Partnership to maintain, improve and expand the
Partnership's business has been less than originally expected.
In order to resolve certain contractual claims, the Partnership
has also agreed to provide discounted gas transportation services
to some customers in lieu of cash settlements. Certain of these
arrangements will continue until the year 2000. The Partnership
is currently involved, directly or indirectly, in various
lawsuits and claims, which, if ultimately resolved in a manner
adverse to the Partnership, could adversely affect the
Partnership's cash flows from operations. For additional
information regarding the above, see "Results of Operations" and
Note 1 - "Other Assets" and Note 6 of Notes to Consolidated
Financial Statements.
Quarterly cash distributions can be declared by the
Partnership only after working capital and other operating
requirements, capital expenditures, debt service and capital
lease obligations are funded. As discussed in Note 1 of Notes to
Consolidated Financial Statements - "Allocation of Net Income and
Cash Distributions", the Preference Period for preferential cash
distributions to holders of Preference Units ended with the cash
distribution for the first quarter of 1992 which was paid in the
second quarter. The quarterly cash distributions thereafter were
reduced from $.625 per unit to $.125 per unit because of the
reduction in the Partnership's available cash flows resulting
from the various factors described above. Cash distributions
totalled $10.4 million, $29.5 million and $48 million for the
years ended December 31, 1993, 1992 and 1991, respectively.
Future cash distributions to unitholders will depend upon the
level of cash from operations and there is no assurance that cash
distributions will continue into the future at the current level.
The General Partner expects that the Partnership's
internally generated funds from operations will be sufficient in
the first quarter of 1994 to fund debt service, lease obligations
and minimum capital expenditure requirements. Cash requirements
in excess of such amounts, such as cash distributions on the
Common Units, any increases in working capital requirements and
capital expenditures necessary to pursue possible industry
opportunities, as described above, are expected to require
supplemental funding, such as borrowings under the short-term
credit lines described above. If the proposed merger with Energy
does not occur, the General Partner believes that the above
described clean-up requirement in 1994 can be achieved, but would
require significant capital expenditure and working capital
reductions, the elimination of cash distributions on the Common
Units, the sale of core assets, or other measures likely to have
adverse effects on the Partnership and the Unitholders. When and
if the proposed merger with Energy is completed, the General
Partner anticipates that distributions to Energy from the
Partnership would be significantly reduced or eliminated, with
such funds utilized for debt service including repayment of
borrowings under the Partnership's short-term credit lines,
working capital, capital expenditures or other Partnership
purposes.
The Partnership is subject to environmental regulation
at the federal, state and local level. During 1993, the
Partnership submitted for approval various permitting matters to
the Texas Natural Resource Conservation Commission with respect
to air emissions at Transmission's compressor stations and Valero
Hydrocarbons, L.P.'s gas processing plants. No such matters are
currently pending. The Partnership's annual expenditures related
to environmental remediation have not been significant to date.
The General Partner does not expect that the Partnership will
expend or be required to expend any significant amount on any
environmental remediation matters, including polychlorinated
biphenyls, which have affected certain natural gas pipeline
companies. No amount has been accrued for any contingent
environmental liability.
<PAGE>
SIGNATURES
Pursuant to the Requirements of the Securities
Exchange Act of 1934, the registrant has duly caused this
amendment to be signed on its behalf by the undersigned,
thereunto duly authorized.
VALERO NATURAL GAS PARTNERS, L.P.
(Registrant)
By Valero Natural Gas Company,
its General Partner
By /s/ Don M. Heep
(Don M. Heep)
Senior Vice President and
Chief Financial Officer
Date: March 2, 1994
<PAGE>
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated. All such capacities are with Valero Natural
Gas Company, General Partner of the registrant.
Signature Title Date
Director, Chairman of the
Board and Chief Executive
Officer (Principal
/s/ * Executive Officer) March 2, 1994
(William E. Greehey)
Senior Vice President and
Chief Financial Officer
(Principal Financial and
/s/ * Accounting Officer) March 2, 1994
(Don M. Heep)
/s/ * Director March 2, 1994
(Edward C. Benninger)
/s/ * Director March 2, 1994
(Ronald K. Calgaard)
/s/ * Director March 2, 1994
(Ruben M. Escobedo)
/s/ * Director March 2, 1994
(Stan L. McLelland)
/s/ * Director March 2, 1994
(Mack Wallace)
* By: /s/ Rand C. Schmidt
(Rand C. Schmidt)
Attorney-in-Fact
